ML20149M792

Responds to NRC Re Violations Noted in Insp Repts 50-327/96-13 & 50-328/96-13.Corrective Actions:Replaced Motor & Brake for Mfiv 2-FCV-3-100,repaired Leaking Rubber Hoses & Installed Spray and Excess Shields

ML20149M792
Person / Time
Site:	Sequoyah
Issue date:	01/23/1997
From:	Zeringue O TENNESSEE VALLEY AUTHORITY
To:	Lieberman J NRC OFFICE OF ENFORCEMENT (OE)
References
NUDOCS 9701280001
Download: ML20149M792 (30)

Text

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Tennessee Valley Authority Post Cftce Bc4 2000 SocceDae, Tennessee 37379 January 23,1997 Mr. James Lieberman Director, Office of Enforcement U.S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 Gentlemen:

In the Matter of ) Docket Nos. 50-327 Tennessee Valley Authority ) 50-328 SEQUOYAH NUCLEAR PLANT (SON) - REPLY TO NOTICE OF VIOLATION (NOV) AND PROPOSED IMPOSITION OF CIVIL PENALITIES - NRC INSPECTION REPORT NOS, 50-327, 328/96 ENFORCEMENT ACTION 96-414 This letter responds to Stewart D. Ebneter's letter to Oliver D. Kingsley, Jr., dated December 24, 1996, that transmitted the subject NOV. The NOV cites six violations and includes two civil penalties. The first three violations were associated with equipment problems experienced during the October 11, 1996, shutdown of SQN Unit 2. Violations A(1) and A(2) involve the failure to take action to preclude repetition of an equipment failure associated with a main feedwater i isolation valve and reactor coolant pump seal return isolation ,

valve solenoid valve. Violation A(3) addresses the failure to i develop an adequate corrective action plan for an inadvertent fire protection system deluge actuation. These "A" violations were classified in the aggregate as a Severity Level III problem. The second group of three violations involved problems related to the maintenance of a reactor trip breaker. .

Violation B(1) involves inadequate maintenance and testing of )

the reactor trip breaker. Violation B(2) involves a failure j to comply with technical specification requirements

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j U.S. Nuclear Regulatory Commission Page 2 January 23, 1997 relative to operable reactor trip channels. Violation B (3) identifies a failure to perform an immediate operability and reportability determination. These "B" violations were also classified in the aggregate as a Severity Level III problem.

The NRC proposed separate $50,000 civil penalties for each 4 Severity Level III problem.

1 I. INTRODUCTION TVA met with the NRC in a predecisional enforcement conference in NRC's region II office on December 16, 1996. During that conference, TVA discussed the Unit 2 shutdown event and the reactor trip breaker issues in detail. The discussion included an analysis of each apparent violation, its root cause, the corrective actions taken at. planned to address the problem, as well as its safety significance. As part of the conference, TVA also provided a broad perspective on plant material condition and described several initiatives which are ongoing to ensure long-term improvements. As NRC knows, TVA continues to dedicate significant resources to improve material conditicn at SQN. This has been communicated to NRC in past management meetings on August 8, October 8, and November 15, 1996, and was again stressed in the predecisional enforcement conference. TVA believes that the key to success in achieving greater plant reliability lies in its continued, vigorous pursuit of ongoing initiatives, and TVA is committed  !

to completing those initiatives. I During the enforcement conference TVA agreed that six of the

, seven apparent violations cited in NRC Special Inspection j Rcport Nos. 50-327, 328/96-13 occurred. TVA also explained in '

great detail the individual facts and circumstances surrounding each of the apparent violations. After a careful l reading of the subject NOV and inspection report, TVA is l concerned about several apparent misinterpretations of facts )

and mischaracterizations of circumstances that are contained '

in the NOV. Some of these misinterpretations were discussed l l with NRC both prior to and at the enforcement conference.

Their clarification is important to obtaining a complete i understanding of events, their significance, and the adequacy

, of TVA's corrective accions. In addition, TVA also believes that a clearer understanding of the events associated with the October 11, 1996, Unit 2 shutdown and a broader perspective of TVA's corrective action program and material condition

. improvements do not support the characteri.zation of the l violations as a Severity Level III problem.

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U.S. Nuclear Regulatory Commission Page 3 January 23, 1997 II. REPLY TO THE NOTICE OF VIOLATION Pursuant to 10 CFR 2.201, Enclosure 1 provides TVA's reply to ,

the NOV. In the reply, TVA agrecs that the identified deficiencies violate regulatory requirements. The reply provides the following: (1) reason for the violation, (2) corrective steps which have been taken and the results achieved, (3) corrective steps which will be taken to avoid further violations, and (4)the date when full compliance will be achieved. As was discussed in the enforcement conference, TVA took comprehensive corrective actions to address each of these violations and is pursuing ongoing initiatives to improve equipment, systems, and plant reliability.

III. ANSWER TO THE NOTICE OF VIOLATION While TVA agrees that violations of regulatory requirements took place, TVA maintains that the NRC's decision to categorize the three "A" violations associated with the October 11, 1996, Unit 2 shutdown as a Severity Level III problem and impose a base civil penalty amount of $50,000 is inconsistent with the Enforcement Policy. TVA therefore '

respectfully requests, for reasons detailed below, that NRC reconsider its decision to characterize violations A(1), A(2) ,

and A(3) as a Severity Level III problem. Pursuant to the provisions of 10 CFR 2.205, TVA also asks that the associated '

$50,000 civil penalty amount be mitigated in its entirety.

CHARACTERIZATION OF VIOLATIONS A (1) , A(2), AND A (3 ) AS g.EVERITY LEVEL III AND MITIGATION OF THE CIVIL PENALTY NRC's decision to aggregate and then classify these violations as Severity Level III was based on the belief that the violations were commonly linked to the inadequate implementation of TVA's corrective action program as well as the NRC's regulatory concern that problems in ensuring

. effective and timely corrective actions are continuing to occur. As TVA emphasized during the enforcement conference, the current site management team is keenly aware that the quality of past corrective actions is still impacting current performance. It is also the case, however, that the problems associated with the corrective action program are being aggressively addressed by ongoing improvement. initiatives.

TVA's comprehensive actions greatly mitigate any regulatory significance that might otherwise exist in this area.

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U.S. Nuclear Regulatory Commission page 4 January 23, 1997 Furthermore, even if the events are viewed in the aggregate as .

a Severity Level III problem, TVA's actions in this area warrant mitigation of the civil penalty.

As early as July 1996, TVA identified the fact that problems i existed with corrective action program implementation. In a management meeting with NRC on August 8, 1996, TVA informed NRC of the top five issues facing the site. One of these issues was that corrective actions did not alwaya achieve problem resolution. Additionally, based on the results of a l previous corrective action program audit that was performed in 1995, TVA Quality Assurance (QA) management accelerated the ,

audit schedule to require a September 1996 audit in the corrective action program area at SQN. The September 1996 audit identified that program implementation was not totally effective. This conclusion was based on QA audit findings, previo1s QA audit results, as well as corrective action issues previorC y identified by NRC. Therefore, although the individual equipment failures associated with the October 11, '

1996, Unit 2 shutdown were identified through an event, the root cause (inadequate corrective action program implementation) was identified by TVA in advance of the equipment failures. NRC's Enforcement Policy specifically recognizes that credit for identification is warranted in those situations where che problem is identified through an event, and the licensee has made a noteworthy effort in determining the root cause associated with the violations.

