ML111930423

Request for Regulatory Conference or Public Management Meeting

ML111930423
Person / Time
Site:	Browns Ferry
Issue date:	06/02/2011
From:	Swafford P Tennessee Valley Authority
To:	Mccree V Region 2 Administrator
References
IR-10-005
Download: ML111930423 (103)

Text

Tennessee Valley Authority A 1101 Market Street, LP 3R Chattanooga, Tennessee 37402 Preston 0. Swafford Executive Vice President and Chief Nuclear Officer June 2, 2011 10 CFR 2.201 Mr. Victor M. McCree Regional Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Avenue, NE, Suite 1200 Atlanta, Georgia 30303-1 257 Browns Ferry Nuclear Plant, Unit 1 Facility Operating License No. DPR-33 NRC Docket No. 50-259

Subject:

Request for Regulatory Conference or Public Management Meeting

References:

1) Letter from NRC to TVA, NRC Report 05000259/2010005, 05000260/2010005, and 05000296/2010005; Preliminary Greater Than Green Finding Browns Ferry Nuclear Plant, dated March 2, 2011

2) Letter from NRC to TVA, Final Significance Determination of a Red Finding, Notice of Violation, and Assessment Follow-up Letter (NRC Inspection Report No. 05000259/2011008) Browns Ferry Nuclear Plant, dated May 9, 2011 Reference 1 identified that the Browns Ferry Nuclear Plant (BFN), Unit 1 low pressure coolant injection/residual heat removal (RHR) outboard injection valve 1-FCV-74-66 failed to open on October 23, 2010, when operators attempted to place RHR Shutdown Cooling loop II in service to support the Unit 1 cycle eight refueling outage activities. The NRC letter identified the performance deficiency as the failure to establish adequate design control and perform adequate maintenance on the valve,

U.S. Nuclear Regulatory Commission June 2,2011 Page 2 which resulted in the valve being left in a significantly degraded condition and RHR loop II unable to fulfill its safety function.

Tennessee Valley Authority (WA) attended a Regulatory Conference on April 4, 2011, to discuss TVAs views on the issue of the performance deficiency as well as other issues. During this meeting, WA provided information, contained in the enclosed presentation (Enclosure 1), that detailed our findings with regard to the performance deficiency based on the results of our root cause analysis (RCA) of the valve failure.

As can be seen in the enclosed presentation, WA explained that the valve failure was due to an original manufacturing defect (i.e., undersized threads) and not inadequate design control or inadequate maintenance on the part of WA. In-service Testing (1ST) of valve 1 -FCV-74-66 in accordance with the applicable American Society of Mechanical Engineers Code for Operation and Maintenance of Nuclear Power Plants (i.e., CM Code), as reflected in the BEN 1ST Program, was not discussed in WAs April 4, 2011 presentation and the NRCs explanation of the performance deficiency in Reference 1 did not include any discussion of the 1ST Program.

On May 9, 2011, the NRC issued its final significance determination letter (Reference 2). Given the results of the TVA RCA, and that the 1ST Program was not explicitly identified as the subject of the original performance deficiency stated in Reference 1, the BEN 1ST Program was not addressed at the Regulatory Conference. However, the NRC stated in Reference 2 its conclusion that WAs 1ST Program inadequacy represents a performance deficiency.

WA takes this issue regarding the 1ST Program very seriously and is taking actions to address any potential noncompliance. TVA has entered this issue into its Corrective Action Program and will be performing an RCA. WA has also hired industry-recognized 1ST experts as well as the principal author of the NRCs NUREG-1482, Guidelines for Inservice Testing at Nuclear Power Plants, Revision 1, to review BENs 1ST Program and its implementation for compliance and performance issues.

TVA expects that additional corrective action may be identified once the RCA is completed and approved.

Because WA did not have an opportunity to discuss the BFN 1ST Program during the April 4, 2011 Regulatory Conference and for the additional reasons delineated below, WA requests that another Regulatory Conference be held to allow WA to discuss its views on the performance deficiency identified in the May 9, 2011 NRC letter. If our request for another Regulatory Conference cannot be granted, WA requests a public management meeting with the NRC so that we can present pertinent information not previously provided regarding this performance deficiency. WA further requests that the 30-day period from the May 9, 2011 letter for responding to the Notice of Violation and to appeal the significance determination be held in abeyance pending a Regulatory Conference or public management meeting.

U.S. Nuclear Regulatory Commission June 2,2011 Page 3 During the period leading up to the April 4, 2011 Regulatory Conference, and for a number of weeks after the Regulatory Conference, WA responded to 52 questions from the NRC. Of those 52 questions, WA received only one question that concerned the BFN 1ST Program. Specifically, Question No. 2 of the third round of NRC questions dealt with Section ISTC 4.2 of the applicable CM Code. TVA provided a written answer on April 14, 2011. No further questions or comments on this issue were received from the NRC until Friday, April 29, 2011, when TVA was informed by NRC Region II management during a conference call that the BFN 1ST Program was not in compliance with the applicable OM Code, specifically Section ISTC 4.1. During that conference call, NRC Region II management also pointed out the need for WA to review the BEN 1ST Program for similar instances of noncompliance. At that time, WA stated that it would enter the issue into its Corrective Action Program.

Before taking additional time to research this issue, TVA quickly provided a written description of how the BFN 1ST Program complies with Section ISTC 4.1 of the applicable CM Code to the NRC on the following Monday, May 2, 2011 (Enclosure 2),

and held a conference call to discuss this information with representatives of the NRC on Tuesday, May 3, 2011. No further questions or comments regarding this issue were received from the NRC until the following Monday, May 9, 2011, when the NRC issued its final determination letter identifying the inadequacy of the BFN 1ST Program as the performance deficiency. While the NRC may have determined that it has all the information it needed to reach this conclusion, WA has assembled considerably more information regarding the BEN 1ST Program as well as pertinent industry information than was provided to the NRC in writing or verbally on May 2 and 3, 2011.

Accordingly, WA considers that it would be in the best interest of both the NRC and WA to present this new information at a Regulatory Conference or public management meeting. WA considers that the additional information is essential for an accurate assessment of the regulatory issues related to the failure of valve 1 -FCV 74-66 and the outcome of the NRCs deliberations, as well as the adequacy of the BEN 1ST Program more broadly.

Since the statement of the performance deficiency changed significantly, then as a matter of law and fairness, the NRC must give notice of the change and an opportunity to address the new performance deficiency prior to the NRC making its final determination. It is well established that a licensee facing a potential enforcement action must be given notice of the alleged deficiency and afforded an opportunity to be heard before the agency finalizes the action. For instance, in Board of Regents v.

Roth, 408 U.S. 564, 569-70, and 573 (1972) the Supreme Court held that procedural due process requires adequate notice and an opportunity to be heard where governmental action might seriously damage reputation. In a case involving WA in particular, the NRC has stated, [bjasic principles of fairness. . . require that the licensee in an enforcement action know the bases underlying the Staffs finding(s) of violation. Tennessee Valley Authority (Watts Bar Nuclear Plant, Unit 1; Sequoyah Nuclear Plant, Units I and 2; Browns Ferry Nuclear Plant, Units 1, 2, and 3), CLI 24, 60 NRC 160, 202 (2004). The requirement for prior notice and an opportunity to

U.S. Nuclear Regulatory Commission June 2, 2011 Page 4 respond holds true if the agency afforded a prior opportunity, but subsequently changes or amends the bases for the violation. See CLI-04-24, 60 NRC at 203, 205.

Manual Chapter 0609, 2.d.2(c), states in this regard that [t]he Preliminary Determination letter will . . . provide sufficient information to allow the licensee to reasonably understand the staffs position and allow them to develop further information, as needed.. [and] must clearly identify to the licensee the basis for the staffs preliminary significance determination . . . Manual Chapter 0609, 2.a(1), also contemplates that the statement of the performance deficiency will be clearly established prior to the Regulatory Conference.

Therefore, for the reasons stated above, TVA respectfully requests that another Regulatory Conference or a public management meeting be held to discuss the performance deficiency documented in the Reference 2 letter. WA further requests that the 30-day period from the May 9, 2011 letter for responding to the Notice of Violation and to appeal the significance determination be held in abeyance pending a Regulatory Conference or public management meeting.

There are no new regulatory commitments as a result of this correspondence. Should you have any questions concerning this submittal, please contact Rod M. Krich at (423) 751-3628.

Respectfully,

• L Preston D. Swafford

Enclosures:

1) April 4, 2011 Regulatory Conference WA Presentation

2) Description of Browns Ferry Nuclear Plant 1ST Program Compliance with OM Code ISTC 4.1 cc (Enclosures):

NRC Document Control Desk NRC Director, Office of Enforcement NRC Senior Resident Inspector Browns Ferry Nuclear Plant

ENCLOSURE I Browns Ferry Nuclear Plant Unit I April 4, 2011 Regulatory Conference TVA Presentation

TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT, UNIT I Regulatory Conference Low Pressure Coolant Injection Valve I -FCV-74-66 Atlanta, Georgia April 4, 2011

Agenda

• Introduction Preston Swafford

• Background Rob Whalen

• Root Cause/Engineering Analyses Rob Whalen

• Significance Determination James Emens

• Performance Deficiency James Emens

• Corrective Actions Rob Whalen

• Long-Term Fire Strategies Rob Whalen

• Closing Remarks Preston Swafford 2

Introduction

• On October 23, 2010, Residual Heat Removal (RHR) Loop II Injection Valve, 1-FCV-74-66, did not pass flow while operations was aligning shutdown cooling at the beginning of a refueling outage

• Disassembly of the valve revealed the disc separated from the stem and lodged in the seat

• The disc separation from the stem resulted from an original manufacturing defect, undersized threads in the disc skirt/disc assembly Preliminary root cause was thought to be lack of skirt key caused disc separation, which was basis for apparent violation Final root cause shows that the cause of the disc separation is not a licensee performance deficiency

• Based on results of extensive forensic examination, analysis, and laboratory mockup tests, we have shown conclusively that the disc would have released within an acceptable time with an RHR pump running (due to friction reduction from pressure pulsations), allowing the valve to provide functional flow

• TVA is taking steps to significantly reduce risk due to fire at the Browns Ferry Nuclear Plant Reducing instances of Self-Induced Station Blackout (SISBO) actions Accelerating plant changes identified as part of NFPA 805 transition Changing the Safe Shutdown Instructions (SSIs) to allow the use of alternate shutdown paths 3

Background

Assessment Approach

• Root cause team was assembled including site and corporate expertise

• Comprehensive forensics were performed to determine root cause Southwest Research Laboratory (weld examinations)

Westinghouse Laboratory (valve component forensics)

Structural Integrity (thread strength analysis, sensitivity study)

Independent Burns & Roe metallurgist (aggregate review of forensics reports)

• Performance Improvement International (P11) performed detailed analysis and laboratory testing to determine the valves capability to function in its as-found state of separation 4

Background

Timeline Timeline 1968 Walworth valve purchased as an assembly from General Electric for construction of Browns Ferry Nuclear Plant (BFN),

Uniti December 1974 Seationhloosening of discs due to flow-induced vibration 1983 Installed modified disc with V notch trim (skirt reused)

June 2006 Replaced stem prior to BFN, Unit 1, restart due to observed stem nut damage 2007 to October 2010 Satisfactory quarterly valve stroke times based on limit switch inccation, not torque March 2009 Initiated shutdown cooling passing 7,000 gpm flow through valve October 2010 InWated shutdown cooling with no observed flow (terminated pump operation after 110 seconds) 5

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Root Cause Disc Separation Forensics (continued)

Forensic examination found axial damage on the threaded connection between disc and skirt Optical Comparator Image of Damaged Threads 10

Root Cause Results

• The manufacturer supplied an undersized skirt to disc connection male thread diameter under a 10 CFR 50, Appendix B program (Part 21 report submitted via revision to Licensee Event Report on April 1, 2011)

• The valve was purchased as an assembly that would not be taken apart to perform receipt inspections Undersized skirt thread diameter caused the threaded connection between disc and skirt to be 38 percent of design strength Pressure on skirt/stem side of disc due to downstream check valve leakage and surveillance testing configuration Tack welds designed to prevent rotational, not axial separation Stem and skirt pulled away from disc in open direction

• Disc was initially separated from stem/skirt before November 2008, based on Motor-Operated Valve Actuator Testing (MOVAT) data review and forensic examination This indicates that the valve passed normal shutdown cooling flow in a separated condition in March 2009 11

Root Cause Summary

• NRC Inspection Report 2010-05 noted.. the licensees failure to establish adequate design control and perform adequate maintenance on the Unit I outboard LPCI injection valve, 1-FCV-74-66, which resulted in the valve being left in a significantly degraded condition and RHR loop II unable to fulfill its safety function, was a performance deficiency.

