ML20214D226

Safety Evaluation Report Related to the Operation of Byron Station,Units 1 and 2.Docket Nos. 50-454 and 50-455. (Commonwealth Edison Company)

ML20214D226
Person / Time
Site:	Byron
Issue date:	11/30/1986
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-0876, NUREG-0876-S07, NUREG-876, NUREG-876-S7, NUDOCS 8611210418
Download: ML20214D226 (89)

Text

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NUREG-0876 Supplement No. 7 4

e Safety Evaluation Report

related to the operation of L Byron Station, Units 1 and 2 Docket Nos. STN 50-454 and STN 50-455 -

Commonwealth Edison Company

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U.S. Nuclear Regulatory Commission -

Office of Nuclear Reactor Regulation November 1986 -

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o NOTICE Availability of Reference Materials Cited in NRC Publications Most documents cited in NRC publications will be available from one of the following sources:

1. The NRC Public Document Room,1717 H Street, N.W.

Washington, DC 20555

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Referenced documents available for inspection and copying for a fee from the NRC Public Docu-ment Room include NRC correspondence and internal NRC memoranda; NRC Office of Inspection and Enforcement bulletins, circulars, information notices, inspection and investigation notices; Licensee Event Reports; vendor reports and correspondence; Commission papers; and applicant and l licensee documents and correspondence.

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to the Division of Technical Information and Document Control, U.S. Nuclear Regulatory Com-mission, Washington, DC 20555.

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NUREG-08/6 Supplement No. 7 Safety Evaluation Report related to the operation of Byron Station, Units 1 and 2 Docket Nos. STN 50-454 and STN 50-455 Commonwealth Edison Company i

U5.~ Nuclear Regulatory Commission Office of Nuclear Reactor Regulation i

r November 1986 1

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ABSTRACT Supplement No. 7 to the Safety Evaluation Report related to Commonwealth Edison Company's application for licenses to operate the Byron Station, Units 1 and 2, located in Rockvale Township, Ogle County, Illinois, has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission. This supplement provides additional information supporting the license for initial criticality and power ascension to full power operation for Unit 2.

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TABLE OF CONTENTS P_ag,e ABSTRACT............................................................... iii 1 INTRODUCTION AND GENERAL DESCRIPTION OF FACILITY ................. 1-1 1.1 Introduction ................................................ 1-1 ,,

1. 7 S umma ry o f Ou ts ta nd i ng I tems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 1.8 Confirmatory Issues ......................................... 1-2 1.9 License Conditions .......................................... 1-4 3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS AND COMPONENTS ........... 3-1 3.5 Missile Protection .......................................... 3-1 3.8 Design of Seismic Category I Structures . . . . . . . . . . . . . . . . . . . . . 3-1 3.9 Mechanical Systems and Components ........................... 3-3 3.9.6 Inservice Testing of Pumps and Valves ................ 3-3 3.10 Seismic and Dynamic Qualification of Mechanical'and Electrical Equipment ........................................ 3-4 3.11 Environmental Qualification of Electric _ Equipment Important to Safety and Safety-Related Mechanical Equipment ........... 3-4 4 REACTOR .......................................................... 4-1 4.3 Nuclear Design .............................................. 4-1 4.4 Thermal and Hydraulic Design ................................ 4-2 5 REACTOR COOLANT SYSTEM ........................................... 5-1 5.2 Integrity of Reactor Coolant Pressure Boundary . . . . . . . . . . . . . . 5-1 6 ENGINEERED SAFETY FEATURES .................,...................... 6-1 6.5 Fission Product Removal and Control System .................. 6-1 6.6 Inservice Inspection of Class 2 and 3 Components............. 6-1 7 INSTRUMENTATI N AND CONTROL ...................................... 7-1

7. 3 Engineered & Safety Features Systems ........................ 7-1

7. 4 Sys tems Requi red for Sa fe Shutdown . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 8 ELECTRIC POWER SYSTEMS ........................................... 8-1 8.4 Other Electrical Features and Requirements for Safety ....... 8-1 Byron SSER 7 Y i

TABLE OF CONTENTS (Continued)

Page 9 AUXILIARY SYSTEMS ................................................ 9-1 9.5 Other Auxiliary Systems ..................................... 9-1 13 CONDUCT OF OPERATION .............................. .............. 13-1 13.1 Organizational Structure of Applicant ....................... 13-1 13.5 Plant Procedures ............................................ 13-1 14 INITIAL TEST PROGRAM ............................................. 14-1 15 ACCIDENT ANALYSIS .............,................................... 15-1 15.6 Anticipated Transients Without Scram ........................ 15-1 18 CONTROL ROOM DESIGN REVIEW ....................................... 18-1 18.2 Main Control Room and Remote Shutdown Panel ................. 18-1 18.3 Safety Parameter Display System ............................. 18-1 APPENDICES A CONTINUATION OF THE CHRON0 LOGY OF NRC STAFF RADIOLOGICAL SAFETY REVIEW 0F THE BYRON STATION F NRC STAFF CONTRIBUTORS K PRESERVICE INSPECTION RELIEF REQUEST EVALUATION N

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! 1 INTRODUCTION AND GENERAL DESCRIPTION OF FACILITY 1.1 Introduction

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The Nuclear Regulatory Commission's Safety Evaluation Report (SER) (NUREG-0876) in the matter of Commonwealth Edison Company's application to operate the Byron Station Units 1 and 2 was issued in February 1982. The first supplement (SSER) i to that SER was issued in March 1982, the second was issued in January 1983, the third was issued in November 1983, the fourth was~ issued in May 1984, the

fifth was issued in October 1984, and the sixth was issued in February 1985.

On February 14, 1985, a full power license was issued for Unit 1.

This seventh SER supplemer.t provides additional information supporting the issuance of an operating license for f uel loading, initial criticality, and power ascension up to full power operation of Byron Station, Unit 2.

Copies of this SER supplement are available for inspection at the NRC Public Document Room, 1717 H Street, NW, Washington, D.C., and at the Rockford Public Library, Rockford, Illinois. Single copies may be purchased from the sources indicated on the inside front cover.

The NRC Project Manager assigned to the Operating License application for

] Byron Station is Leonard N. Olshan. Mr. Olshan may be contacted by calling i (301) 492-4937 or writing:

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1 Leonard N. Olshan Division of Licensing

Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission

Washington, D.C. 20555 1.7 Summary of Outstanding Items

, . The current status of the outstanding items listed in the original SER and the -

l supplements follows:

i (1) Additional information to confirm pipeline foundation design (Section 2.5) -

Closed in Supplement 5.

(2) Turbine missile evaluation (Section 3.5.1.3) - Closed in Supplement 5.

! (3) High- and moderate energy pipe break analysis outside containment (Section 3.6.1) - Closed in Supplement 2.

(4) Pump and valve operability assurance (Section 3.9.3.2) - Closed in l Supplement 5.

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(5) Baseplate flexibility and anchor bolt loading (Section 3.9.3.4) - Closed in Supplement 3.

(6) Seismic and dynamic qualification of equipment (Section 3.10) - Closed in Supplement 5.

(7) Environmental qualification of electrical equipment (Section 3.11):-

Closed in Supplement 5.

(8) Improved thermal design procedures (Section 4.4.1) - Closed in Supplement 5.

(9) TMI action item II.F.2: . Inadequate Core Cooling Instrumentation (Section 4.4.7) - Closed in Supplement 5.

-(10) Steam generator flow-in'duced vibrations (Section 5.4.2) - Closed in Supplement 5.

(11) Reactor pressure vessel forces and moments analysis (Section 6.2.1'.2) -

Closed in Supplement 2.

(12) Equipment and floor drainage system for internal flood protection (Section 9.3.3) - Closed in Supplement 2.

(13) Fire protection program (Section 9.5.1) - Closed in Supplement 5.

(14) Residual moisture in diesel air start piping (Section 9.5.6) - Closed in Supplement 1.

(15) Volume reduction system (Sections 11.1 and 11.4.2) - closed in Supplement 6.

(16) Emergency preparedness plans and facilities (Section 13.3) - Closed in Supplement 4.

(17) Control room human factors review (Sec_ tion 18.0) - Closed in Supplement 4.

(18) Conformance of ESF filter system to RG 1.52 (Section 6.5.1) - Closed in. '

Supplement 5.

1.8 Confirmatory Issues .

(1) Confirmatory analysis to verify river screenhouse seismic response analysis (Section 2.5.4.3) - Closed in Supplement 6.

(2) Category 1 manhole protection from tornado missiles (Section 3.5.3) -

Closed in Supplement 1. -

(3) Analysis of tangential shear on containment (Section 3.8.1) - Errata, deleted in Supplement 2.

(4) Piping vibration test program (Section 3.9.2.1) - Closed in Supplement 6.

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(5) Snubber inspection and testing program details (Section 3.9.2.1) - Closed in Supplement 1.

(6) Seismic reevaluation of components and supports (Section 3.9.2.2) - Closed in Supplement 1.

(7) Basis for steam generator tube plugging (Section 3.9.3.1) - Clcsed in Supplement 3.

(8) Inservice testing of pumps and valves (Section 3.9.6) - Closed in Supple-ment 5.

l (9) Loose parts mon?toring system (Section 4.4.6) - Closed in Supplement 2.

1 (10) Code cases for control valves (Section 5.2.1) - Closed in Supplement 1.

(11) Fracture toughness data for Byron Unit 2 (Section 5.3.1) - Closed in Supplement 2.

l (12) Steam generator tube surveillance (Section 5.4.22) - Closed in Supple-ment 2.

(13) Bo ation to cold shutdown analysis (Section 5.4.3) - Closed in Supple-ment 2. .

(14) Cooldown rate with RHR (Section 5.4.3.1) - Closed in Supplement 2.

(15) RCS vent procedures (Section 5.4.5) - Closed in Supplement 2.

i (16) Charging pump deadheading (Section 6.3.2), (Section 7.3.2.13) - Closed in

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this supplement.

(17) Containment differential pressure analysis (Section 6.2.1) - Closed in Supplement 2.

(18) Containment sump instrumentation (Sect. ion 6.2.1.1) - Closed in Supple-ment 2. .

(19) Minimum containment pr' essure analysis for performance capabilities of ECCS (Section 6.2.1.5) - Closed in Supplement 5.

(20) Containment leakage testing vent and drain provisions (Section 6.2.6) -

Closed in Supplement 5.

l (21) Confirmatory test for sump design (Section 6.3.4.1) - Closed in i

Supplement 5.

l (22) Upper head temperature verificatior (Section 6.3.5.1) - Closed in Supplement 2.

j (23) IE Bulletin 80-06 (Section 7.3.2.2) - Closed in Supplement 6.

(24) Test jacks for P-4 interlock test (Section 7.3.2.9) - Closed in Supplement 2.

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4h (25) Remote shutdown capability (Section 7.4.2.2) - Closed in this supplement for Unit 1.

(26) Steam generator pressure control (Section 7.4.2.3) - Closed in Supple-ment 2.

(27) Switchover from injection to recirculation (Section 7.6.2.3) - Closed in Supplement 3.

(28) TMI Item II.K.3.1 (Section 7.6.2.7); III.D.1.1 (Section 9.3.5); II.K.2.17 (Section 15.5); II.D.~I (3.9.3.3); II.K.2.17 - Closed in Supplement 2, I others closed in Supplement 5.

l (29) Viewing the installation and_ arrangement of electrical equipment (Sec- i tion 8.1)'- Closed in Supplement 3.

(30) Independence of redundant electrical safety equipment (Section 8.4.4) -

Closed in Supplement 2.

(31) Electrical distribution system voltage verification (Section 8.2.4) -

Closed in Supplement 6.

(32) Combined health physics and chemistry organization (Section 12.5.1) -

Closed in Supplement 3.

(33) Revision to Physical Security Plan (Section 13.6) - Closed in Supplement 4. l i

(34) RCP rotor seizure and shaft break (Section 15.3.6) - Closed in Supplement _5. l l

(35) Anticipated Transients Without Scram (ATWS) (Section 15.6) - Closed in Supplement 4.

(36) Applicant compliance with the Commission's regulations (Section 1.1) -

Closed in Supplement 4.

(37) SWS process control prograr (Section 11.4.2) - Closed in Supplement 5.

(38) Noble gas monitor (Section 11.5.2) - Closed in Supplement 5.

1. 9 License Conditions Following is the current status of the license conditions:

(1) Groundwater monitoring program (Section 2.4.6) - Closed in Supplement 5.

(2) Masonry walls (Section 3.8.3) - Closed in Supplement 5.

(3) Preservice and Inservice. inspection program (Sections 5.2.4 and 6.6) -

Closed in Supplement 5 for Unit 1, closed in this supplement for Unit 2.

(4) Response time testing (Section 7.2.2.5) - Closed in Supplement 4.

(5) Post accident monitoring (Section 7.5.2.2) - Closed in Supplement 2.

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(6) Modifications to permit isolation of non-IE loads from Class 1E power sources (Section 8.3.2) - Errata, deleted in Supplement 1.

(7) Compliance with Appendix R of 10 CFR 50, Fire Protection (Section 9.5.1).

(8) Steam valve inservice inspection (Sections 3.5.1.3, 10.2) - Closed in Supplement 5.

(9) Implementation of secondary water chemistry monitoring and control program as proposed by the Byron /Braidwood FSAR (Section 10.3.2) - Closed in Supplement 4.

(10) Personnel on shift with previous commercial PWR experience during startup phase (Section 13.2.1) - Closed in Supplement 4.

(11) TMI Item II.B.3 Postaccident Sampling (Section 9.3.2) - Closed in Supplement 5.

(12) Natural circulation testing (Section 5.4.3) - Closed in Supplement 5.

(13) Control of heavy loads (Section 9.1.5) - Closed in Supplement 6.

(14) Upgrade emergency operating procedures (Section 13.5.2) - Closed in this supplement.

(15) Relocate control room controls (Section 18.2) - Closed in this supplement.

(16) Emergency planning (Section 13.3) - Closed in Supplement 6.

(17) Seismic and dynamic qualification (Section 3.10) - Closed in this supple-ment for Unit 2.

(18) Equipment qualification (Section 3.11) - Closed on November 30, 1985.

(19) Iodine particulate sampling (Section 11.5.2).

(20) Reliability of diesel generators (Section 9.5.4.1).

(21) Feedwater flow measurement accuracy monitoring (Section'4.4.1) - Closed in Supplement 6.

(22) Protection against postulated breaks or cracks in high- and moderate-energy lines (Section 3.6.2) - Closed in Supplement 6.

(23) Volume reduction system (from Outstanding Issue 15) - Closed in Supplement 6.

(24) Shift advisors (Section 13.1.2) - Closed in this sup~plement.

(25) Turbine maintenance program (Section 3.5.1) - Closed in this supplement.

(26) Control room ventilation system (Section 6.5.1) - Closed on July 1, 1985 for Unit 1.

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3 DESIGN CRITERIA FOR STRUCTURES, SYSTEMS AND COMPONENTS 3.5 Missile Protection 3.5.1 Missile Selection and Description 3.5.1.3 Turbines Missiles In SER Supplement 5, the staff stated that it had not completed its review of the turbine inspection program based on the manufacturer's recommendations and committed to by the licensee in its letter of September 26, 1984. By letter dated May 20, 1985, the staff stated it had reviewed and approved the manufac-turer's (Westinghouse) generic turbine integrity methodology which provides procedure for estimating crack growth . missile generation probability, and volumetric in pection intervals. The Westinghouse analysis indicated on Unit 1 that one rotor should be inspected at each refueling outage; thus, all three rotors would be inspected by the end of the third refueling outage.

The staff. in its May 20, 1985 letter, concluded that the. licensee had committed to follow ;he acceptable Westinghouse methodology to determine the low pressure turbine rotor inspection interval and that License Condition 2.C.(14) in the February 14, 1985 Unit 1 license had been satisfied.

3.8 Design of Seismic Category I Structures

• 3.8.3 Other Seismic Category I Structures The staff concludes that the use of Nuclear Construction Issues Group (NCIG)-01, Rev. 2, 05/07/85, " Visual Weld Acceptance Criteria for Structural Welding at Nuclear Power Plants" (VWAC) will ensure adequate quality of non-ASME Code structural steel welds. These crite'ria are limited to non-ASME class welded steel structures where fatigue is not the governing design consideration.

Typical examples of structures to which these criteria may be applied are main building framing members and connecting members, supports for equipment and piping (non-ASME Code), cable trays and conduit, HVAC ducts and duct supports, and miscellaneous steel including bracing and stiffeners, embedments, stairways, and handrails, doors and door frames, windows and window frames, gratings, covers, etc.

There are eleven criteria addressed in VWAC. For cracks, the criteria is the same as in AWS D 1.1 " Structural Welding Code" - the welds shall have no cracks.

Underfilled craters are acceptable if proper weld size is achieved and cracks are absent.

For arc strikes, surface slag and weld spatter, the VWAC criteria are based more on the effects on structural strength than on workmanship. Arc strikes

• By letter dated October 7, 1985, the staff transmitted this section to the licensee.

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are acceptable provided cracks are not visually detectable. Weld spatter remaining after cleaning is acceptable. For surface slag, the criteria are designed to prevent the acceptance of a weld which shows a gross lack of control by the welder. Isolated surface slag which remains after weld cleaning has no structural significance.

Criteria for the following types of defects or faults are also provided in VWAC:

a) fillet weld size b) incomplete fusion c) weld overlap d) weld profiles e) undercut f) surface porosity g) weld length and location The basis for the acceptance criteria in VWAC is the amount of reduction in cross sectional area caused by the defect or fault. In such calculations, the conservative approach used is to consider the length of weld in which a defect occurs as being non-existent, i.e., it does not support any of the load. The-standards usually allow such cross section reductions up to 12.5 percent.

There are some exceptions to this, particularly in thinner section members.

This occurs because measurements of defects or faults are rounded off up to the smallest measurement unit specified. For instance, a 1/32 inch maximum undercut for the entire length on one side for 3/16 inch thickness material results in a 16.7 percent reduction in area. Because the 1/32 inch undercut will not be uniform along the entire length, most of the undercut will be less than 1/32 inch in depth. However, the defect or fault is rounded up to 1/32 inch. Therefore, although the 16.7 percent maximum reduction is a theoretical possibility, it is not likely to occur.

The 12.5 percent " benchmark" was chosen based upon the presently allowed percent reduction in area affected by the undercut criteria'in AWS D 1.1-85 for the most limiting case in the thinnest member. This is because if undercut is allowed to reduce the load carrying capability by a given number, other defects or faults that would result in a reduction of similar or less magnitude should also be acceptable.

The acceptance by engineering evaluation of thousands of field weldments with similar defects or faults not meeting the criteria of AWS 0 1.1 has resulted in the decision to use the weldments "as is" without repair. This is possible because common engineering design practices result _in significant margins above design requirements and a small reduction of 10 to 12 percent can be easily accommodated. The present undercut criteria in AWS D.1.1-85 is a practical demonstration of this.

The deviations from AWS 0 1.1 as proposed in VWAC are relatively insignificant since the redundancy of these structures and their individual welds, and the conservative design practices used, allow non-ASME Code structural steel weldments (which are not designed for fatigue) to use alternative criteria as provided in Criterion II of 10 CFR, Part 50, Appendix B. The staff finds Byron SSER 7 3-2 .

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e these. criteria are appropriate and provide adequate integrity of the affected structures and accordingly, General Design Criterion 1 of Appendix A to 10 CFR Part 50 has been met.

3.9 Mechanical Systems and Components 3.9.6 Inservice Testing of Pumps and Valves By letter dated February 6,1986, the licensee submitted a program for the in-service testing (IST) of pumps and valves. This submittal was reviewed by the staff and was the subject.of a working meeting with the licensee on July 8 and 9, 1986. Based on staff comments during that meeting, the licensee submitted a revised IST program by letter dated September 30, 1986. This revision super-seded the previous submittal and includes changes resulting from discussions during the July 8 and 9, 1986 meeting.

l The licensee's IST program is required by 10 CFR 50.55a(g) to comply with the ASME Boiler and Pressure Vessel Code,Section XI. For Byron Unit 1, the appli-cable version of the ASME Section XI Code is 1980 edition through the Winter 1980 Addenda. Pursuant to CFR 50.55a(g)(5), the licensee has requested relief from certain ASME Code testing requirements for specific pumps and valves where the Code requirements are impractical within the limits of design, geometry and system safety. The licensee's request for relief includes an explanation and justification for the relief and a proposal for alternative test procedures.

The staff has completed a preliminary review of the Byron IST program. That i

program includes both baseline preservice testing and periodic inservice test-ing. It provides both for function testing of components in the operating state and for visual inspection to verify proper valve position.

The staff has not yet completed a detailed review of the licensee's submittal.

However, the preliminary review indicates that it is impractical within the limitations of design, geometry, and system safety for the licensee to meet cer-tain specific requirements of the ASME Code. Granting of interim relief from those requirements as provided by the regulation will not e,ndanger life, prop-erty, or the common defense and security of the public and is in the public interest giving due consideration to the burden on the applicant that could re-suit if the requirements were imposed. Based on experience at similar plants where no significant adverse health and safety effects were found, the staff concludes that the requirements of 10 CFR 50.55a(g)(6)(i) are satisfied.

Therefore, pursuant to 10 CFR 50.55a(g)(i), the relief that the licensee has requested from certain of the pump and valve testing requirements should be granted on an interim basis until no later than three years from the date of~

issuance of the operating license so that a detailed review of the justifica-tions for each request for relief may be completed. This extends the maximum 2 year period of interim approval, granted in SSER No. 5, for another year.