TVA be'd eves that such credit is especially warranted here, where TVA identified the root cause even before the equipment failures arose and was taking action at the time of and after the failures took place to address that cause.

Since September 1996, site management has initiated a series of improvement initiatives designed to improve corrective a action program effectiveness, and increase employee commitment and ownership of the plant. Highlights of these actions are:

(1) providing root cause analysis training to appropriate ,

< Engineering personnel; (2) increasing Engineering awareness of  !

maintenance and plant activities; (3) increasing Operations and Engineering personnel sensitivity to lower the threshold for identifying plant conditions through management monitoring and coaching in the field; and (4) adding senior management

, review of equipment root cause analyses through the management review committee process in order to reinforce management expectations. The details of many initiatives were discussed

, by the Plant Manager during the enforcement conference, along with evidence supporting the bottom-line conclusion that corrective actions are indeed improving and equipment problems

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4 U.S. Nuclear Regulatory Commission Page 5 January 23, 1997 i

are being fixed. For example, plant vital inverters have been extensively rebuilt, we discovered and corrected the problem preventing appropriate throttle valve / governor valve transfer  !

during unit startups, and condenser circulating water trip circuits were analyzed and reset to prevent trips before switchyard electrical faults could clear.

With regard to Violations A(1), A (2) , and A(3) the NRC specifically credited TVA with " extensive corrective actions to improve (1) plant material conditions, (2) management effectiveness, and (3) implementation of the corrective action program." Paradoxically, the very source of the NRC's concern which warranted aggregation of the violations as a Severity Level III problem and imposition of a $50,000 civil penalty, also serves as the basis for NRC's decision to credit TVA's actions. TVA believes a more reasoned approach would be to cite these violations as separate Severity Level IV violations, or to mitigate any civil penalty based on TVA's identification of the underlying cause of these violations .

prior to their occurrence and TVA's efforts to address the

! issue of regulatory significance: the effectiveness of corrective actions.

1 TVA fails to see the regulatory purpose of pursuing escalated l enforcement and imposing a civil penalty "to emphasize the importance of management oversight of plant activities and the

. need for prompt corrective actions," in an instance where TVA

^

has instituted extensive improvement initiatives and where

' credit for those improvements is expressly recognized by the i NRC. The stated purpose of the NRC's Enforcement Program--to emphasize the importance of compliance and encourage prompt identification and correction of problems--would not be served by pursuing escalated enforcement since TVA has already

demonstrated a full appreciation of the problems at hand through its extensive corrective actions. Moreover, TVA

! believes that the factual situation existing here presents a l strong case for application of a broader perspective which i gives credit to TVA's overall actions to improve the corrective action program as well as plant material condition. i In promulgating the " General Statement of Policy and Procedure for Enforcement Actions," (NUREG-1600), the NRC stated: l l

0 l An underlying basis of this policy that is reflected throughout is that the determination of appropriate sanction requires the exercise of discretion that such enforcement action is tailored to the J particular factual situation. 1 (60 Fed. Reg. 34380, June 30, 1995) l 4

. l U.S. Nuclear Regulatory Commission l Page 6  !

January 23, 1997 j P

.In. exercising discretion to tailor an enforcement action to  :

the particular situation, the NRC has traditionally taken a i much broader view to include consideration of all relevant  ;

factors, including the extent to which the licensee has been  ;

implementing a program to upgrade its performance in the area i Such an approach is  !

in which the violation occurred.

appropriate in this case. Therefore, TVA requests that the l NRC view events in the broader perspective of TVA's improved  !

corrective action program and plant material condition j upgrades in exercising its discretion to mitigate the civil '

. penalty associated with these violations.

CLARIFICATIONS REGARDING VIOLATIONS A(1), A (2 ) , AND A (3) l TVA believes that several clarifications are warranted with respect to the descriptions of violations A(1), A(2), and A(3)  ;

in the NOV. A more accurate description of the events and  !

circumstances surrounding the subject violations helps place j them in the proper context as individual Severity Level IV {

violations.  :

Violation A(1) 1

• Enclosure 1 of the NOV cites TVA's failure to perform adequate evaluations or to take adequate corrective actions  ;

for main feedwater isolation valve (MFIV) failures in January 1989, September 1990, September 1994, and April 1995. This listing of MFIV " failures" oversimplifies the l main,enance history of the subject MFIV. l January 1989 marked the first failure of a MFIV because of corrosion product build-up on the brake. Evaluation of the l equipment failure determined that the condition was an i isolated case. In September 1990, the MFIV failed as a result of brake corrosion. TVA's evaluation determined that moisture intrusion had occurred because of specific  !

valve leaks coupled with a broken flex conduit on the ,

valve. Extensive corrective actions were taken and it was believed that those actions were fully adequate to prevent '

recurrence of the condition. In September 1994, a work document was initiated to perform corrective action on the '

MFIV's broken flex conduit. During performance of this maintenance, it was noted that corrosion was evident on the motor brake, the conduit was repaired and the motor brake i

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U.S. Nuclear Regulatory Commission Page 7 January 23, 1997 was replaced. In April 1995, the MFIV did not initially travel to the closed position on operator demand because of an electrical short circuit. The problem was not associated with motor brake corrosion.

• In a related statement, the NOV cover letter states that the MFIV failed to stroke on four previous occasions. More accurately, the MFIV only failed to stroke on two occasions (January 1989, September 1990) because of brake corrosion.

A third failure occurred (April 1995) because of an electrical problem. A review of the fourth occasion (September 1994) shows that the MFIV was not tested before the start of maintenance work, and thus it cannot be said that it failed to stroke. Rather, during other maintenance activities on the valve, corrosion was noted in the motor brake compartment and the motor brake was replaced in conjunction with other maintenance work.

Violation A(21

• The NOV cover letter states that the failure of the ASCO solenoid valve caused excessive reactor coolant pump (RCP) seal leakage. More accurately, TVA shut down the unit in accordance with procedural guidance applicable to the alarm condition resulting from low No. 1 seal return flow.

Specifically, the closure of the No. 1 seal return flow control valve resulted in the normal No. 1 seal return flow cascading to the Nos. 2 and 3 seals. Overall, total seal flow to the RCP remained stable. The No. 2 RCP seal is designed for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of operation at full RCS pressure to allow operators time to react. As such, the condition to which the No. 2 meal was subjected was within the design condition for that seal.

