ML18038B940

Provides Suppl Info to Util'S 970725 Response to Ieb 96-003, Potential Plugging of ECCS Strainers by Debris in Bwrs. Schedule for Completion of License Amend Request Should Be Revised to 981231 or When Amend Is Approved.W/Commitments

ML18038B940
Person / Time
Site:	Browns Ferry
Issue date:	08/25/1997
From:	Abney T TENNESSEE VALLEY AUTHORITY
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
IEB-96-003, IEB-96-3, TAC-M96136, NUDOCS 9709030167
Download: ML18038B940 (56)

Text

CATEGORY 1 REGULATQROZNFORMATZON DZSTRZSUTZON PEM (RZDS)

ACCESSION NBR:9709030167- DOC.DATE: 97/08/25 NOTARIZED: YES DOCKET FACIL:50-260 Browns Ferry Nuclear Power Station, Unit 2, Tennessee 05000260 AUTH. NAME AUTHOR AFFILIATION ABNEY,T.E. Tennessee Valley Authority RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk)

SUBJECT:

Requests that schedule for completion of activity re NRC Bulletin 96-003,be revised to 971231.Supplemental info to plant's 970725 response, provided.

DISTRIBUTION CODE: IE73D COPIES RECEIVED:LTR ENCL SIZE: A TITLE: NRC Bulletin 96-03, "Potential Plugging of ECCS Strainers by Debris i NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL NRR/LYNCH,D'. 1 1 PD2-3-PD 1 1 WILLIAMSFJ. 1 1 INTERNAL. E C R Ol 1 1 NRR/DE/ECGB 1 1 NRR/DE/ECGB/A 1 1 NRR/DSSA/SCSB 4 4 NRR/DSSA/SRXB 1 1 NRR/DSSA/SRXB/A 1 1 NRR/PD3-2 1 1 .RES/DET/GSIB 2 2 EXTERNAL: NOAC 1 1 NRC PDR 1 1 D

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N'OTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTE. TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD) ON EXTENSION 415-2083 TOTAL NUMBER OF COPIES REQUIRED: -LTTR 17 ENCL 17

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Tennessee Valley Authority. Post Office Box 2000. Decatur, Afabama 35609 August '25, 1997 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Gentlemen:

In the Matter of Docket No. 50-260 Tennessee Valley Authority BROWNS FERRY NUCLEAR PLANT (BFN) UN T 2 I NRC BULLET N 9 6 I 03 I POTENTIAL PLUGGING OF EMERGENCY CORE COOLING SUCTION STRAINERS BY DEBRIS IN BOILING-WATER REACTORS (TAC NO. M96136)

This letter provides supplemental information to TVA's July 25, 1997, response to the subject bulletin. TVA requests the schedule for the completion of this activity be revised to December 31, 1998, or when the staff approves and TVA implements the license amendment that incorporates the use of containment overpressure into the BFN licensing basis, whichever is sooner.

Bulletin 96-03 requested TVA implement the appropriate procedural measures and plant modifications to minimize the potential for clogging of the Emergency Core Cooling Systems (ECCS)'uppression pool strainers by debris generated during a loss of coolant accident (LOCA). As discussed in TVA's July 25, 1997 letter, TVA's approach to resolve this issue is to install new, larger, higher debris capacity, passive strainers. These strainers will be installed in Unit 2, during the Fall 1997 outage (Cycle 9), under the provisions of 10 CFR 50.59. This outage is currently scheduled to begin on September 26, 1997.

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i U.S. Nuclear Regulatory Commission Page 2 August 25, 1997 As also discussed in TVA's July 25, 1997 letter, TVA has performed calculations in response to this bulletin to ensure that the debris loading postulated in Regulatory Guide 1.82, Revision 2, will not result in an available net positive suction head (NPSH) below the required NPSH for the ECCS pumps during a postulated loss of coolant accident (LOCA) event. As part of TVA's methodology, containment over pressure in excess of atmosphere is relied on to maintain adequate ECCS pump NPSH. The use of containment over pressure by TVA is only necessary for final resolution of the bulletin.

Recent discussions with the staff have indicated that TVA's proposed use of containment over pressure should be addressed as a license amendment. TVA is in the process of preparing this license amendment request. However, in order to accommodate the time frames necessary for the final resolution of the Bulletin for Unit 2, TVA requests the schedule for the completion of this activity be revised to December 31, 1998, or when the staff approves and TVA implements the license amendment that incorporates the use of containment overpressure into the BFN licensing basis, whichever is sooner. As discussed in detail in Enclosure 1, TVA considers this extension acceptable since:

~

By letters, dated January 29, and February 19, 1997, the staff approved TVA's request for deferral of actions requested by Bulletin 96-03 until December 31, 1998, for Unit 3. This approval was based upon the determination that TVA's compensatory actions provide confidence of continued safe operation with the existing strainers.