If the detailed review results in any request for relief being denied, the licensee will be required to comply with the appropriate Section XI require-ments as required by regulation 10 CFR 50.55a(g). In addition, if the detailed review identifies any pumps or valves which are not categorized as ASME Code Class 1, 2, or 3 but perform a safety function, those pumps and valves will be included in the IST program if they are not currently included.

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3.10 Seismic and Dynamic Qualification of Mechanical and Electrical Equipment SER Supplement No. 5 stated that only one category of equipment, the Westing-house 7300 Process Protection System (ESE-13), had not been qualified. By letter dated October 24, 1986, the licensee stated that qualification of this equipment, including necessary modifications, has been completed on Unit 2.

Therefore, a license condition similar to the one in,the Unit 1 license is not needed.

3.11 Environmental Qualification of Electrical Equipment Important to Safety, and Safety-Related Mechanical Equipment SER Supplement No. 6 approved the. licensee's justification for interim opera-tion regarding the issue of steam superheat caused by a postulated main steam-line break (MSLB) outside containment.

By letters dated July 22 and September 10, 1986, the licensee submitted its evaluation for the Byron and Braidwood Stations of the environmental effects of a main steamline break outside containment with superheated steam blowdown.

This superheat concern was identified in IE Information Notice 84-90. For certain MSLB accidents, the steam generator tube bundle will be progressively uncovered. This will result in the release of superheated steam, which will raise the temperature in the safety valve rooms above that previously calcu-lated. Consequently, the environmental qualification of equipment located in the safety valve rooms needed to be reevaluated.

The mass and energy release data taken from Westinghouse report WCAP-10961 were used as input to the RELAP4/M006 computer code to calculate the temperature profiles in the safety valve rooms. A thermal lag analysis was then performed to obtain component temperature response.

The licensee postulated a spectrum of 40 cases, covering break sizes from 0.1 ft2 to 4.6 ft ,102%

2 and 70% of full power, and auxiliary feedwater. (AFW) flow rates of minimum flow rate, 200 gpm, and 300 gpm. The mass and energy release data were calculated using the Westinghouse computer code LOFTRAN (tabulated as " Category I" in WCAP-10961). The LOFTRAN code was modified to account for heat transfer to the steam during steam generator tube bundle i uncovery. .

l This modification is described in WCAP-8860 (Supplement 1), which was found '

acceptable by the staff in the staff's safety evaluation which was transmitted to Westinghouse by letter dated May 27, 1986. Therefore, the staff finds the mass and energy release data used in the subject analysis to be acceptable.

The computer code RELAP4/ MOD 6 was used to calculate the compartment temperature profiles. The heat sinks in the valve rooms were conservatively neglected.

The applicant indentified-two limiting cases: 0.2 ft2 break at 102% power with minimum AFW flow and 0.3 ft 2 break at 102% power and a constant AFW flow of 300 gpm. Thermal lag analyses of the internals of the MSIV actuator hydraulic cylinder, the MSIV actuator pneumatic reservoir, and the NAMCO limit switch were performed in accordance with the guidance in NUREG-0588, Appendix B.

Condensation heat transfer was modeled until the surface temperature of the component reached the saturation temperature corresponding to the pressure i;)

the valve rooms. Analysis results indicate that condensation heat transfer-Byron SSER 7 3-4 m

will last only a very short time and that forced convection heat transfer will I

occur throughout the remainder of the transient. Forced convection heat 4

transfer was modeled with flow velocity determined by the blowdown rate. t By letter dated October 2, 1986, the. licensee provided a report that presents an evaluation based on component surface temperature which demonstrates that the components in question are also qualified using this conservative approach.

On the basis of a review of the methodology and assumptions, computer code in-put, and analysis results, the staff finds acceptable the licensee's calculated

] valve room temperature response, as well as component temperature profiles for equipment qualification.

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4 REACTOR 4.3 Nuclear Design

• 4.3.2 Evaluation Findings In a letter dated October 24, 1983, the applicant submitted information.describ-ing the nuclear analysis methods it used in support of control rod worth measure-ments using the rod swap technique for its Zion, Byron, and Braidwood reactors.

On March 12, 1981 (letter from S. A. Varga, NRC, to J. S. Abel, CECO), the staff approved.use of the rod swap technique for control rod worth measurements for Zion Station, Units 1 and 2, provided the predictions were done by Westinghouse. The rod swap technique has been used for four reload cycles on the Zion Units. The applicant is now requesting approval to its nuclear analysis methods to do the predictions for rod swap starting with the Zion Unit 1 Cycle 8 reload.

To support its request, the applicant has performed a rod swap benchmark study in which rod swap analyses were performed for the four cycles of Zion data. ,

The computer codes are as described in the applicants' topical report,

" Benchmark of PWR Nuclear Design Methods," NFSR-0016, which has recently been approved by the NRC. The calculational methodology used to generate the rod swap parameters is identical to that used by Westinghouse as described in Section 3.2 of WCAP-9863-A, " Rod Bank Worth Measurements Utilizing Bank Exchange."

The staff has reviewed the summary of the Edison rod swap benchmark study, in the form of the percent differences between measured or inferred rod worth and the Edison predictions. The staff has compared these results with the results obtained using Westinghouse predictions. In general, the differences between measured or inferred and predicted rod worths were smaller for the Ceco data than for the Westinghouse data. The CECO differences measurement prediction prediction 100 tended to be both positive and negative; the Westinghouse differences are almost totally negative. Of the 64 cases (4 cycles x 8 banks x 2 predictors),

there were no differences greater than the design criteria of 115%. Only two differences were larger than 10%. Staff review showed that over the four cycles analyzed, the average difference between the measured and predicted total rod worth values was -2.3% for CECO and -5.38% for Westinghouse. The average difference for individual control rod banks was -1.0% for CECO and

-5.09% for Westinghouse.

Because the rod swap calculations and measurement technique are so intricate, previous NRC approval for rod swap use has required a boron dilution versus rod

• 8y letter dated September 9, 1986, the staff transmitted this section to the licensee.

Byron SSER 7 4-1

, 1 swap comparison. The applicant has not performed a boron dilution versus rod swap comparison to validate its calculational ability. However,.the benchmark study that the applicant did perform is quite extensive and the results show the applicant's ability to perform the rod swap analysis with results comparable to better than those previously approved. On this basis,the staff approves the applicant's use of the nuclear analysis methods in support of control rod worth measurements using the rod swap technique. Use of the rod swap technique is still subject to the other conditions of the March 12, 1981, approval, namely:

(1) All banks (control and shutdown) will be measured.

(2) Procedures as outlined in WCAP-9863-A will be followed.

(3) Design Criteria, Safety Criteria,and Remedial Action as stated in a March 12, 1981, letter to the applicant and in two letters from the applicant (February 4 and March 5, 1981) will be followed.

(4) A report comparing measured and predicted rod worths will be submitted to the NRC within 45 days of completion of the rod worth tests for the first use of rod swap on a reload at each unit.

4.4 Thermal and Hydraulic Design 4.4.7 Inadequate Core Cooling (ICC) Instrumentation

• In Supplement No. 5 to the SER the staff indicated that the licensee should provide a means for trending subcooling margin if the primary display is unavailable. On March 26, 1986, the staff conducted an audit of the Byron ICC instrumentation. During the audit, the licensee contended that because of the way their emergency operating procedures are written, provision of this infor-mation to the operators would in no way enhance their ability to respond to an inadequate core cooling event and would, in fact, unnecessarily burden the operator with an additional task during a period of high stress. Considerable discussion ensued regarding the impact trending this temperature could have on plant safety, and the pertinent emergency operating procedures were reviewed.

Based on this discussion and review, the staff concludes that Byron should not be required to install a temperature recorder for the following reasons:

1. The Byron emergency operating procedures require operator action based on exceeding a discrete temperature limit point. These procedures, which are based on approved guidelines, do not make any use of, nor do they mention, a temperature trend or history;

2. Reanalysis of NUREG-0737 by the NRC staff determined that a requirement for providing trending of subcooling margin if the primary display is unavailab7e is not clearly defined and open to considerable interpreta-tional latitude and therefore not enforceable.

• By letter dated May 13, 1986, the staff transmitted this section to the licensee.

Byron SSER 7 4-2

5 REACTOR COOLANT SYSTEM 5.2 Integrity of Reactor Coolant Pressure Boundary i

! 5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing i

This section was prepared with the technical assistance of DOE contractors from the Idaho National Engineering Laboratory.

1 1 5.2.4.3 Evaluation of Compliance with 10 CFR 50.55a(g) for Byron Unit 2 i

^

This evaluation supplements conclusions in this section of NUREG-0876 which

addressed the definition of examination requirements and the evaluation of com-

pliance with 10 CFR 50.55a(g). The application for the Byron and Braidwood l Stations was submitted and accepted for review under the Commission's standard-1 ization policy using the duplicate plant option. Therefore, the staff consid-ered the review of the preservice inspection (PSI) program to be a confirmatory

, issue based on the staff review of the Byron Unit 1 PSI program, which was

] determined to be acceptable in NUREG-0876, SSER 5, and contingent upon the j Applicant:

a j

(1) Demonstrating that either, (a) the Byron Unit I and Byron Unit 2 PSI pro-i grams are essentially the same, or (b) the Byron Unit 2 PSI program is different but meets the requirements of 10 CFR 50.55a(g)(3),

1 l (2) submitting all relief requests with a supporting technical justification,

and i

(3) submitting conclusions regarding the ability to examine the cast stainless steel pipe elbows.

1 Since the previous supplement, staff review has been completed on the following i information:

1 (1) Tne FSAR through Amendment 47 dated April 1986;

].

j (2) the " Interim Report on Ultrasonic Examination of Welds in Cast Stainless 4 Steel Components at Byron and Braidwood Stations" submitted June 25, 1986; l

(3) the results of the staff meeting at the Bra'idwood Plant site June 26, 1986 to discuss the preservice inspections of the primary coolant system's sta-tically cast stainless steel fittings at both Byron and Braidwood; (4) the Applicant's July 23, 1986 submittal comparing the differences between  !

, the Byron Unit 2 and the Byron Unit 1 PSI Program Plans; l

j (5) the summary report regarding the " Ultrasonic Examination of Cast Stainless j Component Welds at Byron Unit 2 and Braidwood Unit 1" submitted September 2, j 1986; Byron SSER 7 5-1

i (6) requests for relief from the ASME Code Section XI requirements that the Applicant has determined to be impractical for Byron Unit 2, submitted July 23, 1986-and September 2, 1986; (7) clarifications and revisions to the relief requests received in the Appli-cant's submittal dated September 30, 1986; and (8) a submittal dated October 16, 1986, requesting that Byron Unit 2 PSI Pro-gram Note 5 be evaluated as a relief request (Relief Request NR-NOTE 5).

Based on the construction permit issuance date of December 31, 1975, 10 CFR 50.55a(g)(3) requires that the PSI Program be developed and implemented using at least the Edition and Addenda of Section XI of the ASME Boiler and Pressure Vessel Code applied to the construction of the patticular components.

The Applicant has prepared a program based on the requiremtits of ASME Code Section XI, 1977 Edition with Addenda through Summer 1978. The use of later referenced Code editions is acceptable as specified by 10 CFR 50.55a(g)(3).

In the July 23, 1986 submittal, the Applicant verified that the scope and re-quirements of the Byron Unit 2 PSI Program, as well as the augmented inspec-tions, are identical to those of Byron Unit 1. The Byron Unit 2 Code Class I components exempted from preservice examination per Section XI paragraph IWB-1220 correspond directly to the Byron Unit 1 exempted components. It was also reported that the automated ultrasonic examination of the Byron Unit 2 reactor pressure vessel was performed to the requirements of NRC Regulatory Guide 1.150.

On June 26, 1986, the staff met with the Applicant at the Braidwood plant site for a specific demonstration to determine the effectiveness of the Applicant's ultrasonic examinations on the statically cast stainless steel elbows using qualified procedures on the Byron /Braidwood calibration blocks, a 0.5 inch deep mechanical fatigue crack in a specimen obtained from the Westinghouse Owners' Group, machined notches in a pipe-to-elbow weld obtained from the cancelled Marble liill site, and on actual plant welds. The Applicant's examinations, using dual 1.0 inch diameter, 1.0 Milz, Alpha series flat-faced transducers mounted on contoured, removable wedges that produce an approximately 40 to 45 refracted longitudinal wave focused slightly beyond the weld I.D. surface, were completed from the statically cast fitting side of the welds. The wrought side (pipe side) of the welds had been previously examined during PSI using conven-tional shear wave techniques. Based on discussions and demonstrations during the meeting at the Braidwood plant site, the staff reached the following con-clusions regarding the preservice ultrasonic examination of the cast stainless steel fitting welds:

(1) The examination procedures meet the methodology requirements of Section XI of the ASME Code.

(2) The ultrasound penetrated the region of the weld subject to examination and produced reflections from inherent geometrical conditions in the pipe that could be interpreted, and (3) The detection of significant construction-type defects, if present, was possible with the ultrasonic signal-to-noise ratios observed.

Byron SSER 7 5-2

Based on the above, the staff has determined that the fitting and piping welds in the primary coolant system at the Byron Unit 2 plant have sufficiently good acoustical properties to permit a valid ultrasonic examination with state-of-the-art instrumentation. Therefore, the staff considers the issue of the pre- ,

service ultrasonic examination of welds in the primary coolant system to be resolved.

Requests for relief from the ASME Code Section XI requirements which the Appli-i cant has determined to be impractical for systems and components within the reactor coolant pressure boundary at Byron Unit 2 were contained in submittals dated July 23, 1986, September 2, 1986, and October 16, 1986. Clarifications and revisions to relief requests were received in a September 30, 1986 submittal from the Applicant. The July 23, 1986 submittal contained a comparison and cross-reference between the Byron Unit 2 and the Byron Unit I relief requests and detailed any differences between the individual items. All of the relief requests were supported by information pursuant to 10 CFR 50.55a(a)(3). There-

' fore, the staff evaluated the requests for relief from the ASME Code-required examinations that the Applicant ~ stated to be impractical and determined that the Applicant has demonstrated that either (i) the proposed alternatives would l provide an acceptable level of quality and safety or (ii) comoliance with the l requirements would result in hardships or unusual difficulties without a com-

! pensating increase in the level of quality and safety. On the basis of review of the Applicant's submittals and the granting of relief from these preservice examination requirements, the staff concludes that the preservice inspection program for Byron Station, Unit 2 is acceptable and in compliance with 10 CFR 50.55a(g)(3). The detailed evaluation supporting this conclusion is l provided in Appendix K to this report.

1 The initial inservice inspection program has not been submitted by the Appli-cant. The staff requires that this program be submitted within six months from j the date of issuance of the operating license. This program will be evaluated

] based on 10 CFR 50.55a(g)(4) which requires that the initial 120 month inspec-4 tion interval shall comply with the requirements in the latest edition and

! addenda of the Code incorporated by reference in paragraph 50.55a(b) on the

} date 12 months prior to the date of issuance of the operating license. This program will be evaluated after the applicable ASME Code edition and addenda can be determined and before the first refueling outage when inservice inspec-i tion commences.

l 5.2.4.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing Introduction For nuclear power facilities whose construction permit was issued on or after July 1, 1974, 10 CFR 50.55a paragraph (g)(3) specifies that components shall meet the preservice examination requirements set forth in editions and addenda of Section XI of the ASME Boiler and Pressure Vessel Code applied to the con-struction of the particular component. However, 10 CFR 50,55a paragraph (a)(3) permits alternative requirements to paragraph (g)(3) when authorized by the Director of the Office of Nuclear Reactor Regulation. Paragraph (a)(3) requires

! that the applicant demonstrate that (i) the proposed alternatives would provide i

2 an acceptable level of quality and safety, or (ii) compliance with the specified requirements of this section would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

1

Byron SSER 7 5-3

The Byron Station, Unit 2,. steam generators and pressurizer were ultrasonically examined to the preservice inspection (PSI) requirements of Section XI.of the ASME Code, 1977 Edition and Addenda through Summer 1978. In a letter dated May 21, 1986, the applicant requested relief.from certain PSI requirements for the pressurizer and steam generators. Article IWB-3112 of this Code edition and addenda indicates that flaws exceeding the standards of Table IWB-3410-1 shall be unacceptable for service unless such flaws are removed or repaired to the extent necessary to meet the flaw indication standards prior to placement of the component in service. In its May 21, 1986 letter the applicant indicated that twelve indications exceeded the standards of Table IWB-3410-1. The ultra -

sonic size of and location of flaws that exceed the PSI limits in Byron-2 pressure vessels are reported in Table 5.2-1.

In lieu of excavation and weld repair of these flaws, the applicant proposes to leave the flaws in the vessels. The proposal is based on fracture mechanics analyses that indicate that these flaws will not grow to an unacceptable size during the life of the plant. The fracture mechanics analyses are documented in Westinghouse Reports WCAP 11063, " Background and Technical Basis For The Handbook on Flaw Evaluation For Byron Units 1 and 2 Steam Generators and Pres-surizers" and WCAP 11064, " Handbook on Flaw Evaluation For Byron Units 1 and 2 Steam Generators and Pressurizers." These reports were submitted in a letter from A. D. Miosi to H.R. Denton dated June 11, 1986. Additional information that was used to justify the applicant's request for relief from these require-ments was submitted in a letter from K. A Ainqer to H. R. Denton dated Septem-ber 30, 1986.

Flaws were previously repetted by the applicant in the Byron-1 pressurizer and Braidwood-1 pressurizer and loop one steam generator. The ultrasonic size and location of flaws that exceed the PSI limits in Byron-1 and Braidwood-1 pressure vessels are reported in Table 5.2-2. The staff allowed the Byron 1 and Braid-wood 1 components, which contained those flaws, to be placed in service after the applicant had committed to an augmented inservice inspection.

Discussion The applicant concluded that the flaws in the Byron-2 steam generators and pressurizer were small subsurface slag inclusions and small surface defects formed during vessel fabrication and not cracks or lack of fusion. This con-clusion was based on volumetric and destructive examination of flaws in core samples removed from steam generators at both Byron-1 and Byron-2. Volumetric examination of welds in Braidwood 1 and Byron 1 and 2 steam generators and pressurizers was performed using ultrasonic inspection techniques. The ultra-sonic procedures, equipment and calibration blocks used for the Byron-2 inspec-tion meet the Section XI,1977 Edition with Addenda through Summer 1978 re-quirements, which were the applicable requirements for inspection of Byron-1.

The calibration blocks are of the same material specification with the same size machined reflectors. At both plants the transducers used were 2.25 MHz with 0.5" X 1.0" element sizes. Destructive examination of the flaws in the Byron 2 steam generators was perf'ormed by metallographic e'xamination of two core samples and by visual examination during excavation of six flaws. As a result of these examinations, the flaws were determined to be (a) embedded slag inclusions resulting from the welding process, (b) smaller in size than the size estimated by the ultrasonic sizing method, and (c) subsurface flaws that did not open to the surface. The ultrasonic characteristics of the flaws in

-Byron SSER 7 5-4

the Byron-2 steam generator and pressurizer were similar to the ultrasonic characteristics of the flaws removed and evaluated in the Byron 1 and 2 steam generators. Based on the similarity in the ultrasonic characteristics, the remaining flaws in the Bryon-2 steam generator and the pressurizer are believed to be small slag inclusions.

The applicant indicates that the remaining indications at Byron-2 are difficult to remove because of their location and removal would not guarantee an increase in the integrity of the vessel. Core sampling of flaws in steam generator weld seams SGC-03, SGC-05, SGC-06 and SGN-02 is impossible without weld repair because of the component's geometry. Although some flaws in the steam generator weld seam SGC-02 could be removed by core sampling, the resultant handhole would not increase vessel integrity and would increase the possibility for leakage into containment. Since the pressurizer is clad, core sampling of the flaw in this component is impossible without extensive weld repair.

Three flaws (number 1-1, 1-6 and 1-9) not removed by excavation are reported to be located at or near steam generator inside surfaces. Their removal by grind-ing from the inside surface is not possible because the steam generator secon-dary side internal design prevents accessibility to the weld inside surface.

Two indications are located in weld seam SGC-02, the stub barrel-to-tubesheet weld. Since this weld is located just above the tubesheet, the steam generator tube bundle and tube bundle wrapper prevent access to the weld's inside surface.

Consequently, these indications cannot be removed from the inside surface by grinding without removing major components of the vessel. The third surface indication is located in weld seam SGN-2, the main feedwater nozzle-to-shell weld. Access to the inside surface of this weld is prevented by the preheater section of the steam generator. Because of limited accessibility to the welds' inside surfaces all three surface flaws can only be removed by excavation from the outside surface. Excavation from the outside surface would require we7d repair. Weld repair of the flaws could result in additional slag inclusions '

and would result in increased internal residual weld stress.

The applicant in Appendix A to WCAP 11064 has provided flaw evaluation charts for circumferential and longitudinal oriented welds in the Byron-2 pressurizer and steam generators. These charts were constructed using fracture mechanics analyses. The method and criteria used in the fracture mechanics analyses are documented in WCAP 11063. The fracture mechanics analyses that were performed to develop the flaw evaluation charts were in accordance with the methodology and criteria specified in paragraph IWB-3600 and Appendix A of the ASME Code Section XI except that stresses were not linearized and stress intensity factors were not calculated in accordance with the recommendations in Appendix A. In lieu of linearizing the stress, the method used represented the actual stress profile by a cubic polynomial. Stress intensity factors were calculated using the expressions in References 1 through 4. These stress profiles and stress intensity factor expressions are believed to provide a more accurate determina-tion of the critical flaw size, and are particularly important during the evalu-ation of emergency and faulted conditions where the stress profile is generally nonlinear and often very steep.