The NRC cover letter states that a number of other valves l were subsequently determined to be degraded. More accurately, following the October 11, 1996 event, TVA's extent of condition review found no other instances where solenoid valves had failed. The review did identify some solenoid valves containing Buna-N material with signs of aging. As a conservative measure to increase equipment reliability, those solenoid valves were replaced. The replaced solenoid valves were capable of performing their intended function in their "as-found" condition.

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U.S. Nuclear Regulatory Commission Page 8 January 23, 1997

• The NRC cover letter and Enclosure 1 stated that TVA had been alerted to problems with Buna-N by NRC Bulletin 78-14, Generic Letter 91-15, and a SQN Problem Evaluation Report (PER). ' Listing these documents gives the impression that each document directly addressed the problem at hand. This is not the case.

f NRC Bulletin 78-14, " Deterioration of Buna-N Components in ASCO Solenoids" discussed an event at the Monticello Nuclear Power Station. Investigation of the event identified problems with the Buna-N disk in the scram pilot valve solenoid core assembly where the disk had fractured and fragments became wedged between the core assembly and the valve pilot body. The problem was characterized as

" deterioration through natural aging of the Buna-N components in boiling water reactor control rod drive scram pilot valves." The Bulletin did not specifically address thermal degradation of Buna-N materials.

Generic Letter (GL) 91-15, " Operating Experience Feedback Report, Solenoid-Operated Valve Problems at U.S. Reactors" provided case study NUREG-1275, Volume 6, that integrated operating experience of solenoid valves. Through its primary focus on the case study, the GL mainly expresses NRC's concern about the reliability of solenoid valves used in safety applications. Additionally, the case study discusses solenoid valve failures that compromise multiple trains of multiple safety systems, leading the reader to believe the discussion is related to safety system environmental qualification. The RCP seal return isolation valve solenoid valve is not safety related.

The SQN PER (SQPER930001) was initiated to address solenoid valves that were mounted directly to hot piping systems where piping design temperatures reached extreme conditions ranging from 321 to 600 degrees Fahrenheit. The solenoid valve on the RCS pump seal return flow control valve operated in a much more moderate temperature and was not mounted directly to any hot piping systems.

Violation A(3)

• The NOV cover letter and Enclosure 1 state that TVA failed to develop an adequate corrective action plan and failed to implement corrective action to detect water intrusion into plant equipment after a deluge event. TVA did correct the leaking water source, replace the fire detector, and

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i U.S. Nuclear Regulatory Commission l 4 Page 9

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conduct a post-deluge walkdown of the area affected by the 1 event, but did not inspect the particular junction box  !

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associated with the affected turbine impulse pressure ,

j switches. As TVA stated in the enforcement conference, .

however, it would have been difficult to recognize the  !

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, water intrusion path to the turbine impulse pressure  !

, switches. The mechanism by which the water traveled into  ;

i the pressure switches was not apparent and would have ,

l required disassembly of each individual pressure switch.

" The water intrusion path was later confirmed through 4 testing after it was known that water was present in the

, . pressure switches. j i

I CONCLUSION REGARDING VIOLATIONS A(1), A (2) , AND A (3 )

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! Given TVA's early identification and initiation of corrective ,

l actions, and its several initiatives to upgrade plant's l

!- material condition, TVA maintains that sufficient basis exists l for not imposing any civil penalty for events associated with i the October 11, 1996, Unit 2 shutdown event. This conclusion i can be reached by citing the event as separate Severity Level i IV violations, or by using mitigation discretion based on l

' licensee identification and comprehensive corrective action.  ;

A civil penalty under the facts and circumstances at hand t would serve no purpose other than to punish the licensee and i i would be in contrast to the enforcement policy's stated focus  ;

to, among other things, " focus on current performance of -

, licensees."

j (60 Fed. Reg. 34381, June 30, 1995).

Based on the foregoing, TVA respectfully requests that the NRC

reconsider its decision to categorize violations A(1), A(2),  !

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and A(3) as a Severity Level III problem and to propose a

civil penalty. ,

i I IV. CLARIFICATIONS REGARDING VIOLATIONS B (1) , B(2), AND B (3 )

i With regard to the three "B" violations associated with the reactor trip breaker, TVA believes that there are important clarifications to be made. These clarifications help show why l certain events occurred, why decisions were made, and why 1 TVA's actions actually reflected a conservative decision-

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making approach contrary to NRC's discussion in the letter.

In sum, TVA does_not believe non-conservative decision making I

to be a root cause of the "B" violations. However, TVA is not i contesting the "B" violations or the associated $50,000 civil penalty.

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U.S. Nuclear Regulatory Commission Page 10 January 23, 1997 TVA is especially concerned about the descriptions of violations B (1) , B (2) , and B(3) in the NOV and speculation over what should or could have been recognized or accomplished at the time in question, given that events can now be more clearly analyzed with the benefit of hindsight. These concerns were expressed in the enforcement conference, and TVA would like to clarify the following points:

• The NRC cover letter identifies one of the root causes of the violations as poor communications among Operations, Maintenance, and Engineering from which it could be inferred that poor communication was prevalent throughout the event. However, TVA's examination of the events showed no sign of poor communications among Operations, Engineering, and Maintenance during the replacement of the Reactor Trip Breaker (RTB), up through and including the point when the Operations Shift Manager (SM) determined that the breaker should be removed from service. TVA believes that the poor communications was limited to the subsequent analysis of the equipment condition.

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• The NRC cover letter identifies non-conservative decision l making as one of the root causes of the violations. More j specifically, in item (3) on page 3, the letter states that l Operations failed to make a conservative decision to remove the RTB for a number of hours, and that an early conservative decision on RTB operability could have precluded exceeding the Limiting Condition for Operation ,

(LCO). TVA does not believe this to be the case.  !

1 In order to make an accurate assessment of the decisions I regarding removal of the breaker, it is necessary to look ]

at the information available at the time in question. J Based on the information available at each step in the sequence of events, TVA believes that each decision made by the SM was conservative as described below.

At the time the LCO was exceeded, the annunciation of rod deviation had been received in the control room and technical support personnel had determined that the annunciation occurred because a computer point was indicating that the RTB was open. A voltage reading taken across the contacts that fed the computer point yielded a voltage reading above that associated with the closed breaker but below that of an open breaker. These indications led to the belief that this set of contacts was dirty or that the circuit contained a loose connection.

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The evidence available at the time the LCo time expired did not indicate any abnormality beyond a set of dirty contacts or loose connection associated with the computer input circuit. Based on this information, a conservative decision was made to not remove the RTB until an evaluation was made to ensure this would not cause a unit transient and that the breaker was the most likely cause.

After additional information became available to the SM 4 indicating that the RTB was a potential cause of the

' condition, the SM prudently prevented further online

< troubleshooting. This decision was based on the potential adverse consequences that continued online activity posed I to plant operation. The SM then ordered the removal of the RTB from service for further evaluation and testing. TVA believes this entire sequence of events, occurring over a short period of time (approximately two hours),

demonstrates conservative decision-making.