In addition to the installation of the larger strainers on Unit 2, TVA will also implement similar compensatory actions as those previously approved on Unit 3. These compensatory actions are detailed in Enclosure 1 and provide confidence of continued safe operation of Unit 2;

~ Containment overpressure is a byproduct of the conditions which will exist in the containment after the pipe break inside containment. The credit taken for this pressure in ECCS NPSH analyses has been done in such a manner as to assure that the actual containment overpressure will always exceed the value assumed in the analyses;

i U.S. Nuclear Regulatory Commission Page 3 August 25, 1997

~ The use of containment overpressure was previously part of the BFN licensing basis. Staff approval was documented in Section 6.7, Net Positive Suction Head (NPSH) to RHR and Core Spray Pumps, in the original Safety Evaluation of the Tennessee Valley Authority Browns Ferry Nuclear Plant Units 1, 2 and 3, dated June 26, 1972;

~ The use of containment overpressure has been approved by the staff on other dockets.

Enclosure 2 is a summary of the commitments made in this letter. If you have any questions, please telephone me at (205) 729-2636.

Sincerel T. E. Ab y Manager of 'nsi g and In stry Aff irs Subscribed nd sworn before me on this Day of August 1997.

Notary Public Sg QQQQitsJRb EÃpfcs 10/06%5 My Commission Expires

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U.S. Nuclear Regulatory Commission Page 4 August 25, 1997 Enclosures cc (Enclosures):

Mr. Mark S. Lesser, Branch Chief U.S. Nuclear Regulatory Commission 61 Forsyth Street, S.W.

Suite 23T85 Atlanta,, Georgia 30303 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road, Athens, Alabama 35611 Mr. J. F. Williams, Project Manager U.S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852

I+I ENCLOSURE 1 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNIT,2 NRC BULLETIN 96-03 POTENTIAL PLUGGING OF EMERGENCY CORE COOLING SUCTION STRAINERS BY DEBRIS IN BOILING-WATER REACTORS Recent discussions with the staff have indicated that TVA's proposed use of containment over pressure should be addressed as a license amendment. TVA is in the process of preparing this license amendment request,. This enclosure provides TVA's justification for delayed implementation of the final resolution to NRC Bulletin 96-03 on Unit 2 until December 31, 1998, or when the staff approves and TVA implements the license amendment that incorporates the use of containment overpressure into the BFN licensing basis, whichever is sooner.

BACKGROUND On May 11, 1993, NRC issued Bulletin 93-02 (Reference 1),

which notified licensees of a previously unrecognized contributor to the potential loss of net positive suction head (NPSH) for the Emergency Core Cooling Systems (ECCS) during the recirculation phase of a loss of coolant accident (LOCA). The filtering of corrosion products, dust, fibrous thermal insulation, debris, and other temporary material may cause an unexpected rapid loss of net positive suction head for the ECCS pumps when they are needed to perform their intended function. Li;censees were requested to identify fibrous air filters or other temporary sources of fibrous material, not designed to withstand a LOCA, which are installed or stored within the primary containment and take prompt action to remove any such material.

TVA responded to the bulletin on May 23, 1993, (Reference 2). As a result of the bulletin, TVA performed a walkdown of the Unit 2 drywell (primary conta'inment) and found no temporary or permanently installed fibrous air filters or other sources of fibrous material not designed to withstand a LOCA. The piping inside the drywell is insulated with reflective metal insulation which is not a potential source of fibrous material. Subsequently, TVA identified fibrous material in the drywell. TVA discussed these findings in a letter dated December 1, 1994,

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(Reference 5). Specifics of the findings are described later in this enclosure.

On February 18, 1994, NRC issued Supplement 1 to Bulletin 93-02 (Reference 3). The staff's, ongoing review of this issue suggested that the previous method of estimating the fragmentation of insulation materials may not be representative of the large break LOCA scenario. As such, the extent of debris generation due to a jet impingement from a postulated pipe break may have been underestimated.

Small particles of fibers, in combination with debris, have been found to significantly increase the pressure drop across strainers.

On April 18, 1994, TVA responded to Supplement 1 to NRC Bulletin 93-02 (Reference 4). In the letter, TVA committed to implement changes that would minimize the risk of clogging of the suppression pool strainers and provide the Operator with the means to identify possible strainer clogging and the mitigating actions. In addition:

TVA augmented the Operator's required reading program, conducted classroom and simulator training, revised appendices in the BFN Emergency Operating Instructions (EOI), and changed the applicable design procedures to control the amount of fibrous material introduced into the drywell area through changes in the facility design.

Information Notices 88-28, 90-07, 92-71, 93-34, Supplement 1 to 93-34 and TVA's response, to Bulletin 93-02 Supplement 1 were included in the Operator's required reading program.

TVA conducted classroom training on the symptoms of ECCS strainer blockage and the mitigating actions allowed by the BFN EOIs. In addition, simulator demonstration training was observed by the Operators in order to illustrate the indications of ECCS strainer blockage.

Applicable EOI appendices were revised to include a precautionary statement warning the Operator that continuous operation of the low pressure injection system pumps with inadequate NPSH may result in pump damage or pump inoperability. The Operator is instructed to monitor NPSH using an attachment to the EOI appendices that contains a NPSH limit curve, showing pump flow versus suppression pool temperature

i for various suppression pool pressures. The attachment also lists additional indications of inadequate NPSH.

Operators are trained on these procedures as part of their periodic requalification program.