Important parameters in a fracture mechanics analyses are the materials' brittle fracture resistance and the projected flaw growth rate during operation of the component. The standard measurement of brittle fracture resistance for the vessel materials in the Byron-2 pressurizer and steam generator are their crack Byron SSER 7 5-5

initiation and arrest tracture toughness. These values of fracture toughness are used to determine a critical flaw size. Westinghouse indicates that the critiril flaw size calculation used the crack initiation and arrest fracture toughness for vessel materials that are recommended in Appendix A of the ASME Code Section XI . The critical flaw size for each weld location was determined using a reference temperature, RTNDT, f 10 F and an upper shelf toughness of 200ksi/in. These values are acceptable for the steam generator and pressurizer welds, since the weld material in these components is not subject to neutron irradiation damage.

The amount of projected flaw growth was calculated using the transients reported in Table 2-1 and 2-2 of WCAP 11063 and the rate of fatigue growth recommended in Appendix A of Section XI of the ASME Code. The rates of fatigue growth doc-umented in Appendix A are for surface flaws in a water reactor environment and subsurface flaws in an air environment, but are not for accelerated growth due to stress corrosion or thermal stratification mechanisms.

The staff believes that stress corrosion should not be a problem for the flaw in the pressurizer, because it is located 0.4 inches from the clad / steel inter-face in the vessel. Hence, it will not be in contact with a corrosive environ-ment and will not be subjected to a stress corrosion mechanism.

Stress corrosion of the upper shell-to-transition cone circumferential weld (SGC-06) was observed in the Indian Point Unit 3 steam generator. The operating characteristics and weld configuration are similar for the Indian Point 3 and Byron-2 steam generators. Stress corrosion of the Indian Point Unit 3 steam generator vessels was studied by Brookhaven National Laboratory in Reference 5.

Major factors in the accelerated growth of the stress corrosion observed in the Indian Point 3 vessel were high residual weld stresses resulting from stress relief at 1000 F and copper cations in solution. The copper cations resulted from corrosion of the copper condenser tube material. The stress corrosion growth of the flaw in the Byron-2 steam generator is not considered likely because its welds were stress relieved at 1125125 F, its feedwater system heat exchangers and main condensers are made of Type 304 stainless steel, and the defect in SGC-06 weld is located 1.94 inch from the inside surface.

Feedwater piping in PWR steam generators (Ref. 6) have experienced accelerated crack growth due to thermal stratification. Thermal stratification results from poor mixing, during le w flow conditions, of cold water injected into the feedwater piping and backf60w of hot water from the steam generator. Similar cracking has been observed in BWR feedwater nozzles (Ref. 7). The applicant indicates that the design of the Byron steam generators precludes thermal stratification at the main feedwater nozzle. Low temperature feedwater will be provided at low flows to the steam generator only through the auxiliary feed-water nozzle. The feedwater will be sufficiently heated before entering the vessel through the main nozzle. Therefore, the layering of hot and cold feed-water will not occur in the main nozzle. However, to account for uncertainties in flaw growth rate flaws in the pressurizer and steam generators the flaws will be reexamined as part of an augmented inservice inspection program.

In the augmented inservice inspection program proposed by the applicant, the flaw in the pressurizer would be inspected to the requirements of paragraph IWB-2420 and the flaws in secondary side of the steam generators would be inspected to the requirements of paragraph IWC-2420 in Section XI of the ASME Byron SSER 7 5-6

Code. Paragraph IWB-2420 requires that flaws discovered during inservice inspection be reexamined during the next three inspection periods listed in IWB-2411 or IWB-2412. The flaw in the Byro'n-2 pressurizer that is reexamined to these requirements will be observed over three periods of plant operations.

Three reexamination intervals will be sufficient to evaluate whether fatigue growth resulting from plant operations is represented by the curves in Appen-dix A of Section XI of the ASME Code.

Paragraph IWC-2420 requires that flaws discovered during inservice inspection be reexamined during the~next inspection period listed in IWC-2411 or IWC-2412.

The flaws in the secondary side of the Byron-2 steam generator that are re-examined to these requirements would be observed after only one period of plant operations. Flaw growth during one operating period will not provide sufficient information to determine whether the fatigue growth resulting from plant operations is represented by the curves in Appendix A of Section XI of the ASME Code. The staff bafieves at least two reexamination periods are re-quired to provide this information. A flaw discovered during inservice inspec-tion and reexamined at the next inspection period, in accordance with the requirements of paragraph IWC-242C/. would have had two periods of plant opera-tion, the periods prior to and subsequent to the discovery of the flaws.

Since the applicant's proposal for reexamination of the flaws on the secondary side of the steam generators will only result in observation after only one operating period, it does not meet the intent of IWC-2420 and will not provide sufficient information to determine whether fatigue growth that could result from plant operations is represented by the curves in Appendix A of Section XI of the ASME Code.

Based on the location and depth determined by ultrasonic examination, the flaw evaluation charts in Appendix A of WCAP 11064 indicate that the flaws in the Byron-2 steam generators and pressurizer are acceptable per analytican criteria of IWB-3600 of Section XI of the ASME Code and future component hydrotest and leak tests must be performed at temperatures greater than those listed in Table III. ,

Conclusions

1) The flaws that exceed the standards of Table IWB-3410-1 of Section XI of the ASME Code in the steam generators and pressurizer are most likely slag inclusions resulting from weld fabrication.

2) Excavation and weld repair of these flaws would not increase the level of quality and safety of the components.

3) The fracture mechanics evaluations that are illustrated in charts in WCAP 11063 and 11064 domonstrate that the flaws will not grow during the life of the plant to a size which will affect the integrity of the vessels.

4) The proposed alternative provides an acceptable level of quality and safety, subject to the following examination and test requirements:

a) The area containing the flaw in the pressurizer must be reexamined in accordance with the inspection interval requirements of IWB-2420 and the areas containing the flaws in the steam generators must be reexamined during the first two inspection periods listed in the schedules of the inspection programs of IWC-2411 or IWC-2412.

Byron SSER 7 5-7

b) The pressurizer and steam generator secondary side future hydrotest and leak tests must be performed at temperatures greater than those listed in Table 5.2-3.

5) By letter dated October 29, 1986 the applicant committed to the inservice examinatic, and test requirements of conclusion 4), and therefore demon-strated compliance with the criteria in 10 CFR 50.55a paragraph (a)(3).

Hence, the applicant may be permitted to place the Byron 2 pressurizer and steam generators into service without weld repair of the flaws that exceed the preservice acceptance standard of Section XI of the ASME Code.

References (1) McGowan, J. J. and Raymund, M. , " Stress Intensity Factor Solutions for Internal Longitudinal Semi-elliptic Surface Flaw in a Cylinder Under Arbitrary Loading," ASTM STP 677, 1979, pp. 365-380.

(2) Newman, J. C. Jr. and Raju, I.S. , " Stress Intensity Factors for Internal Surface Cracks in Cylindrical Pressure Vessels," ASME Trans., Journal of Pressure Vessel Technology, Vol. 102, 1980, pp. 342-346.

(3) Buchalet, C. B. and Bamford, W. H. , " Stress Intensity Factor Solutions for Continuous Surface Flaws in Reactor Pressure Vessels," in Mechanics of Crack Growth, ASTM STP 590, 1976, pp. 385-402.

(4) Shah, R. C. and Kobayashi, A. S. , " Stress Intensity Factor for an Elliptical Crack Under Arbitrary Loading," Engineering Fracture Mechanics, Vol. 3, 1981, pp. 71-96.

(5) C. J. Czajkowski, " Investigation of Shell Cracking on the Steam Generators at Indian Point No. 3," NUREG/CR-3281,. June 1983.

(6) USNRC, " Investigation and Evaluation of Cracking Incidents in Piping in Pressurized Water Reactors, NUREG-0691, September 1980.

(7) USNRC, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking", NUREG-0619, November 1980.

Byron SSER 7 5-8

TABLE 5.2-1 Ultrasonic Size and Location of Flaws that Exceed the PSI Limit in Lyron-2 Pressure Vessels Weld Depth from Depth Length Thickness Flaw I.D Surface of Flaw of Flaw Component *Wel'd Seam (t) No. (S) (d) (1)

Loop 1 St. Gen SGC-02 3.2 1-1 .01 .14 .70 SGC-02 3.2 2-1 1.97 .235 .75 SGC-02 3. 2 2-2 1.50 .41 .60 Loop 2 St. Gen SGC-03 3.1 2-5 .80 .40 .88 SGC-05 3.4 2-6 .90 .60 .88 Loop 3 St. Gen SGC-02 3.4 1-6 0 .36 .75 SGN-02 3.2 1-9 0 .31 .50 SGC-05 3.2 2-7 .11 .22 .75 SGC-05 3.2 2-8 .26 .26 .88 Loop 4 St. Gen SGC-02 3.2 2-9 .26 .26 .70 SGC-06 4.0 2-10 1.94 .325 .70 Pressurizer PC-04 4.0 2-11 .40 .64 1.00

• Weld Identification SGC-02:

Tubesheet to stub barrel, secondary side weld .

SGC-03: Stub barrel to intermediate, secondary side weld SGC-05: Lower shell to cone, secondary side weld SGC-06: Upper shell to cone, secondary side weld SGN-02: Feed:ater nozzle to shell, secondary side weld PC-04: Upper shell to upper middle shell, primary side weld Byron SSER 7 5-9

TABLE 5.2-2 Ultrasonic Size and Location of Flaws that Exceed the PSI Limit in Byron-1 and Braidwood-l Pressure Vessels Weld Depth from Depth Length Thickness Flaw I.D Surface of Flaw of Flaw Component

• Weld Seam (t) No. (S) (d) (1)

Byron-1 PC-01 4.0 1 1.0" 0.59 3.19 Pressurizer 3raidwood-1 PC-03 4.0 1 2.19" 0.288 0.95 Pressurizer Braidwood-1 SGC-06 3.95 2 0.55" 0.45 1.20 Loop 1 St. Gen.

• Weld Identification PC-01: Lower head to shell, primary side weld PC-03: Upper middle to lower shell, primary side weld SGC-06: Upper shell to cone, secondary side weld Byron SSER 7 5-10

TABLE 5.2-3 Minimum Hydrotest and Leak Test Temperatures for the Pressurizer and the Secondary Side of the Steam Generators Minimum Minimum Hydrotest Leaktest Component Temperature ( F) Temperature ( F)

Secondary Side of Loop 1 Steam 165 140 Generator Secondary Side of Loop 2 Steam 120 120 Generator Secondary Side o'f Loop 3 Steam 165 140 Generator Secondary Side of Loop 4 Steam 150 130 Generator Pressurizer 120 120 Byron SSER 7 5-11

l l

4 6 ENGINEERED SAFETY FEATURES 6.5 Fission Product Removal and Control System 6.5.1 Engineering Safety Feature (ESF) Atmospheric Cleanup System 4

In an October 1,1986 letter tne licensee requested that interim operation of Byron Unit 2 be ' allowed until July 1,1987 with the auxiliary building ventila-tion (VA) system incapable of maintaining at least a 1/4 inch water gage (W.G.)

negative pressure in each individual compartment of the VA system. The Unit 2 portion of the VA system is constructed and supply and exhaust air flows main-tain the Unit 2 areas at a negative pressure with respect to atmosphere. How-ever, individual flow balancing dampers must be adjusted to obtain the desired 1/4 inch W.G. negative pressure and then an integrated test must be performed.

During these tests, it is possible that some subcompartments may become positive with respect to others.

I In its letter, the licensee indicated that operation of VA system was unneces-sary during the period of Unit 2 fuel load and initial criticality. Cubicle coolers would provide cooling of the ESF equipment cubicles during this period.

Beyond initial criticality the applicant proposed operation with the VA system testing incomplete and, therefore, the system considered inoperable.

4 The licensee has provided an analysis which demonstrates that the offsite doses and the doses to the control room operator can be maintained within 10 CFR Part 100 and GDC 19, respectively, even with the.VA system inoperable and ECCS equipment leakage rates of 1 gpm for 30 days following the accident and 50 gpm for 30 minutes at a time 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the initiation of the accident. The licensee proposed that the reactor be allowed to operate above 30% if ECCS leakage is reduced below 1 gpm and provided a figure demonstrating the allowable power level as a function of such leakage. By letter dated October 24, 1986, the licensee provided a description of the program that will be utilized to

, demonstrate that leakage is less than 1 gpm. The program is a portion of the i

program that was approved in Section 9.3.5 of SER Supplement No. 5 and is acceptable for demonstrating that ECCS leakage is below 1 gpm.

! The staff has performed an independent analysis to verify the acceptability of the licensee's approach and has determined that the interim plan for operation

} of the VA system is acceptable.

6.6 Inservice Inspection of Class 2 and 3 Components This section was prepared with the technical assistance of DOE contractors from the Idaho National Engineering Laboratory.

6.6.3 Evaluation of Compliance with 10 CFR 50.55a(g) for Byron Unit 2 2

! This evaluation supplements conclusions in this section of NUREG-0876 which I

addressed the definition of examination requirements and the evaluation of compliance with 10 CFR 50.55a(g). The application for the Byron and Braidwood Byron SSER 7 6-1

- - - - _ - - - , , =. -. - - --- - . _

9 Stations was submitted and accepted for review under the Commission's stand-ardization policy using the duplicate plant option. Therefore, the staff considered the review of the preservice inspection (PSI) program to be a con-l firmatory issue based on the staff review of the Byron Unit 1 PSI program, which was determined to be acceptable in NUREG-0876, SSER 5, and contingent upon the Applicant:

(1) Demonstrating that either, (a) the Byron Unit 2 and Byron Unit 1 PSI pro-grams are essentially the same, or (b) the Byron Unit 2 PSI program is different but meets the requirements of 10 CFR 50.55a(g)(3), and (2) submitting all relief requests with a supporting technical justification.

Since the previous supplement, staff review has been completed on the following information:

(1) The FSAR through Amendment 47 dated April 1986; (2) the Applicant's July 23, 1986 submittal comparing the differences between the Byron Unit 2 and Byron Unit 1 PSI Program Plans, and also containing requests for relief from the ASME Code Section XI requirements that the Applicant has determined to be impractical for Byron Unit 2; and (3) the Applicant's September 30, 1986 submittal containing clarifications and revisions to the previously submitted relief requests.

Based on the construction permit issuance date of December 31, 1975, 10 CFR 50.55a(g)(3) requires that the PSI Program be developed and implemented using at least the Edition and Addenda of Section XI of the ASME Boiler and Pressure Vessel Code applied to the construction of the particular components.

The Applicant has prepared a program based on the requirements of the ASME Code Section XI, 1977 Edition with Addenda through Summer 1978. The use of later referenced Code editions is acceptable as specified by 10 CFR 50.55a(g)(3).

In the July 23, 1986 submittal, the Applicant verified'that the scope and re-quirements of the Byron Unit 2 PSI Program, as well as the augmented inspec-tions, are identical to those of Byron Unit 1. The Byron Unit 2 Code Class 2 and Class 3 components exempted from preservice examination per Section XI paragraph IWC-1220 and Table IWO-2500-1 correspond directly to the Byron Unit 1 exempted components.

Requests for relief from the ASME Code Section XI requirements which the Appli-cant has determined to be impractical for Class 2 and Class 3 components at Byron Unit 2 were contained in the submittal dated July 23, 1986. This sub-mittal also contained a comparison and cross-reference between the Byron Unit 2 and the Byron Unit 1 relief requests and detailed any differences between the individual items. Clarifications and revisions to the previously submitted ,

relief requests were received in the Applicant's submittal dated September 30, 1986. All of these relief requests were supported by information pursuant to 10 CFR 50.55a(a)(3). Therefore, the staff evaluated the requests for relief from the ASME Code-required examinations that the Applicant determined to be impractical and determined that the Applicant has demonstrated that either (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the requirements would. result in hardships or Byron SSER 7 6-2

unusual difficulties without a compensating increase in the level of quality and safety. On the basis of review of the Applicant's submittals and the granting of relief from these preservice examination requirements, the staff concludes that the preservice inspection program for Byron Station, Unit 2 is acceptable and in compliance with 10 CFR 50.55a(g)(3). The detailed evaluation-supporting this conclusion is provided in Appendix K to this report.

The initial inservice inspection program has not been submitted by the Appli-cant. The staff requires that this program be submitted within six months from the date of issuance of the operating license. This program will be evaluated based on 10 CFR 50.55a(g)(4) which requires that the initial 120-month inspec-tion interval shall comply with the requirements in the latest edition and addenda of the Code incorporated by reference in paragraph 50.55a(b) on the date 12 months prior to the date of issuance of the operating license. This program will be evaluated after the applicable ASME Code edition and addenda can be determined and before the first refueling outage when inservice inspec-tion commences.

Byron SSER 7 6-3

7 INSTRUMENTATION AND CONTROL 7.3 Engineered Safety Features Systems

• 7.3.2 Specific Findings 7.3.2.13 Charging Pump Deadheading*'

In Supplement No. 3 to the Byron SER, the staff stated that the licensee had provided a conceptual outline for a design change which would provide open and close signals for a solenoid-operated valve in each charging pump miniflow line to prevent. pump deadheading. These signals were to be developed from four redundant reactor coolant system wide range pressure transmitters combined in two-out-of-four logic for both high (open) and low (close) pressure' signals taken in coincidence with the safety injection signal. The staff reviewed the conceptual information and found it acceptable pending review of the detailed design.

The licensee has submitted detailed design information (logic diagrams and

. electrical schematics) for review and provided, in Amendment 45 to the FSAR, .

appropriate revisions covering the modifications. The staff has reviewed the detailed information provided and finds the design modification acceptable.

Thus, Confirmatory Item 16 is considered closed. (This item is.also discussed in Section 6.3.2, SER Supplement No. 4.)

7.4 Systems Required for Safe Shutdown 7.4.2 Specific Findings 7.4.2.2 Remote Shutdown Capability Test i

I The original SER required a one-time demonstration of the ability to maintain the plant in a safe shutdown condition from outside the control room following a plant trip from above 10% reactor power. This item has been completed on Unit 1. Staff confirmation of its completion is documented in Inspection Report No. 50-454/85024 (DRS), dated July 10, 1985.

, 1 By letter dated June 23, 1986, the licensee has proposed to eliminate this test from the Unit 2 startup test program. The staff does not find this accept" able, as discussed in Section 14 of this supplement.

1

• By letter dated May 21 1986, the staff transmitted this section to the licensee.

Byron SSER 7 7-1 4

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8 ELECTRIC POWER SYSTEMS 8.4 Other Electrical Features and Requirements for Safety 8.4.4 Physical Identification and Independence of Redundant Safety-Related Electrical Systems

• A site visit was conducted on May 21-23, 1985, at Braidwood Station, Units 1 and 2 in order to view the installation and arrangement of electrical equipment and cables. During this visit, specific issues identified during the Braidwood Station Construction Appraisal Team (CAT) inspection were discussed. The CAT inspection revealed several items regarding physical separation, particularly between Class IE and non-Class IE cables. Commonwealth Edison Company has established the separation criteria between redundant Class 1E raceways in accordance with R.G.1.75 for Byron and Braidwood Stations.

However, the licensee has established separation criteria of non-Class 1E from Class IE raceways which deviates from the' specific separation distances i detailed in R.G. 1.75. Acceptability of the licensee's lesser separation l distance with its bases and justification was not specifically addressed in the Byron Safety Evaluation Report (SER).

Therefore, the staff has performed the following evaluations of the licensee's separation criteria of Class IE cables from non-Class lE cables to eliminate any further differences in interpretation of separation requirements in this area.

The applicant instituted a test program conducted by W'le y Laboratories and per-formed calculations and analysis to justify lesser separation distances. By letter dated August 6, 1985, the licensee's submitted the test results, with its associated information, and the analysis on the separation criteria.

l ,-

The purpose of these tests was to establish a basis of analysis which could be applied in justifying a lesser physical separation distance. Any lesser separa-l tion distance than the separation criteria specified in RG 1.75 must be estab-lished by the test results.

In order to perform a test program to verify the adequacy of the raceway separa-tion criteria, it was necessary to define the worst case electrical failure that could be postulated to occur in a raceway. The Byron raceway separation test program was based on the following failure assumptions:

(1) The cable or equipment in the circuit develops an electrical fault that is not cleared due to the postulated failure of the primary overcurrent protective device.

, *By letter dated February 25, 1986, the staff transmitted this section to the licensee.

Byron SSER 7 8-1

(2) The fault current used was the RMS value which produces the maximum possible credible heating effect without tripping the breaker by magnetic force.

(3) Load curr'ent effects from other loads on the same circuit was not considered to cause the next higher level overcurrent device to trip.

The worst case failure of a cable for which the electrical separation criteria must protect cables in an adjacent raceway is a sustained overload condition where the magnitude of the current is such that the cable would be able to sus-tain the overload for a significant length of time. This condition would allow the cable to generate the greatest amount of heat over a period of time and, therefore, has the greatest potential for causing damage to nearby circuits. ~

On the other hand, if the cables were exposed to the maximum short circuit cur-rent available at the bus, the higher fault current would lead to rapid clearing of the fault by a breaker. This condition causes less energy to be generated to the ambient and hence results in less temperature rise in the adjacent raceway. For the purpose of the test, the cables were subjected to the overload currents for the length of time it took to open the circuit through failure of the cable conductors. This is considered to be a very conservative test since no credit was taken for any current interrupting devices operating in the circuit.