Item (2) on page 3 of the NRC cover letter states that Maintenance and Engineering personnel failed to recognize the significance of the rod deviation computer alarm and failed to understand its potential impact on operability.

The NRC states that this was evidenced by a proposal to troubleshoot the RTB problems online and divert resources toward clearing the alarm by inserting a " dummy" signal j into the computer prior to determining the cause for the i signal. Finally, the NRC states that these issues should l have led to taking prompt action to ensure RTB operability  ;

prior to exceeding the LCo. TVA would like to clarify i several aspects of these statements:

TVA agrees that personnel initially failed to recognize the I rod deviation alarm was caused by a disconnected linkage in the reactor trip breaker. TVA did determine that the alarm condition existed as a result of a breaker contact input i circuit providing an incorrect breaker status to the  !

computer. Immediate action was taken to determine if the problem was due to a computer problem or a field input.

Upon determining the breaker contact was indicating high l resistance, the SM was notified and a discussion was held to determine if other contacts were affected. No indications were present; the breaker had been tested satisfactorily; and there were no indications that more than one contact was suspect. However, because the breaker was newly installed, action was taken to troubleshoot the additional contacts and replace the breaker as discussed above.

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U.S. Nuclear Regulatory Commission Page 12 January 23, 1997 Since the computer rod deviation alurm was being held in by the nonfunctioning breaker contact, a value was inserted to enable the rod step counters to be updated and clear the alarm. The evolution to insert the entered value took less than five minutes and did not detract from finding or correcting the contact voltage problem. The inserted value allowed continuous rod deviation monitoring as required by technical specifications and did not remove the computer status that showed the breaker to be tripped. This also provided additional confirmation that the computer software was performing correctly and that the breaker contact circuit was the source of the problem. These actions effectively evaluated the alarm condition while returning the computer software and alarm to a state where the intended function could be performed. They also relieved operators from the additional LCO action required while the rod monitor is not functioning.

TVA believes that the insertion of this value into the computer placed the plant into a more conservative operational position with respect to potential rod deviation conditions. Also, TVA does not agree with NRC's statement that resources were diverted for insertion of a value into the computer in order to clear the alarm. The maintenance work associated with this activity was performed in parallel with several troubleshooting activities, and did not detract from overall efforts to find and correct the problem. This activity was not performed to mask the alarm condition.

CONCLUSION REGARDING VIOLATIONS B(1), B (2) , AND B ( 3 )

TVA acknowledges that these violations occurred and does not contest the fact they were classified as a Severity Level III problem or assessed a civil penalty of $50,000. However, TVA does not believe that it acted in a non-conservative manner in response to the RTB-related operating event or that TVA necessarily should have been more keenly aware of the cause of specific events as they occurred at the time. Moreover, TVA has learned from the RTB event, particularly with regard to needed improvements in maintenance, and is applying that knowledge to help ensure improved future operations.

U.S. Nuclear Regulatory Commission Page 13 January 23, 1997 In accordance with the foregoing, payment of the proposed civil penalty in the amount of $50,000 has been made by electronic fund transfer No. 064236000000130 for the Severity Level III problem associated with the "B" violations.

Enclosure 2 provides the list of commitments associated with TVA's reply.

If you have any questions concerning this submittal, please telephone R. J. Adney at (423) 843-7001.

Sin prel

l. J 'eringu S ior Vice President Nuclear Operations Sworn to bapd subscribed day of 3hbefore me this M3 nMa N , 1997 O.hb.A -

Notary Public My Commission Expires b-3' b Enclosures cc (Enclosures) :

Mr. R. W. Hernan, Project Manager Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 NRC Resident Inspector Sequoyah Nuclear Plant 2600 Igou Ferry Road Soddy-Daisy, Tennessee 37379-3624 Regional Administrator U.S. Nuclear Regulatory Commission Region II 101 Marietta Street, NW, Suite 2900 Atlanta, Georgia 30323-2711 U.S. Nuclear Regulatory Commission Document Control Desk Waghington, D.C. 20555

ENCLOSURE 1 REPLY TO THE NOTICE OF VIOLATION NRC REPORT NOS. 50-327, 328/96-13 STEWART D. EBNETER'S LETTER TO OLIVER D. KINGSLEY, JR.

DATED DECEMBER 24, 1996 VIOLATION 50-337, 328/96-13 "A. (1) 10 CFR 50, Appendix B, Criterion XVI requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, defective material and equipment, and nonconformances, are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

Contrary to the above, the licensee identified a significant condition adverse to quality, i.e., rust in the brake assembly of main feedwater isolation valve (MFIV) 2-MVOP-003-0100-B, but failed to adequately determine the root cause of the rust (water intrusion) and failed to take corrective action to preclude repetition of this significant condition adverse to  ;

quality. Specifically, the licensee failed to perform adequate evaluations or take adequate corrective actions for MFIV failures in January 1989, September 1990, September 1994, and April 1995. The failure to preclude repetition of this adverse condition resulted in the failure of MFIV 2-MVOP-003-0100-B to close on October 11, 1996. upon a valid feedwater isolation signal.

(01013)

(2) 10 CFR 50, Appendix B, Criterion XVI requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, defective material and equipment, and nonconformances, are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition.

Contrary to the above, the licensee identified a significant condition adverse to quality, i.e.,

degradation of the elastomer material Buna-N when exposed to temperatures greater than 125 degrees Fahrenheit ( F) , which resulted in repetitive failures of

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d solenoid valves, but failed to take corrective action to preclude repetition of this significant condition adverse to quality. Specifically, the licensee failed

' to implement a corrective action plan developed in late 1993 to address issues identified in NRC IE Bulletin j i 78-14. Deterioration of Buna-N Components in ASCO Solenoids and Generic Letter 91-15, Operating Experience Feedback Report, Solenoid-Operated Valve Problems at United States Reactors, and failed to implement effective corrective actions for Problem Evaluation Report (PER) SQPER930001, which identified previous deficiencies in the operation of ASCO solenoid valves due to degradation of the Buna-N material. On October 11, 1996, a quality-related solenoid operated valve, on a reactor coolant system (RCS) pump seal leak-off isolation valve, failed due to temperature aging of Buna-N material in the valve, which caused

initiation of a plant shutdown resulting in a reactor trip. A subsequent licensee investigation identified that a number of safety-related and quality-related valves exposed to temperatures of greater than 125 j degrees ( F) and containing Buna-N were not evaluated for l Buna-N degradation. (01023)

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(3) Technical Specification 6.8.1.a requires, in part, that procedures shall be established, implemented, and

< maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, I l February 1978, " Quality Assurance Program Requirements

(Operations)." Appendix A of Regulatory Guide 1.33,

j. Section 1, includes administrative procedures.

Site Standard Practice 3.4, Section 3.3 and 3.4,

) require, in part, that the Responsible Organization (1) develop the corrective action plan, and (2) implement i and/or monitor implementation of the approved corrective action, for conditions documented in Problem Evaluation

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Reports.