~ Site Standard Practice (SSP)-9.3, "Plant Modifications and Design Change Control," was revised to require that any proposed addition of fibrous material in the drywell be coordinated with the Lead Mechanical Nuclear Engineer in accordance with Browns Ferry Engineering Procedure (BFEP) Project Instruction (PI)89-06, "Design Change Control." BFEP PI 89-06 requires an evaluation of fibrous material being introduced into the drywell that could become dislodged during a LOCA or other event and contribute to ECCS strainer blockage.

Also, in the April 18, 1994, letter, TVA detailed an administrative program utilized as part of our defense in depth. The program ensures maintenance activities will not introduce debris that could induce clogging of the ECCS strainers and affect ECCS pump performance. Site Standard Practice-12.8, "Foreign Material Exclusion," provides the requirements for maintaining cleanliness by preventing uncontrolled introduction of foreign material into open systems that lead to the torus.

In the original response to Supplement 1, dated April 18, 1994, (Reference 4), TVA stated that a walkdown had been performed on Unit 2 which confirmed there were no permanently or temporarily installed fibrous material not approximately 190 8

ft'f asbestos, 35 ft'f designed to withstand a LOCA. Subsequently, TVA identified ft'f fiberglass, and calcium silicate (which is 95 percent non-fibrous) in the drywell penetrations. The Unit 2 drywell contains an additional approximate two square foot piece of encapsulated fibrous insulation for thermal protection of a cable. TVA detailed these findings on Unit 2 in a letter dated December 1, 1994, (Reference 5). NRC was informed of completion of the Unit 3 walkdown in a letter dated

'February 8, 1996, (Reference 6). This walkdown identified similar amounts of fibrous material inside the Unit 3 drywell penetrations.

On October 17, 1995, NRC issued Bulletin 95-02 (Reference 7). TVA responded to the bulletin detailing steps to ensure the operability of the ECCS pumps in a letter dated November 15, 1995, (Reference 8). In doing so, TVA committed to clean the Unit 3 suppression pool, and perform a confirmatory inspection and test prior to Cycle 7

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operation. TVA also committed to visually inspect the Unit 2 suppression pool including the ECCS ring header strainers during the Cycle 8 Refueling Outage and develop a program for suppression pool cleaning.

When Bulletin 95-02 was issued, Unit 3 was in the final stages of recovery from an extended outage. As part of the recovery effort, the Unit 3 torus was cleaned, the coatings were confirmed acceptable or repaired as needed. The torus was then filled with condensate water. The Unit 3 suppression pool was verified clean and a confirmatory test was completed prior to restart from the outage. TVA notified NRC that this action was completed in a letter submitted February 8, 1996, (Reference 6).

The Unit 2 suppression pool and ECCS strainers were cleaned during the Unit 2 Cycle 7 Refueling Outage in October 1994.

During the Cycle 8 Refueling Outage, divers performed an underwater visual inspection of the Unit 2 torus and ECCS strainers. They removed any debris that could contribute to strainer blockage. TVA detailed the results of this inspection in a letter submitted April 19, 1996, (Reference 9). TVA found that the overall clarity of the water was good, and a minimal amount of sediment was identified in the torus. The divers retrieved small items from the pool floor, which included small pieces of masking tape, small pieces of paper, plastic tie wraps, and small pieces of wire.

By letter dated November 4, 1996, (Reference 10), TVA provided a detailed justification for an extension to the implementation of the final resolution to Bulletin 96-03 for Unit 3. This justification included:

The operator training program was augmented with required reading, and enhanced classroom and simulator training.

The BFN Emergency Operating instruction Appendices were revised. This provides the operator with the means to identify potential ECCS strainer clogging and implement mitigating actions.

The Foreign Material Exclusion Program requires cleanliness be maintained by preventing uncontrolled introduction of foreign material into open systems that lead to the torus.

~ TVA performs a visual inspection of the ECCS Strainers

0 during refueling outages. The inspection includes an examination of the suppression pool for sludge and debris that could potentially lead to ECCS strainer clogging. If the inspection results indicate desludging is necessary, TVA will desludge the suppression pool. Prior to the inspection, the ECCS pumps will have been operated to allow available material to be drawn to the strainers.

By letters, dated January 29, and February 19, 1997, (References 11 and 12), the staff approved TVA's request for deferral of actions requested by Bulletin 96-03 until December 31, 1998 for Unit 3, based upon the determination that TVA's compensatory actions provide confidence of continued safe operation with the existing strainers.

As discussed in TVA's July 25, 1997, letter (Reference 13),

TVA's approach to resolve this issue is to install new, larger, higher debris capacity, passive strainers. These strainers will be installed in Unit 2, during the Fall 1997 outage (Cycle 9). TVA's calculations for the resolution of this bulletin ensure that the debris loading postulated in Regulatory Guide 1.82, Revision 2, will not result in an available net positive suction head (NPSH) below the required NPSH for the ECCS pumps during a postulated loss of coolant accident (LOCA) event. These calculations determined that containment over pressure in excess of atmosphere is required to maintain adequate ECCS pump NPSH.