The purpose of these tests was to establish an analytical basis for demonstrat-ing the minimum acceptable separation distance. Any separation distance less than the separation criterion specified in RG 1.75 shall also be established by the test program.

In selection of the test configuration, the primary concern was to ensure that the quantity and types of racewdy and cable arrangements tested would satisfac-torily reprasent actual plant configurations and provide a basis for applying the results of the testing to similar configurations which were not tested.

Using this criterion, the following representative configurations were selected for our evaluation:

(1) Separation distances of one foot (12") vertical and three inches (3")

horizontal between safety-related and nonsafety-related raceways.

The staff concludes that fire or failure resulting from electrical faults induced in nonsafety-related cables in a raceway would not cause electrical failure of safety-related cables in a raceway located 12" directly above or below or 3" horizontally away from the nonsafety-related raceway. The analysis was based on actual results of tests performed to establish elec-trical separation distance. The cable failures addressed in the establish-ment of separation distance in this analysis are those which are induced by an electrical fault within the nonsafety-related cable only.

The raceway configuration chosen for the test is one in which an open top cable tray containing nonsafety-related power cables is located (2") below a cable tray containing safety-related cables. The configuration also inclu'ded a 2" flexible steel conduit, containing safety-related cables run-ning vertically, separated by 2" horizontally from the nonsafety-related cable tray.

Byron SSER 7 8-2

The value of overload current which was selected for the test was approxi-mately six and one half times the rated current overload value for the given cable size. This value is based on the fact that a stalled motor would draw about six and one half times rated current. The current of a stalled motor was selected because it was considered a credible overload current which may occur during normal operating conditions.

The target cables in the upper cable tray and vertical flex conduit were continually energized during the test with their rated current. Tne actual value of overload current which the faulted cables were exposed to during the test are 462A for 3/C #2AWG (American wire gauge) 737A for 3/C 1/0, and 2070A for 3/C 350 MCM (thousand circular mils). These values are based on 6.5 times rated current over-current test. The length of time for which each of the faul'ted cables were energized with the overload is very conservative. As stated previously, the overload current value was selected because it was representative of the test current which a stalled motor may draw. This was evaluated as the most credible cause of a sus-tained overload current. In reality, the motor windings would eventually short together and result in a full short circuit which would be of a high enough magnitude to trip upstream circuit breakers even if a feeder breaker fails. Calculated fault currents are 4600 amperes for the size 2 AWG cable, 5400 amperes for the size 1/0 AWG cables, and 6700 amperes for the size 350 MCM cables short circuit test. The test results demonstrated that these fault current values caused relatively minor damage to'the fault cable insulation, particularly when compared to the extreme degradation incurred with the lower (6.5 times rated current) overcurrent tests. The major reason for the decreased insulation system damage is the fact that the conductor circuits open much faster at higher current values.

At the completion of each cable test, functional tests for the target cables consisting of the insulation resistance test, high potential test, overcur-rent test and post-test functional test) were performed. The target cables passed the above tests in accordance with the acceptance criteria and cable manufacturer's specification.

The results of Wyle Laboratories' investigation (Test Report No. 46511-3) discussed in the August 6, 1985 submittal demonstrate that all of the target cables in upper cable tray (located 12" above the cable tray containing the faulted cable) and in the vertical conduit (located 2" horizontally away from faulted cable tray) maintained their integrity to conduct specified current and voltage before, during and after the fault specimens were sub-jected to the overload currents. The target cables passed the post-functional insulation resistance tests at 500 volts DC and high potential withstand at 2200 volts AC. The temperature which was measured on the tar--

get cables in the upper cable tray and in the flex conduit was much less than the temperature for which the cables are continuously rated and sig-nificantly less than the emergency temperature rating of 130 C of the power, control, and instrument cables.

, Tne staff has reviewed the result of Test Report No.~46511-3 conducted by Wyle Laboratories and the licensee's analysis of this report. On the basis of its review, the staff concludes that the separation distance of 12" ver-tical and 3" horizontal between safety-related and nonsafety-related raceway Byron SSER 7 8-3

is adequate to prevent a fault in nonsafety-related cable causing failure of safety related cables and is, therefore, acceptable.

(2) Separation of a safety-related cable in free-air in contact with a raceway containing a nonsafety-related cable and of a nonsafety-related cable in free-air in contact with a raceway containing a safety-related cable.

e The purpose of this analysis and test is to demonstrate that fire or fail-ure resulting from electrical faults induced in nonsafety-related cables in free-air or in raceway will not cause electrical functional failure of safety-related cables in raceway or in free-air respectively.

This configuration consists of a test between two horizontal, rigid steel conduits and various free-air instrumentation cables. The faulted cable is a 3/C 500 MCM routed in a rigid steel conduit. Three target cables located in a.1" rigid steel conduit in contact with the conduit containing the faulted cable. Three other target cables, respectively, are mounted in free air in contact with the conduit of the faulted cable. This con-

-figuration test demonstrates the adequacy of separation design that:

(1) two horizontal, rigid conduits are physically separated by zero inches vertically when a worst-case electrical fault occurs in the lower conduit, or (2) free air cables are physically separated from a horizontal rigid steel conduit by zero inches horizontally when a worst-case electrical fault occurs in the conduit. All instrumentation cables for use in both safety-related and nonsafety-related applications are rated for 600 volts with

' insulation tested to a minimum of 1500 volts with a overall jacket and are applied in circuits with a system voltage less than 30 volts. Control cables are applied in circuits with a system voltage of either 120 Vac or 125 Vdc.

Low voltage power cables are applied in circuits with a system voltage of 480 Vac. Control and low power cables have insulation rated at 600 volts.

The cable is also tested to show that it can withstand voltage. transients up to 1500 volts. Medium voltage power cables are applied in circuits with system voltages of 4160 V or 6900 V. These are required to have insulation rated at 5 kV and 8 kV respectively. The cable is also tested to show that it can withstand voltage transients of up to 16 kilovolts and 22 kilovolts respectively. Therefore, there is a conservative design margin in the cable -

to assure adequate isolation ~from voltage transients in the nonsafety-related circuit from adversely affecting a safety-related circuit.

For the purpose of the verification test, it was assumed that the circuit breaker feeding the overloaded cable fails to trip and the overcurrent will persist in the cable. The fault current which was considered the most credible severe overload condition which the cable may see during plant operation is that resulting from a motor failing to start but con-tinuing to draw locked rotor current as described above. The actual test current values were selected from the largest motor which is fed with a 500 MCM 600-volt cable at Byron or Braidwood. This motor is a 250 horse-power motor which has a locked rotor current of approximately 1700 amperes (A).

If the voltage drop is taken into consideration, the actual current which would be seen by~the cable is approximately 1300A. The overcurrent test, therefore, consisted of energizing the 500 MCM size to 1300A for one hour and 1700A until the cable open circuited. The two step overcurrent test was selected in order to simulate a worst case condition by energizing the cables with a fault current which cause the cable to generate considerable Byron SSER 7 8-4

heat but would not cause an open circuit, and then jump the fault current to a value which would eventually open circuit the cable. The one hour time limit on the 1300A portion of the test was considered conservative since a stalled motor- would be alarmed and deenergized long before one hour.

Alternatively, the r.iotor winding would short together and result in a full short circuit which would be interrupted by the upstream breakers.

The target cables-..were energized continually during the test. The target cables passed pre and post functional tests which consisted of both insula-tion resistance and high potential withstand tests.

As previously stated, the primary objective in the selection of the test configuration was to ensure that the quantity of raceway and cable arrange-ments tested would satisfactorily represent actual plant configurations and provide a basis for applying the results of the testing to similar config-urations which were not tested.

The results of these tests performed (Test Report No. 17769-1 by Wyle i Laboratories) indicate that all of the target cables maintained integrity to conduit specified current and voltage before, during and after the fault specimen was subjected to the overload current. At the completion -

of each cable test, the functional tests were performed for the target cables. The target cables passed the above tests in accordance with the acceptance criteria and cable manufacturer's specification. l The staff has reviewed the results of Wyle Laboratories Test Report No. 17769-1 and the licensee's analysis of these configuration tests. On the basis of its review, the staff concludes that it is acceptable for (a) safety related cables in free-air to come in contact with a raceway containing nonsafety-related cables and (b) nonsafety-related cable in free-air to come in contact with a raceway containing safety-related cables.

This analysis has demonstrated that safety-related cable will not be de-graded below an acceptable level due to the reduced separation as specified in the FSAR.

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, cs NT Byron SSER 7 8-5

9 AUXILIARY SYSTEMS 9.5 Other Auxiliary Systems 9.5.1 Fire Protection Program SER Supplement No. 5 discussed the safe shutdown analysis for Unit 1 as-built conditions. By letter dated June 11, 1986, the licensee submitted Amendment 8 to the Fire Protection Report which included the safe shutdown analysis for Unit 2 as-built conditions. Based on its review of the June 11, 1986 submittal, the staff concludes that the post-five safe shutdown capability for Unit 2 com-plies with the guidelines of Standard Review Plan Section 9.5.1, Position C.6.b, with the exception of several items noted during the staff's fire protection audit of Unit 2, conducted the week of September 22, 1986. These items, which include an incomplete high/ low pressure interface analysis of the reactor head vent and excess letdown lines, will be resolved in a future SER supplement.

By letter dated September 23, 1986, the licensee submitted a list of National Fire Protection Associated (NPPA) Code deviations for Unit 2 which were not identified for Unit 1. Because of the small quantities of radionuclide inven-tory in the reactor coolant system, the staff concludes that these NPPA Code deviations are acceptable for plant operation up to 5% power. Staff evaluation of these deviations for operation above 5% will be provided in a future SER supplement.

Byron SSER 7 9-1

13 CONDUCT OF OPERATIONS 13.1 Organizational Structure of Applicant 13.1.2 Operating Organization 13.1.2.1 Organization Supplement 5 stated that the license would be conditioned to require shift advisors until such time as the requirements for hot operating experience have been met. By letter dated January 10, 1986, the licensee stated that its on-shift licensed senior operators meet the experience requirements and that the shif t advisors were being released from further service on February 15, 1986.

The staff finds that the licensee has satisfied the license condition and agrees that shift advisors are no longer necessary. The licensed senior opera-i tor with the hot operating experience on Unit 1 satisfies the requirements for Unit 2; only one individual is needed for both units, as required in Technical Specification Table 6.2-1. Thus, a similar license condition is not needed for Unit 2.

13.5 Plant Procedures .

13.5.2 Operating and Maintenance Procedures After the accident at Three Mile Island (TMI), the staff developed the TMI Action Plan (NUREG-0660 and NUREG-0737), which required licensees of operating reactors to reanalyze transients and accidents and upgrade emergency operating procedures (EOPs) (Item 1.C.1). The plan also required the NRC staff to develop a long-term plan that integrated and expanded efforts in the writing, reviewing, and monitoring of plant procedures (Item I.C.9). NUREG-0899, " Guidelines for Preparation of Emergency Operating Procedures," represents the staff's long-term program for upgrading EDPs, and describes the use of a Procedures Genera-tion Package (PGP) to prepare E0Ps. Submittal of the PGP was made a requirement by Supplement 1 to NUREG-0737, " Requirements for Emergency Response Capability" (Generic Letter 82-33). Generic Letter 82-33 requires each licensee to submit to the NRC a PGP, which includes:

(1) plant specific technical guidelines (2) a writer's guide (3) a description of the programs to be used for the validation and verification of E0Ps (4) a description of the training program for the upgraded E0Ps Byron SSER 7 13-1 l

This report describes the staff's review of.the applicant's response to Sec- I tion 7 of Generic Letter 82-33 related to the' development and implementation of E0Ps.

Criteria for the review of a PGP are in Standard Review Plan (SRP) Section 13.5.2.

Further guidance is contained in NUREG-0899, the reference document for the E0P i upgrade portion of Generic Letter 82-33.

The staff determined that the PGP is acceptable for full power operation. The applicant has committed to address a list of items in the longer term, as dis-cussed in the following sections, consistent with generic resolution of Westing-house Owners Group (WOG) Emergency Response Guidelines (ERGS) long-term issues.

Discussion and Evaluation By letter dated March 26, 1985, the applicant submitted its PGP for Byron /

Braidwood. By letter dated September 16, 1986, the applicant provided addi-tional information. The PGP contained an' introduction and the following sections:

Plant-Specific Technical Guidelines

- Abnormal and Emergency Operating Procedures Writer's Guide

- E0P Verification Program E0P Validation Program E0P Training Program (1) Plant-Specific Technical Guidelines (P-STGs) -

All licensees and applicants are required to submit P-STGs. These guidelines may be based on generic technical guidelines (prepared by the owner's group) or on a plant-specific reanalysis of transients and accidents as described ir -

TMI Action Plan Item 1.C.l. In either case, the P-STG should be based on the identification of plant systems and functions, and should be supported by an analysis of operator tasks to identify operator information and control needs.

If generic technical guidelines are referenced, additional task specification may be needed, depending on the level of task information provided by the generic technical guidelines and the nature of deviations from the guidelines.

Examples of deviations that should be reviewed and documented are as follows:

any modification to the mitigative strategy of the generic technical guidelines (e.g., for a Westinghouse plant, initial depressurizing of the reactor coolant system (RCS) following a steam generator tube rupture without first having conducted a limited cooldown in accordance with the guidelines to establish a margin to saturation) differences in equipment operating criteria (e.g. , reactor coolant pump (RCP) trip criteria, safety injection (SI) termination criteria) ,

differences in equipment operating characteristics (i.e., between the plant-specific equipment and that assumed in the generic analyses, such as SI that can be throttled vs. only on/off)

Byron SSER 7 13-2

identification of methods and equipment used to address the technical areas of the generic guidelines that are specified as " plant-specific" plant-specific setpoints or action levels that are calculated or deter-mined in the manner other than specified in the generic technical guidelines NOTE: Plant-specific setpoints (e.g., setpoints associated with automatic initiation of the emergency core cooling system) called for by the generic guidelines need not be included in the P-STG submittal.

actions that are taken in addition to those specified in the generic guidelines and that affect the mitigative strategy differences that affect the equipment's ability to adequately provide the necessary mitigative function use of different instruments or control parameters than those specified in the generic technical guidelines or determining instrumentation and control characteristics in a manner different than, or with a different basis than, that specified in the generic technical guidelines identification of items not covered by the NRC-approved generic technical guidelines (e.g., plant-specific conditions, equipment, operations, or bracketed [ ] information from the generic technical guidelines that re-late to systems, functions or methods)

The purpose of the review of the technical guidelines submittal is to determine that the following grneral objectives are adequately addressed:

(1) The E0Ps will be based on acceptable, validated technical guidelines de-rived from approved analyses of transients and accidents as described in NUREG-0660, Items I.C.1 and I.C.9 (as clarified by NUREG-0737 and Supple-ment 1 to NUREG-0737). The P-STG along with the generic guidelines (if referenced) and supporting documentation provide E0P writers with all the technical information necessary for preparing E0Ps which direct operators' actions to mitigate the consequences of transients and accidents without needing to first diagnose an event to maintain the plant in a safe condi-tion (function orientation).

(2) The PGP describes an adequate method to identify information and control needs to be used as a basis for identifying control room instrumentation and controls necessary to perform the tasks specified in the technical guidelines.

By letter dated March 26, 1985, the applicant provided information on plant emergency response guidelines and referenced the Westinghouse Emergency Re-sponse Guidelines (ERGS), Revision 1 (high pressure version) which were authorized for implementation by the staff in a letter dated December 27, 1984, supersede those based on the Westinghouse ERGS, Revision 0. The applicant identified the following source documents for use in generating E0Ps for Byron /

, Braidwood (B/B):

Byron SSER 7 13-3

B/B E0P Writers Guide

- WDG ERG (Revision 1) and background documents B/B electrical drawings B/B piping and instrumentation drawings B/B FSAR licensing commitments relating to E0Ps Westinghouse Bulletins and Memos-(as appropriate) vendor technical manuals (as appropriate) 8/B plant descriptions B/B instrumentation description B/B administrative procedures B/B system operating procedures B/B general operating procedures 8/B abnormal operating procedures existing B/B emergency operating procedures B/B precautions, limitations, and setpoints document In the September 16, 1986, letter, the applicant provided (1) clarification of the PGP identified instrumentation and controls needed to support use of the B/B E0Ps, (2) a sample plant E0P with accompanying deviation, training, and validation documentation for staff audit, and (3) a written commitment to ex-pand the step deviation documentation to include justification for the bracketed, plant-specific steps by 6 months following the issuance of a full power license for either Braidwood Unit 1 or Byron Unit 2, whichever comes first.

From its review, the staff concludes that the B/B PGPs reflect essentially the same objective and mitigative strategies as the referenced WOG ERGS which were approved for implementation.

The staff has noted concerns regarding treatment of steam generator tube rup-ture (SGTR) events, partially attributable to the lack of status tree identifi-cation of " radioactivity control" as a critical safety function, and regarding a questionable interface with the emergency action levels (EALs) of plant emer-gency plans in the referenced ERGS. However, these concerns are attenuated by provisions identified in the staff's review of the material submitted by the applicant. Attachment A, Table 2, of the B/B PGP identifies the availability of steamline radiation monitors which would assist in the diagnoses of SGTR events.

The sample E0P which the staff audited has an added note that indicates an in-terface with the site emergency plan.

From its review of the B/B PGP and its audit of the sample E0P and its support-ing documentation, the staff finds that the B/B P-STGs provide appropriate tech-nical variance to account for plant-specific differences from the reference plant design, and to include other emergency operational considerations, e.g.,

interaction with EALs, not covered by the generic guidelines.

On the basis of its review (discussed above), the staff finds that the plant-specific emergency procedures guidelines described in the B/B PGP are techni-cally acceptable for implementation. In support of this finding, the applicant has committed to expand the technical deviations documentation to include brack-eted items from the WDG ERGS. Concerns related to the treatment of SGTRs, pro-vision of a radiation control safety function, and interaction with EALs are Byron SSER 7 13-4

~ ... . .- . -

attenuated by B/B P-STG feature, and will be pursued further consistent with generic resolution of WOG ERG long-term issues.

I .

The B/B P-STGs, expanded as committed, contain plant-specific technical infor-mation which is necessary as a reference to supplement the E0Ps, as a basis for the plant task analysis program, and as documentation of status in amending the P-STGs in the future.

In consideration of the above, the staff concludes that the technical content of the B/B PGPs is consistent with the requirements of SRP Section 13.5.2 and

! the B/B PGPs are, therefore, acceptable for implementation.

(2) Writer's Guide Applicants are required to submit a writer's guide that details the specific methods to be used in preparing E0Ps which are based on the P-STGs. NUREG-0899 provides objectives and intent for the writer's guide. Because of the variety of available technical writing style guides and other references pertaining to the presentation of information, the specific information found in the writer's guide is expected to vary considerably among plants. For this reason, the staff did not perform a generic review of the human factors aspects of the Westinghouse owners Group Writer's Guide. Each applicant has to submit a plant-specific writer's guide for staff review.

The purpose of the evaluation is to determine if acceptable methods are described for accomplishing the following general objectives:

The writer's guide provides sufficient information for developing E0Ps from the P-STG, which are usable, accurate, complete, readable, convenient

! to use, and acceptable to control room personnel.

i The writer's guide supports upgrading of the procedures and long-term consistency within.and between procedures.

By letter dated March 26, 1985, the applicant submitted its PGP. This package included the Byron /Braidwood E0P Writer's Guide. By letters dated September 16 and 29, 1986, the applicant provided additional information.

On the basis of its review, the staff concludes that the Writer's Guide submit-ted by the applicant provides acceptable information for developing E0Ps which are usable, accurate, complete, readable, convenient to use, and acceptable to control room personnel, meets the requirements of SRP Section 13.5.2, and there-fore is acceptable.

(3) Program for Validation / Verification (V/V)

The' purpose of evaluating the applicant's V/V program is to determine whether the applicant has provided evidence that the upgraded E0Ps are technically correct, are written to accurately reflect the plant-specific Writer's Guide, are usable, correspond to control room / plant equipment, are compatible with the minimum number, qualifications, training, and experience of the operating staff, 4

and provide a high level of assurance that the procedures will work as a component of the accident mitigation system.

! Byron SSER 7 13-5

By letter dated March 26, 1985, the applicant described its V/V program. The program implemented by the applicant is systematic and comprehensive. However, certain details and criteria that were used in the program were omitted from the PGP. These details would be necessary to replicate the V/V program properly in future years. The applicant has committed in its letter of September 16, 1986, to add these details to the PGP by January 31, 1987.

On this basis, the staff concludes that the applicant has developed a V/V pro-gram that provides adequate assurance that E0Ps are techt.ically correct and usable, follow the Writer's Guide, correspond to the control room / plant hard-ware, and are compatible with the minimum number, qualifications, training, and experience of the operating staff, meets the requirements of SRP Section 13.5.2, and is therefore acceptable.

(4) Program for Operator Training and E0Ps The purpose of evaluating the applicant's training program on E0Ps is to ensure that operators understand the philosophy, mitigation strategies, and technical bases of the E0Ps; that they have a working knowledge of the technical content of the E0Ps, and are capable of successfully executing the E0Ps under emergency conditions.