Contrary to the above, the licensee failed to develop an 3

adequate corrective action plan and failed to implement corrective action to ensure that equipment affected by a July 1996 inadvertent fire system deluge actuation, documented in PER SQ961977PER, was surveyed for

degradation and refurbished as necessary. As a result, turbine impulse pressure switches PS47-13B and PS47-13E were subsequently identified as failed, due to water intrusion. The failed switches caused a spurious i turbine runback on October 11, 1996, and complicated

" recovery from a subsequent reactor trip by inhibiting l

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4 manual control of the Auxiliary Feedwater System.

Subsequent licensee investigation identified 18 other junction boxes affected by water intrusion. (01033)

"These violations represent a Severity Level III problem (Supplement I)."

" Civil Penalty - $50,000."

"B. (1) Technical Specification 6.8.1.a requires, in part, that procedures shall be established, implemented, and 1 maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33. Revision 2, February 1978, " Quality Assurance Program Requirements (Operations) . " Appendix A of Regulatory Guide 1.33, Section 9, includes procedures for performing maintenance.

Maintenance Instruction (MI) -10. 9.1, REACTOR TRIP BREAKER TYPE DB50 INSPECTION ASSOCIATED WITH SYSTEM 99, Revisic7 16, describes, in part, the steps for i lubrication and testing of the reactor trip breaker

! (RTB) inertia latch. ,

Contrary to the above, the licensee failed to properly 1 implement procedure MI-10.9.1 and failed to establish i adequate procedural steps to ensure complete reassembly l

of the RTB inertia latch during latch lubrication and i appropriate testing of the RTB contacts after it was

reassembled. Specifically

1. On September 14, 1996, personnel performed two sections of MI-10.9.1 out of sequence. Section 7, Post Performance Activities, was performed prior to the completion of Section 6, Performance, which

+ resulted in completion of the RTB post-maintenance 1 test prior to a step requiring that the auxiliary contact linkage assembly oe disconnected from the inertia latch.

2. Since July 29, 1994, MI-10.9.1, was inadequate in that Step 6.2.6 functionally tested operability of the auxiliary contacts when a subsequent step, Step 6.4.1, required disassembly of the auxiliary contact linkage assembly to allow lubrication of the inertia latch. The procedure did not contain precautions or adequate instructions regarding the disassembly / reassembly of the RTE inertia latch during latch lubrication. The failure to provide i adequate instructions for assembly of the inertia

' latch resulted in an inoperable P-4 channel.

(02013) 9 i 4 4

1

. i (2) Unit 2 Technical Specifications 3.3.1, Table 3.3-1, Item 22.G, Reactor Trip, P-4, Action 14, requires that, while in Mode 1, with the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

Contrary to the above, on September 19. 1996 while operating in Mode 1, the number of P-4 channels OPERABLE was one less than required by the Minimum Channels OPERABLE requirement and the licensee failed to place Unit 2 in HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. (02023)

(3) Technical Specification 6.8.1.a requires, in part, that procedures shall be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. " Quality Assurance Program Requirements (Operations) . "

Site Standard Practice, SSP-3.4, CORRECTIVE ACTION, Revision 17, Appendix E, Step 2.0.D, requires, in part, that if a condition described in a PER potentially affects operability or is potentially reportable, that prompt verbal notification of the condition to the Shift Operations Supervisor (SOS) shall be provided and that 4

the SOS shall promptly receive a copy of the PER.

Contrary to the above,.as of September 20, 1996, prompt verbal notification of the condition described in PER I SQ962451PER was not provided to the SOS nor did the SOS promptly receive a copy of the PER. As a result, the licensee failed to perform an immediate operability /reportability determination on an inoperable j RTB, as required by SSP-3.4, Appendix E, Step 5.0, until

]

October 7, 1996, after being prompted by the NRC.

(02033)

"These violations represent a Severity Level III Problem (Supplement I) . "

" Civil P .alty - $50,000" e

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1 VIOLATION A.1 (EEI 50-327, 328/96-13-01): '

ADMISSION OR DENIAL OF THE ALLEGED VIOLATION TVA admits the violation. [

REASON FOR VIOLATION The cause.for the violation was the less than fully effective corrective actions taken for previously-identified deficiencies.

During the-October 11, 1996, Unit 2 manual reactor trip, main feedwater isolation valve (MFIV) 2-FCV-3-100 failed to close upon-receipt of a feedwater isolation signal. The valve's motor operator failed because the position retention brake did not release. The equipment evaluation determined that corrosion buildup within the brake assembly forced the brake gap closed-with sufficient force to lock the motor's rotor and ultimately l cause the motor to fail. The corrosion buildup in the motor brake compartment is attributed to various leaks within the Main Steam Valve Vault. During review of the valve motor failure, three occurrences of brake corrosion were identified along with l one occurrence of brake failure because of an electrical short i circuit.

I In January 1989, the motor brake for MFIV 2-FCV-3-100 was found to be bound because of corrosion. A corrective action document l was initiated to document the condition and the brake and motor j' were replaced. The corrective action document identified the

! apparent cause of the condition as water intrusion, but the

! condition was treated as a single isolated failure and no action  ;

l was taken to prevent water intrusion. An extent of condition i inspection of the other three Unit 2 MFIVs and the four Unit 1 MFIVs did'not identify any other corrosion problems.

! In September 1990, the motor brake for MFIV 2-FCV-3-100 was found i

! in a bound condition and the condition was documented in a corrective action-document. According to that corrective action l document, motor brake failure resulted from corrosion product >

buildup that was caused by water leakage from a nearby valve that entered the brake compartment through a damaged conduit. The

failure was considered an isolated case because of the

combination of valve leakage and conduit damage. The corrective I action document associated with this failure indicated that

-additional actions to prevent recurrence were not required because completion of identified corrective actions should prevent recurrence. Actions taken for the' condition replaced the  !

i valve motor and brake, repaired the damaged conduit, and replaced j

the leaking valve. The motor brakes on the other three Unit 2 MFIVs were inspected and found to be in good condition (no

moisture intrusion or corrosion). Additionally, the requirement

to visually inspect insulated conduit in the valve vaults for f

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e damage was proceduralized and flex conduit inspection was added to the preventive maintenance program.

In September 1994, a work document was initiated to repair a broken flex conduit between the limit switch and motor brake compartments on MFIV 2-FCV-3-100. During this maintenance activity it was discovered that the motor brake compartment contained water and that the brake was corroded. The flex conduit was repaired and the motor brake was replaced.

In April 1995, MFIV 2-FCV-003-100 did not close when demanded by the main control room handswitch. The circuit breaker had tripped and prevented the valve from traveling to the closed position. The valve was manually operated to move the valve from the full-open position and then electrically closed by use of the main control room handswitch. Subsequent troubleshooting found that one of the coil leads to the motor brake was electrically grounded to the brake housing. The ground (short circuit) was the result of damaged electrical insulation on the brake coil lead. The short circuit prevented the brake coil from being energized to release the brake. This resulted in the circuit breaker tripping on the first attempt to close the valve. Review of the event determined that the coil wire was damaged either during installation or was received in a damaged condition. A maintenance history review found that the motor brakes on the other three Unit 2 MFIVs and four Unit 1 MFIVs had not been replaced. Therefore the extent of condition was isolated to the one MFIV and spare mutor brakes remaining in stock.