II. JUSTIFICATION FOR UNIT 2 DEFERRAL As discussed above, the staff approved TVA's request for deferral of actions requested by Bulletin 96-03 until December 31, 1998 for Unit 3. The new, larger, higher debris capacity strainers will be installed in Unit 2, during the Fall 1997 outage"'Cycle 9), under the provisions of 10 CFR 50.59. This outage is currently scheduled to begin on September 26, 1997. TVA has previously implemented compensatory actions to provide confidence in the continued safe operation of the facility until the issue is completely resolved. These included:

TVA previously committed to install the new strainers on Unit 2 during the Fall 1'997 outage as part of its July 25, 1997 submittal.

Therefore, this is not considered a new commitment.

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~ Augmented operator training program, 'that included required reading, and enhanced classroom and simulator training.

~ Revised BFN Emergency Operating Instructions that provide the operator with the means to identify potential ECCS strainer clogging and implement mitigating actions.

In addition to the installation of the larger strainers on Unit 2, TVA will also implement similar compensatory actions as those previously approved on Unit 3 for the Spring 1997 outage. These include:

~ Continuing to implement the Foreign Material Exclusion Program, which requires cleanliness be maintained by preventing uncontrolled introduction of foreign material into open systems that lead'o the torus.

~ Performing a thorough drywell and suppression pool inspection (including the vents, downcomers, and ECCS suction strainers) during the refueling outage to verify that all foreign material such as maintenance tools, equipment, construction materials and miscellaneous debris has been removed. TVA will desludge the suppression pool, if necessary.

~ Performing an inspection in the drywell to verify that the insulation is securely fixed in order to minimize the potential for debris generation during a LOCA.

The installation of the new strainers and the compensatory actions discussed above will:

~ Increase the plants capacity to tolerate debris while maintaining adequate NPSH for ECCS pumps;

~ Reduce the potential debris generated during a LOCA; and

~ Enhance operators'bility to identify potential ECCS strainer clogging and implement mitigating actions.

~ i III. CONCLUSION Recent discussions with the staff have indicated that TVA's proposed use of containment over pressure should be addressed as a license amendment. TVA is in the process of preparing this license amendment request. However, in order to accommodate the time frames necessary for the final resolution of the Bulletin for Unit 2', TVA requests the schedule for the completion of this activity be revised to December 31, 1998, or when the staff approves and TVA implements the license amendment that incorporates the use of containment overpressure into the BFN licensing basis, whichever is sooner. TVA considers this schedule extension acceptable since:

TVA's compensatory actions provide confidence of continued safe operation of Unit 2; Containment overpressure is a byproduct of the conditions which will exist in the containment after the pipe break inside containment; The use of containment overpressure .was previously part of the BFN licensing basis. Staff approval was documented in Section 6.7, Net Positive Suction Head (NPSH) to RHR and Core Spray Pumps, in the original Safety Evaluation of the Tennessee Valley Authority Browns Ferry Nuclear Plant Units 1, 2 and 3, dated June 26, 1972; and 1

The use of containment overpressure has been approved by the staff on other dockets.

IV. REFERENCES

1. NRC letter to all holders of Operating Licenses or Construction Permits for Nuclear Power Reactors, dated May 11, 1993 NRC Bulletin No. 93-02: Debris Plugging on Emergency Core Cooling Suction Strainers

2. TVA letter to NRC, dated May 23, 1993 NRC Bulletin No. 93-02, Debris Plugging of Emergency Core Cooling Suction Strainers

3. NRC letter to all holders of Operating Licenses or Construction Permits for Boiling-Water and Pressurized-Water Reactors, dated February 18, 1994 NRC Bulletin

0 TVA letter to NRC, dated'pril 18, 1994 NRC Bulletin No. 93-02 Supplement 1, Debris Plugging of Emergency Core Cooling:Suction Strainers TVA letter to NRC, dated December 1, 1994 Debris Plugging of Emergency Core Cooling Suction System (ECCS),Strainers TVA letter to NRC, dated February 8, 1996 Completion Status of Unit 3 Restart Issues Revision 3 NRC letter to all holders of Operating Licenses or Construction Permits for Nuclear Power Reactors, dated October 17, 1995 NRC Bulletin No. 95-02: Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer While Operating in The suppression Cooling Mode TVA letter .to NRC, dated November 15, 1995 NRC Bulletin No. 95-02: Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer While Operating in The suppression Cooling Mode TVA letter to NRC, dated April 19, 1996 NRC Bulletin No. 95-02: Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer While Operating in The Suppression'Pool Cooling Mode TVA letter to NRC, dated November 4, 1996 NRC Bulletin No. 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors NRC letter to TVA, dated January 29, 1997 Response to Bull'etin 96-03 NRC letter to TVA, dated February 19, 1997 Response

.to Bulletin 96-03 TVA letter to NRC, dated July 25, 1997 Potential Plugging of'mergency Core Cooling Suction (ECCS)

Strainers by Debris in Boiling.-Water Reactors E1-8

0 Qi E ENCLOSURE 2

'TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNIT 2 NRC BULLETIN 96-03 POTENTIAL PLUGGING OF EMERGENCY CORE COOLING SUCTION STRAINERS BY DEBRIS IN BOILING-WATER REACTORS

SUMMARY

OF COMMITMENTS

1) TVA will perform a thorough drywell and suppression pool inspection (including the vents, downcomers, and ECCS suction strainers) during the refueling outage to verify that all foreign material such .as maintenance tools, equipment, construction materials and miscellaneous debris has been removed. TVA will desludge the suppression pool, if necessary.