By letter dated March 26, 1985, the applicant described a program of classroom and simulator training directly aimed at enabling operators to understand the structure, basis, and limitations of the E0Ps and to provide a working know-ledge of the technical content of the E0Ps by practicing E0Ps under simulated emergency conditions. The staff finds that the program is acceptable, but has not been fully documented in the PGP. By letter dated September 16, 1986, the applicant committed to revise the PGP to provide further detail regarding the training program by January 31, 1987. The staff finds this commitment accept-able because of the low probability of needing the revised guidance before that date. The staff concludes that implementation of the described training pro-gram should result in the operator understanding the philosophy behind the approach to the E0Ps, understanding the mitigative strategy and technical basis of the E0Ps, having a working knowledge of the technical content of the E0Ps, and having the capability to execute the E0Ps under operational conditions.

The training program meet, the requirements of SRP Section 13.5.2, and is acceptable.

Conclusions (1) Plant-Specific Technical Guidelines (P-STGs)

The staff concludes that because the applicant's E0Ps are based on the Westirg-house Emergency Response Guidelines that have been approved for implementation, and because they retain the basic mitigation strategies of the Westinghouse ERGS, they contain adequate technical basis. The applicant has committed to add plant-specific information as discussed above. The B/B PGP is consistent with the applicable technical requirements of SRP Section 13.5.2 and i<, accept-able.

Byron SSER 7 13-6

(2) Writer's Guide The applicant has committed to an acceptable Writer's Guide that provides infor-mation for developing EDPs from the P-STGs, which are usable, accurate, complete, readable, convenient to use, and acceptable to control room personnel. The Writer's Guide will be revised to comply with staff recommendations by Janu-ary 31, 1987. This commitment is acceptable because of the low probability of needing the revised guidance before that date.

(3) V/V Program The applicant has conducted activities which meet the objectives of a V/V pro-gram. The applicant has committed to fully document its V/V process in a revi-sion to the PGP by January 31, 1987. This commitment is acceptable because of the low probability of needing the revised guidance before that date.

(4) E0P Training Program The E0P training progam described in the applicant's letter of March 22, 1986 (with the commitment regarding the E0P training program), meets the requirements of SRP Section 13.5.2 and is, therefore, acceptable.

By letter dated September 16, 1986, the applicant has committed to provide further information regarding the E0P training program in the' PGP by January 31, l 1987. This commitment is acceptable because of the low probability of needing the revised guidance before that date.

A

,. , u ,

4 Byron SSER 7 13-7

) 14 INITIAL TEST PROGRAM By letter dated October 7, 1985, the licensee modified the review of startup test results that will be done for Unit 2. Before proceeding to the next power level plateau, the licensee stated that review of the test results will l be performed by the onsite Test Review Board (TRB) only, and not by the onsite j TRB and offsite Project Engineering Department as was done on Unit 1.

! The staff reviewed the licensee's proposal and the qualifications of the TRB members, and, by letter dated February 13, 1986, found the licensee's proposal acceptable.

By letter dated June 23, 1986, the licensee proposed to revise one test and eliminate five others from the Unit 2 startup test program. The request to eliminate the shutdown from outside the control room and tha loss of offsite power tests are not acceptable; however, the other four proposals are acceptable.

The staff evaluation follows*:

1 Shutdown from Outside the Control Room The licensee has proposed to modify the test summary to indicate that it will be performed on Unit 1 only. The licensee justifies this change on the basis of preoperational tests of the remote shutdown systems, which require the plant to be maintained in the hot standby condition for at least 30 minutes, and which provide all necessary design information regarding remote shutdown capability.

Regulatory Guide 1.68.2 Section C states, in part, that the test program should verify that "the nuclear power plant can be safely shutdown from outside the control room." The applicant has provided no alternative test which will demon-strate this capability. In addition, Regulatory Guide 1.68.2 states, in part, that " licensees... conduct a test program to demonstrate remote shutdown capa-bility for each unit of their plants." This demonstration is necessary to verify proper operation of the remote shutdown capability on each unit.

Experience at other facilities has demonstrated that preoperational and sub-system level tests do not achieve these objectives. This change is, there-fore, not acceptable.

Loss of Offsite Power t

The licensee has proposed to modify the test summary to indicate that it will be performed on Unit 1 only. The licensee justifies this on the basis of the test performed on Unit 1, and the preoperational test program on Unit 2 which verifies that onsite power systems are functional.

4 *By letter dated October 1, 1986, the staff transmitted this evaluation to the i licensee.

I Byron SSER 7 14-1

Regulatory Guide 1.68 Appendix A Section 5.j.j states that the test program

" demonstrate that the dynamic response of the plant is in accordance with design for a condition of loss of turbine generator coincident with loss of all sources of offsite power (i.e., Station Blackout)." While the test per-formed on Unit I demonstrated that the plant design is adequate, each unit must be tested to verify that the hardware performance at the system level is expected. Experience at other facilities has demonstrated that preoperational and subsystem level tests are not adequate to demonstrate that the dynamic response of each unit is in accordance with design. This change is, therefore, not acceptable.

Rod Drop Measurements The test summary requires measurement of rod drop times at cold no-flow, cold full-flow, hot no-flow, and hot full-flow conditions following core loading.

The licensee proposed to modify the test summary to indicate that it applies to Unit 1 only, and to add a new summary for Unit 2 which requires measurement of rod drop times at hot, full-flow conditions only. The licensee justifica-tion for this change is that the Westinghouse acceptance criteria apply to the hot, full-flow condition only, and that from previous experience they have found rod drop times at other test conditions fall under the hot, full-flow values. The staff finds this justification bounds the other test conditions.

These additional tests are not necessary, and therefore the proposed modification is acceptable.

Pseudo Rod Ejection The licensee has proposed to modify the test summary to indicate that it applies to Unit 1 only. Verification of core design parameters for Unit 2 will be achieved through control rod worth measurements, boron worth measurements, and flux mapping at zero power.

The purpose of this test is to verify calculational models and accident analysis assumptions. These design features have been verified on Unit 1. Regulatory Guide 1.68, Appendix A, Item 5.e, specifically allows the test to be deleted for facilities using calculational models and designs identical to prototype facilities. Therefore, this change is acceptable.

Flux Asymmetry Evaluation The licensee proposed to delete this test from the Startup Test Program for Unit 2. The performance of this test on Unit I has confirmed that the core thermal and nuclear parameters are in accordance with predictions. The staff finds this change acceptable.

Turbine Trip From 25% Power The licensee prop sed to delete this test from the Starty Test Program for Unit 2. This test is not required since a 100 percent power. full load rejection test will be performed in accordance with Regulatory Guide 1.68, Appendix A, Item 5.n.n. Therefore, this change is acceptable.

Byron SSER 7 14-2

i s

4 15 ACCIDENT ANALYSIS 15.6 Anticipated Transients Without Scram

, On February 25, 1983, both of the scram circuit breakers at Unit 1 of the Salem Nuclear Power Plant failed to open upon an automatic reactor trip signal from

) the reactor protection system. This incident occurred during the plant startup, 3 and the reactor was tripped manually by the operator about 30 seconds after the 4

initiation of the automatic trip signal. The failure of the circuit breakers has been determined to be related to the sticking of the undervoltage trip attachment. Before this incident, on February 22, 1983, at Unit 1 of the Salem l Nuclear Power Plant, an automatic trip signal was generated based on steam gen-

erator low-low level during plant startup. In this case, the reactor was tripped manually by the operator almost coincidentally with the automatic trip. Follow-ing these incidents, on February 28, 1933, the NRC Executive Director for

, Operations (EDO), directed the staff to investigate and report on the generic i implications of these occurrences at Unit 1 of the Salem Nuclear Power Plant.

{ The results of the staff's inquiry into the generic implications of the inci-

dents at the Salem unit are reported in NUREG-1000, " Generic Implications of

, ATWS Events at the Salem Nuclear Power Plant." As a ' result of this investiga-j tion, the Commission requested (by Generic Letter 83-28, dated July 8, 1983)

that all licensees of operating reactors, applicants for an operating license, and holders of construction permits respond to certain generic concerns. These

! concerns are categorized into four areas: (1) Post-Trip Review, (2) Equipment Classification and Vendor Interface, (3) Post-Maintenance Testing, and (4) Reac-tor Trip System Reliability Improvements.

! The staff has reviewed the licensee's responses to Generic Letter 83-28 and

approved certain items. The safety evaluations and approvals were sent to the licensee in the following letters: Item 1.1, Post-Trip Review (Program Descrip-tion and Procedure), letter dated July 11, 1985; Item 1.2, Post-Trip Review (Data ard Information Capability), letter dated May 5, 1986; Item 3.1, Post-Maintenance Testing (Reactor Trip System Components), letter dated September 26,

! 1985, for 3.1.1 and 3.1.2, letter dated November 5, 1935, for 3.1.3; Item 3.2, Post-Maintenance Testing (All Other Safety-Related Components), letter dated September 26,1985, for 3.2.1 and 3.2.2, letter dated November 5,1985, for i 3.2.3; Item 4.1, Reactor Trip System Reliability (Vendor-Related Modifications),

j letter dated September 26, 1985; Item 4.2, Reactor Trip System Reliability l (Preventative Maintenance and Surveillance Program for Reactor Trip Breakers),

i

' letter dated April 28, 1985, for 4.2.1 and 4.2.2; Item 4.3, Reactor Trip System Reliability (Automatic Actuation of Shunt Trip Attachment for Westinghcuse and i B&W Plants), letter dated March 13, 1985; Item 4.5, Reactor Trip System Relia-1 bility (System functional Testing), letter dated September 26,1985 for 4. 5.1.

i l The staff is still reviewing Item 2.1, Equipment Classification and Vendor l Interface (Reactor Trip System Components); Item 2.2, Equipment Classification t

and Vendor Interface (Programs for All Safety-Related Components); and j Items 4.2.3, 4.2.4, 4.5.2, and 4.5.3. The licensee must also submit Technical

Specifications for Item 4.3 as requested in Generic Letter 85-09, dated May 23, 1985. These items will be the subject of future correspondence.

J Byron SSER 7 15-1

. . _ ~.

l i

! 18 CONTROL ROOM DESIGN REVIEW 18.2 Main Control Room and Remote Shutdown Panel

, SER Supplement 4 discussed the one unresolved Human Emergency Discrepancy from

the staff's onsite Control Room Design Review / Audit. The item involved reloca-i tion of the range and volume controls for the SOURCE RANGE nuclear instrumenta-tion from nuclear instrument cabinet IPM07J to the main control board 1PM05J.

The Unit I license contained a condition that these controls be relocated if test results on Unit 2 indicate no technical problems.

, By letter dated September 26, 1986, the licensee stated that these controls have been relocated on Unit 2 and preoperational testing has been successfully com-pleted. Thus, no license condition is required on Unit 2. The licensee also I

committed to relocate the Unit 1 controls prior to startup following the first refueling outage in order to satisfy the Unit 1 license condition.

18.3 Safety Parameter Display System

, All holders of operating licenses issued by the Nuclear Regulatory Commission 1 (licensees) and applicants for an operating license (0L) must provide a safety parameter display system (SPDS) in the control room of their plants. The Commission-approved requirements for the SPDS are defined in Supplement 1 to NUREG-0737.

The purpose of the SPDS is to provide a concise display of critical plant variables to control room operators to aid them in rapidly and reliably deter-mining the safety status of the plant. NUREG-0737, Supplement 1, requires licensees and applicants to prepare a written safety analysis describing the l basis on which the selected parameters are sufficient to assess the safety status of each identified function for a wide range of events, including i

symptoms of severe accidents. Licensees and applicants shall also prepare an implementation plan for the SPDS which contains schedules for design, develop-ment, installation, and full operation of the SPDS as well as a design Verificat ion and Validation (V&V) Plan.

The staff conducted an audit of the Byron SPDS on July 24-76, 1986, and sent the results of its audit to the licensee in a letter dated October 30, 1985.

The audit verified that the design of the Byron SPDS should meet the require-ments of Supplement 1 to NUREG-0737. However, there were several problems noted i by the audit team. The corporate verification and validation project for the Byron SPDS had not been fully developed at the time of the audit. The licensee should submit the corporate verification and validation re; ort so that the staff j can complete its evaluation of this issue.

The audit team also noted three human engineering problems: (1) there was no clear way of determining whether the wide-range or narrow-range display was on the screen, (2) the red alarm bars at the end of each Iconic spoke were diffi-cult to detect, and (3) the wide range steam generator level spoke did not cover 4

~

1 Byron SSER 7 18-1

the full range of plant operation. The licensee attempted to correct these pro- I blems. Inspection Report No. 50-454/86021(DRP), dated July 15, 1986, stated j that the licensee had satisfactorily corrected the last two discrepancies. How- '

ever, the licensee's attempt to distinguish the between wide- and narrow-range by solid coloring the center of the wide-range display was not founu acceptable.

By letter dated October 24, 1986, the licensee committed to provide the titles wide-range and narrow-range on the Iconic displays. The staff finds this acceptable.

l i

Byron SSER 7 18-2

l l

APPENDIX A Continuation of the chronology of the NRC staff's radiological safety review

! for the period January 29, 1985, to October 7, 1986, for the Byron Station.

l Units 1 and 2 January 29, 1985 Letter from applicant concerning Byron Station, Units 1

and 2 Technical Specifications. The changes were discussed in a meeting with NRC on January 28, 1985.

1 j January 30, 1985 Letter from applicant concerning Byron Units 1 and 2 Technical Specifications.

j January 31, 1985 Letter from applicant concerning startup tests.

1 2

February 1,1985 Letter to applicant concerning Initial Test Program, i February 1, 1985 Letter from applicant transmitting Amendment No. 45 to i the FSAR.

1 February 5,1985 Letter from applicant concerning volume reduction system.

1 I

February 5, 1985 Letter from applicant concerning improved thermal design procedures.

February 6, 1985 Letter from applicant concerning FSAR changes.

t February 6, 1985 Letter from applicant concerning volume reduction system. >

1 February 7, 1985 Letter from applicant concerning volume reduction system.

February 8, 1985 Letter from applicant concerning Environmental 1

Qualification of Equipment.

February 11, 1985 Letter from applicant concerning Interim Operation of >

HVAC Systems.

i February 11, 1985 Letter from applicant concerning Initial Test Program.

1 1

February 11, 1985 Letter from applicant concerning source range neutron monitors.

1 i February 12, 1985 Letter to applicant concerning Byron Stations, Units 1 and 2 final draft of Technical Specifications.

1 i

Byron SSER 7 1 Appendix A

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c.-99..y_ -

k 4

February 12, 1985 Letter from applicant concerning Byron Technical

} Specifications.

J February 13, 1985 Letter to applicant concerning staff audit of Byron

). Station, Units 1 and 2 safety parameter display system.

{'

February 14, 1985 Letter from applicant concerning response to Generic Letter No. 84-24.

f February 14, 1985 Letter to applicant transmitting 2 copies of Supplement No. 6 to the SER (NUREG-0875 Supplement i

4 No. 6).

February 14, 1985 Letter to applicant transmitting Facility Operating

License No. NPF-37 for 100% power.

February 15, 1985 Letter from applicant transmitting a Supplemental Response to Generic Letter No. 83-28 " Requiring Actions Based on Generic Implications of Salem ATWS Events."

l l February 19, 1985 Letter to applicant concerning test program changes, j

Byron Unit 1.

February 20, 1985 Letter to applicant concerning Receipt of Updated

) Antitrust Information, Byron Station, Unit 2 and Braidwood Units 1 and 2.

I

February 20, 1985 Letter from applicant transmitting Amendment No. 46 to j the FSAR.

February 20, 1985 Letter from applicant concerning the Byron Technical Specifications.

j February 21, 1985 Letter to applicant transmitting 20 copies of Supplement No. 6 to NUREG-0875 (Byron SER Supplement No. 6),

i l February 22, 1985 Letter from applicant transmitting the 1984 Annual j Report, j February 22, 1985 Letter from applicant concerning instrumentation and the detection of inadequate core cooling.

February 25, 1985 Letter from applicant transmitting Review 13 to the Byron Security Plan.

J February 26, 1985 Letter to applicant limiting condition for operation i relaxation program.

t March 1, 1985 Letter from applicant transmitting Amendment No. 6 to i the Fire Protection Report.

I i

Byron SSER 7 2 Appendix A

f March 5, 1985 Letter to applicant transmitting the monthly Federal Register Receipts. The Federal Register of February 27, 1985, contains the notice of issuance of Amendment No. 1 to NPF-37.

March 8, 1985 Letter from applicant transmitting FSAR changes.

March 8, 1985 Letter to applicant concerning seismic qualification of equipment.

March 12, 1985 Letter to applicant requesting additional information j following staff review of licensee responses to Generic Letter 83-28.

March 13, 1985 Letter to applicant concerning automatic shunt trip for reactor trip breakers.

March 15, 1985 Letter from applicant concerning preservice inspection.

i March 27, 1985 Representatives from NRC and Commonwealth Edison meet in Bethesda, Maryland to discuss Byron /Braidwood Limiting Condition for Operation Relaxation Program (Summary issued March 29, 1985).

April 8, 1985 Letter from applicant concerning Byron Units 1 and 2 Technical Specifications.

1 i April 8, 1985 Letter from applicant transmitting the Monthly Performance Report for Byron 1 for the period March 1 through March 31, 1985.

April 10, 1985 Representatives from NRC and Commonwealth Edison meet j in Bethesda, Maryland for CE to present their Design

Verification Activities for Byron 2 and Braidwood 1

! and 2. (Summary issued April 29, 1985.)

April 16, 1985 Letter from applicant concerning seismic qualification of equipment.

l April 16, 1985 Letter from applicant transmitting the Byron Station Environmental Protection Plan 1984 Annual Environmental Operating Report.

April 16, 1985 Letter from applicant regarding updating FSAR.

) April 24, 1985 Letter from applicant concerning Design Verification

Activities.

c April 29, 1985 Letter to applicant transmitting the Trade Journal Legal Ads for Byron Unit 2 and Braidwood Units 1 and 2.

4 May 14, 1985 Letter to applicant requesting additional information on clarifying the response to Question 423.45.

t Byron SSER 7 3 Appendix A

i.

i May 15, 1985 Letter to applicant concerning Generic Letter 83-28, Item 1.1,' Post-Trip Review-Byron Station, Units 1 and 2.

j May 16, 1985 Letter from applicant concerning Byron Security Plan.

May 20, 1985 Letter to applicant concerning Environmental Effects of High Energy Line Breaks - Byron 1.

May 20, 1985 Letter to applicant concerning License Condition on Turbine Missiles - Byron Unit 1.

May 20, 1985 Letter to applicant concerning seismic qualification of valves 1RF026 and 1RF027 - Byron Unit 1.

May 24, 1985 Letter to applicant concerning TMI Action Item II.K.3.30.

1 May 29, 1985 Letter from applicant concerning Initial Test Program.

I June 10, 1985 Letter to applicant concerning Environmental Assessment and Finding of No Significant Impact - Exemption from Submittal of an Updated Final Safety Analysis Report for Byron /Braidwood.

June 10, 1985 Letter to Westinghouse concerning withholding from i public disclosure CAW-84 WCAP-10553 and WCAP-10554

" Technical Bases for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Bases for Byron Units 1 and 2 and Braidwood 1 and 2."

, ' June 17, 1985 Letter from applicant transmitting a response to 1 Generic Letter No. 85-02 Steam Generator Tube

Integrity.

June 18, 1985 Letter from applicant concerning ASME Code Cases N-403

! and N-413.

June 19, 1985 Letter from applicant concerning fees for Technical Specification Revisions.

i .

June 19, 1985 Letter from applicant concerning Piping Design Criteria.

June 24, 1985 Letter to~ applicant requesting additional information -

Items 4.1, 4.2.1 and 4.2.2 of Generic Letter 83-28.

June 26, 1985 Letter from applicant transmitting an application for Amendment to NPF-37, Appendix A Technical Specification Section 6 - Administrative Controls.

June 27, 1985 Letter from applicant transmitting a Supplement to the

Annual Environmental Report for Facility License NPF-37.

Byron SSER 7 4 Appendix A

l l

l June 28, 1985 Letter from applicant concerning Elimination of Postulated Pipe Breaks in the RCS Primary Loops.

July 9, 1985 Letter from applicant responding to NRC request for additional information to FSAR Question 423.45 - Diesel Generator Testing.

July 11, 1985 Letter to applicant concerning Generic Letter 83-28, t

Item 1.1, Post-Trip Review for Byron /Braidwood.

July 15, 1985 Letter to applicant concerning Supplemental Request for Additional Information - Byron Unit 2 and Braidwood t Units 1 and 2.

July 30, 1985 Letter from applicant transmitting Revision 15 to the Byron Security Plan.

August 2, 1985 Letter from applicant concerning environmental effects of high energy line breaks.

j August 5, 1985 Letter to applicant transmitting the July 31, 1985 issue of the Federal Register of Bi-Weekly notices containing the notice on the revision to Technical Specification Section 6.12.2 to allow personnel to enter areas with radiation levels greater than 100 mR/H during certain

) emergencies without an approved Radiation Work Permit.

dB August 6, 1985 Letter from applicant transmitting supplemental informa-I tion on separation criteria of Class 1E from non-class 1E cables.

August 14, 1985 Letter from applicant concerning elimination of postulated pipe breaks in the RCS primary loops.

August 15, 1985 Representatives from NRC, Brookhaven Laboratory, Westinghouse & Commonwealth Edison Company met in Bethesda, Maryland to discuss progress of review of Byron LCO Relaxation Program. (Summary issued August 20, 1985.)