• Root cause analysis determined that no licensee performance deficiency existed No reasonable basis existed to examine threads and identify the undersized thread condition

• Corrective actions discussed later in this presentation

• No other root or contributing cause was identified

• We will show that the valve, while being degraded, would have performed its fire safe shutdown safety function 1:2

Functionality Analysis

• Industry research shows that pump-induced vibrations dramatically reduce frictional forces

• Idaho National Laboratory research shows static coefficient of friction behavior for stellite valve seating surfaces 74-66 valve disc contacting surface immediately after removal (11/2/10) bcttorr cf 15 chanftr 13

Analysis of Force Balance and Coefficient of Friction Significance

• A two-dimensional static analysis was performed to determine the normal force and coefficient of friction

• The calculated coefficient of friction was well aligned with the method discussed in Idaho National Laboratory stellite aging research 1

• An energy balance approach was used to determine the energy applied by the disc to the valve body and associated deflection from each stem stroke 1

Idaho National Engineering and Environmental Laboratory Document, INEEL/EXT-02-01021,Results of NRC-Sponsored Stellite 6 Aging and Friction Testing, October 2002. 14

Analysis of Force Balance and Coefficient of Friction Significance (continued)

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Analysis of Force Balance and Coefficient of Friction Significance (continued)

Lift Force (Kips) Friction Force (Kips) Axial Unseating Force (Kips) 700 600 500 400 Force 300

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Analysis of Force Balance and Coefficient of Friction Significance (continued)

Appendix R (limiting scenario) Percent Friction Change Needed 20.0 18.0 16.0 14.0 12.0 COF % change 10.0 8.0 6.0 4.0 2.0 0.0 0 2 4 6 8 10 12 14 16 Strokes 17

Analysis of Force Balance and Coefficient of Friction Significance (continued)

A finite element analysis showed:

• Close correlation with the simplified Roark stiffness used in the work energy approach

• Slight plastic deformation limited the axial deflection suggesting the simplified linear elastic approach produces a conservative frictional force 18

Analysis of Force Balance and Coefficient of Friction Significance (continued) 19

Vibration Effect on Coefficient of Friction Theory

• A very similar experiment conducted by researchers concludes that vibrations greatly reduce the coefficient of friction.

• The coefficient of friction is most reduced by vibration frequency and amplitude, surface roughness, speed, and quadratic terms of the surface roughness and speed.

DESIGN-EXPERT Plot Interaction Graph CoF B: Amp 0.56 X = A: Vib V B: Amp.

• 0- -1.000 0.41 0+ 1.000 Coded Factors Image taken from The Effect if Frequency and C: Roug. = 1.000 0: Speed 1.000 Amplitude of Vibration on the Coefficient of Friction 0.27 Image taken from The Effect if Frequency and Amplitude for Metals by Jamil Abdo and Mahmoud Tahat, of Vibration on the Coefficient of Friction for Metal by Issue 7, Volume 3, July2008. ISSN 1991-8 747.

Jamil Abdo and Mahmoud Tahat, Issue 7, Volume 3, July 2008. ISSN 1991-8 74 7.

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-10 -05 0.6 A: Vib = 0.3 13 0.142A 0.0356B 0.0458C Steel C1020 with a surface 0.12 1OD 0.0822C + 0.0561D 2 2 roughness and speed of 2.5 pm where and 1.2 mIs; respectively p: Coefficient of Friction A: Vibration Frequency B: Vibration Amplitude C: Surface Roughness D: Speed 20

Vibration Effect on Coefficient of Friction Testing

• The valve disc was compressed into the valve body by a hydraulic press.

• Strain gauges were positioned on the outside of the valve body.

• Vibrations were applied to the disc modeled on the plant configuration.

21

Vibration Effect on Coefficient of Friction Testing (continued)

• Pressure amplitude and frequency data were measured at Browns Ferry Nuclear Plant using a high-speed recorder with the RHR pump running

• Fast-Fourier Transform was performed and utilized in laboratory mockup testing 22

Vibration Effect on Coefficient of Friction Testing (continued)

• Multiple laboratory mockup tests concluded:

During multiple valve stroke surveillances, the free end of the stem hammered the disc into the seat Disc loosens promptly with seats in clean unoxidized condition Disc loosens within seven minutes with seating surfaces in roughened condition System differential pressure would lift the disc, allowing proper flow as required by Safe Shutdown Analysis (SSA) for Appendix R fire (highest risk event) 23

Vibration Effect on Coefficient of Friction Testing (continued)

Review of MOVAT testing data, combined with stellite aging research, strongly indicates that the disc separated prior to November 2008 PrH l:1r4olo I:IC:O1 PM l2l46.

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Vibration Effect on Coefficient of Friction Testing (continued)

• Analysis concludes that four impacts of the separated stem into the disc accomplishes 94 percent of the maximum possible unseating force

• Review of plant data shows that a minimum of four impacts occurred before March 2009 when the disc lifted from the seat (operated as a check valve)

• MOVAT data (supported by stellite aging research, forensics, and the fact that unseating trace is evident following repair) indicates that the disc separated prior to November 2008

• This is strong supporting evidence that the valve loosened and operated as a check valve in March 2009 25

Root Cause/Engineering Analyses Conclusions

• Root cause of separation was clearly the undersized disc to skirt threads This was a manufacturing deficiency and has been reported under 10 CFR 21 No reasonable basis existed to examine threads and identify the undersized thread condition No other root or contributing cause was identified There was no licensee performance deficiency

• The disc would have released and provided proper flow within seven minutes, fully supporting the limiting Appendix R fire event Industry experts performed extensive analysis and laboratory testing As a result, P11 has very high confidence in the credibility of its findings.

This confidence is supported by the conclusion that valve was functional in March 2009, even though the disc was separated from the stem 1

P erformance Improvement International Report, TVA Browns Ferry Nuclear Plant, Analysis of the October 23, 2010, BFN-1-FCV-076-066 Shutdown Cooling Event, dated March 22, 2011.

26

Significance Determination TVA performed significance determination using Inspection Manual Chapter 0609, Appendix M versus Appendix F

• Appendix F does not allow quantification of defense-in-depth features

• NRC significance determination using Appendix F dominated by fire probabilistic risk assessment assumptions and conservatisms Recognized by industry as overestimating baseline risk Calculated fire risk conservative by factor of 5 to 10, or higher Results do not conform with operating experience

• Associated RHR Loop II would have been able to fulfill fire safe shutdown function Conclusion

• Appendix M methodology is appropriate for evaluating risk associated with failure of valve 1 -FCV-74-66

• We will show that the results of Significance Determination Process evaluation should conclude that this situation is of Very Low Safety Significance 27

Significance Determination (continued)

Defense-in-depth associated with fire protection and fire safe shutdown

• Administrative controls to prevent fires

• Fire Protection Systems and features (including walkdowns and fire watches) to detect rapidly, control, and extinguish promptly any fires Fire detection Fire suppression Fire barriers between fire areas Dedicated onsite fire department Weekly fire operations walkdowns Hourly roving fire watches Normal personnel traffic 28

Significance Determination (continued)

Ability of valve I -FCV-74-66 to fulfill fire safe shutdown function

• Based on results of testing and analyses

• Results indicate valve disc freed within seven minutes Would perform as check valve Injection flow would be established

• Passing flow within seven-minute time period fully complies with 10 CFR 50 Appendix R SSIs and the SSA

• Operators would continue to run RHR pump to establish flow during an Appendix R event Consistent with SSIs caution note to prevent exceeding pump design temperature limits 29

Significance Determination (continued)

Alternate flow paths available to support fire safe shutdown if valve I -FCV-74-66 failed to pass flow Makeup to support fire safe shutdown (not specified in SSIs)

Condensate System (except for Turbine Building fire areas)

Core Spray System High Pressure Coolant Injection System and/or Reactor Core Isolation Cooling System

• Long-term decay heat removal available RHR Suppression Pool Cooling 30

Significance Determination (continued)

Defense-in-depth associated with design basis accidents if valve 1-FCV-74-66 failed to pass flow

• Remaining Emergency Core Cooling System subsystems available LPCI associated with RHR Loop I Two Core Spray Subsystems High Pressure Coolant Injection System Automatic Depressurization System

• Long-term decay heat removal available RHR Suppression Pool Cooling Significance determination shows that, regardless of whether valve 1-FCV-74-66 is assumed to pass flow or not, this condition was of Very Low Safety Significance 31

Performance Deficiency Root cause of valve failure was manufacturing defect

• Preliminary cause of valve failure, identified as performance deficiency, was subsequently determined to not be the root cause

• Original manufacturers design requirements not met Undersized disc skirt threads at disc connection

• Disc skirt part of original valve assembly installed during construction in 1968-69 timeframe

• No receipt inspection of a valve assembly of this nature and classification required Manufacturer provided certification documentation 32

Performance Deficiency (continued)

• Reviewed valve maintenance history Valve skirt part of original valve assembly and not replaced prior to failure No work performed that required measuring/confirming disc skirt thread size

• Cause is a manufacturing defect Not reasonably within TVA ability to foresee and correct to prevent valve failure

• Condition should not be considered a licensee performance deficiency 33

Corrective Actions

• Short-term corrective actions Repaired valve I -FCV-74-66 Verified discs attached in all like valves, with tack welds intact and in good condition Implemented controls limiting back-pressure on valves

• Long-term corrective actions Restore or repair valve skirts to address potential undersized thread issue 34

Long-Term Fire Strategies

• Operator Manual Action (OMA) reduction

• SSI revisions

• Proactive installation of NFPA 805 transition modifications

• Driving down risk impacts utilizing NRC risk methodology

SSI Revision Goals

• Reduce plant risk in serious fire events Reduce instances of SISBO actions

• Add branching steps to SSIs Entry conditions would remain unchanged Operator would be directed to use alternate safe shutdown methods if the SSI cannot be executed

