[Federal Register Volume 62, Number 106 (Tuesday, June 3, 1997)]
[Notices]
[Pages 30349-30355]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-14397]


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NUCLEAR REGULATORY COMMISSION

[Docket Nos. 50-327 and 50-328, License Nos. DPR-77 and DPR-79, EA 96-
414]


In the Matter of Tennessee Valley Authority, Sequoyah Nuclear 
Plant, Units 1 and 2; Order Imposing Civil Monetary Penalty

I

    Tennessee Valley Authority (Licensee) is the holder of Operating 
License Nos. DPR-77 and DPR-79 issued by the Nuclear Regulatory 
Commission (NRC or Commission) on September 17, 1980, and September 15, 
1981, respectively. The licenses authorize the Licensee to operate the 
Sequoyah Nuclear Plant, Units 1 and 2 in accordance with the conditions 
specified therein.

II

    An inspection of the Licensee's activities at the Sequoyah Nuclear 
Plant was conducted during the period September 19 through November 2, 
1996. The results of this inspection indicated that the Licensee had 
not conducted its activities in full compliance with NRC requirements. 
A written Notice of Violation and Proposed Imposition of Civil 
Penalties (Notice) was served upon the Licensee by letter dated 
December 24, 1996. The Notice stated the nature of the violations, the 
provisions of the NRC's requirements that the Licensee had violated, 
and the amount of the civil penalty proposed for the violations.
    The Licensee responded to the Notice in a letter dated January 23, 
1997. In its response, the Licensee agreed that the violations occurred 
but contested NRC's application of the Enforcement Policy and requested 
the NRC to reconsider its decision to categorize Violations A(1), A(2) 
and A(3) as a Severity Level III problem and mitigate the proposed 
civil penalty for Violations A(1), A(2) and A(3) in its entirety. The 
Licensee's request was based on its view that NRC's categorization of 
Violations A(1), A(2) and A(3) as a Severity Level III problem and the 
proposed imposition of a $50,000 civil penalty was inconsistent with 
the NRC Enforcement Policy.

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III

    After consideration of the Licensee's response and the statements 
of fact, explanation, and argument for mitigation contained therein, 
the NRC staff has determined, as set forth in the Appendix to this 
Order, that the violations occurred as stated and that the penalty 
proposed for the violations designated in the Notice should be imposed.

IV

    In view of the foregoing and pursuant to Section 234 of the Atomic 
Energy Act of 1954, as amended (Act), 42 U.S.C. 2282, and 10 CFR 2.205, 
It is hereby ordered That:
    The Licensee pay a civil penalty in the amount of $50,000 within 30 
days of the date of this Order, by check, draft, money order, or 
electronic transfer, payable to the Treasurer of the United States and 
mailed to James Lieberman, Director, Office of Enforcement, U.S. 
Nuclear Regulatory Commission, One White Flint North, 11555 Rockville 
Pike, Rockville, MD 20852-2738.

V

    The Licensee may request a hearing within 30 days of the date of 
this Order. Where good cause is shown, consideration will be given to 
extending the time to request a hearing. A request for extension of 
time must be made in writing to the Director, Office of Enforcement, 
U.S. Nuclear Regulatory Commission, Washington, D.C. 20555, and include 
a statement of good cause for the extension. A request for a hearing 
should be clearly marked as a ``Request for an Enforcement Hearing'' 
and shall be addressed to the Director, Office of Enforcement, U.S. 
Nuclear Regulatory Commission, Washington, D.C. 20555, with a copy to 
the Commission's Document Control Desk, Washington, D.C. 20555. Copies 
also shall be sent to the Assistant General Counsel for Hearings and 
Enforcement at the same address and to the Regional Administrator, NRC 
Region II, Atlanta Federal Center, 61 Forsyth Street, S.W., Suite 
23T85, Atlanta, Georgia 30303.
    If a hearing is requested, the Commission will issue an Order 
designating the time and place of the hearing. If the Licensee fails to 
request a hearing within 30 days of the date of this Order (or if 
written approval of an extension of time in which to request a hearing 
has not been granted), the provisions of this Order shall be effective 
without further proceedings. If payment has not been made by that time, 
the matter may be referred to the Attorney General for collection.
    In the event the Licensee requests a hearing as provided above, the 
issue to be considered at such hearing shall be:
    Whether on the basis of the violations admitted by the Licensee, 
this Order should be sustained.

    Dated at Rockville, Maryland this 23d day of May 1997.

    For the Nuclear Regulatory Commission.
Edward L. Jordan,
Deputy Executive Director for Regulatory Effectiveness, Program 
Oversight, Investigations and Enforcement.