August 20, 1985 Letter to applicant concerning Acceptance of Byron Offsite Dose Calculation Manual (0DCM).

August 20, 1985 Letter from applicant concerning Safety Parameter i Display System.

August 22, 1985 Letter from applicant concerning Supplemental Response to Generic Letter No. 85-02 Steam Generator Tube Integrity.

Byron SSER 7 5 Appendix A

l August 22, 1985 Letter from applicant concerning Response to Generic Letter 85-12 Implementation of TMI Action Item II.K.3.5 Automatic Trip of Reactor Coolant Pumps.

l August 23, 1985 Letter from applicant concerning Environmental Effects of liigh Energy Line Breaks.

August 23, 1985 Letter to applicant requesting additional information -

Vibration of Diesel Generator Instrumentation - Byron /

Braidwood.

August 23, 1985 Letter to applicant concerning Use of ASME Code Cases N-403 and N-413 for Byron Station 1 and 2 and Braidwood Station, Units 1 and 2.

I August 27, 1985 Letter to applicant Concerning Environmental Effects of fligh Energy Line Breaks - Byron 1.

l Letter to applicant granting an Exemption from August 27, 1985 Submittal Date for Updated Final Safety Analysis Report (FSAR) for Byron and Braidwood.

August 29, 1985 Letter from applicant transmitting a response to Generic Letter No. 85-07 Implementation of Integrated Schedules for Plant Modifications.

August 30, 1985 Letter to applicant concerning Emergency Relief Request Safety Injection System Class 2 Welds - Byron Unit 1.

September 3, 1985 Letter from applicant concerning Supplemental Response to Generic letter No. 83-28, " Required Actions Based on Generic Implications of Salem AlWS Events."

l September 5, 1985 Letter from applicant concerning Fluid Jet Impingement

! Analyses.

September 17, 1985 Letter from applicant concerning System Leakage Monitoring.

September 24, 1985 Letter to applicant concerning Relief Request Safety Injection System Class 2 Welds - Byron Unit 1.

September 25, 1985 Letter from applicant requesting amendments to construction permits CPPR-131, CPPR-132 and CPPR-133 for Byron Unit 2 and Braidwood Units 1 and 2 in accordance with a partial exemption request to allow implementation of the leak-before-break concept on the reactor coolant system primary loops.

l September 26, 1985 Letter to applicant concerning Generic letter 83-28:

Items 3.1.1, 3.1.2, 3.2.1, 3.2.2, 4.1 and 4.5.1.

i l Byron SSER 7 6 Appendix A

October 1, 1985 Letter to applicant concerning Staff Evaluation of Topical Report Relating to Requalification Programs for Licensed Operators, Senior Operators and Senior Operators (Limited).

October 1, 1985 Letter to apolicant transmitting Amendment No. 1 to NPF-37. The Amendment approves changes to Technical Specifications relating to administrative controls for access to high radiation areas during certain emergency situations and corrects an error made in the printing of Technical Specifications. Page 3/4 6-2, instead of page 6-2, was inadvertently printed in Section 6.0, Administrative Controls.

October 7, 1985 Letter to applicant concerning Visual Weld Inspection Requirements.

October 7, 1985 Letter from applicant concerning Startup Test Program.

October 8, 1985 Letter to applicant accepting Criteria for Firecode CT Gypsum Fire Stops for Byron and Braidwood.

October 9, 1985 Letter to applicant concerning Draft Technical Evaluation Report (TER) for Salem ATWS Item 1.2 (Generic Letter 83-28).

October 10, 1985 Letter from applicant concerning Schedule for Complying with 10 CFR 50.62, ATWS.

October 11, 1985 Letter from applicant concerning Preservice Inspection.

October 23, 1985 Letter to applicant concerning Interim Guidance on Emergency Planning Standard 10 CFR 50.47(b)(12)

Regarding Byron Station Unit 2, and Braidwood Station, Units 1 and 2.

October 28, 1985 Letter to applicant issuing an Exemption from a Portion of General Design Criterion 4 of Appendix A to 10 CFR Part 50 regarding the need to analyze large primary loop pipe ruptures as the Structural design basis for Byron Station, Unit 2 and Braidwood Station, Units 1 and 2.

October 30, 1985 Letter to applicant concerning audit results for Byron's safety parameter display systems.

October 31, 1985 Letter to applicant transmitting the Federal Register with the NRC Bi-Weekly Notices of Applications and amendments to operating licenses involving no significant hazards considerations for Byron Unit 1.

Two notices on Byron were in this issue of the Federal Register dated October 23, 1985 - Technical Specifications change to correct typographical and grammatical errors on six pages published on page 43022 and the notice of issuance of Amendment No.1 to NPF-37 found on page 43038.

( Byron SSER 7 7 Appendix A

November 5, 1985 Letter to applicant concerning Safety Evaluation Report for Generic Letter 83-28 Items 3.1.3 and 3.2.3 (Post-Maintenance Testing) - Byron and Braidwood.

November 15, 1985 Letter from applicant concerning A Model Implementation Schedule.

November 18, 1985 Letter from applicant concerning a revision to the expected fuel load dates.

December 3, 1985 Representatives from NRC, CE, BNL and Westinghouse meet in Bethesda, Maryland, to discuss results of Review of Byron LC0 Relaxation Program. (Summary issued January 24, 1986.)

December 10, 1985 Letter to applicant concerning review of Byron LCO Relaxation Program.

December 11, 1985 Letter from applicant concerning Environmental Effects of High Energy Line Breaks.

December 17, 1985 Letter from applicant transmitting Revision 16 to the Byron Security Plan.

January 17, 1986 Letter from applicant concerning Pressurized Thermal Shock.

February 6, 1986 Letter from applicant transmitting the Annual Fire Protection Report (1985).

February 7, 1986 Letter from applicant concerning Limiting Conditions for Operation Relaxation Program.

February 10, 1986 Letter to applicant reminding them the construction completion date for CPPR-131 will expire on April 1, 1986, and therefore are required to file an extension request pursuant to 10 CFR 2.109.

February 13, 1986 Letter from applicant transmitting the Annual Financial Report for 1985.

February 13, 1986 Letter to applicant transmitting Amendment No. 2 to NPF-37 for typos and grammatical errors.

February 13, 1986 Letter to applicant concerning Startup Test Program.

February 25, 1986 Letter to applicant concerning Byron /Braidwood Supple-mental Safety Evaluation Report for Physical Identifica-tion and Independence of Redundant Safety-Related Electrical Systems.

February 27, 1986 Letter from applicant transmitting a request for Construction Permit Extension of latest completion date for Byron Station, Unit 2 to June 1, 1987.

Byron SSER 7 8 Appendix A

l

! March 11, 1986 Letter from applicant transmitting an application for

! amendment to Facility Operating License NPF-37, Appendix A, Technical Specifications. The change would provide more flexibility for demonstrating operability of the residual heat removal pumps.

March 12, 1986 Letter from applicant concerning Inspection of Cast Stainless Steel Component Welds.

March 18, 1986 Letter from applicant transmitting an Application for Amendment to facility Operating License NPF-37, Appendix A, Technical Specifications which involves a revision to the measurement range of the triaxial acceleration sensors in the seismic monitoring system.

March 18, 1986 Letter from applicant advising that Michael I. Miller, Esq.

is the legal contact for Byron /Braidwood.

April 1, 1986 Letter from applicant transmitting revised emergency operations facility procedures.

April 10, 1986 Letter to applicant transmitting an Environmental Assessment for the proposed CP Extension for Byron Unit 2. The original of the notice has been forwarded to the Federal Register for publication.

April 11, 1986 Letter from applicant concerning Units 1 and 2 Technical Specifications Residual Heat Removal Pumps.

April 17, 1986 Environmental Assessment and Finding of No Significant Impact for Byron Station, Unit 2, for Construction Completion Date Extension noticed in the Federal Register on April 17, 1986 (51FR13117).

April 22, 1986 Letter from applicant concerning Supplemental Safety Evaluation Report for Physical Identification and Independence of Redundant Safety-Related Electrical Systems, FSAR Changes and S&L Design Manual Change.

April 23, 1986 Letter from applicant concerning FSAR Amendment No. 47.

April 24, 1986 Letter to applicant transmitting a6 Order Extending the Latest Construction Completion Date for Byron Station, Unit 2, from April 1, 1986 to June 1, 1987.

April 25, 1986 Letter from applicant concerning NUREG-0737, I.A.1.1. -

Shift Technical Advisor.

April 28, 1986 Letter to applicant concerning Generic Letter 83-28:

Items 4.2.1 and 4.2.2.

Byron SSER 7 9 Appendix A

April 29, 1986 Letter to applicant transmitting Amendment No. I to Construction Permits CPPR-131, CPPR-132 and CPPR-133 for Byron Station, Unit 2, and Braidwood Station, Units 1 and 2, to include the exemption from GDC-4 received from NRC on October 25, 1985.

April 29, 1986 Letter from applicant concerning Environmental Effects of High Energy Line Breaks.

May 5, 1986 Letter to applicant concerning Byron Station, Units 1 and 2 - Safety Evaluation of Compliance with Item 1.2 of Generic Letter 83-28.

May 9, 1986 Letter from applicant concerning NUREG-0737, I.A.1.1 -

Shift Technical Advisor.

May 13, 1986 Letter to applicant concerning Audit of Inadequate Core Cooling Instrumentation - Byron Station, Units 1 and 2.

May 21, 1986 Letter to applicant concerning Charging Pump Deadheading - Byron 1 and 2.

May 21, 1986 Letter from applicant concerning Preservice Inspection Steam Generators and Pressurizer - Byron Unit 2.

June 4, 1986 Letter from applicant concerning Byron Station Unit 1 Generic Issues.

, June 4, 1986 Letter from applicant concerning A Model Implementation-Schedule.

June 6, 1986 Letter to applicant transmitting Amendment No. 1 to NPF-37 revising the Byron Units 1 and 2 Technical Specifications - Acceptance Criteria for RHR Pump Performance.

June 11, 1986 Letter from applicant transmitting Amendment 8 to the Byron /Braidwood Fire protection Report (FPR). I June 16, 1986 Letter from applicant transmitting an Amendment request supplement for a letter dated November 26, 1985 -

Technical Specification 3.5.2, Emergency Core Cooling Systems. The proposed change would allow certain valves in the safety injection system to be temporarily closed during leak testing of some reactor coolant system 4 pressure isolation check valves.

June 23, 1986 Letter from applicant concerning Startup Test Program.

June 25, 1986 Letter from applicant concerning Inspection of Cast Stainless Steel Component Welds.

l l

Byron SSER 7 10 Appendix A

July 2, 1986 Letter from applicant concerning Confirmation of Design Adequacy for Jet Impingement Effects.

l July 8 & 9, 1986 Representatives from NRC and CEC 0 meet in Bethesda, j Maryland, to discuss inservice testing. (Summary issued i

July 28, 1986.)

July 15, 1986 Letter to applicant concerning Application for Amendment to Byron Technical Specifications - Changing Full Scale Range of Seismic Monitoring Instrumentation.

July 22, 1986 Letter from applicant concerning evaluation of environmental effects of main steam line break outside containment (IE Information Notice 84-90).

July 23, 1986 Letter from applicant concerning Byron Unit 2 Preservice Inspection.

July 25, 1986 Representatives from NRC and Commonwealth Edison meet in Bethesda, Maryland, to discuss Byron's proposal to reduce hot leg temperature. (Summary issued August 8, 1986.)

July 30, 1986 Letter from applicant concerning Byron Station Unit 2 NEPA Code Deviations.

July 30, 1986 Letter from applicant concerning Byron and Braidwood Station, Units 1 and 2 IE Information Notices 86-02 and 86-03.

July 30, 1986 Letters from applicant concerning Application for Amendment to Facility Operating License, NPF-37, Appendix A, Technical Specifications (Fuel Assemblies, Surveillance Requirements).

August 5, 1986 Letter from applicant transmitting an application for amendment to Facility Operating License, NPF-37, Appendix A, Technical Specifications. Request includes changes to Technical Specifications for Limiting Condition for Operation, Surveillance Requirements.

August 13, 1986 Letter from applicant transmitting an Application for Amendment to Facility Operating License, NPF-37, Appendix A Technical Specifications for Limiting Condition for Operation and Surveillance Requirements.

August 15, 1986 Letter from applicant concerning Description of Appendix R Conformance as provided by Appendix A5.7 of the B/B Fire Protection Report.

Byron SSER 7 11 Appendix A

August 19, 1986 Letter from applicant concerning IE Information Notices 86-02 and 86-03, Compliance with the EQ Rule, and  ;

Information on Seismic and Dynamic Qualification. l August 22, 1986 Letter from applicant submitting revised Heatup and Cooldown Curves andTL Value for Byron Unit 2.

August 27, 1986 Letter from applicant requesting a technical specifica-tion change which involves D.C. electrical sources re-visiting pages 3/4 8-10 and 3/4 8-13 and adding a new 3/4 8-11a.

August 29, 1986 Letter from applicant transmitting an application for amendment to NPF-37, Appendix A, Tech. Specs. Amendment would delete the Fire Protection Technical Specifications in accordance with Generic Letter 86-10. Fire protection License Condition 2.C(6) would be revised.

September 2, 1986 Letter from applicant requesting a relief from inspection of cast stainless steel component welds.

September 9, 1986 Letter to applicant concerning Byron /Braidwood Rod Swap Technique.

September 10, 1986 Letter from applicant transmitting proposed amendment to Tech. Spec. for Facility Operating License NPF-37, Appen-dix A. The changes reflect the most current on-site and off-site organizational structures. ' The required changes to the Administrative Controls portion of Tech. Spec.

(Section 6.0) have been made to reflect this new organization.

September 10, 1986 Letter from applicant transmitting Technical Specifica-tion Changes for Section 3/4, " Instrumentation," to the Byron Tech. Specs. Changes have been made to Table 3.3-11b,

" Fire Detection Instruments" (pages 3/4 3-61 through 3-63) and Table 3.7-5b " Fire Hose Stations" (pages 3/4 7-42 through 7-45).

September 10, 1986 Letter from applicant transmitting supplemental informa-tion on Environmental Effects of Main Steam Line Break Outside Containment Information Notice 84-90 for Byron Station, Units 1 & 2 Braidwood Station, Units 1 & 2.

September 15, 1986 Letter from applicant transmitting an application for Amendment to Facility Operating License, NPF-37, Appen-dix A, Technical Specifications.

September 16, 1986 Letter from applicant concerning Interim Guidance on Emergency Planning Standard 10 CFR 50.47(b)(12) for Byron Unit 2 and Braidwood Units 1 & 2.

Byron SSER 7 12 Appendix A

September 16, 1986 Letter from applicant concerning Emergency Operating Procedures - Byron and Braidwood Stations.

September 16, 1986 Letter from applicant concerning Technical Specifica-tions Ultimate Heat Sinks (UHS) Cooling Towers.

September 23, 1986 Letter from applicant concerning Fire Protection - Byron Station Unit 2.

l l September 25, 1986 Letter to applicant concerning Anticipated Transients l without Scram - Byron Station, Unit 1.

t September 26, 1986 Letter from applicant concerning Control Room Human Factors.

September 29, 1986 Letter from applicant concerning Emergency Operating Procedures - Byron 1 & 2 and Braidwood 1 & 2.

September 30, 1986 Letter from applicant concerning Byron Station, Unit 2 Preservico Inspection.

October 1, 1986 Letter from applicant concerning Byron Station Unit 2 -

Deferral of Limited Aspects of the Initial Test Program.

October 2, 1986 Letter from applicant concerning Byron Station, Unit 2 -

Revision to Expected Fuel Load Date.

October 3, 1986 Letter from applicant concerning Submittal of Revised Heatup and Cooldown Curves.

October 7, 1986 Letter from applicant concerning Section 6.0 Technical Specifications.

d Byron SSER 7 13 Appendix A

l APPENDIX F NRC STAFF CONTRIBUTORS 4

This Supplement No. 7 to the SER is a product of the NRC staff and its consultants. The NRC staff members listed below were principal contributors to this report.

NAME TITLE

• REVIEW BRANCH

• D. Smith Materials Engineer Engineering (PWR-A)

R. Karsch Nuclear Engineer Reactor Systems (PWR-A)

, F. Burrows Electrical Engineer Electrical, Instrumentation, 4

and Control Systems (PWR-A)

S. Rhow Electrical Engineer Electrical, Instrumentation,

, , and Control Systems (BWR)

D. Hickman Technical Training Specialist Facilities Operation (PWR-A)

M. Chatterton Nuclear Engineer Reactor Systems (PWR-A)

B. Elliot Materials Engineers Engineering (PWR-A)

G. Johnson Materials Engineer Engineering (PWR-A)

J. Hayes Nuclear Engineer Plant Systems (PWR-A)

G. Lapinsky Engineering Psychologist Facility Operations (PWR-A)

C. Y. Li Mechanical Engineer Plant Systems (PWR-A) ,

F. Orr Reactor Systems Engineer Facility Operations (PWR-A) l A. Singh Mechanical Engineer Plant Systems (PWR-A)

! H. Walker Mechanical Engineer Electrical, Instrumentation and Control Systems (PWR-A) a M. Rushbrook Licensing Assistant . Project Directorate / 5 (PWR-A) 1 i

• Reflects reorganization since Supplement 6 was issued.

I t

Byron SSER 7 1 Appendix F

D i

l APPENDIX K l COMMONWEALTH EDISON COMPANY l BYRON STATION - UNIT 2 DOCKET NUMBER 50-455 SAFETY EVALUATION REPORT SUPPLEMENT PRESERVICE INSPECTION RELIEF REQUEST EVALUATION I. INTRODUCTION This section was prepared with the technical assistance of DOE contractors from the Idaho National E,ngineering Laboratory.

For nuclear power facilities whose construction permit was issued on' or T after July 1, 1974, 10 CFR 50.55a(g)(3) specifies that compone'nts shall meet the preservice examination requirements set forth in, editions and addenda of Section XI of the ASME Boiler and Pressure Vessel Code applied to the construction of the particular component. The provisions of-10 CFR 50.55a(g)(3) also state that components (including supports),may'3 meet the requirements set forth in subsequent editions and addenda of.this Code which are incorporated by reference in 10 CFR 50.55a(b) subject to the limitations and modifications listed therein.

Requests for relief frc= the ASME Codo Section XI requirements which the Applicant has determined to be impractical for systers and compailents at Byron Unit 2 were contained in the submittals dated' July 23, 1986, Septem-ber 2, 1986, and October 16, 1986. Clarifications and revisions in re, lief requests were received in the Applicant's September 30, 1986 submittat.

The July 23, 1986 submittal contained a comparison and. cross-reference )

betweentheByronUnit2anotheByronUnitIreliefrequestsanddetai{ed /

any differences between the individual items. These relief requests were ,

all supported by information pursuant to 10 CFR 50:55a(a)(3). Therefore, the staff evaluation consisted ,of reviewing the submittals to the require-ments of the applicable Code edition and addenda and determining if relief from the Code requirements was justified.

II. TECHNICAL REVIEW CONSIDERATIONS l A. The construction permit for Byron Station, Unit 2 was issued on December 31, 1975. In accordance with 10 CFR 50.55a(g)(3), compo-

~

nents (including supports) which are classified as ASME Code Class 1 ~

and 2 have been designed and provided with' access to enable the per-formance of required preservice examinations.

i B. Verification of as-built structural integrity of the primary pressure boundary is not dependent on the Section XI preservice examination.

The applicable construction codes to which the primary pressure ' vound-ary was fabricated contain examination and terting' requirements which Byron SSER 7 1 Appendix K

_ _ _ _ _ _ _ _ _ - - - _ J

s

\

by themselves provide the necessary assurance that the pressure bound-ary components are capable of performing safely under all operating conditions reviewed in the FSAR and described in the plant design specification. As a part of these examinations, all of the primary pressure boundary full penetration welds were volumetrically examined I (radiographed) and the system was subjected to hydrostatic pressure tests. .

C. The intent of a preservice examination is to establish a reference or baseline prior to the initial operation of the facility. The results of subsequent inservice examinations can then be compared with the original condition to determine whether changes have occurred. If the inservice inspection results show no change from the original condition, no action is required. In the case where baseline data are not available, all. flaws must be treated as new flaws and evalu-ated accordingly.Section XI of the ASME Code contains acceptance standards which may be used as the basis for evaluating the accepta-bility of such flaws.

D. Other benefits of the preservice examination include providing redun-dant or alternative volumetric examination of the primary pressure boundary using a test method different from that employed during the component fabrication. Successful performance of the preservice examination also demonstrates that the welds so examined are capable of subsequent inservice examination using a similar test method.

In the case of Byron Station Unit 2, a large percentage of the pre-service examination required by the ASME Code was performed. Failure to perform a 100% preservice examination of the welds identified below will not affect the assurance of the initial structural integrity.

E. In some instances where the required preservice examinations were not performed to the full extent specified by the applicable ASME Code, the staff may require that these examinations or supplemental examinations be conducted as a part of the inservice inspection pro-gram. Requiring supplemental examinations to be performed at this time would result'in hardships or unusual difficulties without a compensating increase in the level of quality or safety. The per-formance of supplemental examinations, such as surface examinations, in areas where volumetric examination is difficult will be more meanin;fful af ter a period of operation. Acceptable preoperational integrity has already been established by similar ASME Code Sec-tion III fabrication examinations.