• Alternate paths include Condensate System, Core Spray System, High Pressure Coolant Injection System, and/or Reactor Core Isolation Cooling System 36

SSI Revision Goals (continued)

• Address Appendix R compliance Reduce (but not eliminate) number of OMAs

• Reduce complexity of SSIs

• Support of NFPA 805 implementation Implement post-transition shutdown strategies and procedures in advance Implement modifications proactively 37

SSI Revision Plan Phase I Turbine Building and Intake

• Complete most risk sensitive area (planned for July 2011)

• Use upgraded SSA currently in progress for NFPA 805 transition

• Risk map (using conservative NRC approach) shows significant OMA issue risk reduction in July 2011

• Independent team established to execute this in parallel with NFPA 805 transition

• Utilizes plant recently completed modifications Turbine Building/Intake Structure fire barrier Cable tray covers Incipient detection 38

SSI Revision Plan (continued)

Phase I Turbine Building Specifics

• New fire barrier completed Separate Turbine Building from intake 3-hour rated Allows a separate SSA for the Turbine Building One train free of fire damage

• Symptom-based procedure Essentially eliminates SISBO for this fire area Allows use of available equipment Additional precautions and instructions specific to the fire area Protection of the credited train 39

SSI Revision Plan (Current Schedule)

(continued)

First Phase (Turbine Building Fire Area Separation: 25 and 26)

I I 04/04/2011 07/29/2011 Second Phase (Fire Areas with CDF> 1E-6: 5, 6, 3-3, 3-4, 1-5, 2-3, 9, 12. 22, 23) 08/08/2011 12/30/201 1 Third Phase of SSI Revision (All Fire Areas Between LAR and 6 months afer SER Date, Assume 18 month NRC review)

I I I I I I I I I 03/02/2012 06/02/2012 09/02/2012 12/02/2012 03/02/2013 06102/2013 09/02/2013 12102/2013 03/02/2014 01102/2012 03/28/2014 40

Extrapolated SDP Risk Estimates (Current Schedule)

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.-.Extrapolated SDP Risk for Unit 1 2.29E-05 1 .85E-05 1 .67E-05 1 .26E-05 6.30E-06 5.68E-06 2.89E-06 1 .OOE-06 2.13E-05 1.85E-05 1.70E-05 1.38E-05 6.88E-066.49E-06 3.76E-06 .9Ez9 Extrapolated SDP Risk for Unit 3 1 .66E-05 1.35E-05 1 .33E-05 1. 12 E-05 5.58E-06 5.15E-06 1.16E-06 1.OOE-06 41

SSI Revision Plan (continued)

Phases II and Ill Additional High Risk Fire Areas

• Utilize advantages gained from upgraded SSA

• Improve shutdown strategy and procedures, if possible under Appendix R deterministic requirements

• Plant modifications, if feasible

• Will require completion of cable routing and analysis for affected areas 42

SSI Revision Team Approach

• Team managed from TVA corporate offices with work being performed in Chattanooga and vendor locations

• Team composition Browns Ferry Nuclear Plant operations procedure writer and operations trainer TVA corporate engineering manager for technical direction and oversight Vendor engineers (2) for SSA support Vendor engineers (3) for engineering design change development and support 43

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Closing Remarks TVA has shown conclusively that:

• There was no licensee performance deficiency

• LPCI valve 1-FCV-74-66 would have performed its safety function under Appendix R fire conditions

• Significance determination results in a finding of Very Low Safety Significance TVA has also shown how accelerating some actions from the transition to NFPA 805 will quickly reduce fire risk at the Browns Ferry Nuclear Plant

• Changing SSls to allow use of alternate safe shutdown paths

• Reducing the number of times that SISBO actions are taken

• Completed plant modifications such as incipient detection and cable tray covers 45

ENCLOSURE 2 Browns Ferry Nuclear Plant Unit I Description of Browns Ferry Nuclear Plant 1ST Program Compliance with OM Code ISTC 4.1

• Inservice Testing.. (1ST) of FCVJ4-52 and FCV.7466 Question:

On the afternoon of Friday 04/29/2011, the NRC questioned Browns Ferry Nuclear Plant (BEN) Inservice Testing (1ST) Program compliance with American Society of Mechanical Engineers (ASME) Operations and Maintenance (OM) Code, Subsection ISTC 4.1 (reference SR 362156). This document was written to establish the basis for compliance.

TVA Response:

During the Unit 1 Cycle 8 refueling outage on October 23, 2010, 1-ECV-74-66 did not open while attempting to place RHR Loop 2 in service. Lights indicated open but pump discharge pressure was at maximum and no flow was indicated in the loop. This condition and the root cause are documented in PER 271338.

The BEN 1ST Program is implemented in accordance with ASME OM Code 1995 Edition with 1996 Addenda (1995 OMa 1996). 1995 OMa 1996, Subsection ISTC 4.1, specifies the requirements for valve position verification as follows:

Valves with remote position indicators shall be obseived locally at least once eve,y 2 years to verify that valve operation is accurately indicated. Where practicable, this local observation should be supplemented by other indications such as use of flowmeters or other suitable instrumentation to verify obturator position. These observations need not be concurrent. Where local observation is not possible, other indications shall be used for verification of valve operation.

The BEN 1ST Program is described in BEN Technical Instruction (TI) 0-Tl-362, lnservice Testing of Pumps and Valves. This TI lists in tabular form the ASME Class, Category, Normal and Safety Position, Surveillance Procedures, and Surveillance Frequencies.

The configuration and testing of valves 1-FCV-74-52 and 1-FCV-74-66 (FCV-74-52/66) is typical for all three Units. These valves are classified as Category B valves with an active safety function. FCV-74-52/66 are normally open valves with an open safety position; however, these valves may be throttled and are therefore considered active in the 1ST Program. In accordance with the Code ISTC Table 3.6-1, Category B, active valves require exercising, stroke timing, and position indication verification. Exercising and stroke timing is conducted quarterly and position indication verification is conducted once per 2 years. In addition, remote position indication verification includes direct observation of stem movement.

NUREG-1482, Revision 1, Guideline for Inservice Testing at Nuclear Power Plants, was used to develop the BEN 1ST Program. No specific additional guidance is provided for verification of remote position indication other than Section 4.2.7, Verification of Remote Position Indication for Valves by Methods Other Direct Observation. NRC recommendations related to this section contain some guidance applicable to ECV-74-52/66:

Page 1 of 5

Inservice Testing (IST of FCV.74-52 and FCV-74-66 For certain types of valves that can be observed locally, but for which stem travel does not ensure that the stem is attached to the disk, the local observation should be supplemented by observing an operating parameter as required by Subsections ISTC 4.1, 4.2, and 4.5.

Note that ISTC Subsections 4.2 and 4.5 are not applicable to remote position indication as described by Subsection 4.1.

Neither the CM Code nor NUREG-1482 requires the use of supplemental parameters in conjunction with position verification. ASME CM Code Interpretation 99-9 confirms that it is not the intent of the ASME CM Code to require observation of stem movement to be supplemented by other indications to verify obturator position regardless of practicability.

Interpretation: 99-9

Subject:

ASME/ANSI OMa-1988, Part 10, para. 4.1 and equivalent subsequent editions and addenda Date Issued: December 23, 1998 File: OMI-98-20 Question: If it is practicable, is it a requirement of OMa-1988, Part 10, para. 4.1 that local observation of stem movement be supplemented by other indication to verify obturator position?

Reply: No.

Contact with an CM Code committee member identified that the committee did not intend supplemental verification be performed on all 1ST valves during position indication testing. This position is consistent with CM Code and NUREG guidance.

Therefore, supplemental verification of the position of valves FCV-74-52 and FCV-74-66 has not been required for implementation of the CM Code at BEN, based on the CM Code itself, NUREG-1 482, and Code Interpretation 99-9.

However, even though supplemental verification is not a Code requirement, it should be noted that exercise of CKV-74-68 and CKV-74-54 during performance of the surveillance procedures identified in Table 3 (see References below) provides indication that ECV 52 and ECV-74-66 are in the open position and passing flow. If flow was not observed during performance of these surveillance procedures, the surveillance acceptance criteria would not be met and investigation would determine any blockage of ECV-74-52 or FCV-74-66.

The requirements of the ASME CM Code are fulfilled through O-TI-362 and the surveillance procedures listed in Appendices H, I, and J of O-TI-362. In accordance with ISTC Table 3.6-1, Category B, active valves require exercising and position indication verification.

Page 2 of 5

Inservice Testing (LST) Gf FCV-74-52 arid FCV-74-6&

Exercising of FCV-74-52/66 is conducted quarterly in accordance with the surveillance procedures listed in Table 1 (see References below). Position indication is conducted once every two years in accordance with the procedures listed in Table 2 (see References below).

Recirc. Loop A SHV-74-69 FCV-74-67 FCV-74-66 Drywell Access Room C KV-74-68 El. 565 Figure 1 The configuration for RHR Loop II shown in Figure labove illustrates the location of FCV-74-66 in relation to other 1ST Program valves (FCV-74-67 and CKV-74-68). RHR Loop I containing FCV-74-52 is similarly configured as shown in Figure 2 below.

Recirc. Loop B CKV-74-54 FCV-74-52 Drywell Access Room El. 565 C KV-74-54 Figure 2 Page 3 of 5

Lnservice Testing (IST) of FCV-74-52 arid- FCV-74-66 FCV-74-66 is normally open and is required to be open to provide flow to the reactor vessel.

1ST Program implementing procedures, shown in Table 3, exercise CKV-74-68 to the open position using Shutdown Cooling flow of greater than or equal to 9000 gpm at a frequency of once per operating cycle in accordance with the BEN Condition Monitoring Program as described in 0-Tl-443, Condition Monitoring of Check Valves. This check valve test provides supplemental indication that FCV-74-66 is in the open position.

Although not specifically documented in the check valve exercise test, supplemental indication that FCV-74-66 is open is provided when the check valve exercise test is performed.

1-S1-3.2.21(lI) was scheduled to be performed at Cold Shutdown during U1R8.

However, upon initiation of Shutdown Cooling, no flow was observed and the issue with 1-FCV-74-66 was identified, which precluded performance of the surveillance procedure.

==

Conclusion:==

The BEN 1ST Program testing specified for FCV-74-52 and ECV-74-66 is in compliance with ASME CM Code, Code Interpretation 99-9, and the guidance provided in NUREG 1482, including verification of position indication. Although supplemental position indication verification is not required by the Code or NUREG-1482 for all 1ST valves subject to position verification requirements, verification of flow through CKV-74-54/CKV-74-68 at BEN does provide the recommended supplemental indication as discussed in the ASME CM Code and NUREG-1 482.