2) TVA will perform an inspection. in the drywell to verify that the insulation is securely fixed in order to minimize the potential for debris generation during a LOCA.

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Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 October 28, 1999 U.S. Nuclear Regulatory Commission ATT.: Document Control Desk Washington, D.C. 20555 Gentlemen:

In the Matter of Docket Nos. 50-260 Tennessee Valley Authority 50-.296 BROWNS FERRY NUCLEAR PLANT (BFN) NRC BULLETIN NO. 96-03, POTENTIAL PLUGGING OF EMERGENCY CORE COOLING SUCTION (ECCS)

STRAINERS BY DEBRIS IN BOILING-WATER REACTORS (TAC NOS. M96136 AND M96137)

This letter provides notification of actions completed by TVA to resolve issues described by the subject bulletin. BFN has implemented modification Option 1 of Bulletin 96-03, installation of a large passive strainer design. The ECCS suction strainers in both Units 2 and 3- have been replaced

,with a high capacity, passive, "stacked disk" strainer configuration. The replacement strainer design was governed by the Boiling Water Reactor Owner Group (BWROG) Utility Resolution Guidance (URG) (General Electric NEDO-32686) and is consistent with Regulatory Guide 1.82, Revision 2, "Water.

Sources for Long-term Recirculation Cooling Following A Loss-Of-Coolant Accident."

Il r

U.S. Nuclear Regulatory Commission

~

Page 2 October 28, 1999 TVA modified the plant by installing the new strainers under the provisions of 10 CFR 50.59. These were installed on Unit 2 in 1997 and on Unit 3 in 1998.

As part of the design review for resolution of the NRC bulletin, TVA determined that containment pressure in excess of atmospheric (containment overpressure) was required to maintain adequate net positive suction head (NPSH) for the low pressure ECCS pumps. Since credit for containment overpressure was not part of BFN's licensing basis, by letter dated September 4, 1998 (Reference 1), TVA requested an amendment to the Units 2 and 3 license to utilize the available containment overpressure to maintain adequate net positive suction for the low pressure ECCS pumps.

By letter dated September 3, 1999 (Reference 2), NRC request to amend the BFN license, allowing the use of granted'VA's containment overpressure to support NPSH requirements for the low pressure ECCS pumps. TVA has implemented the licensee amendment by revising the BFN Updated Final Safety Analysis Report.

In response to NRC Bulletin 95-02 dated, October 17, 1995 (Reference 3), Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer While Operating ln The Suppression Cooling Mode, TVA developed a program for suppression pool cleaning.

The program, maintains the suppression pool such that the requirements set forth by the BWROG URG. are satisfied.

Based on the previous discussion, TVA believes that NRC Bulletin .96-03 should be closed for BFN Units 2 and 3. There are no commitments contained in this letter.

~ '

U. S. Nuclear Regulatory Commission Page 3

'October 28, 1999 If you 729-2636.

have any questions regarding this please contact me at (256)

S'e 4

T. E. Abney Manager of icensin and Ind stry Affair Subscribe d swor efore me on this Q of ,1999.

Notary Public My Commission expires: 2002

~I U.S. Nuclear Regulatory Commission Page 4 Oct:ober 28, 1999 RE FERENCE S TVA Letter to NRC Dated September 4, 1998, Browns Ferry Nuclear Plant Units 2 And 3 license Amendment Regarding, Use of Containment Overpressure For Emergency Core Cooling System (ECCS) Pump Net Positive Suction Head (NPSH) Analysis

2. NRC Letter to NRC Dated September 3, 1999, Browns Ferry Nuclear Plants, Units 2 and 3 Issuance Of Amendments regarding Crediting Of Containment Overpressure For Net Positive Suction Head Calculations For Emergency Cooling pumps (Tac Nos. MA3492 and MA3493)

3. NRC Letter To TVA Dated October 17, 1995, NRC Bulletin 95-02: Unexpected Clogging Of A Residual Heat Removal (RHR') Pump Strainer While Operating. In Suppression Pool Mode.

4l U.S. Nuclear Regulatory Commission Page 5 October 28, 1999 cc: Mr. William 0 Long, Senior Project Manager U. S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville. Pike Rockville, Maryland 20852 Mr. Paul E. Fredrickson, Branch Chief U.S. Nuclear Regulatory Commission Region II 61 Forsyth Street, S. W.

Suite 23T85 Atlanta, Georgia 30303 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611

II l591) 05 1999

Distri68.txt Distribution Sheet Priority: Normal <7(v <Y From: Elaine Walker Action Recipients: Copies:

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'NRR/DSSA/SPLB 1 Not Found NRR/DRIP/REXB Not Found NRR/DIP M/IO~LB 1 Not Found C~F;ILE;CENTER 1 Not Found ACRS Not Found External Recipients:

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Subject:

BROWNS FERRY NUCLEAR PLANT (BFN) UNIT 2 - DOCKET 50-260 - FACILITYOPERA Page 1

1ll i

Distri68.txt TING LICENSE DPR LICENSEE EVENT REPORT (LER) 50-260/1999411'-000 Body:

PDR ADOCK 05000260 q Docket: 05000260, Notes:. N/A

-Page 2

0 41 Tennessee Valley Authority, Post Office Box 2000, Decatur. Alabama 35609.2000 Johit-T. Henon Vice President, Browns Feny Nucfear Pfant December 17, 1999 U.S. Nuclear Regulatory Commission 10 CFR 50.73.