Intcases where parts of the required examination areas cannot be effectively examined because of a combination of component design or current examination technique limitations, the development of new or inproved examination techniques will continue to be evaluated. As improvements in these areas are achieved, the staff will require that these new techniques be made a part of the inservice examination re-ouirements for the components or welds which received a limited pre-service examination.

Byron SSER 7 2 Appendix K

Several of the preservice inspection relief requests involve examina-l tion of less than the required. volume of a specific weld. The inservice inspection (ISI) program is based on_the examination of a l representative sample of welds to detect generic service-induced degradation. In the event that the welds identified in the PSI relief requests are required to.be examined again, the possibility of augmented inservice inspection will be evaluated during review of the Applicant's initial 10 year ISI program. An augmented program may include increasing the extent and/or frequency of examination of accessible welds.

l III. EVALUATION OF RELIEF REQUESTS The Applicant' requested relief from specific preservice inspection re-quirements in submittals dated July 23, 1986, September 2, 1986, and October 16, 1986. Clarifications and revisions to relief requests were received in a submittal from the Applicant dated September 30, 1986. The July 23, 1986 submittal cor.tained a comparison and cross reference between the Byron Unit 2 and the Byron Unit 1 relief requests and detailed any )

differences between the individual items. Of the eighteen relief requests  !

submitted, five are plant specific for Byron Unit 2,-and thirteen are I common to both Byron Units 1 and 2. All of these relief requests were supported by information pursuant to 10 CFR 50.55a(a)(3). Based on the information submitted by the Applicant and the staff's review of the design, geometry, and materials of construction of the components, certain preservice inspection requirements of the ASME Boiler and Pressure Vessel Code,Section XI have been determined to be impractical to perform. The Applicant has demonstrated that either (i) the proposed alternative would provide an acceptable level of quality and safety or (ii) compliance with the specified requirements of this section would result'in hardships or unusual difficulties without a compensating increase in the level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(a)(3), conclu-sions that these preservice requirements are impractical are justified as follows. Unlen otherwise stated, references to the Code refer to the ASME Code, SocMon XI,1977 Edition including Addenda through Summer 1978.

A. Relief Request No. NR-1 (Rev. 1), Examination Category B-J, Item B9.11, Class 1 Cast Stainless Steel Elbow-to-Cast Stainless Steel Pump or Valve Welds (fitting-to-fitting)

Code Requirement: Section XI, Table IWB-2500-1, Examination Category B-J, Item B9.11 requires a 100% surface and volumetric examination on l Class 1 pressure retaining welds in piping 4 inch and greater nominal l pipe size as defined by Figure IWB-2500-8. In addition, Appendix

[ III, Supplement 7, requires that ultrasonic examination sensitivity L be established using I.D. notches with a depth of 10% wall thickness.

i i Code Relief Request: Relief is requested from performing 100% of I the Code-required volumetric examination on the following 8 elbow-to-l pump or valve welds. Relief is also requested from the examination sensitivity being established to resolve 10% I.D. notches.

Byron SSER 7 3  : Appendix K

Elbow-to-Pump Welds Elbow-to-Valve Welds Line Number Weld Number Line Number Weld Number 2RC02AA-31" J-8 2RC01AA-29" J-4 2RC02AB-31" J-8 2RC01AB-29" J-4 2RC02AC-31" J-8 2RC01AC-29" J-4 l 2RC02AD-31" J-8 2RC01AD-29" J-5 i

l Reason for Request: The above listed welds join cast stainless steel elbows to either cast stainless steel pumps or valves (fitting-to-fitting welds). The ultrasonic examination technique utilizes two l

1.0 inch diameter, 1.0 MHz transducers, mounted on a contoured wedge search unit which produces an approximately 41 degree refracted j longitudinal wave focused near the I.D. surface. Therefore, because -

! of the large contoured wedge search units and the weld geometry, these welds experience axial and circumferential scanning limitations.

The Applicant. reported that the examinations performed on the above listed welds represent state-of-the-art examinations for the inspec-I tion of,the statically cast stainless steel and that this optimized ultrasonic technique will only reliably detect flaws 25% or greater through the wall. This sensitivity is less than the 10% required by the Code. Despite the reported limitations, both the axial and circumferential scans were capable of locating flaws within the counterbore region as verified by the identification of root and counterbore signals.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject welds received both volumetric examination by radio-graphy and surface examinations during fabrication in accordance with ASME Code Section III requirements.

2. The staff has determined that the Applicant has developed, within the state-of-the-art, ultrasonic equipment and procedures for an effective ultrasonic examination of the cast stainless steel welds.

3. The staff will continue to evaluate the development of new or improved NDE procedures and will require that these enhanced procedures be made a part of the inservice examination requirements.

Based on the above, the staff concludes that the Section.III fabrica-tion examinations, supplemented by the Section XI surface examination and the state-of-the-art Section XI volumetric examination, provide an acceptable level of preservice structural integrity and that com-pliance with the specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

Byron SSER 7 4 Appendix K

3 B. Relief Request No. NR-2 (Rev. 1), Examination Category B-J, Item B9.11, Reactor Pressure Vessel Safe End-to-Cast Stainless Steel Elbow Welds Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-J, Item B9.11 requires a 100% surface and volumetric examina-tion on Class 1 pressure retaining welds in piping 4 inch and greater nominal pipe size as defined by Figure IWB-2500-8. In addition, Appendix III, Supplement 7, requires that ultrasonic examination

, sensitivity be established using I.D. notches with a depth of 10%

l wall thickness.

Code Relief Request: Relief is requested from performing 100% of the Code-required volumetric examination on the following welds. Relief is also requested from the examination sensitivity being established to resolve 10% I.D. notches.

Elbow-to-Safe End Welds Line Number Weld Number 2RC03AA-27.5" J-12 2RC03AB-27.5" J-12 2RC03AC-27.5" J-13 2RC03AD-27.5" J-12 Reason for Request: The above listed welds all join cast austenitic stainless steel elbows to reactor vessel nozzle safe-ends. Ultrasonic examinations were performed circumferentially in both directions for transverse reflectors, and axially for parallel reflectors, from the safe-end side of each of the above listed welds. In addition, a "best effort" ultrasonic examination consisting of 1/2 V path scans from the elbow side was performed. Because of the large contoured wedge search units and the elbow geometry, the axial and circumferen-tial scans from the elbow side were limited due to the inability of the search unit to maintain sufficient coupling while scanning over the weld to base metal transition.

The Applicant reported that the examinations performed on the above listed welds represent state-of-the-art examinations for the inspec-tion of statically cast stainless steel and that this optimized ultra-sonic technique will only reliably detect flaws 25% or greater through the wall. This sensitivity is less than the 10% required by the Code.

I Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject welds received both volumetric examination by radio-graphy and surface examinations during fabrication in accordance with ASME Code Section III requirements.

2. The staff has determined that the Applicant has developed, within the state-of-the-art, ultrasonic equipment and procedures for an effective ultrasonic examination of the cast stainless steel welds.

Byron SSER 7 5 Appendix K

3. The Code-required ultrasonic examination was completed from the non-cast (safe end) side of the weld and a "best effort" ultra-sonic examination using-state of-the-art techniques was completed from the cast stainless side.

4. The staff will continue to evaluate the development of new or improved NOE procedures and will require that these enhanced procedures be made a part of the inservice examination requirements.

Based on the above, the staff concludes that the Section Ill fabrica-tion examinations, supplemented by the Section XI surface examination and the limited state-of-the-art Section XI volumetric examination, provide an acceptable level of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

C. Relief Request No. NR-3 (Rev. 1), Examination Category B-F, Item BS.30, Steam Generator Nozzle-to-Safe End Welds Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-F, Item B5.30 requiies a 100% surface and volumetric examina-tion on steam generator nozzle-to-safe end welds as defined by Figure IWB-2500-8. In addition, Appendix III, Supplement 7, requires that ultrasonic examination sensitivity be established using I.D. notches with a depth of 10% wall thickness.

Code Relief Request: Relief is requested from performing 100% of the Code-required volumetric examination on the following welds.

Relief is also requested from the examination sensitivity being established to resolve 10% I.D. notches.

Line Number Weld Number Line Number Weld Number 2RC01AA-29" F-2 2RC02AA-31" F-1 2RC01AB-29" F-2 2RC02AB-31" F 2RC01AC-29" F-2 2RC02AC-31" F-1 2RC01AD-29" F-2 2RC02AD-31" . F-1 Reason for Request: The above listed welds join cast austenitic stainless steel (SA-351-CF8A) to cast carbon steel (SA-261 GR-WWC) and are clad with austenitic stainless steel. Ultrasonic examina-tions were performed circumferentially in both directions for trans-verse reflectors, and axially for parallel reflectors, from the steam generator nozzle side with a 1/2-V path scan. In addition a state-of-the-art ultrasonic examination, consisting of the Code-required axial 1/2 V path scan from the elbow side and circumferential 1/2 V path scans along the weld, was completed for each of the above listed welds. The elbow side circumferential scans were limited a short distance from the edge of the weld crown due to the inability of the search unit to maintain sufficient coupling while scanning over the weld to base metal transition.

Byron SSER 7 6 Appendix K

The Applicant reported that the examinations performed on the above listed welds represent state-of-the-art examinations for the inspec-tion of statically cast stainless steel and that this optimized ultrasonic technique will only reliably detect flaws 25% or greater through the wall. This sensitivity is less than the 10% required by the Code. Both the axial and circumferential stans were capable of locating any flaws within the counterbore region as verified by the identification of root and counterbore signals.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject welds received both volumetric examination by radiography and surface examinations during fabrication in accordance with ASME Code Section III requirements.

2. The staff has determined that the Applicant has developed, within the state-of-the-art, ultrasonic equipment and procedures for an effective ultrasonic examination of the cast stainless steel welds.

3. The Code-required ultrasonic examination was completed from the carbon steel side of the weld and a "best effort" ultrasonic examination using state of-the-art techniques was completed from the cast stainless steel side.

4. The staff will continue to evaluate the development of new or improved NDE procedures and will require that these enhanced I

procedures be made a part of the inservice examination requirements.

Based on the above, the staff concludes that the Section III fabrica-i tion examinations, supplemented by the Section XI surface examination and the state-of-the-art Section XI volumetric examination, provide an acceptable level of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

D. Relief Request No. NR-4 (Rev. 0), Examination Category C-F, Items C5.31 and C5.32, Class 2 Pressure Retaining Branch Connection Welds in the Main Steam, Safety Injection, and Residual Heat Removal Systems Code Requirement: Section XI, Table IWC-2500-1, Examination Cate-gory C-F, Items C5.31 and C5.32 require a 100% surface examination on Class 2 pipe branch connections as defined by Figures IWC-2520-9 and IWC-2520-7, respectively.

Code Relief Reauest: Relief is requested from performing 100% of the Code-required surface examination on the following 24 branch connection welds:

Byron SSER 7 7 Appendix K

! Line Number Weld Numbers l

2MS07AA-28" C-12, 13, 14, 15, and 16 2MS07AB-28" C-15, 16, 17, 18, and 19 2MS07AC-28" C-15, 16, 17, 18, and 19 2MS07AD-28" C-12, 13, 14, 15, and 16 2SIO6BA-24" C-26 2SIO6BB-24" C-26 2RH01CA-16" C-ll 2RH01CB-16" C-1L Reason for Request: The above listed welds are inaccessible for a 100% surface examination due to the location of saddle plates over the pressure retaining welds. The Applicant has committed to a sur-face examination (liquid penetrant) and visual examination (leak test) on the saddle plate fillet welds in lieu of the required sur-face examinations for the-pressure retaining welds listed above.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The branch pipe circumferential welds listed above have received radiographic volumetric examinations in accordance with the ASME Code Section III, Class 2, requirements during fabrication.

2. The as-built component geometry makes the required Section XI examination impractical. Removal of the welded reinforcement collars to make the area accessible for a preservice surface examination would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety since the radiography performed during construction on the branch pipe circumferential welds verifies the preservice structural integrity. Based on the above, the staff has deter-mined that performing a surface and visual examination of the saddle plate fillet weld is an acceptable alternative to the Code-required surface examination.

E. Relief Request Nos. NR-5 (Rev. 0) and NR-6 (Rev. 0), Examination Category C-F, Items C5.ll and C5.12, Pressure Retaining Class 2 Welds in the Residual Heat Removal and the Containment Spray Systems Code Requirement: Section XI, Table IWC-2500-1, Examination Cate-gory C-F, Items C5.11 and C5.12 require a 100% surface examination on pressure retaining welds in Class 2 piping with 1/2 inch or less nominal wall thickness as defined by Fig ue IWC-2520-7.

Code Relief Request: Relief is requested from performing 100% of the Code-required surface examination on the following welds:

Byron SSER 7 8 Appendix K L __ .

Relief Request NR-5 Relief Request NR-6 Residual Heat Removal System Containment Spray System.

Line Number Weld Number Line Number Weld Number 2RH01BA-12" C-16 2SC02AA-10"- C-61 2RH03AB- 8" C-53 2SC02AA-10" ~C-62-L 2RH03AB- 8" C-50-L 2SC02AB-10" C-35 2RH03AB- 8" C-52-L 2SC02AB-10" C-34-L 2RH03AB- 8" C-54-L 2SC02AB-10" C-36-L Reason for Request: The Applicant reports that these welds are inac-cessible for the Code-required surface examination as they are either located in a floor penetration, a wall penetration, or are located under a permanent restraint.

The Applicant reports that all other welds located on the subject lines are examinable. Therefore, examination of these adjacent welds provides a reasonable assurance of.the structural integrity of the subject welds. The Applicant also reports that the subject welds received the Code-required Section III examinations during.

fabrication. 4 Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject welds received radiographic examinations during fabrication in accordance with ASME Code Section III requirements.

2. The staff notes that complete examinations which met the re-quirements of ASME Code Section XI were performed on similar-welds using the same inspection techniques, equipment and procedures as these uninspectable welds. Since these welds will see the same operating and environmental conditions as the inspected welds, a reasonable assurance of the structural integrity of the welds for which relief is requested has'been attained.

3. All of these welds will be subjected to a system pressure test in accordance with Section XI requirements.

The staff therefore concludes that the Section III fabrication exami-nations and system pressure tests provide an acceptable level of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardship or unusual dif-ficulties without a compensating increase-in the level of quality and safety.

F. Relief Request No. NR-7 (Rev. 1), Examination Category B-M-2, Item B12.40, Class 1 Valve Bodies in the Reactor Coolant, Pressurizer, Safety Injection, and Residual Heat Removal Systems Code Requirement: Section XI, Table IWB-2500-1, Examination Cate--

gory B-M-2, Item B12.40 requires a visual . (VT-3) examination of the valve body internal surfaces on valves exceeding 4 inch nominal pipe _

Byron SSER 7 9 ' Appendix K .

_ . . . _ J

size. Examinations are limited to one valve within each group of valves that are of the same constructional design, e.g., globe, gate or check valve, and manufacturing method, and that perform similar functions in the system, e.g., containment isolation and system overpressure protection.

Code Relief Request: Relief is requested from disassembly of an operable valve for the sole purpose of performing a preservice visual examination (VT-3). The following valves are included in this request:

\

Reactor coolant Safety Injection 2RC8001-A, B, C, & D 2SI8808-A, B, C, & D 2RC8002-A, B, C, & D 2SI8948-A, B, C, & D 2RC8003-A, B, C, & D 2SI8818-A, B, C, & D Pressurizer 2SI8949-A, B, C, & D 2RY8010-A, B, & C 2SI8956-A, B, C, & D Residual Heat Removal 2SI8841-A & B 2RH8701-A & B 2RH8702-A & B Reason for Request: The requirement to disassemble an operable valve for the sole purpose of performing a visual examination (VT-3) of the internal pressure retaining boundary is impractical and not commensurate to the increased safety achieved by this inspection.

Class 1 valves are installed in their respective systems and many have completed functional testing. To disassemble these valves would provide a very small potential for increasing plant safety margins with a very disproportionate impact on expenditures of plant manpower ana resources.

The Applicant states that the manufacturer's test data will be used in lieu of a preservice visual examination (VT-3). This includes documentation of examinations performed during fabrication and in-stallation of the subject valves. The examinations performed may include volumetric, surface, and visual examinations, as required by ASME Section II, " Material Specifications for Ferrous and Nonferrous Materials."

The Applicant also states that the integrity of the pressure retain-ing boundary of both carbon steel and stainless steel valve bodies has been excellent. Class 1 valve bodies cannot historically be linked to breaching of the pressure retaining boundary in plant sys-tems. Class 1 valves are subjected to numerous types of nondestruc-tive testing and a rigorous quality assurance program during all stages of fabrication, storage, and installation. These valves have been found acceptable by the manufacturer, the ASME Authorized Nuclear Inspector, and Commonwealth Edison's Quality Assurance.

Staff Evaluation: The staff concludes that disassembly of these valves at this time solely to perform the required Section XI pre-service visual examination of the internal surface is impractical.

The staff has determined that the nondestructive examinations and Byron SSER 7 10 Appendix K

functional tests performed to date significantly exceed the require-i ments of the Section XI visual examination and, therefore, these l examinations and tests are an acceptable alternative to the Code

) requirement; relief is granted as requested.

l G. Relief Request No. NR-8 (Rev.1), Examination Category B-L-2, l

Item B12.20, Visual Examination of Reactor Coolant Pump Internal Surfaces Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-L-2, Item 812.20 requires a visual (VT-3) examination of Class 1 pump casing internal surfaces.

Code Relief Request: Relief is requested from disassembly of the Reactor Coolant, Pumps for the sole purpose of performing a preservice visual examination (VT-3). The following pumps are included in this request:

Reactor Coolant Pumps 2RC01PA 2RC01P3 2RC01PC 2RC01PD Reason for Request: The requirement to disassemble an operable pump for the sole purpose of performing a visual examination (VT-3) of the internal pressure retaining boundary is impractical and not commensu-rate to the increased safety achieved by this inspection. To disas-semble these pumps would provide a very small potential for increas-ing plant safety margins with a very disproportionate impact on expenditures of plant manpower and resources.

The above listed pumps are of the integrally cast type and therefore have no pump casing welds. All internal surfaces received liquid penetrant examinations performed by the manufacturer. This exceeds the Section XI requirements for visual examination.

Staff Evaluation: The staff concludes that disassembly of these  ;

pumps at this time solely to perform the required Section XI preser-vice visual examination of the internal surface is impractical. The staff has determined that the manufacturer's liquid penetrant exami-nation of all internal surfaces of these pumps exceeds the Section XI requirements for visual examination and, therefore, is an acceptable alternative to the Code-requirement.

. H. Relief Request No. NR-9 (Rev. 0), Examination Category 8-D, Items B3.120 and B3.140, Inside Radius Sectioas on Pressurizer and Steam Generator Vessel Nozzles Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-D, Items 83.120 and B3.140 requires a 100% volumetric exami-nation on pressurizer and steam generator nozzle inside radius sections as defined by Figure IWB-2500-7.

Byron SSER 7 11 Appendix K

Code Relief Request: Relief is requested from performing the ultra-sonic examination of the Code required volume of the following nozzle inner radii (14 items total):

Component Number Weld Numbers I

2RC018A Primary Nozzles (2) 2RC01BB Primary Nozzles (2) 2RC01BC Primary Nozzles (2) 2RC01BD Primary Nozzles (2) 2RYO15 PN-1, 2, 3, 4, 5, and 6

Reason for Request

These nozzles all contain inherent geometric I constraints and clad inner surfaces which limit the ability to perform meaningful volumetric examinations. In an attempt to develop a technique to locate flaws in the nozzle inner radii area, a mock-up was used with little success.

The steam generator primary side nozzles received a liquid penetrant examination. The nozzles were examined up to a ring welded to the inner radii which is used to hold down the nozzle cover during steam generator channel head work. In addition, all pressure retaining components were hydrostatically tested to the requirements of ASME Code Section III.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. All pressure retaining components were hydrostatically-tested to the requirements of ASME Code Section III prior-to plant startup.

2. The staff review of the design configuration of the nozzle inner radius has concluded that the Code-required volumetric examina-tion is impractical. The staff has determined that performing the ASME Section III hydrostatic test is an acceptable alternative.

3. The staff will continue to evaluate the development of new or improved NDE procedures and will require that these enhanced procedures be made part of the ISI examination requirements.

I. Relief Request No. NR-10 (Rev. 0), Examination Category B-A, Pressure Retaining Welds in the Reactor Vessel Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-A, Items B1.11, Bl.21, and B1.30 requires a 100% volumetric examination of the subject reactor pressure vessel welds as defined by Figures IWB-2500-1, 3, and 4 respectively.

Code Relief Request: Relief is requested from performing preservice volumetric examination of the inaccessible portions of the following three reactor pressure vessel welds:

Byron SSER 7 12 Appendix K

Weld Numbers RPVC-WR29 RPVC-WR16 RPVC-WR7 Reason for Request: Configuration, permanent attachments and/or structural interferences prohibit 100% ultrasonic examination coverage of the required volume.

1. Lower Shell Course-to-Dutchman weld RPVC-WR29 has six core barrel locating lugs welded to the interior surface of the reactor vessel approximately 4.0 inches above the weld. These lugs re-stricted the automated inspection tool from inspecting the re- '

quired volume from the shell course side in the areas of the lugs. All of the weld metal was examined from the shell course side where access was available between the lugs. Below the lugs, the inner 2 to 4 inches of weld metal was examined. Exam-inations from the Dutchman side for parallel reflectors covered 100% of the weld metal and heat-affected zone (HAZ) and 100% of the weld metal and HAZ was examined for transverse reflectors in two opposing directions.