Page 4 of 5

Lnservice Testing (1ST) of FCV.!74-52 and FCVJ446

References:

• ASME CM Code 1995 Edition 1996 Addenda

• O-Tl-362, Inservice Testing of Pumps and Valves

• NUREG-1 482, Revision 1, Guideline for Inservice Testing at Nuclear Power Plants

• ASME CM Code Interpretation 99-9, Dated December 23, 1998 (OMI-98-20)

• BEN Surveillance Procedures:

Table 1: Quarterly Exercise of ECV-74-52/66 1-SR-3.6.1.3.5(RHR I) 2-SR-3.6.1.3.5(RHR I) 3-SR-3.6.1.3.5(RHR I) 1-SR-3.6.1.3.5(RHR II) 2-SR-3.6.1.3.5(RHR II) 3-SR-3.6.1.3.5(RHR II)

Table 2: Position Indication of ECV-74-52/66 1-SI-3.6.1.3.5(H I) 2-Sl-3.6.1.3.5(H I) 3-Sl-3.6.1.3.5(H I) 1-Sl-3.6.1.3.5(H II) 2-Sl-3.6.1 .3.5(HIl) 3-SI-3.6.1 .3.5(H II)

Table 3: Exercise of CKV-74-68 I -Sl-3.2.21(l) 2-Sl-3.2.21(l) 3-Sl-3.2.21(I) 1 -Sl-3.2.21(lI) 2-SI-3.2.21(ll) 3-SI-3.2.21(ll)

Page 5 of 5

SUPPORTING DOCUMENTATION

1. 0-11-362 Appendix H Showing matrix of Unit 1 1ST valves

2. Completed 1-SI-3.2.21(II) Package (2007)

Showing completion of Cold Shutdown Testing of 1-CKV-74-68

3. Completed I -SI-3.2.21 (II) Package (2008)

Showing completion of Cold Shutdown Testing of 1-CKV-74-68

O-TI-362 Appendix H BFN Inservice Testing of Pumps and Valves 0-TI-362 Unit 0 Rev. 0026 Page 45 of 102 Appendix H (Page 1 of 14)

UI Valve Matrix VALVE ID FUNCTION ASME DWGIDWG CATEGORY SE VLV ACTUATOR NORM SAFE TEST RR1 SI/SR SI/SR CLASS COORDINATES TYPE PCS POS RE0O RO/CSDJ NUMBER DESCRIPTION FREG 1-PCV-01-0004 MSLNARLF 1 1-47E801-1/B-3 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.I.a&b BENCHTEST 1-SR-3.4.3.2 CYCLENRPIL 1-PCv-01-0005 MSLNARLF 1 1-47E801-1/B-5 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a&b BENCHTEST 0/00 1-SR-3.4.3.2 CYCLENRPIL 0/CC 1-FCV-01-0014 MSLNAINBDISCL 1 1-47E601-1/B-6 A 26 GL AC 0 C 0 RO-Ol 1-SR-3.3.1.1.8(5) PARTSTROKE QNRPIL 1-SR-3.6.1.3.6 TIME VLVNRPIL RFO FS 1-SI-3.2.12 FAIL SAFE REC LT 1-SR-3.6.1.3.10(A) LEAK TEST 0/CC 1-FCV-01-0015 MSLNAOUTBDISOL 1 1-47E801-1/B-7 A 26 GL AC 0 C C CSDJ-04 1-SR-3.3.1.1.8(5) PART STROKE

• CJNRPIL 1-SR-3.6.1.3.6 TIME VLVNRPIL CSD PS 1-SI-3.2.12 FAIL SAFE CSD LT 1-SR-3.6.1.3.10(A) LEAK TEST 0/CC 1-PCV-01-0018 MSLNBRLF 1 1-47E601-1/C-1 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a&b BENCHTEST 0/CC 1-SR-3.4.3.2 CYCLENRPIL C/CC 1-PCV-01-0019 MSLNBRLF I 1-47E801-1IC-2 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a&b BENCHTEST C/CD 1-SR-3.4.3.2 CYCLENRPIL 0/CC.

1-PCV-01-0022 MS LN B RLF 1 1-47E801-1/C-3 C 6 RV AC/SELF C C RV N/A 0-SR-3.4.3.1 .a & b BENCH TEST C/CC 1-SR-3.4.3.2 CYCLENRPIL 0/CC 1-PCV-0l-0023 MSLNBRLF 1 1-47E601-1/C-4 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a&b BENCHTEST C/CC 1-SR-3.4.3.2 CYCLENRPIL 0/CC 1-FCV-01-0026 MSLNBINBDISOL 1 1-47E801-1/C-6 A 26 GL AC 0 C 0 RO-Ol 1-SR-3.3.1.1.6(5) PARTSTRCKE 0 QNRPIL 1-SR-3.6.1.3.6 TIME VLVNRPIL RFO PS 1-SI-3.2.12 FAIL SAFE RFO LT 1-SR-3.6.1.3.10(B) LEAK TEST 0/CC.

1-FCV-01-0027 MSLN8OUTBDISOL 1 1-47E801-1/C-7 A 26 CL AC 0 C C CSDJ-04 1-SR-3.3.1.1.8(5) PARTSTROKE 0NRPIL 1-SR-3.6.1.3.6 TIME VLVNRPIL CSD FS 1-SI-3.2.12 FAIL SAFE CSD LT 1-SR-3.6.1.3.10(B) LEAK TEST 01CC 1-PCV-C1-0030 MS LN C RLF 1 1-47E801-1/E-1 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a & b BENCH TEST C/CC 1-SR-3.4.3.2 CYCLENRPIL C/CC 1-PCV-Q1-0031 MS LN C RLF 1 1-47E801-1/E-2 C 6 RV AC/SELF C 0 RV N/A 0-SR-3.4.3.1.a & b BENCH TEST C/CC 1-SR-3.4.3.2 CYCLENRPIL 0/CC 1-PCV-O1-0034 MSLNCRLF 1 1-47E801-1/E-4 C 6 RV AC/SELF C 0 RV N/A 0-SR-3,4.3.1.a&b BENCHTEST C/CC 1-SR-3.4.3.2 CYCLENRPIL 0/CC 1-FCV-01-0037 MSLNCINBDISOL 1 1-47E801-1/E-6 A 26 GL AC 0 C C RO-Ol 1-SR-3.3.1.1.B(5) PARTSTROKE 0 0/VRPIL 1-SR-3.6.1.3.6 TIME VLVNRPIL RFC FS 1-SI-3.2.12 FAIL SAFE RFC LT 1 -SR-3.6.1 .3.10(C) LEAK TEST 0/CC 1-FCV-01-0038 MSLNCCUTBDISCL 1 1-47E801-1/E-7 A 26 GL AC C C 0 CSDJ-04 1-SR-3.3.1.1.8(5) PARTSTRCKE C CNRPIL 1-SR-3.6,1.3.6 TIME VLVNRPIL CSD FS 1-SI-3.2.12 FAIL SAFE CSD LT 1-SR-3.6.1.3.10(C) LEAK TEST 0/CC.

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BEN Inservice Testing of Pumps and Valves 0-Tl-362 Unit 0 Rev. 0026 Page 52 of 102 Appendix H (Page 8 of 14)

UI Valve Matrix B 1 1 5Wfll 1-CKV-71-0580 RCIC TRB EXH CKV 2 1-47E813-1/E-7 AC 10 CK SELF C 0/C CM N/A 1-Si-32.3 COND MON 1-SR-3.5.3.3 1-SR-36.1 35(SO) 1-SI-4.7A.2.g-3/71b 1-CKV-71-0589 RCIC COND PMP CKV 2 1-47E813-1/A-3 C 2 CK SELF C C CM N/A 1-SI-3.2.3 COND MON

• 1-SR-3.5.3.3 1-CKV-71-0592 RCICVCPMPDISCH 2 1-47E813-1/D-5 C 2 CK SELF C C CM N/A 1-51-3.2.3 COND MON CM 1-SR-3.6.1.3.5(SD) 1-CKV-71-0597 RCIC TRB EXH VC RLF 2 1-475813-1/E-7 C 2 CK SELF C 0 CM N/A 1-SI-3.2.3 COND MON 1.SR-3.6.1.3.5(SD) 1-CKV-71-0598 RCICTRBEXHVCRLF 2 1-475813-1/E-7 C 2 CK SELF C 0 CM N/A 1-81-32.3 CONDMON CM 1-SR-3.6.1.3.5(SD) 1-CKV-71-0599 RCIC TRB EXH VC RLF 2 1-47E813-1/D-7 C 2 CK SELF C 0 CM N/A 1-81-32.3 CONG MON CM 1-SR-3.6.1.3.5(SD) 1-CKV-71-0600 RCICTRBEXHVCRLF 2 1-47E613-1/D-7 C 2 CK SELF C 0 CM N/A 1-SI-3.2.3 CONDMON ii 1-SR-3 .6_1.3. 5(SD) 1-FCV-73-0002 HPCE STM LN INBD ISOL 1 1-47E612-1/G-7 A 10 GA MO 0 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIME VLV 0 LT 1-SI-4.7.A.2g-3/73a LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(G) VRPIL O/2YF 1-FCV-73-0003 HPCI STM LN OUTED ISOL 1 1-47E812-1/G-6 A 10 GA MO 0 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIME VLV LT 1-St-4.7.A.2.g-3/73a LEAK TEST 0/OC VRPIL 1-SP-3.3.3.1.4(G) VRPIL 1-FCV-73-0006A HPCI STM LN TO CONG DRN 2 1-47E812-1/E-2 B 1 GA A0 0 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIME VLV 0 VRPIL 1-SR-3.3.3.1.4(G) VRPIL 0/2YI 1-FCV-73-0006B HPCI STM LN TO CONG DRN 2 1-47E812-1/E-2 B 1 GA AO 0 0/C Q N/A 1-SR-3.6.1.3.5(HPCI) TIME VLV VRPIL 1-SR-3.3.3.1.4(G) VRPIL 0/2YR 1-FCV-73-0016 HPCITRBSTMSPLYVLV 2 1-47E812-1/G-3 B 10 GA MO C 0 0 N/A 1-SR-3.6.1.3.5(HPCI) TIMEVLV T VRPIL 1-SR-3.3.3.1.4(G) VRPIL 1-FCV-73-0018 HPCITRBSTOPVLV 2 1-47E812-1/G-3 B 10 GA EJH C 0 SKID N/A 1-SR-3.5.1.7 HPCIPumpTest 0 1-SHV-73-0023 HPCITRBEXHVLV 2 1-47E812-1/D-7 AC 16 SC H/SELF 0 0/C CM N/A 1-SI-3.2.3 CONDMON CM VRPIL 1-SR-3.6,1 .3.5(SD) VRPIL O/2YR 1-S R-3. 5. 1.7 1-SI-4.7.A.2.g-3173b 1-SHV-73-0024 HPCI TRB EXH COND POT 2 1-47E812-1/D-6 C 2 SC H/SELF C 0/C CM N/A 1-SI-3.2.3 COND MON CM DISCH 1-SR-3.6.1.3.S(SD) 1-FCV-73-0026 PSCTOHPCIINBOISOL 2 1-47E812-1/8-6 B 16 GA MO C 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIMEVLV 0 VRPIL 1-S-3.3.3.1.4(G) VRPIL O/2YR 1-FCV-73-0027 PSCTOHPCIOUTBDISOL 2 1-47E812-1IG-S B 16 GA MO C 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIMEVLV 0 VRPIL 1-SR-3.3.3.1.4(G) VRPIL O/2YR 1-FCV-73-0030 HPCI PMP MIN FLOW 2 1-47E612-1/D-5 B 4 GL MO C 0/C 0 N/A 1-SR-3.6.1.3.5(HPCI) TIME VLV VRPIL 1-SR-3.3.3.1.4(G) VRPIL 0/2YR 1-FCV-73-0035 HPCIPMPTESTRTNTO 2 1-47E812-1/F-6 B 10 GL MO C C 0 N/A 1-SR-3.6.1.3.5(HPCI) TTMEVLV 0 CST VRPIL 1-SR-3.3.3.1.4(G) VRPIL OJ2YP.