ATTN: Document Control Desk Washington, D. C. 20555

Dear Sir.:

BROWNS FERRY NUCLEAR PLANT (BFN) UNIT 2 DOCKET 50-260 FACILITY OPERATING LICENSE DPR-52 LICENSEE EVENT REPORT (LER) 50-260/1999-011-000 The enclosed report provides details concerning the Unit 2 High Pressure Coolant Injection System being made inoperable due to an oil system breach during corrective maintenance.

This condition is reportable in accordance, with 10 CFR 50.73 (a)(2)(v) as a condition that alone could have prevented the fulfillment of the safety function of a structure or system needed to mitigate the consequences of an accident. There are no commitments contained in this letter.

Sincerely, J hn T. H erron CC ,See page 2

U.S. Nuclear Regulatory Commission Page 2 December 17', 1999 Enclosure cc (Enclosure):

Mr. William O. Long, Senior Project Manager

• U.S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Mr. Paul E. Frederickson, Branch Chief U.S. Nuclear Regulatory Commission Region II Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611

ll NRCP'QRM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104 EKFIREs IB-1999) oelsonoos Estimated burden per response to compty with th(s mandatory informst)on LlCENSEE EVENT REPORT (LER) the ricensing process and fed ~

coeection request; 50 hrs. Reported lessons learned are hcorpmted into to industry. Forward comments regarding burden estimate to the Records Management Branch (TA F33), V.S.

Nudear Regulatory Commission, Washington, OC 205554001. and to the (See reverse for required number of Paperwork Reduction Project (315(W)104), 05ce of Management and digits/characters for each block) Budget, Washington, OC 20503. If an informat)on cogecem does not display a cunently valid OMB control number. the NRC may not conduct or sponsor, and a pefsofl is not requ(red to fespofld 'to, the hfoAllsbon

)ec()0IL FACIUTY NAME ll) OOCKET NUMBER (2) PACE (3)

Browns Ferry Nuclear Plant Unit 2 05000260 1 of5 Trrtz (4)

High Pressure Coolant'Injection IHPCI) Inoperable Due To Oil System Breach EVENT DATE (5) LER NUMBER (6) REPORT DATE (7) 0 H R FACILITIES N 0 ED 6 MONTH OAY YEAR YEAR SEQUENTIAL REVISION ILI OOCKET NUMBER NUMBER NUMBER NA OOCKET NUMBER 18 99 1999 011 000 12 17 99 NA NA OPERATINe THIS REPORT IS SUBMITTED PURSUAN T To THE REQUIREMENTS OF 10 CFR 5: (Check one or moro) (11)

MODE (9) 20. 2201 (b) 20.2203(a)(2) (v) 50.73(a) (2) (i) (B) 50.73(a)(2)(viii)

POWER 20.2203(a)(1) 20.2203(a)(3) (i) 50.73(a)(2)(ii) 50.73(a)(2)(x)

LEVEL (10) 100 20.2203(a) (2)(i) 20. 2203(a) (3) (ii) 50.73(a)(2) (iii) 73.71

20. 2203(a) (2) (ii) 20.2203(a) (4) 50.73(a)(2)(iv) OTHER 20.2203(a) (2) (iii) 50.36(c)(1) 50.73(a)(2)(v) Specify in Abstract below or in NAC Form 366A 20.2203(a) (2) (iv) 50.36(c)(2) 50.73(a) (2)(vii)

LICENSEE CONTACT FOR THIS LER (12)

NAME TELEPHONE NUMBER (Include Ares Code)

Gerald F. Moody, Licensing Project Manager (256) 729-7534 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13)

CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE NPROS TO NFROS SUPPLEMENTAL REPORT EXPECTED (14) EXPECTED MONTH OAY YEAR YES No SUBMISSION X DATE (15)

(If Yes, complete EXPECTED SUBMISSION DATE).

ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16)

On November 18, 1999, at approximately 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> Central Standard Time (CST) work was begun to replace the Unit 2 High Pressure Coolant Injection (HPCI) System Oil Cooler Discharge Temperature Switch TS-73-52. This switch is used to monitor the HPCI System oil temperature and actuates a control room alarm if HPCI system oil temperature reaches the alarm set point. During the switch replacement, the switch cover was removed, the wires were lifted and the switch was extracted. Instrument Maintenance (IM) craftsmen then noticed the presence of oil on the switch. Inspection of the mounting location for the switch revealed that the oil system had been unexpectedly breached. Contrary to the Unit 3 drawing provided in the work package and a local tag that indicated the presence of a thermo-well, there was no thermo-well in place for mounting the switch. The Unit 2 drawing correctly indicated no thermo-well. The IM craftsmen installed the new switch, obtained the necessary pipe sealant and sealed the penetration. The HPCI oil system was breached for approximately 5.minutes. The. event was caused by inattention to detail during the planning of the activity. On November 22, 1999, it was determined that HPCI had'been inoperable during the time the oil system was breached. This condition was reported to the NRC pursuant to 10 CFR 50.72 (b) (iii) (D). This report is submitted pursuant to 10CFR 50.73 (a) (2) (v) as a condition that alone could have prevented the fulfillment of the safety function of a structure or a system needed to mitigate the consequences of an accident.