2. Lower Disk-to-Dutchman weld RPVC-WR16 has 58 instrument tubes that penetrate the lower disk and physically obstruct the search unit and/or search unit positioning device. The weld and HAZ received essentially 100% coverage for parallel reflectors from the Dutchman side and for transverse reflectors in two opposing directions. Full coverage for parallel reflectors from the disk side was limited to about 85% of the weld length; partial cov-erage was achieved on the remainder of the weld.

3. Nozzle shell course-to-flange weld RPVC-WR7 is located just be-low the tapered portion of the flange which prevents 100% exam-ination of the required adjacent base metal. All of the requireo volume was manually examined for parallel reflectors from the vessel flange. All of the weld metal and approximately 90% of the adjacent base metal was examined for transverse reflectors.

Staff Evaluation: The staff has reviewed the above information, in-cluding the figures submitted with Relief Request NR-10 which show the areas receiving the required examination and the areas which could not be examined, and concluded that this relief request is acceptable based on the following considerations:

1. A significant percentage of the above listed welds received the preservice volumetric examination in accordance with the ASME Code Section XI. Completion of the remaining portions of the required examination is impractical and would result in undue hardship without a compensating increase in safety.

2. All of the reactor pressure vessel welds passed volumetric examinations during fabrication in accordance with ASME Code Section III.

Byron SSER 7 13 Appendix K

3. All of these welds will be subjected to a system pressure test in accordance with Section XI requirements.

Therefore, the limited Section XI ultrasonic examination, the Sec-tion III radiographic examinations performed during fabrication, and the hydrostatic test provide an acceptable level of preservice struc-tural integrity.

J. Relief Request No. NR-11 (Rev. 1), Examination Category B-D, Full Penetration Nozzle Welds in the Reactor Pressure Vessel ,

Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-D, Item B3.90 requires a 100% volumetric examination of the subject reactor pressure vessel nozzle welds as defined by Figure IWB-2500-7.

Code Relief Request: Relief is requested from performing 100% of the preservice volumetric examination on the inaccessible portions of the following four reactor pressure nozzle-to-vessel welds:

Weld Numbers RPVN-A, D, E, & H Reason for Request: The Code-required volume of the subject nozzle-to vessel welds are obstructed by the nozzle's integral extension.

The required volume was inspected for parallel reflectors from the I.D. surface of the nozzle, however, approximately 15% of the required base metal was not inspected for transverse reflectors from the vessel side.

Staff Evaluation: The staff has reviewed the above information, in-cluding the figures submitted with Relief Request NR-11 which show the areas receiving the required examination and the areas which could not be examined, and concluded that this relief request is acceptable based on the following considerations:

1. A significant percentage of the above listed welds received the preservice volumetric examination in accordance with the ASME Code Section XI. Completion of the remaining portions of the required examination is impractical and would result in undue hardship without a compensating increase in safety.

2. All of the reactor pressure vessel welds passed. volumetric exam-inations during fabrication in accordance with ASME Code Sec-tion III.

3. All of these welds will be subjected to a system pressure test in accordance with Section XI requirements.

Therefore, the limited Section XI ultrasonic examination, the Sec-tion III radiographic examinations performed during fabrication, and the hydrostatic test provide an acceptable level of preservice struc-tural integrity.

Byron SSER 7 14 Appendix K

K. Relief Request No. NR-12 (Rev. 1), Examination Category B-J, Item 89.11, Class 1 Wrought Sfainless Steel Pipe-to-Cast Stainless Steel Elbow, Pump, or Valve Welds Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-J, Item B9.11 requires a 100% surface and volumetric examina-tion on Class 1 pressure retaining welds in piping 4 inch and greater nominal pipe size as defined by Figure IWB-2500-8. In addition, Appendix III, Supplement 7, requires that ultrasonic examination sensitivity be established using I.D. notches with a depth of 10%

wall thickness.

Code Relief Request: Relief is requested from the examination sensitivity being established to resolve 10% I.D. notches. Relief is also requested from performing 100% of the Code-required volumetric examination on the following welds listed with an asterisk:

Elbow-to-Pipe Welds Line Number Weld Numbers 2RC02AA-31" J-l*, 2, 3, & 7 2RC02AB-31" J-l*, 2, 3, & 7 2RC02AC-31" J-1, 2, 3*, & 7 2RC02AD-31" J-1, 2, 3, & 7 2RC03AA-27.5" J-11 2RC03AB-27.5" J-ll 2RC03AC-27.5" J-12 2RC03AD-27.5" J-11 ,

Pump-to-Pipe Welds Line Number Weld Number 2RC03AA-27.5" J-1*

2RC03AB-27.5" J-1*

2RC03AC-27.5" J-l*

2RC03AD-27.5" J-1*

Valve-to-Fipe Welds Line Number ' Weld Number 2RC01AA-29" J-3*

2RC01AB-29" J-3*

2RC01AC-29" J-3*

2RC01AD-29" J-4*

2RC03AA-27.5" J-5* & 6*

2RC03AB-27.5" J-5* & 6*

2RC03AC-27.5" J-5* & 6*

2RC03AD-27.5" J-4* & 5*

Reason for Request: The.above listed welds join cast stainless steel components to wrought stainless steel pipe. The optimized ultrasonic technique used for the statically cast stainless steel welds will only reliably detect flaws 2S% or greater through the wall. This sensitivity is less than the 10% required by the Code.

In addition, the axial scans of welds 2RC02AB-31"/J-l and 2RC03AB-27.5"/J-5 were limited by 3% due to base metal concavity ,3 Byron SSER 7 15 Appendix K

l (J1) and a permanent support (J-5). The unwieldy characteristics of the contoured wedge search unit and the valve body contour on the 0.D. surface presented some limitations during the axial scans of the pipe-to-valve welds. Circumferential scans were limited to a short distance from the edge of the weld crown for all the pipe-to-valve welds, all the pipe-to pump welds, and three of the pipe-to-elbow welds (2RC02AA-31"/J-1, 2RC02AB-31"/J-1, and 2RC02AC-31"/J-3) because of the inability of the search unit to maintain sufficient coupling while scanning over the weld to base metal transition.

f Staff Evaluation: This relief request is acceptable for PSI based on l the following considerations:

f i

1. The subject welds received both volumetric examinations (radio-graphic) and surface examinations during fabrication in accord-ance with ASME Code Section III requirements.

~

2. The staff has determined that the Applicant has developed, within the state-of-the-art, ultrasonic equipment and procedures for an effective ultrasonic examination of the cast stainless steel welds.

3. The Code-required ultrasonic examination was completed from the wrought stainless pipe side of the weld and a "best effort" ultrasonic examination using state-of-the-art techniques was completed from the cast stainless side.

4. The staff will continue to evaluate the development of new or improved NDE procedures and will require that these enhanced procedures be made a part of the inservice examination requirements.

Based on the above, the staff concludes that the Section III fabrica-tion examinations, supplemented by the Section XI surface examination and the state-of-the-art Section XI volumetric examination, provide an acceptable level of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardsnip or unusual difficulties without a compensating increase in the level of quality and safety.

L. Relief Request No. NR-13 (Rev. 1), Examination Category C-B, Item C2.20, Pressure Retaining Class 2 Nozzle Welds in the Steam Generator and Residual Heat Exchanger Code Requirement: Section XI, Table IWC-2500-1, Examination Cate-gory C-8, Item C2.20 requires a 100% surface and volumetric examina-tion on Class 2 nozzles in vessels over 1/2 inch nominal wall thick-ness as defined by Figure IWC-2520-4. This figure requires volumetric examination of the nozzle-to-vessel weld and, for pipe sizes over 12 inches, an examination of the nozzle inner radii.

Code Relief Request: Relief is requested from performing the Code-required volumetric examination on the following 10 steam generator and residual heat exchanger nozzle welds:

Byron SSER 7 16 Appendix K

Component No. Nozzle No. Restricted Exam 2RC01BA SGN-02, 03 Inner radii 2RC01BB SGN-02, 03 Inner radii 2RC01BC SGN-02, 03 Inner radii 2RC01BD SGN-02, 03 Inner radii 2RH02AA RHXN-01, 02 Inner radii and nozzle to vessel weld Reason for Request: The nozzles listed above contain inherent geometric constraints which limit the ability to perform meaningful ultrasonic examinations. The main steam nozzles (SGN-03's) have an internal multiple venturi-type flow restrictor. This design does not have a nozzle inner radii as described in Figure IWC-2520-4. This nozzle has seven individual inner radii, corresponding to each venturi, none of which could be examined ultrasonically. The main feedwater nozzles (SGN-02's) also have an internal multiple venturi-type flow restrictor, but have a thermal sleeve in addition. This design could not be examined due to the geometry of the nozzles' internal design. The Applicant reports, however, that the increased safety margin afforded by these nozzles makes them a desirable part of plant design.

The Residual Heat Removal Heat Exchanger is approximately 7/8 inch nominal wall thickness with nozzles of 14 inch diameter and approxi-mately 3/8 inch nominal wall thickness. The configuration is best characterized as a fillet-welded nozzle using an internal reinforce-ment pad and, thereby, is not analogous to a full penetration butt welded nozzle as shown in Figure IWC-2520-4. In addition, the inner radius of the reinforcement pad would be representative of the nozzle inner radius required for inspection. The inherent geometric con-straints of the nozzle design prevent the performance of the required ultrasonic examinations of the nozzle-to-shell weld and the nozzle inner radius.

Ultrasonic examination of the above listed nozzle. inner radii is not practicable and the inner radii are not accessible to direct contact for surface examination or even remote visual examination.

However, these nozzles have been examined at the point of attachment to the vessel by radiography per ASME Section III, and by ultrasonic exaraination per ASME Section XI. In addition, a system hydrostatic test, at 125% of the design pressure, has been performed in accordance with ASME Section III.

Staff Evaluation: This relief request is acceptable for PSI based on the following coibiderations:

1. The subject weld area received radiographic examination and a hydrostatic test during fabrication in accordance with ASME Code Section III requirements. An ultrasonic examination has been performed on the nozzle-to-vessel welds per ASME Code Section XI requirements.

Byron SSER 7 17 Appendix K

l l

l

2. The staff review of the design configuration of the nozzle inner radius has concluded that the Code-required volumetric examina-tion is impractical. The staff has determined that the ASME Section III examinations demonstrate an acceptable level of  !

preservice structural integrity.

l M. Relief Request No. NR-14 (Rev. 0), Examination Categories C-C and

! C-E, Item C3.70, Integrally Welded Support Attachments on Containment Spray, Chemical and Volume Control, and Residual Heat Removal Pumps Code Requirement: Section XI, Table IWC-2500-1, Examination Cate-gories C-C and C-E, Item C3.70 requires a 100% surface examination on integrally welded support attachments on Class 2 pumps as defined by Figure IWC-2520-5.

Code Relief Request: Relief is requested from performing the Code-required surface examination on the following 8 integrally welded support attachments on Class 2 pumps:

Component Number Weld Numbers 2CS01PA CSPE-01, 02, & 03 2CV01PA CVPE-01 & 04 2RH01PA RHPE-01, 02, & 03 Reason for Request: The above listed welds connect the support lugs to the pump casings. These integrally welded attachments were examined by the manufacturer using a surface examination technique.

The Code-required surface examination was performed on three sides of each attachment, but the fourth side could not be inspected due to l the structural support members being installed. The Applicant reports that the manufacturer's surface examination results will serve as an alternate examination for the Code-required preservice surface examination.

Staff Evaluation: Paragraph IWB-2200 of ASME Code Section XI allows shcp and field examinations to serve in lieu of the on-site PSI examination provided that such examinations are conducted under con-ditions and with equipment and techniques equivalent to those which are expected to be employed for subsequent inservice examinations, ana that the shop and field examination records are or can be docu-mented and identified in a for.n consistent with those required in caragraph IWA-6000. The staff therefore concludes that if these conditions have been met, as reported by the Applicant, relief is not required.

N. Relief Request Nos. NR-15 (Rev. 1) and NR-16 (Rev. 0), Examination Category C-A, Items C1.10 and C1.20, Pressure Retaining Welds in the Chemical and Volume Control, Excess Letdown Heat Exchanger (1 weld) and Regenerative Heat Exchanger (2 welds)

Code Requirement: Section XI, Table IWC-2500-1, Examination Cate-gory C-A, Items C1.10 and C1.20 require a 100% volumetric examination-on Class 2 vessel shell and head circumferential welds as defined by Byron SSER 7 18 Appendix K

Figure IWC-2520-1. The volumetric examination of the shell cir-cumferential welds is required for welds at gross structural.discon-tinuities only.

Code Relief Request: Relief is requested from performing 100% of the Code-required preservice volumetric examination on the inac-cessible portions of the following welds:

NR Excess Letdown Heat Exchanger Component Number Weld Number 2VC01AA ELHXC-03 NR Regenerative Heat Exchanger Component Number Weld Number 2VC03AA RGXC-01 ,

2VC03AA RGXC-06 Reason for Request: NR-15: Ultrasonic examination of Weld ELHXC-03 was limited for approximately 70% of the weld length due to four branch connections welded to the vessel. The Applicant reported that ,

this weld received radiographic examination per the requirements of ASME Code Section III during fabrication and that, in addition to the limited Section XI volumetric examination, a liquid penetrant surface examination will also be performed on the subject weld.

NR-16: The circumferential scan for reflectors transverse to the weld seam was limited to approximately 90% of the weld length of Welds RGXC-01 and RGXC-06 due to the shell side nozzles. 100% of the Code-required volumetric examination was performed in the axial direction for reflectors parallel to the weld seam. The Applicant reported that these welds also received radiographic examination per the requirements of ASME Code Section III during fabrication and that, in addition to the Limited Section XI volumetric examination, a liquid penetrant surface examination will also be performed on the subject welds.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject welds received radiographic examinations during fabrication in accordance with ASME Code Section III requirements. *

2. The staff notes that a significant percentage of the Code-required Section XI volumetric examination was completed and '

that the Applicant has committed to an alternative liquid penetrant examination in addition to the limited volumetric examination. '

3. All of these welds will be subjected to a system pressure test in accordance with Section XI requirements.

Based on the above, the staff concludes that the Section III fabrica-tion examinations, supplemented by the limited Section XI volumetric examination and the alternate liquid penetrant examination, provide Byron SSER 7 19 Appendix K

I 1

an acceptable level of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

O. ' Relief Request No. NR-17 (Rev. 0), Examination Category B-J, Item B9.11, Pressure Retaining Welds in Class 1 Piping

)

j Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-J, Item B9.11 requires a 100% surface and volumetric examina-tion on Class 1 pressure retaining welds in piping 4 inch and greater nominal pipe size as defined by Figure IWB-2500-8.

Code Relief Request: Relief is requested from performing 100% of the Code-required volumetric examination on Pressurizer Line No. 2RY01AA-4", Weld No. J-3.

Reason for Request: The axial scan for reflectors parallel to the weld seam was limited to approximately 82% of the weld length due to a sockolet connection. The circumferential scan for reflectors transverse to the weld seam was completed. As an alternative to the required ultrasonic examination for reflectors transverse to the weld seam, the Applicant performed a calibrated 0 degree longitudinal wave examination of the missed area of the weld. In addition, the subject weld received a radiographic examination in accordance with ASME Code Section III requirements during fabrication.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The subject weld received radiographic examinations during fabrication in accordance with ASME Code Section III requirements.

2. The staff notes that a significant percentage of the Code-required Section XI voltmetric. examination was completed and that the Applicant committed to an alternative 0 longitudinal wave examination of the missed area of the weld.

3. The subject welds will undergo a system pressure. test in ac-cordance with Section XI requirements.

Based on the abeve, the staff concludes that the Section'III fabri--

cation examination, supplemented by the limited Section XI volumetric examination, the alternate volumetric examination of the missed area, and the Code-required surface examination provides an' acceptable level of preservice structural integrity and that compliance with tne-specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

Byron SSER 7 20 Appendix K

~. - - _ - _ _ _ - _ _ _ _ _ _ _ _

P. Relief Request No. NR-Note 5 (Rev. 0), Examination Category B-J, Item B9.11, Circumferential Pressure Retaining Welds in Safety injection System Class 1 Piping Code Requirement: Section XI, Table IWB-2500-1, Examination Cate-gory B-J, Item 89.11 requires a 100% volumetric and surface exami-nation on circumferential pressure retaining welds in Class 1 piping of 4 inch and greater nominal pipe size as defined by Figure IWB-2500-8.

Code Relief Request: Relief is requested from performing the Code-required volumetric examination on inaccessible portions on the following four welds in the Safety Injection System:

% of Weld Length Line No. Weld No. Not Examined 2SIO9BA-10" J-18 6.29%

2SIO9BA-10" J-27 6.29%.

2SIO9BD-10" J-1 8.29%

2SIO9BD-10" J-25 6.66%

Reason for Request: The above listed welds have either a gamma plug or a branch connection adjacent to the weld which prohibits examination of 100% of the Code-required volume.- The Applicant reports that 100% of the required weld volume was examined by a circumferential scan. However, a small percentage of each weld (in no case greater than 8.29%) was not examinable by an axial half-v path or full-v path scan.

In addition to the Section XI PSI surface examination-(liquid pene-trant) and visual examination (leak test), these welds also received the ASME Code Section III radiographic examination performed during-fabrication.

Staff Evaluation: This relief request is acceptable for PSI based on the following considerations:

1. The staff notes that a significant percentage of the Code-reqctred volumetric examination was completed and that all of the subject welds received radiographic examination during fabrication in accordance with ASME Code Section III requirements.

2. Complete examinations which met the requirements of ASME Code Section XI were performed on similar welds using the same inspection techniques, equipment, and procedures as these partially inspected welds. Since these welds will see the same operating and environmental conditions as the inspected welds, a reasonable e.surance of the structural integr'ity of the welds for which relief is requested has been attained.

Based on the above, the staff concludes that the Section III radio-graphic examination, the Section XI surface examination, and the limited Section XI volumetric examination provide an acceptable level Byron SSER 7 21 Appendix K

of preservice structural integrity and that compliance with the specific requirements of Section XI would result in hardship or unusual difficulties without a compensating increase in the level of quality and safety.

IV. CONCLUSIONS Based on the foregoing, pursuant to 10 CFR 50.55a(a)(3), the staff has determined that certain Section XI required preservice examinations are impractical. The Applicant has demonstrated that either (i) the proposed alternatives would provide an acceptable level of quality and safety or (ii) compliance with the requirements would result in hardships or unusual difficulties without a compensating increase in the level of quality and safety.

The staff technical evaluation has not identified any practical method by which the existing Byron Station Unit 2 can meet all the specific preser-vice inspection requirements of Section XI of the ASME Code. Compliance with all the exact Section XI required inspections would delay the startup of the plant in order to redesign a significant number of plant systems, obtain sufficient replacement components, install the new components, and repeat the preservice examination of these components. Examples of components that would require redesign to meet the specific preservice examination provisions are: the reactor pressure vessel, the regenerative and letdown heat exchangers, the steam generators, and a number of the piping and component support systems. Even after the redesign efforts, complete compliance with the preservice examination requirements probably could not be achieved. However, the.as-built structural integrity of the existing primary pressure boundary has already been establ,ished by the construction code fabrication examinations.

l Based on the staff review and evaluation, it is concluded that the public interest is not served by imposing certain provisions of Section XI of the ASME Code that have been determined to be impractical. Pursuant to 10 CFR '

50.55a(a)(3), relief is allowed from these requirements which are imprac-tical to implement.

Byron SSER 7 22 Appendix K

u 5 Nuca AoEausATo , covM.55loN , t E o T Nuv e E m ., ,, , ,o c ,,, v., e, . ., ,

,a,c,,,oaM m NUD.EG-0876 BIBLIOGRAPHIC DATA SHEET Supplement i .7

> u.n.a. j 3 TITLE AND SuaTITL 4 RECIPIENT 5 ACCE ON NUMBE R Safety Eva ation Report related to the operation of /

Byron Stat n, Units 1 and 2 *

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• o MONfM gi YEAR NOVE@ER 1986 6 AUTHORisi i p A T E R f 0R T 155uE D MONTop VEAR NpYEMBER 1986 9 PROJECT < T ASE ' WORK UNIT NUMBER 8 PERFORMING ORGANIZATION NAME AND M ' NG ADDRESS fiarsede /,p Codel Division of pWR Licensi A /

Office of Nuclear Reactor Regulation . io "~ NuMaa U. S. Nuclear Regulatory Cohpission /

Washington, D. C. 2G555 /

II SPON50RsNG ORG ANIZ ATtON N AME AND M AILING ADDRESS flakar l@ Codel 12s TYPE OF REPORY Same as 8. above Technical I?n PERsOO COVE RED f#arres, e caress February 1985 - November 1986 13 SUPPLEMENT ARY NOTES Docket Nos. 50-454 and 455 14 All5 TRACT I200 words or arssi Supplement No. 7 to the Safety Evaluation Repgrt elated to Commonwealth Edison Company's application for licenses to operate the ByrofStat n, Units 1 and 2, located in Rockvale Township, Ogle County, Illinois, has been pr# pared the Office of Nuclear Reactor RegulationoftheU.S.NuclearRegulatoryfommission.

t Because of the favorable resolution of the items discuss .in this report, the staff concludes that the Byron Station, Unit 2[can be operated b the licensee at power levels not to exceed 5% without endangering th[ health and safety the public, f

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