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BFN lnservice Testing of Pumps and Valves 0-Tl-362 Unit 0 Rev. 0026 Page 56 of 102 Appendix H (Page 12 of 14)

UI Valve Matrix 1-CKV-75-0609 Cs LP II KP FILL CKV 2 1-47E814-1/H-4 C 2 CK SELF 0/C C CM N/A 1-51-3,2.3 and 1-SI-3.2.31 COND MON *T OR_1-SI-3.2.15 1-CKV-75-0610 CS LP II KP FILL CKV 2 1-47E814-1/H-4 C 2 CK SELF 0/C C CM N/A 1-51-3.2.3 and 1-SI-3.2.31 COND MON OR_l-SI-3.2.15 1-FCV-76-0017 DWN2MKUPOUTBDISOL 2 1-47E860-1/C-6 A 2 SF CYL 0/C C 0 N/A 1-SR-3.6.1,3.5 TIMEVLV LT 1-SI-4.7.A.2.g-3/76k LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(0) VRPIL O/2Y 1-FCV-76-0018 OW N2 MKUP INBO ISOL 2 1-47E860-1/C-6 A 2 BF CYL 0/C C Q N/A 1-SR-3.6.1.3.5 TIME VLV 0 LT 1-SI-4.7.A.2.g-3/76k LEAK TEST 0/OC VRPIL 1-SR.3.3.3.1.4(O) VRPIL 0/2YR 1-FCV-76-0019 PSCN2MKUPINBDISOL 2 1-47E860-1/B-5 A 2 SF CYL 0/C C 0 N/A 1-SR-3.6.1.3.5 TIME VLV Q LT 1-SI-4.7.A.2.g-3/76k LEAK TEST 0/OC VRPIL 1.SR-3.3.3.1.4(0) VRPIL 0/2Y 1-FCV-76-0024 DWN2PURGEOUTBDISOL 2 1-47E860-1/C-5 A 10 SF CYL C C 0 N/A 1-SR-3.6.1.3.5 TIME VLV 0 LT 1-SI-4.7.A.2.g-3/64a LEAK TEST 0/OC VRPIL 1-SR-3.3.3./.4(0) VRPIL 1-FSV-76-0049 DWH2ANLYZRAINBDISOL 2 1-47E1610-76-3/D-7 A 1/2 GA S 0/C 0/C 0 N/A 1-SR-3.6.1.3.5(76) TIMEVLV 0 LT 1-SI-4.7.A.2.g-3/76a LEAK TEST 0/OC 1-FSV-76-0050 DWH2ANLYZRAOUTBD 2 1-47E1610-76-3/D-7 A 1/2 GA S 0/C 0/C 0 N/A 1-514-3.6.1.3.5)76) TIME VLV Q ISOL LT 1-SI-4,7,A.2.g-3/76a LEAK TEST O/OC 1-FSV-76-0055 PSCH2ANLYZRAINBD 2 1-47E1610-76-3/E-7 A 1/2 GA S 0/C 0/C 0 N/A 1-SR-3.6.1.3.5(76) TIME VLV ISOL LT 1-SI-4.7.A.2.g-3/76d LEAK TEST 0/OC.

1-FSV-76-0056 PSC H2ANLYZRAOUTBD 2 1-47E1610-76-3/E-7 A 1/2 GA S 0/C 0/C 0 N/A 1-SR-3.6.1.3.5(76) TIME VLV ISOL LT 1-SI-4.7.A.2.g-3/76d LEAK TEST 0/OC 1-FSV-76-0057 PSCRTNINBDISOL 2 1-47E1610-76-3/E-7 A 1/2 GA S 0 0/C 0 N/A 1-SR-3.6.1.3.5(76) TIME VLV a LT 1-SI-4,7,A.2.g-3176e LEAK TEST 0/OC 1-FSV-76-0058 PSCRTNOUTSDISOL 2 1-47E1610-76-3/E-7 A 1/2 GA 5 0 0/C 0 N/A 1-514-3.6.1.3.5(76) TIMEVLV LT 1-SI-4.7.A.2.g-3176e LEAK TEST 0/OC 1-CKV-76-0653 TIP INDEXER PURGE 2 1-47E600-14/S-5 AC 1/4 CK SELF C CM N/A 1-Sl-3.2.3 and 1-SI-3.2.31 COND MON 1-SI-4.7.A.2.g-3/94b 1-FCV-77-0002A DWFLRDRNSUMPINBD 2 1-47E852-1/C-4 A 3 BA A0 0 C 0 N/A 1-SR-3.6.1.3.5 TIMEVLV 0 ISOL LT 1-SI-4.7.A.2.g-3/77a LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1 .4(J) VRPIL 0/2YR 1-FCV-77-0002B DWFLRDRNSUMPOUTBD 2 1-47E852-1/C-4 A 3 BA A0 0 C 0 N/A 1-SR-3.6.1.3.5 TIMEVLV 0 ISOL LT 1-SI-4.7.A.2.g-3/77a LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(J) VRPIL 1-FCV-77-0015A DWEQDRNSUMPINBD 2 1-475652-2/0-3 A 3 BA AO 0 C 0 N/A 1-SR-3.6.1,3.5 TIMEVLV 0 ISOL LT 1-SI-4.7.A.2.g-3177b LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(J) VRPIL 0/2YR 1-FCV-77-0015B DWEQDRNSUMPOUTBD 2 1-47E6S2-2/D-3 A 3 BA A0 0 C 0 N/A 1-SR-3.6.1.3.5 TIME VLV ISOL LT 1-SI-4.7.A.2.g-3/77b LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(J) VRPIL 0/2YR 1-FSV-84-0008A DWN2SPLYTRNA 2 1-47E662-1/E-7 A 2 GL S C 0/C 0 N/A 1-SR-3.6.1.3.5(CAD) TIME VLV 0 LT 1-SI-4.7.A.2.g-3/84a LEAK TEST 0/OC VRPIL 1-514-3.3.3.1.4(0) VRPIL 0/2YR 1-FSV-84-0008B PSCN2SPLYTRNA 2 1-47E862-1/E-5 A 2 GL S C 0/C a N/A 1-SR-3.6.1.3.5(CAD) TIME VLV 0 LT 1-SI-4.7.A.2.g-3/84b LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(Q) VRPIL O/2YR 1-FSV-84-0008C PSCN2SPLYTRNB 2 1-47E862-1/E-5 A 2 GL S C 0/C 0 N/A 1-SR-3.6.1.3.5(CAD) TIME VLV 0 LT 1-Sl-4.7.A.2.g-3/84c LEAK TEST 0/OC VRPIL 1-514-3.3.3.1.4(0) VRPIL O/2Y

C4 CDO

• 0 Cl, a)

C Cl)

0. Dci, C,_

a) >

0.0 c 0.0, >

S 0)

C 4-,

U)

C)

I a)

C.)

a)

U)

C C

BFN Inservice Testing of Pumps and Valves 0-TI-362 Unit 0 Rev. 0026 Page 58 of 102 Appendix H (Page 14 of 14)

UI Valve Matrix VRPIL 1-SR-3.3.3.14(S) VRPIL 1-FSV-90-0254B DW LEAK GET ISOL 2 1-47E610-90-1/G-1 A 1 GA S 0 0/c 0 N/A 1-SR-3.6,1.3.5 TIME VLV 0 LT 1-SI-4.7.A.2.g-3/90 LEAK TEST 0/OC VRPIL 1-SR.3.3.3.1.4(S) VRPIL 1-FSV-90-0255 DWLEAKDETISOL 2 1-47E610-9O-1/G-2 A 1 GA 5 0 0/C 0 N/A 1-SR-3.6,13.S TIME VLV 0 LT 1-SI-4.7.A.2g-3/90 LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(S) VRPIL 1-FSV-90-0257A DWLEAKDETISOL 2 1-47E610-90-1/H-2 A 1 GA S 0 0/C 0 N/A 1-SR-3.6.1.3.S TIMEVLV 0 LT 1-SI-4.7.A.2.g-3/90 LEAK TEST 0/OC VRPIL 1-SR-3.3.3.1.4(S) VRPIL 1-FSV-90-0257B DWLEAKDETISOL 2 1-47E610-90-1/H-2 A 1 GA 5 0 0/C 0 N/A 1-SR-3.6.1,3.5 TIME VLV 0 LT 1-SI-4.7.A.2g-3/90 LEAK TEST 0/OC VRPIL 1-SR.3.3.3.1.4(S) VRPIL 1-FCV-94-O5O1 TIPINDEXERBALLVLV 2 1-47E600-14/B-8 A 3/8 BA S C C 0 N/A 1-5R-3.6.I.3.5 TIME VLV C LTNRPIL 1-SI-4.7.A.2.g-3/94a LEAK TESTNRPIL 0/OC 1-FCV-94-0502 TIPINDEXERBALLVLV 2 1-47E600-14/A-8 A 3/8 BA S C C 0 N/A 1-SR-3.6.13.5 TIME VLV C LTNRPIL 1-SI-4.7A.2.g-3/94a LEAK TESTNRPIL 0/OC 1-FCV-94-0503 TIP INDEXER BALL VLV 2 1-47E600-14/A-8 A 3/8 BA S C C C N/A 1-SR-3.6.13.5 TIME VLV C LTNRPIL 1-SI-4.7,A.2g-3/94a LEAK TEST)VRPIL 0/OC 1-FCV-94-0504 TIP INDEXER BALL VLV 2 1-47E600-14/A-8 A 3/8 BA S C C C N/A 1-SR-3.61.15 TIME VLV C LTNRPIL 1-SI-4.7A2.g-3/94a LEAK TESTNRPIL 0/OC 1-FCV-94-05I35 TIP INDEXER BALL VLV 2 1-47E600-14/A-8 A 3/8 BA S C C 0 N/A 1-SR-3.6.1.3.5 TIME VLV C LTNRPIL 1-SI-4.7A.2.g-3/94a LEAK TESTNRPIL 0/OC

Completed 1-SI-32.21(Il) Package (2007)

Browns Ferry Nuclear Plant Unit I Surveillance Instruction 141-3.2.21(11)

Cold Shutdown Testing of I -CKV-74-68 Revision 0000 Quality Related Level of Use: Continuous Use Effective Date: 10-04-2006 Responsible Organization: OPS, Operations Prepared By: H D Sawyer Approved By: Robert Moll

4.0 PREREQUISITES VERIFY th is co py of th e Su rv eillance Instruction is the current Cr

[1]

revision.

or is at e Un it is in th e pr oc ess of shutting down

[2] CHECK th e 4 or 5).