NRC FORM 366B (6-1999)

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NRCFORM 36QA U.S. NUCLEAR REGULATORY COMMISSION (6-1998)

LICENSEE EVENT REPORT (LER)

"TEXT CONTINUATION FACILITY NAME 1 DOCKET LER NUMBER 6 PAGE 3 YEAR SEQUENTIAL 'EVISION NUMBER 2 of 5 ~

Browns Ferry Nuclear Plant - Unit 2 05000260 1999 011 000 TEXT fifmore spaceis required. use addidonal copies of NRC Form 366AJ )17)

I. PLANT CONDITIONS At the time of this event, Unit 2 was at 100 percent power, approximately 3458 Megawatts thermal. Unit 3 was at 100 percent power, approximately 3458 Megawatts thermal. Unit 1 was shutdown and defueled.

II. DESCRIPTION OF EVENT A. Event:

On November 18, 1999, at approximately 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> Central Standard Time (CST) work was begun to replace the Unit 2 High Pressure Coolant Injection (HPCI) [BJ] System Oil Cooler Discharge Temperature Switch [TS] TS-73-52. This switch is used to monitor the HPCI System oil temperature and actuates a control, room alarm if HPCI system oil temperature reaches the alarm set point.

During the switch replacement, the switch cover was removed, the wires were lifted'and the switch was extracted. Instrument Maintenance (IM) craftsmen then noticed the presence of oil on the switch.

Inspection of the mounting location for the switch revealed that the oil system had been unexpectedly breached. Contrary to both the drawing provided in the work package and a local label that indicated the presence of a thermo-well for mounting the temperature switch, when in fact there was no thermo-well mounting for the temperature switch. The IM craftsmen installed the new switch pipe temporarily until sealant could be obtained. After obtaining the necessary pipe sealant the temperature switch was permanently installed and sealed. The HPCI oil system was breached for approximately 5 minutes.

The workers returned to the shop to complete the pape)work associated with the job at approximately 1730 hours0.02 days <br />0.481 hours <br />0.00286 weeks <br />6.58265e-4 months <br />. A Problem Evaluation Report was initiated by the IM supervisor to document what was initially perceived by the craft personnel as a Drawing Discrepancy. At approximately 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br />, Operations personnel were informed of the as-found field condition. Further investigation into the event revealed that the controlled drawing that had been included in the work package was a drawing for the Unit 3 HPCI system. The issue was not discussed with the off going STA or Shift Manager as this occurred during turnover and they had already been relieved. The oncoming Unit Supervisor was told that the problem had been evaluated and that there were no operability concerns. The oncoming STA reviewed the problem evaluation report and also found no operability issues.

On November 22, 1999, after further review, it was determined that the HPCI System had been made inoperable during the breach of the oil system. TVA made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> report to the NRC in accordance with 10 CFR 50.72 (b) (iii) (D). This report is submitted pursuant to 10CFR 50.73 (a) (2) (v) as a condition that alone could have prevented the fulfillment of the safety function of a structure or a system needed to mitigate the consequences of an accident.

B. Ino erable Structures Com onents or S stems that Contributed to the Event:

None.

NRC FORM 366 I6-1998)

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NRCPORM 366A 0 U.S. NUCLEAR REGULATORY COMMISSION (6-1998I LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 1 OOCKET LER NUMBER 6 PAGE 3 YEAR SEQUENTIAL REVISION NUMBER 3 of 5 Browns Ferry Nuclear Plant - Unit 2 05000260 1999 011 000 TEXT (Ifmore space is required, use additional copies of IVRC Form 366A / I17I C. Dates and A roximate Times of Ma or Occurrences:

November 18, 1999 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> CST Work began to replace Unit 2 temperature switch 2-TS-73-52.

November 18, 1999 1715 hours0.0198 days <br />0.476 hours <br />0.00284 weeks <br />6.525575e-4 months <br /> CST Craftsmen recognized the oil system had been breached. The new switch was temporarily installed to close, the system.

November 18, 1999 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br /> CST Operations was notified of the oil system breach.

November 22, 1999 2218 hours0.0257 days <br />0.616 hours <br />0.00367 weeks <br />8.43949e-4 months <br /> CST Subsequent review revealed that this event had resulted in HPCI system inoperability and therefore was reportable. TVA made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency report to the NRC in accordance with 10 CFR 50.72 (b) (iii) (D).

D. Other S stems or Seconda Functions Affected:

None.

E. Method of Discove The breach of the HPCI oil system was discovered after removing the temperature switch from the lubricating system piping, F. 0 erator Actions No operator actions contributed to this event.

G. Safe S stemRes onses None.

ill. CAUSE OF THE EVENT A. Immediate Cause The HPCI oil system was breached causing the system to be inoperable.