Safety Significance Review of the condition determined that no actual safety significance existed as a result of the equipment failure and there was minimal potential safety significance. Before the I event, in May 1996, the Unit 2 MFIVs were stroke-tested and the l four valves were found to operate properly. During the transient that resulted from the October 11, 1996 manual reactor trip, a feedwater isolation signal occurred and MFIVs for Loops 1, 2, and 3 closed. The four feedwater regulating valves (one valve on l each loop, located upstream of the MFIVs) closed. These valves are the primary isolation valves for isolation of feedwater for loss of coolant and nonloss of coolant accidents. Additionally, the operating feedwater pump tripped as expected to stop feedwater flow. As such, the inability of the Loop 4 MFIV to close is within the safety analysis for the design basis of the plant.

CORRECTIVE STEPS TAKEN AND THE RESULTS ACHIEVED Subsequent to the Unit 2 manual reactor trip, the motor and brake for MFIV 2-FCV-3-100 were replaced, the valve was tested, found l

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i acceptable, and returned to service. Leaking rubber hoses that provided drainage for telltale drains from Unit 2 steam generator blowdown and cold wet layup valves and quick connect fittings to  ;

those hoses were repaired, preventing additional wetting of the i MFIV. Based on an extensive equipment root cause analysis, spray l and access shields were installed over MFIV 2-FCV-3-100. l These shields prevent water intrusion and damage to the valve's flex conduit. The motor brakes of the other three Unit 2 MFIVs were inspected and found to be in good condition (no moisture or i corrosion), and the valves were tested and found to be acceptable. A walkdown of Units 1 and 2 MFIVs was performed and based on the location water staining of concrete and structural steel, it was determined that valve wetting and moisture intrusion was unique to the one MFIV.

Corrective action program improvements have been implemented.

The following actions that were recently taken are improving cause determination and corrective action development:

(1) providing root cause analysis training to appropriate Engineering personnel; (2) qualifying individuals as root cause lead investigators; (3) increasing Engineering awareness of maintenance and plant activities; (4) increasing the sensitivity of Operations and Engineering personnel to lower the threshold for identifying plant conditions through management monitoring and coaching in the field; (5) developing a standard format for reporting equipment root cause analyses and incorporating it in the corrective action program procedure; and (6) adding management review of equipment root cause analyses through the management review committee process in order to reinforce management expectations until desired results are achieved.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS No additional actions are required to address the violation.

However, as enhancements to the actions already taken, replacement of the existing motor brakes with corrosion-resistant brakes is being pursued pending component qualification to safety-related requirements. Permanent piping will be installed during the upcoming Unit 2 refueling outage in the fall of 1997 for the Unit 2 tell-tale drains on steam generator blowdown and cold wet layup valves. Additionally, as a follow-up on monitoring activity, MFIV 2-FCV-3-100 will be inspected during the fall 1997 Unit 2 refueling outage. These enhancement actions are not commitments for resolution of the violation.

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED With respect to the violation, TVA is in full compliance.

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l VIOLATION A.2 (EEI 50-327, 328/96-13-03):

j ' ADMISSION OR DENIAL OF THE ALLEGED VIOLATION

/

j TVA admits the violation.

E I REASON FOR VIOLATION 1

i The cause of.the violation was a less than fully effective use of  !

[

industry and previous plant operating experience. On October 11, l 1996, a low seal return flow alarm was received in the main control room. After Unit 2 was shut down, as a result of the condition, the Loop 4, No. 1 seal return, flow control valve was i examined and found to be in the closed position. Further

evaluation found a failure of the seal return flow control ,

valve's solenoid valve'that provides control air to the operator. i

'The cause of the solenoid valve failure is temperature age

- , hardening of the Buna-N o-rings and diaphragm contained in the i solenoid valve. Failure of these components allowed air to flow

] through the valve and pressurize the main valve diaphragm while 4- discharging air through the solenoid valve's open exhaust port.  ;

f As part of the evaluation of the solenoid valve failure, a review

! of industry and previous site experience was performed. The .

j review identified three documents that were potentially related

to the equipment failure, NRC Bulletin 78-14, NRC generic letter 4 (GL) 91-15, and SON problem evaluation report (PER) SQPER93001.

l Review of Bulletin 78-14 indicated boiling water reactors had i experienced problems with Buna-N materials in reactor control rod

< drive scram pilot solenoid valves. From review of GL 91-15, it

was found that the action plan TVA had developed in December '

~

1993, to address industry operating experience relative to j solenoid valves provided an opportunity to address the failure of Buna-N material which could have prevented the solenoid valve failure. Additionally, the case study discusses solenoid valve failures that compromise multiple trains of multiple safety .

j systems, leading the reader to believe the discussion is related i

j. to safety system environmental qualification. Similarly, the PER 4 which was initiated in January 1993, addressed failure of a solenoid valve on a secondary side system. The failure was the i result of exceeding elastomer temperature limits because of the i i solenoid valve being in direct contact with hot piping. In this j case, evaluation of the condition determined that nonsafety-related solenoid valves were directly attached to piping systems '

l with high design temperatures (321 to 600 degrees Fahrenheit) ,

[ far in excess of the acceptable temperatures for Buna-N. However the extent of condition focused on solenoid valves in similar l configurations and failed to address other temperature

]

degradation problems associated with Buna-N.

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Safety Significance There were no actual safety significance associated with failure of the solenoid valve and there was minimal potential safety significance. Upon identification of the low seal return flow condition, the appropriate procedure was entered and in accordance with its requirements, the reactor coolant pump (RCP) parameters were verified. The parameters were identified to be:

(1) less than 0.9 gallons per minute (gpm) seal return flow from RCP No. 4, No. 1 seal, with stable seal injection flow, (2) approximately 1.5 gpm total leakoff from the Nos. 2 and 3 seals, (3) stable No. 1 seal inlet and outlet temperatures, and (4) stable pump lower bearing temperatures. To minimize potential damage to the pump seals, a controlled shutdown was initiated.

In accordance with procedure, the RCP was removed from service within the procedurally required eight-hour timeframe.

The closure of the No. 1 seal return flow control valve resulted j in the normal No. 1 seal return flow cascading to the Nos. 2 and 3 seals. Overall total seal flow to the remained stable. The No. 2 RCP seal is designed for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of operation at full reactor coolant system pressure to allow operators time to react.

As such, the seal leakoff from the No. 2 seal was not excessive, seal leakoff was normal for the design condition that the seal was subjected to.