Cold Shutdown (Mod perform e pe rs on ne l lis te d below are available to

[3] VERFIY th this test. (Y UO:AUO:

acted to otection has been cont ce of this Sl (N1A VERFIY Radiation Pr an

[4] quired for the perform coordinate support re if not required.).

MMENDED EC IA L TO O LS AN D EQUIPMENT RECO 5.0 SP ing the closure check)

Drain Hose (if perform ERIA ACCEPTANCE CRIT y 6.0 ep ta nc e Cr ite ria co nstitute unsatisfactor fail to meet the Acc ication of the Unit A. Responses which tion results and require immediate notif Surveillance Instruc time of failure.

e Supervisor (US) at th d by (AC) low ing A cc ep ta nc e Criteria are designate y the fol B. Steps which verif ank.

next to the in iti al s bl e full open and EC K VL V, 1- CK V -074-0068, shall cycl

1. RHR SYSTEM II CH m minimum).

ed us in g sh ut do w n cooling flow (9000 gp full clos actor Vessel.

l cl os e to pr ev en t backflow from the Re shal

2. 1-CKV-074-0068

.1 7.0 PROCEDURE STEPS 7.1 Initial Conditions

[1] VERIFY that the following Initial Conditions are satisfied;

• Precautions and Limitations in Section 3.0 have been reviewed.

• Prerequisites in Section 4.0 have been met.

[2] OBTAIN permission from Unit Supervisor to perform this tes2_

[31 INRCICJ NOTIFY the Unit 1 Operator (UO) that this test is commencing. IRPT 82-16, LER 259/820321

[4] RECORD the start date, start time, reason for test, plant conditions, and any pre-test remarks on Attachment 1, Surveillance Instruction Review Form.

I BFN Cold Shutdown Testing of 1-CKV-74-68 1-51-3.2.21(11)

Unit I Rev. 0000 Page 8 of 15 Date 1)fZEL 7.2 Test Steps NOTE Steps 7.2[1] and 7.2[2] are stand-alone sections. The preferred test sequence Is to perform Step 7.2[1J prior to Step 7.2[21 but it is not mandatory to do so if plant/system operating conditions prevent testing in that sequence. Step 7,2[2] is not required if an LLRT of 1-CKV-074-0068 is performed during the current Reactor shutdown.

f 1] PERFORM the following steps to check RHR SYSTEM II CHECK VLV, 1-CKV-074-0068, is OPEN using Shutdown Cooling flow (NIA this section (7.2[1j) if open position testing is not required at this time.):

[1.1] IF RHR System II is in Shutdown Cooling, THEN RECORD RHR System II flp.y below for the indicator 9 I jfr used (Otherwise NIA) 7 Nbflcl Flow gpm Ui ICS display Flow 91 gpm 1-Fl-74-64 on Panel 1-9-3.

0

[1.2] IF RHR System II is NOT in Shutdown Cooling, THEN INITIATE Shutdown Cooling per 1-01-74 (Otherwise NIA).

[1.31 ThROTTLE RHR SYS II LPCI OUTBD INJECT VALVE 1 i-FCV-074-0066, using RHR SYS II LPCI OUTBD INJECT VALVE, i-HS-74-66A on Panel 1-9-3 to obtain a minimum RHR System II flow rate of 9000 gpm on either of the following and MARK which indicator is used:

D Ui ICS display

-FI-74-64 on Panel 1-9-3.

4

Vt BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21(II)

Unit I Rev. 0000 V

Page9ofi5 Date JSfr7 7.2 Test Steps (continued)

[1.4] CHECK a Containment Spray flow reading of approximately zero on either of the following and MARK which indicator is used:

0 ICS display I31-Fl-74-7O on Panel 1-9-3.

[1.5] IF RHR System II was initially in Shutdown Cooling, THEN RESTORE the RHR System II system flow to approximately the flow recorded in Step 7.2[1 .11 or as directed by the US using RHR SYS II LPCI OUTBD INJECT VALVE, 1-HS-74-66A (Otherwise NIA).

[1.6] IF RHR System II Shutdown Cooling was initiated in Step 7.2[1 .2], THEN PERFORM the following as directed by the Unit Supervisor (Otherwise NIA):

[1.6.1] REMOVE RHR System II from service per 1-01-74 (NIA if RHR System I will remain in service.).

[1.6.2] IF RHR System II will remain in service, THEN ADJUST Flow per 1-01-74 to achieve the desired Shutdown Cooling flow (Otherwise NIA).

BFN Cold Shutdown Testing of 1CKV-74-68 1-51.3.2.21(11)

Unit I Rev. 0000 Page 10 of 15 Date 7.2 Test Steps (continued)

[2] PERFORM steps 7.2(2.1] to 7.2(2.14] to check RHR SYSTEM II CHECK VLV, 1-CKV-074-0068, is CLOSED using backflow testing (N!A if closed position testing is not required at this time. Closure testing is not required if an LLRT is performed for this valve during the current Reactor shutdown.):

[2.1] IF RHR System II is in Shutdown Cooling, THEN PERFORM the following (Otherwise NIA):

[2.1.1] RECORD RHR System II flow below for the indicator used (Otherwise NIA):

Flow gpm Ui ICS display Flow gpm 1-Fl-74-64 on Panel 1-9-3.

A-

[2.1.2] REMOVE RHR System II from Shutdown Cooling per 1-01-74.

[2.2] CHECK RHR System II Shutdown Cooling flow rate is approximately zero.

[2.3] CLOSE RHR SYS II LPCI OUTBD INJECT VALVE, i-FCV-074-0066, using RHR SYS II LPCI OUTBD INJECT VALVE, 1-HS-74-66A on Panel 1-9-3.

[2.4] OPEN RHR SYS II LPCI INBD INJECT VALVE, i-FCV-074.0067, using RHR SYS II LPCI INBD INJECT VALVE, 1-HS-74-67A on Panel 1-9-3.

[2.5] CONNECT drain hose to test connection at RHR/SDC RETURN HDR TEST, 1-TV-074-0630B (DW Access, El. 565) and ROUTE hose to nearest floor drain.

[2.6] OPEN RHRISDC RETURN HDR TEST, I -SHV-074-0629B (DW Access, El. 565). V

• BFN Cold Shutdown Testing of 1-CKV-74.68 1-S14.2.21(ll)

Unit I Rev. 0000 Page 11 of 15 Date Ifr9 7.2 Test Steps (continued)

NOTE An initial stream of water may be observed in Step 7.2[2.7]. This is expected and should subside rapidly.

[2.7] OPEN 1-TV-074-0630B.

[2.8] CHECK that no pressurized solid stream of water is observed from the drain hose (checks that 1-CKV-074-0068 is CLOSED).

(2.9] CLOSE 1-TV-074-0630B.

[2.10] CLOSE 1-SHV-074-0629B.

[2.11] CLOSE 1-FCV-074-0067 using RHR SYSTEM II LPCI INBD INJECT VALVE, 1-HS-74-67A.

[2.12] OPEN 1-FCV-074-0066 using RHR SYS II OUTBD INJECT VALVE, 1-HS-74-66A.

[2.13] REMOVE drain hose from test connection at 1 -TV-074-0630B.

[2.141 IF RHR System II was initially in Shutdown Cooling, in Step 7.2(2.1] and it is desired to return RHR System II to Shutdown Cooling, THEN PERFORM the following as directed by the Unit Supervisor (Otherwise N!A):

PLACE the RHR System II in Shutdown Cooling per 1-01-74 and ESTABLISH the desired Shutdown Cooling flow (N!A if RHR System II will not be placed in service.).

BFN Cold Shutdown Testing of 1-CKV-74-68 1-51-3.2.21(11)

Unit I Rev. 0000 Page 12 of 15 7.3 Restoration Date J 5I NOTES

1) The Independent Verifications of the following steps may be performed in any order.

2) If a deficiency is identified during the performance of the Independent Verifications in the next steps, the Independent Verifier shall stop and notify the Unit Supervisor immediately for further instructions prior to correcting the deficient condition(s).

[1] On Panel 1-9-3, INDEPENDENTLY VERIFY the following:

• RHR SYS II LPCI OUTBD INJECT VALVE, 1-FCV-074-0066, is THROTTLED for desired Shutdown Cooling flow.

IV

• RHR SYSTEM II LPCI INBD INJECT VALVE, 1-FCV-074-0067, is in the OPEN position.

IV

[2] At OW Access, El. 565, INDEPENDENTLY VERIFY the following (NIA if Step 7.2[2] was not performed):

• RHR/SDC RETURN HDR TEST, 1-SHV-074-0629B, is in the CLOSED posliton.

• RHR/SDC RETURN HDR TEST, 1-TV-074-0630B, is in the CLOSED position.

[3] VERIFY that the work area is dean. Cr

[4] COMPLETE Attachment 1, Surveillance Instruction Review Form, through Unit Supervisor review.

[5] NOTIFY the Unit 1 Operator that this Surveillance Instruction is complete. cr

[6] NOTIFY the Unit Supervisor that this Surveillance Instruction is complete and PROVIDE status of any test deficiencies or unsatisfactory test results. cr

[7] COMPLETE Attachment 2, ASME OM Code lnservice Testing Review Form.

BFN Cold Shutdown Testing of 1-CKV-74-68 1-51-3.2.21(11)

Unit I Rev. 0000 Page l3of 15 8.0 I LLUSTRATIONSIATTACHMENTS Attachment 1, Surveillance Instruction Review Form Attachment 2, ASME OM Code Inservice Testing Review Form

BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21(tl)

Unit I Rev. 0000 Page 14 of 15 Attachment I (Page 1 of 1)

Surveillance Instruction Review Form REASON FOR TEST: DATE!TIME STARTED I7 O8oo C Scheduled Surveillance DATE/TIME COMPLETED 5 C System Inoperable (Explain in Remarks) PLANT CONDITIONS I-.l(

C Maintenance (WO No.

bther (Explain in Remarks)

PRE-TEST REMARKS: I. N f C/ fL I,-

i1417

• I1 -

PERFORMED BY:

Initials Name (Print) Name (Signat,p) p 7 k 7)i2, dL Cr- j1A(.Ax, i ---

Delays or Problems (If yes, explain in post-test remarks)? DYjs C1o Acceptance Criteria Satisfied? V es C No If the above answer is no, the Unit Supervisor shall determine if an LCO exjss. LCO DYes UNIT SUPERVISOR Date i SECTION REVIEWER 5 - Date_____________

INDEPENDENT REVIEWER Date i (cjo]

SCHEDULING COORDINATOR Date___________

POST-TEST REMARKS: c, -

/QL/F

C.

BFN Cold Shutdown Testing of 1-CKV-7468 1-81-3.2.21(11)

Unit I Rev. 0000 Pagel5ofi5 Attachment 2 (Page 1 oil)

ASME OM Code Inservice Testing Review Form Fully Not NIA or Component Tested Acceptabl Acceptable Not Tested l-CKV-074-0068 V ci a (Open, Step 7.2[l])

l-CKV-074-0068 0 0 (Closed, Step 7.2[2])

ASME OM Code Reviewer Date ( *_)

ASME OM Code data enter in Si(s) 1-Si-3.2.1 ANII Reviewer 4Q-Q4,zfiJ.. - Date o i -07 REMARKS:

\

SPP..B.1 TVAN STANDARD CONDUCT OF TESTING Date 2-16-2000 PROGRAMS AND Page 12 of 15 PROCESSES TEST DIRECTOR ASSiGNMENT SHEET Page lof I TEST DIRECTOR ASSIGNMENT SHEET Page I of I Data Package Page J of Procedure No. SI . Rev.