NRC FORM 366 I6-1998)

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NRCSORM 36/A U.S. NUCLEAR REGUI.ATORY COMMISSION i6-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITY NAME 1 DOCKET LER NUMBER 6 PAGE 3 YEAR SEOUENTIAL REVISION NUMBER 4 of 5 Browns Ferry Nuclear Plant - Unit 2 05000260 1999 011 " 000 TEXT Iifmore space is required, use addi dona/ copies of NRC Form 366A) I17I B. Root Cause The root cause of this event was the use of the wrong unit (Unit 3) controlled drawing in the work order package as a result of inattention to detail. (cognitive error) by the maintenance planner [utility, non-licensed]. The Unit 3 drawing correctly showed the presence of a thermo-well for the Unit 3 HPCI system, which when used to plan the Unit 2 corrective maintenance, led to the incorrect conclusion that there was a thermo-well present in Unit 2. The Unit 2 drawing correctly indicated no themo-well.

The incorrect label that indicated the presence of a thermo-well contributed to this event. There were no other unusual characteristics in the work location that would have contributed to this event. No procedures errors contributed to this event.

IV. ANALYSIS OF THE EVENT During this event, personnel exhibited a lack of attention to detail as well as a lack of a questioning attitude.

This is evidenced by reviews of the work package which failed to identify the incorrect unit controlled drawing. However, when the craft personnel performing the work realized that the oil system piping had been breached, they installed new switch to temporarily close the oil system until pipe sealant could be obtained and applied. Additionally, they immediately notified their supervisor of their findings. The HPCI lubricating oil system was breached. for less than the 5 minute total time period. With the lubrication system breached, the oil system would not attain designed pressure. Initial reviews by Operations did not identify any operability or- reportability issues with this event. Upon further review, it was determined that HPCI had been inoperable during the time the oil system was breached. Therefore, this condition was reportable to the NRC.

V.. ASSESSMENT OF SAFETY, CONSEQUENCES The HPCI system is designed to ensure that the reactor is adequately cooled to limit fuel cladding temperature in the event of a small pipe break in the nuclear system and a resulting loss of coolant which does not rapidly depressurize the reactor vessel. The HPCI system permits the nuclear plant to be shut down while maintaining sufficient reactor vessel water inventory until the reactor vessel is depressurized.

The HPCI system continues to operate until the reactor vessel is below the pressure at which Low Pressure .

Coolant injection (LPCI) [BO] operation or Core Spray (CS) [BM] operation maintains core cooling. In the event HPCI is not available or not sufficient to maintain reactor water level, the Automatic Depressurization System (ADS) [SB] functions to reduce reactor pressure so that flow from the LPCI and CS enters the reactor vessel in time to cool the core and,limit fuel cladding temperature.

BFN Technical Specifications allow continued reactor operation for up to fourteen days if HPCI is inoperable, provided the ADS, CS, LPCI and Reactor Core Isolation Cooling (RCIC) [BN] systems are operable. RCIC provides an alternate supply of high pressure reactor coolant makeup while ADS would depressurize the reactor to allow CS and LPCI to provide adequate low pressure ECCS makeup to the reactor. The availability of these redundant and diversified systems provides adequate assurance of core cooling while the HPCI system is inoperable. During this event HPCI was inoperable approximately 5 minutes out of the fourteen days allowed by the Technical Specifications LCO. The above required systems were operable and would have performed their-designed function if called upon. Accordingly, there was no significant reduction in the degree of protection provided to the public health and safety.

NRC FORM'366 I6-1998)

gr NR~ORMNE@A U.S. NUCLEAR REGULATORY COMMISSION Ie-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITYNAME 1 DOCKET LER NUMBER 6 PAGE 3 YEAR SEQUENTIAL REVieiON NUMBER 5 of 5 Browns Ferry Nuclear Plant - Unit 2 05000260 1999 - 011 000 TEXT (If more space is reqvired, vse edditionel copies of ItIRC Form 366AJ I17)

VI. CORRECTIVE ACTIONS A. Immediate Corrective Actions Upon discovery of the condition, the new temperature switch was temporarily installed to close the breach of the HPCI oil system.

B. Corrective Actions to Prevent Recurrence Human Performance stand down briefings were conducted with the appropriate Operations, Maintenance, Scheduling and Work Control personnel. Additionally, briefin~s will be held with appropriate plant personnel on the lessons learned as a result of this event.

The incorrect label that indicated the presence of a thermo-well was removed from the Unit 2 temperature switch.

VII. ADDITIONAL,INFORMATION A. Failed Com onents None.

B. Previous LERs on Similar Events A review was performed of previous LERS for. events resulting from inattention to detail during work planning, and none were identified.

C. Additional Information None.

D. Safet S stemFunctional Failure:

This event resulted in a safety system functional failure in accordance with draft NEI 99-02 Revision D.

Vill. COMMITMENTS None.

Energy Industry Identification System (EIIS) system and component codes are identified in the text by brackets (e.g., [XX)).

'VAdoes not consider these corrective actions regulatory commitments. The completion of these items will be tracked in TVA's Corrective Action Pro ram.

NRC FORM 366 (6-1998l

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