CORRECTIVE STEPS TAKEN AND T!fE RESULTS ACHEIVED The failed solenoid valve along with solenoid valves on the seal return lines of the other three, Unit 2, loops were replaced. As found, the other three solenoid valves functioned properly. ,

These three valves were disassembled and the elastomer components l were found to be pliable and in good condition. The o-rings and i diaphragms of these valves were of viton or ethylene propylene (EPDM) composition.

As a first step in determining the extent of the condition, a  !

i screening criteria was developed for review of solenoid valves. l i The screening criteria took the following attributes into consideration: (1) Equipment Qualification program scope, (2) environment ambient temperatures, (3) type of elastomer in use (Buna-N, Viton, or EPDM), (4) solenoid valve service time, (5) importance of the air-operated valve to safe continued operation, and (6) solenoid valves that are normally energized. Based on l this criteria, 28 Unit 2 and 25 Unit 1 solenoid valves were j replaced. )

ASCO solenoid valves with Buna-N elastomers were placed on engineering hold pending evaluation for disposition.

An assessment of both industry and plant operating experience was performed and no other implementation problems were identified. )

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. Corrective action program improvements have been implemented.

The following actions that were recently taken are improving cause determination and corrective action development: (1)

! providing root cause analysis training to appropriate Engineering i personnel; (2) qualifying individuals as root cause lead

!- investigators; (3) increasing Engineering awareness of

maintenance and plant activities; (4) increasing the sensitivity l of Operations and Engineering personnel to lower the threshold j for identifying plant conditions through management monitoring j and coaching in the field; (5) developing a standard format for

! reporting equipment root cause analyses and incorporating it in I the corrective action program procedure; and (6) adding i management review of equipment root cause analyses through the j management review committee process in order to reinforce i i management expectations until desired results are achieved.

j CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS An engineering evaluation will be performed by July 16, 1997, to

! determine the adequacy of Buna-N for the environment of solenoid l_

valves that were not replaced in the Units 1 and 2 forced outages, including the lifespan if Buna-N components remain in '

the solenoid valves.

1 Preventive maintenance will be established by November 14, 1997, j to periodically replace solenoid valves that were not replaced  ;

j during the Units 1 and 2 forced outages based on the engineering l

> evaluation of Buna-N adequacy. l i

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED i

With respect to the violation, TVA will be in full compliance

after completion of an engineering evaluation by July 16,1997, <

and development of associated preventive maintenance instructions by November 14, 1997. ,

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VIOLATION A.3 (EEI 50-327, 328/96-13-05):

ADMISSION OR DENIAL OF THE ALLEGED VIOLATION TVA admits the violation.

REASON FOR VIOLATION  ;

4 The cause for the violation was failure to conduct a sufficiently l detailed post-deluge walkdown. On July 16, 1996 the area below the high-pressure turbine was inadvertently sprayed by a high- l

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pressure fire protection system deluge header. Immediately after 1 the spraydown event, inspections were performed by Operations and  !

Engineering personnel, including electrical equipment potentially l affected by the spraydown event, and no indication of damage or {

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affect to in-service equipment was identified. The spray down was caused by a failed fire detector. The fire detector failure was the result of steam seal condensate migrating along turbine building structural surfaces and penetrating the fire detector housing. In addition to the immediate walkdowns, corrective actions taken for the failed fire detector included adjustment of the steam seal pressure to prevent the outward flow of condensate, and replacement of the fire detector with a water resistant type following the Unit 2 trip. Subsequent to the October 11, 1996, Unit 2 trip, it was discovered that the turbine impulse pressure switches had failed because of water intrusion into the pressure switch housing. It was also determined that the associated junction box had not been inspected after the spraydown event. Inspection of the junction box did not readily identify that water had entered the junction box or related conduits. The junction box was tested for water intrusion and it was discovered that water was migrating along the electrical cables through the local panel electrical junction box and the flex conduit leading to the pressure switches into the switch housings.

Safety Significance There was no actual safety significance associated with the failure of the pressure switches and there was minimal potential safety significance. Failure of the pressure switches in the balance of plant runback circuit has no impact on the automatic actuation, automatic control or manual initiation of the auxiliary feedwater (AFW) system to perform its safety function.

Consequently, there are no adverse impacts in the design basis ability of the AFW system to provide an adequate heat sink for the reactor coolant system (RCS) heat-up events. Design basis events which require manual control of AFW, primarily to limit RCS cooldown to maintain adequate shutdown margin and to isolate a faulted or ruptured steam generator, are analyzed. Although the October 11, 1996, event prohibited the operators from taking manual control of the turbine-driven AFW pump and the motor-driven AFW pump level control valves, no new failure was introduced. The failure of a level control valve to close was previously considered in the final safety analysis report. This failure, in conjunction with a design basis event and credible '

single failure, can be (and was) mitigated using the existing AFW system design, emergency procedures, and operator capability.

CORRECTIVE STEPS TAKEN AND THE RESULTS ACHIEVED After it was determined that the Unit 2 turbine impulse pressure switches had failed, the pressure switches were replaced and the associated junction box was sealed to prevent water migration l l

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1 into the switch housings. Unit 1 turbine impulse pressure 1 switches were inspected and found to be in good condition with no evidence of moisture intrusion or corrosion.

t l Unit 2 turbine building instrument panels of similar geometry j were reviewed to determine which panels were potentially j susceptible to water migration along the electrical wiring to the instrument. The review identified 66 local instrument panels

throughout the Unit 2 turbine building. The instrument panels 1 i were inspected, evaluated, and repairs were either completed

, -during the forced outage or scheduled for repair within the work i

scheduling process with review and concurrence of operations to establish a priority-based schedule, k Similarly, 70 junction boxes were inspected throughout the Unit 1 i turbine building. The observed conditions were evaluated and repairs were either completed during the forced outage or j scheduled for repair within the work scheduling process.

! Design requirements sealing electrical junction boxes were 1 reviewed. It was determined that sealing requirements existed for the reactor, control, diesel, and auxiliary buildings and for i other specific locations. Sealing requirements were not provided j

for junction boxes in the turbine building. Based on this i* review, the appropriate procedures have been revised to provide proper se' ling techniques.

I In addit' a to the above actions, improved inspection methodology

for inspection of water intrusion was developed.

E CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS i

No additional actions are required to address the violation.

! DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED i

With respect to the violation, TVA in in full compliance.

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VIOLATION B.1 (EEI 50-327, 328-96-13-07):

ADMISSION OR DENIAL OF THE ALLEGED VIOLATION l TVA admits the violation. l l

REASON FOR VIOLATION The causes of the violation were: (1) failure to follow

). maintenance instruction MI-10.9.1, and (2) improper revision of

MI-10.9.1. With regard to the first cause, personnel improperly I. performed Section 7.0, " Post Performance Activities" before i

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Section 6.0, " Work Performance." Working these sections out of sequence allowed the disconnected linkage to go undetected. With regard to the second cause, personnel improperly revised the procedure without specific instructions or details as to how to disassemble and replace the inertia latch, and the revision also allowed testing within Section 6.0 to check continuity across auxiliary contacts before the inertia latch was removed and reinstalled.