The responsible supervisor will answer the following three questions:

Chronological Test Log (CTL) 41 Required?

> Yes E.No C Pre Test Formal Briefing Required?

(2) Yes 12 No Li CIPTE?

Is this test a 3

> Yes Li No When more than one test directo r is design ated, indicat e the curren t test director in the CTL.

CAUTION: THE RESPONSIBLE SUPERVISOR DESIGNATES THE TEST DIRECTOR AND IS RESPONSIBLE FOR DESIGNATING A QUALIFIED PERSON.

Designated Test Director Responsible Supervisor (4) Date Printed_Name re Form SPP-8.1-2 should be used as specified in section 3.4, (2)

The pretest formal briefing should be performed as specified in section 3.2.

Determine if CIPTE as stated in Section 3.1.A.

(4)

Signature attests to the requirements in Section 3.1.C, Signature attests to the requirements in Section 3.1 .B.

Page 1 of I SPP-8.1 -t [02-18-2000]

[VA 40680 [02-2000)

SPP-8.l TVAN STANDARD CONDUCT OF TESTING Date 2-16-2000 PROGRAMS AND Page 13 of 15 PROCESSES CHRONOLOGICAL TEST LOG (CTL)

Page 1 of I CHRONOLOGICAL TEST LOG (CTL)

Data Package Page . of Procedure No. 3t3 .1(X) Rev. -

Narrative Initials p t3 te

/Tim e oi! mircT - liz) 4-c C) s___a pPi Cr Dc.__cac (j

• 2C3__u.)LL__1 1SoEt4*i__

1 ho4% -___

V4c (N%ç2ir c*, $Øt1LPLk1T -

(V wttTh i 2

1 C].

Nw hs1& t0 1C-S C.PLL i cYt..J 1\E -tcc c- v ri-

/3M ,ti1 A

Log have items are d 1 appr des opria sed teIy .

e etZetr1d Test Director Date 1

k ise 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> clock for each entry.

can be marked N/A.

Test Director signature only required on last sheet of CTL. The other review blanksentry after each date 2

(3)

The Date column needs to be filled in for the first entry on the CTL and for the frst change.

Page 1 of 1 SPP-8. 1-2 02-16-2000J TVA 40681 [02.2c00J

SPP4.1 TVAN STANDARD CONDUCT OF TESTING Date 04-03-2006 PROGRAMS AND Page 14 of 15 PROCESSES PRETEST BRIEFING CHECKLIST Page 1 of 2 PRE-TEST BRIEFING CHECK LIST Page 1 of 2 TEST PROCEDURE NUMBER V51 -3 2 Ly TEST PROCEDURE TITLE (tL.fl b$n cç 1C LeJl -

ASSIGNED TEST DIRECTOR Complete N/A 1.0 BRIEFINGS WILL INCLUDE AS A MINIMUM THE FOLLOWING: PART I The level of detail and applicability of the following items is dependent on the complexity of the test to be performed.

11 Discuss scope, objectives, and expected results.

U 1.2 General personnel safety and equipmentprotection, U

1.3 Major precautions of test.

U 1.4 Prepare teat schedule (prerequisites, initial conditions, test 0 U performance and post test recovery).

1.5 Responsibilities and specific tasks of test personnel.

U 1.6 Locations of and communications with test support personnel.

U

1.7 Interfaces

a. Reporting/notification requirements

b. Support organization requirements 1.8 Discussion of critical steps as defined in SPP-2.2 C NOTE Critical steps shall be flagged (via designated stamp or equivalent marking) for review at the pie-test briefing.

1.9 Impact of the test on plant equipment and operations.

C 1.10 Effect on reactor core reactivity or nuclear fuel storage reactivity, or U

Independent Spent Fuel Storage Installation activities.

1.11 Expected and unexpected plant responses.

U 1.12 Potential problems and contingencies, 0 C 1.13 Differences between normal and test plant conditions.

U 1.14 Criteria for aborting the test.

1.15 Emphasis on quality over schedule.

C 1.16 Emphasis on Self-Checking.

U Page 1 of2 SPP-8, 1-3 [04-03-2006j TVA 40682 [04-20061

SPP-8.1 TVAN STANDARD CONDUCT OF TESTING Date 04-03-2006 PROGRAMS AND Page 15 of 15 PROCESSES PRE-TEST BRIEFING CHECKLIST Page 2 of 2 PRE..TEST BRIEFING CHECK LIST Page 2 of 2 Complete N/A 2.0 CIPTEs WILL ALSO INCLUDE AS A MINIMUM THE FOLLOWING: PART II In addition to PART I above CIPTEs will include (he following items as applicable:

2.1 State the need for exercising cautions and conservatism during the C test, particularly when uncertainties are encountered.

2.2 Ensure responsibilities have been clearly assigned, especially those that are different from normal duties and accountabilities.

2.3 State the lessons learned from pertinent in-house and industry U experience.

2.4 State the need to take proper actions when unexpected conditions U arise or unexpected plant behavior is experienced. These actions could include stopping the test, stopping power ascension, decreasing power, or shutting down the unit, 2.5 Emphasize maintaining the highest margin of safety to place proper perspective on any sense of urgency that may otherwise prevail.

2.6 State the need for open communication, U Page 2 of 2 SPP-8. 1-3 [040320061 TVA 40682 [04-2006J I

Completed 1-SI-3.221(II) Package (2008) 4 Browns Ferry Nuclear Plant Unit I Surveillance Instruction I -Sl-3.2.21Ql)

Cold Shutdown Testing of 1-CKV-74-68 Revision 0000 Quality Related Level of Use: Continuous Use ffective Date: 10-04-2006 Responsible Organization: OPS, Operations Prepared By: H D Sawyer Approved By: Robert Moll

BFN Cold Shutdown Testing of 1-CKV-74-68 141-3.2.21(11)

Unit I Rev. 0000 Page 4 of 15

1.0 INTRODUCTION

1.1 Purpose This Surveillance Instruction (SI) provides a method to test RHR SYSTEM II CHECK VLV, 1 -CKV-074-0068.

1.2 Scope This SI will test RHR SYSTEM II CHECK VLV, 1-CKV-074-0068. Testing will consist of valve cycling using Shutdown Cooling flow. This will satisfy ASME OM Code and Technical Specification 5.5.6 requirements.

1.3 Frequency Valve cycling is conditional in accordance with the BFN Condition Monitoring Program.

2.0 REFERENCES

2.1 Technical Specifications Section 5.5.6, lnservice Testing Program 2.2 Final Safety Analysis Report A. Chapter 6.0, Emergency Core Cooling Systems B. Chapter 6.6, Inspection and Testing C. Chapter 7,3, Primary Containment Isolation System D. Chapter 7.4, Emergency Core Cooling Control and Instrumentation E. Figure 7.4-6a, Residual Heat Removal System Flow Diagram F. Chapter 13.0, Conduct of Operations 2.3 Plant Instructions A. 0-GOI-300-3, General Valve Operations B. 1-01-74, Residual Heat Removal System

r BFN Unit I Cold Shutdown Testing of 1-CKV-74-68 1-Sl.3.2.21(lI)

Rev. 0000 Page 5of 15 2.3 Plant Instructions (continued)

C. 1-Sl-3.2.1, Inservice Testing and Augmented Inservice Testing Valve Performance D. O-Tl-362, Inservice Testing of Pumps and Valves E. O-Tl-443, Condition Monitoring of Check Valves F. SPP-8.1, Conduct of Testing G. SPP-1O.3, Verification Program 2.4 Plant Drawings 1-47E81 1-1, Flow Diagram Residual Heat Removal System 2.5 Miscellaneous Documents INPO SER 4-89, Loss of Coolant Transient from Response to Open Check Valve 3.0 PRECAUTIONS AND LIMITATIONS A. If maintenance other than what is provided for in this instruction becomes necessary, a separate Work Order (WO) must be initiated.

B. When testing the RHR System components without Shutdown Cooling flow, maintain awareness of the Reactor water temperature. Termination of this test and return to Shutdown Cooling will be necessary should the moderator temperature approach 212° Fahrenheit.

C. Prior to using the drain hose, the hose should be inspected for cuts, damaged fittings, etc., to determine suitability for safe use. If hose is questionable or needs replacing, contact Mechanical Maintenance.

D. This SI checks that RHR SYSTEM U CHECK VLV, 1-CKV-074-0068, is closed by demonstrating there is no pressurized backflow from the primary coolant system past 1-CKV-074-0068. INPO SER 4-89 documents problems encountered when attempting to seat check valves using backflow from the primary coolant system during operation. Backflow testing specified in this SI should only be used to check that 1-CKV-074-0068 is already seated and only during Cold Shutdown (Mode 4 or 5) conditions.

BFN Cold Shutdown Testing of 1-CKV-74-66 141-3.2.21(11)

Unit I Rev. 0000 Page 6 of 15 Date iI* s4.ci 4.0 PREREQUISITES

[1] VERIFY this copy of the Surveillance Instruction is the current revision. ci,

[2] CHECK the Unit is in the process of shutting down or is at Cold Shutdown (Mode 4 or 5).

[3] VERFIY the personnel listed below are available to perform this test.

UO: I AUO: I (.7

[4] VERFIY Radiation Protection has been contacted to coordinate support required for the performance of this SI (NIA if not required.).

5.0 SPECIAL TOOLS AND EQUIPMENT RECOMMENDED Drain Hose (if performing the closure check) 6.0 ACCEPTANCE CRITERIA A. Responses which fail to meet the Acceptance Criteria constitute unsatisfactory Surveillance Instruction results and require immediate notification of the Unit Supervisor (US) at the time of failure.

B. Steps which verify the following Acceptance Criteria are designated by (AC) next to the initials blank.

1. RHR SYSTEM II CHECK VLV, I-CKV-074-0068, shall cycle full open and full closed using shutdown cooling flow (9000 gpm minimum).

2. l-CKV-074-0068 shall close to prevent backflow from the Reactor Vessel.

BFN Cold Shutdown Testing of 1-CKV-74-68 1-SI-3.2.21(II)

Unit I Rev. 0000 Page7ofl5 Date JlII4ln.

7.0 PROCEDURE STEPS 7.1 Initial Conditions

[1] VERIFY that the following Initial Conditions are satisfied:

• Precautions and Limitations in Section 3.0 have been reviewed.

• Prerequisites in Section 4.0 have been met.

[2] OBTAIN permission from Unit Supervisor to perform this t

[3] tNRC/C1 NOTIFY the Unit 1 Operator (UO) that this test is commencing. [RPT82-16, LER259/82032]

[4J RECORD the start date, start time, reason for test, plant conditions, and any pre-test remarks on Attachment 1, Surveillance Instruction Review Form.

BFN Cold Shutdown Testing of 1-CKV-74-68 141-3.2.21(11)

Unit I Rev. 0000 Page 8 of 15 Date II Iiq/

7.2 Test Steps NOTE Steps 7.2(1] and 7.2(2] are stand-alone sections. The preferred test sequence is to perform Step 7.2(1] prior to Step 7.2(2] but it is not mandatory to do so if plant/system operating conditions prevent testing in that sequence. Step 7.2(2] is not required if an LLRT of 1-CKV-074-0068 is performed during the current Reactor shutdown.

[1] PERFORM the following steps to check RHR SYSTEM II CHECK VLV, 1-CKV-074-0068, is OPEN using Shutdown Cooling flow (NIA this section (7.2(1]) if open position testing is not required at this time.):

[1.1] IF RHR System Ills in Shutdown Cooling, THEN RECORD RHR System II flow below for the indicator used (Otherwise NIA):

Flow 7c gpm UI ICS display Flow gpm 1-Fl-74-64 on Panel 1-9-3.

f3 a,

[1.2] IF RHR System II is NOT in Shutdown Cooling, THEN INITIATE Shutdown Cooling per 1-01-74 (Otherwise NIA).

[1.3] THROTTLE RHR SYS II LPCI OUTBD INJECT VALVE, 1-FCV-074-0066, using RHR SYS II LPCI OUTBD INJECT VALVE, I-HS-74-66A on Panel 1-9-3 to obtain a minimum RHR System II flow rate of 9000 gpm on either of the following and MARK which indicator is used:

D UI ICS display W1-Fl-74-64 on Panel 1-9-3.

BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21(Il)

Unit I Rev. 0000 Pag9 of 15 Date 7.2 Test Steps (continued)

[1.4] CHECK a Containment Spray flow reading of approximately zero on either of the following and MARK which indicator is used:

0 Ui ICS display I1-Fl-74-7O on Panel 1-9-3.

[1.5] IF RHR System II was initially in Shutdown Cooling, THEN RESTORE the RHR System II system flow to approximately the flow recorded in Step 7.2[1 .1] or as directed by the US using RHR SYS II LPCI OUTBD INJECT VALVE, 1-HS-74-66A (Otherwise N!A).

[1.6] IF RHR System II Shutdown Cooling was initiated in Step 7.2[1 .2], THEN PERFORM the following as directed by the Unit Supervisor (Otherwise NIA):

[1.6.1] REMOVE RHR System II from service per 1-01-74 (NIA If RHR System I will remain In service.).

[1.6.2] IF RHR System II will remain in service, THEN ADJUST Flow per 1-01-74 to achieve the desired Shutdown Cooling flow (Otherwise N!A).

BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21(lI)

Unit I Rev. 0000 PageIOofl5 Date iJ,iJjiii 1

7.2 Test Steps (continued)

[2] PERFORM steps 7.2[2.1] to 7.2[2.14] to check RHR SYSTEM II CHECK VLV, 1-CKV-074-0068, is CLOSED using backflow testing (N!A if closed position testing is not required at this time. cJjjre testing is not required if an LLRT is performed for this valve during the current Reactor shutdown):

[2.1] IF RHR System Ills in Shutdown Cooling, THEN PERFORM the following (Otherwise NIA):

[2.1.1] RECORD RHR System U flow below for the indicator used (Otherwise NIA):

Flow ,4JJ4 gpm UI ICS display Flow gpm I-Fl-74-64 on Panel 1-9-3.

[2.1.2] REMOVE RHR System II from Shutdown Cooling per 1-01-74.

[2.2] CHECK RHR System II Shutdown Cooling flow rate is approximately zero.

[2.3] CLOSE RHR SYS II LPCI OUTBD INJECT VALVE, I -FCV-074-0066, using RHR SYS II LPCI OUTBD INJECT VALVE, 1-HS-74-66A on Panel 1-9-3.

[2.4] OPEN RHR SYS II LPCI INBD INJECT VALVE, I-FCV-074-0067, using RHR SYS II LPCI INBD INJECT VALVE, 1-HS-74-67A on Panel 1-9-3.

[2.5] CONNECT drain hose to test connection at RHRISDC RETURN HDR TEST, I-TV-074-0630B (DW Access, El. 565) and ROUTE hose to nearest floor drain.

[2.6] OPEN RHRISDC RETURN HDR TEST, 1-SHV-074-0629B (DW Access, El. 565).

BFN Cold Shutdown Testing of 1-CKV-7468 1-SI-3.2.21(lI)

Unit I Rev. 0000 Page 11 of 15 Date i(Itdki 7.2 Test Steps (continued)

NOTE An initial stream of water may be observed in Step 7.2[2.7]. This is expected and should subside rapidly.

[2.7] OPEN 1-TV-074-0630B. _LQ,

/

1 4_

[2.8] CHECK that no pressurized solid stream of water is observed from the drain hose (checks that 1 -CKV-074-0068 Is CLOSED). (AC)

[2.9] CLOSE 1-TV-074-0630B.

[2.10] CLOSE 1-SHV-074-0629B.

[2.11] CLOSE 1-FCV-074-0067 using RHR SYSTEM II LPCI INBD INJECT VALVE, 1-HS-74-67A.

[2.12] OPEN 1-FCV-074-0066 using RHR SYS II OUTBD INJECT VALVE, 1-HS-74-66A.

[2.13] REMOVE drain hose from test connection at I -TV-074-0630B.

[2.14] IF RHR System II was initially in Shutdown Cooling, in Step 7.2[2.1] and it is desired to return RHR System II to Shutdown Cooling, THEN PERFORM the following as directed by the Unit Supervisor (Otherwise NIA):

PLACE the RHR System II in Shutdown Cooling per 1-01-74 and ESTABLISH the desired Shutdown Cooling flow (NIA if RHR System II will not be placed in servicer).

BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21{II)

Unit I Rev. 0000 Page 12 of 15 DatejLjgI1 7.3 Restoration NOTES

1) The Independent Verifications of the following steps may be performed in any order,

2) If a deficiency is identified during the performance of the Independent Verifications in the next steps, the Independent Verifier shall stop and notify the Unit Supervisor immediately for further instructions prior to correcting the deficient condition(s).

[1] On Panel 1-9-3, INDEPENDENTLY VERIFY the following:

• RHR SYS II LPCI OUTBD INJECT VALVE, 1-FCV-074-0066, is THROTTLED for desired Shutdown Cooling flow.

IV

• RHR SYSTEM II LPCI INBD INJECT VALVE, 1-FCV-074-0067, is in the OPEN position.

IV

[2] At DW Access, El. 565, INDEPENDENTLY VERIFY the following (NIA if Step 7.2[2] was not performed):

• RHRISDC RETURN HDR TEST, 1-SHV-074-0629B, is in the CLOSED posiiton.

IV

• RHRISDC RETURN HDR TEST, 1-TV-074-0630B, is in the CLOSED position.

/lv

[3] VERIFY that the work area is clean.

[4] COMPLETE Attachment 1, Surveillance Instruction Review Form, through Unit Supervisor review.

[5] NOTIFY the Unit I Operator that this Surveillance Instruction is complete.

[6] NOTIFY the UnIt Supervisor that this Surveillance Instruction is complete and PROVIDE status of any test deficiencies or unsatisfactory test results.

[7] COMPLETE Attachment 2, ASME CM Code Inservice TestIng Review Form.

BFN Cold Shutdown Testing of 1-CKV-74-68 1-Sl-3.2.21(ll)

Unit I Rev 0000 Pagel3ofI5 8.0 ILLUSTRATIONS/ATTACHMENTS Attachment 1, Surveillance Instruction Review Form Attachment 2, ASME OM Code Inservice Testing Review Form

BFN Cold Shutdown Testing of 1-CKV-74-68 141-3.2.21(11)

Unit I Rev. 0000 Page 14 of 15 Attachment I (Page 1 of 1)

Surveillance Instruction Review Form REASON FOR TEST: DATE/TIME STARTED Scheduled Surveillance DATE/TIME COMPLETED ij 4

D System Inoperable (Explain in Remarks) PLANT CONDITIONS AIA O Maintenance (WO No.

O Other (Explain in Remarks)

PRE-TEST REMARKS: i: si ftl i 44 i-c 074- O(cI w#. ;7:i7E3:

LE2 QIØJ4LL ?.iIoE hPJAi4. 7 f tTh Iviiwihi f-rr in..Q - nr I iI-,t-nr PERFORMED BY:

Initials Name (Prinfl Name (Signatr 27 J h LJ,LI c.u .L.

w Delays or Problems (If yes, explain in post-test remarks)? DYes Acceptance Criteria Satisfied? 0 No If the above answer is no, the Unit Supervisor shall determine if an LCO exists LCO DYes DNo UNIT SUPERVISOR Date //-/cW SECTION Date iL INDEPENDENT pVFEWZ/ Date//,i7 SCHEDULING 6 0CR 1NTOR Date____________

POST-TEST REMARKS:______________________________________________

BFN Cold Shutdown Testing of 1-CKV-14-68 141-3.2.21(N)

Unit I Rev. 0000 Page 15 of 15 Attachment 2 (Page 1 of 1)

ASME OM Code Inservice Testing Review Form Fully Not NIAor Comoonent Tested Acceptable Acceptable Not Tested 1-CKV-074-0068 D 0 (Open, Step 7.2[1])

I -CKV-074-0068 0 (Closed, Step 7.2[2])

ASME OM Code Reviewer (A.L- LiAA_L.A Date i j fc) 6 ASME OM Code data enter in Si(s) 1-SI-3.2.1 ANII Reviewer Date ,,.j /Od REMARKS: j - trig - o -r-7Z, ci-o. LLSJLJ4 LT 9Z)E6 1-si u 0 1-zg,-

jpc(7s- 7

-BFN Primary Containment Loc3l leak Rate 1SI4.7.A2;G-3t74D ii Unit I Test RHR Shutdown Cooling Return: Rev 0002 -

Penetration X-13B Page 19 of 30 Attachment I (Page lofI)

Surveillance Instruction Review Form REASON FOR TEST: DATE/TIME STARTED Ig2.7/ac3 / .1t5 QScheduled Surveillance DATE/TIME COMPLETED El System Inoperable (Explain in Remarks) PLANT CONDITIONS 5-C Maintenance (WO No.

El Other (Explain in Remarks)

PRE-TEST REMARKS:

PERFORMED BY:

Initials Name (Print)

-:;ML 4.. gL -

, 4jrr t14.5

• .L 7kvr

4. 2 Tc Delays or Problems (If yes, explain in post-test rer Acceptance Criteria Satisfied? DNa If the above answer is determine if an LCO LCO DYes UNIT SUPERVISOR Date ii SECTION REVIEWER (MM) Date iiJ I

1 ,r -

Signature attests that I understand the scope and purpose of this instruction and that, to the best of my knowledge, it was properly performed in accordance with instruction in that: the recording, reduction, ahi evaluation of data is complete and correct; acceptance criteria is met or justification for exceptions is provided; portions of test performed were appropriate for specified test conditions or reasons for test; deficiencies wereévaluatecl and dispositioned; reportability was evaluated; marginal results were evaluated with respect to potential for future problems based on operating experience and regulatory requirements; and instruction was complete except as noted in post-test remarks.

INDEPENDENT REViEWER Date SCHEDULING COORDINATOR Date_____________

POST-TEST REMARKS: -

.