Safety Sionificance There was no actual safety significance associated with the reactor trip breaker (RTB) event and there was minimal potential safety significance. Both the "A" and "B" train RTBs were capable of tripping the reactor throughout this event. The following functions would not have been performed by the "B" breaker but would have functioned as a result of operation of the contacts on the redundant "A" reactor trip breaker: (1) The signal for feedwater isolation on a reactor trip coincident with lo-lo Tavg, and (2) the signal that maintains feedwater isolation, turbine trip, and the main feedpump trip signals initiated on a high steam generator level trip.

The affected contacts also enable the safety injection signal (SIS) reset on one train. The linkage problem would have prevented the SIS reset from functioning on that train. However, operators would be able to manually isolate the individual components actuated by the SIS rather than using the reset function to remove the actuation signal from the components. The SIS reset function on the other train was unaffected.

CORRECTIVE STEPS TAKEN AND THE RESULTS ACHIEVED Maintenance instruction MI-10.9.1 " Reactor Trip Breaker Type DB50 Inspection associated with System 99" and MI-10.9.2 " Bypass Trip Breaker Type DB50 Inspection associated with System 99" have both been revised so that the steps to check continuity across the auxiliary contacts are performed after the removal and reinstallation of the inertia latch.

Although the type DS breakers do not have the same linkage arrangement as the DB50 breaker that experienced the problem, the two types are similar in overall design. Therefore MI-10.5

" Westinghouse Type DS Breaker and Switchgear Maintenance" was enhanced to provide continuity checks of the auxiliary contacts with the breaker in the open and closed position prior to placing the breaker in service.

A training letter has been issued to appropriate personnel. This I

training letter reinforces job performance expectations relative to maintenance procedure revisions. These expectations include: i l

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I (1) ensuring that procedures are revised with a-sound technical l basis, (2) reviewing the procedure for functionality as a whole not just the_section being revised, (3) evaluating the effect that a revision could have on other sections of the procedure including the post-maintenance test and sequence of performance,  ;

and (4) evaluating the need to have the procedure verified.

An Operations department training letter has been issued for appropriate personnel. This training letter reviews lessons learned from the event.

The requirements of SSP-2.51 " Rules of Procedure Use" were reinforced with maintenance supervisors. The procedural  :

requirements for documenting the performance of steps out of sequence in work documents was reinforced with maintenance shop personnel.

Disciplinary actions have been taken with the appropriate personnel.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS No additional actions are required to address the violation.

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED With respect to the violation, TVA is in full compliance.

VIOLATION B.2 (EEI 50-327. 328-96-13-08):

1 ADMISSION OR DENIAL OF THE ALLEGED VIOLATION TVA admits the violation.

REASON FOR VIOLATION l l

The cause of the violation was the failure to identify that the P-4 contacts were inoperable. After the rod deviation annunciation was received in the control room and operators determined that no rod deviation or quadrant power tilt ratio condition existed, activities to assess the cause of the annunciation were initiated. The annunciation was generated because the rod monitoring software was being inhibited from allowing updates to the computer step-counter information and preventing correct calculations of rod deviations, rod insertion limits, control bank D withdrawal, and bank deviations. This resulted from high resistance in the breaker contact which caused the computer to incorrectly status the trip breaker as open and the reactor as tripped. "A voltage reading taken across the contacts that fed the computer point yielded a voltage reading ,

above that associated with the closed breaker but below that of 1

= *

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f an open breaker. These indications led to the belief that this

! set of contacts was dirty or that the circuit associated with the  !

l computer input contained a loose connection.  !

i Options were presented to management to conduct additional

! troubleshooting of the circuits with the breaker in place or to remove the breaker for further evaluation. Management made a j conservative decision to replace the breaker. Inspections 1 performed following removal of the breaker identified that the i I linkage necessary to operate the two upper sets of relays (which j included the P-4 interlock) was not connected.

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Safety Significance i Same as stated in previous violation (VIOLATION B.1 (EEI 50-327, 328-96-13-07)).

CORRECTIVE STEPS TAKEN AND THE RESULTS ACHIEVED 1 .

l Same as stated in previous violation (VIOLATION B 1 (EEI 50-327, 5 328-96-13-07)).

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS i

No additional actions are required to address the violation.

i DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED

)

l With respect to the violation, TVA is in full compliance.

1 4 VIOLATION B.3 (EEI 50-327, 328-96-13-09):

1 5

ADMISSION OR DENIAL OF THE ALLEGED VIOLATION TVA admits the violation.

l REASON FOR VIOLATION 4

! The cause of the violation was the failure to use the 2

proceduralized process for operability and reportability determinations. Initially, the equipment condition was i determined to affect operability and not reportability. While l the root cause analysis (RCA) was in progress the Management Review Committee (MRC) questioned the initial "not reportable"

determination and requested the.reportability determination be J

reexamined. This reexamination of reportability was not reentered into the original formal process as was performed for the initial determination, i.e., handcarry the PER to the Shift

- Manager for disposition. Instead MRC assigned a verbal action to reevaluate reportability. Because the proper process was not i

used, a conclusion concerning reportability was not reached in a j 1

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timely manner. Contributing to the condition was poor

- communications that resulted in the intermixing of analysis methods (RCA evaluation that took the form of an e'ient critique team process) resulting in the evaluation being rarrowly_ focused on the root cause determination and not maintaining an overall perspective of the event.

Safety Significance s

. There was no safety significance because the reactor trip breaker had already been replaced and reporting is an administrative i

function. ,

CORRECTIVE STEPS TAKEN AND THE RESULTS ACHIEVED ,

J Review of the untimely reportability determination found that the scope of condition was limited to the MRC members. As such, MRC

! was briefed on lessons learned from the issue. As part of the briefing, the need to have clear and concise communications relative-to the specification of cause determination methods and the need to avoid intermixing cause determinations was also

- stressed.

CORRECTIVE STEPS THAT WILL BE TAKEN TO AVOID FURTHER VIOLATIONS

! No additional actions are required to address the violation.

DATE WHEN FULL COMPLIANCE WILL BE ACHIEVED 1

i With respect to the violation, TVA is in full compliance.

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ENCLOSURE 2 COMMITMENTS TO THE NOTICE OF VIOLATION NRC REPORT NOS. 50-327, 328/96-13 STEWART D. EBNETER'S LETTER TO OLIVER D. KINGSLEY, JR.

DATED DECEMBER 24, 1996 VIOLATION A.2 (EEI 50-327, 328/96-13-03):

An engineering evaluation will be performed by July 16, 1997, to determine the adequacy of Buna-N for the environment of solenoid valves that were not replaced in the Units 1 and 2 forced outages, including the lifespan if Buna-N components remain in the solenoid valves.

Preventive maintenance will be established by November 14, 1997, to periodically replace solenoid valves that were not replaced during the Units 1 and 2 forced outages based on the engineering evaluation of Buna-N adequacy.

.