Evaluations and Conclusion

Violations A(1), A(2) and A(3)

    On December 24, 1996, the NRC issued to Tennessee Valley Authority 
(licensee or TVA) a Notice of Violation and Proposed Imposition of 
Civil Penalties (NOV) including three violations, described as A(1), 
A(2) and A(3), identified during an NRC inspection conducted during the 
period September 19 through November 2, 1996, at the Sequoyah Nuclear 
Plant. In its response dated January 23, 1997, the licensee agreed that 
the violations occurred but stated that NRC's categorization of 
Violations A(1), A(2) and A(3) as a Severity Level III problem and the 
proposed imposition of a $50,000 civil penalty was inconsistent with 
the NRC Enforcement Policy. The licensee requested that the NRC 
reconsider its decision regarding the severity level of the violations 
and/or mitigate the proposed civil penalty in its entirety. The NRC's 
evaluations and conclusion regarding the licensee's requests are as 
follows:

Summary of Licensee's Request for Reduction in Severity Level

    In its request for reconsideration of the severity level of 
Violations A(1), A(2) and A(3), the licensee maintained that site 
management had begun a series of initiatives designed to improve 
corrective action program effectiveness. The initiatives included: (1) 
Providing root cause analysis training to engineering personnel, (2) 
increasing engineering awareness of maintenance and plant activities, 
(3) lowering the threshold for identifying deficient plant conditions 
through management monitoring and coaching in the field, and (4) adding 
senior management review of equipment root cause analysis to reinforce 
management expectations.
    With regard to TVA's history of activities to upgrade the Sequoyah 
corrective action program, the licensee maintained that as early as 
July 1996, TVA had identified the fact that problems existed with 
corrective action program implementation. In a management meeting with 
the NRC on August 8, 1996, TVA informed the NRC that corrective actions 
did not always achieve problem resolution. Additionally, based on a 
1995 TVA quality assurance audit, an accelerated audit schedule was 
initiated in the area of the corrective action program. The September 
1996 corrective action audit identified that corrective action program 
implementation was not totally effective. Therefore, the licensee 
concluded that the root cause for the October 11, 1996 equipment 
failures (inadequate corrective action program implementation) was 
previously identified by TVA in advance of the equipment failures.
    In addition, TVA noted that the NRC's Enforcement Policy 
specifically recognizes that credit for identification is warranted in 
those situations where the problem is identified through an event, and 
the licensee has made a noteworthy effort in determining the root cause 
associated with the violations. TVA stated that it believed that such 
credit is especially warranted in this case because TVA had identified 
the root cause even before the equipment failures arose and was taking 
action, both at the time of the failures and after the failures took 
place, to address the cause. The following summarizes the violations 
cited by NRC and information submitted by TVA in support of a request 
for reduction in severity level.
Violation A(1)
    This violation involved the licensee's failure to perform adequate 
evaluations of deficient conditions and to take adequate corrective 
actions to preclude repetition of significant conditions adverse to 
quality for the main feedwater isolation valve (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, 
after receiving a valid feedwater isolation signal.
    The licensee stated that the listing of the earlier MFIV 
``failures'' oversimplified the maintenance history of the subject 
valve. The January 1989 failure marked the first failure of a MFIV due 
to corrosion build-up on the brake. Extensive corrective actions were 
taken, and it was believed that those actions were fully adequate to 
prevent recurrence following the 1990 MFIV failure. The licensee noted 
that the motor did not fail to stroke in September 1994; however, water 
and rust were found in the brake assembly. The licensee stated that in 
April 1995,

[[Page 30351]]

the MFIV did not initially travel to the closed position on operator 
demand due to an electrical short in the brake circuitry and the 
problem was not associated with motor brake corrosion.
    In addition, the licensee noted that the NOV cover letter discussed 
failures of the MFIV to stroke on four previous occasions. The 
licensee, in clarification of the previous failures, noted that the 
valve failed to stroke on two occasions due to corrosion of the brake 
assembly and failed a third time due to an electrical problem. The 
licensee also indicated that the brake was not tested prior to 
maintenance in September 1994 and, therefore, the NRC statement that 
the valve failed to stroke was not accurate.
Violation A(2)
    This violation involved the licensee's failure to implement a 
corrective action plan developed in late 1993 to address issues 
identified in NRC Inspection and Enforcement (IE) Bulletin 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.'' This violation also 
addressed the licensee's failure 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.
    The December 24, 1996 NRC letter stated that the failure of the 
ASCO solenoid valve caused excessive reactor coolant pump (RCP) seal 
leakage. The licensee stated that, more accurately, TVA shut down the 
unit in accordance with procedural guidance for an alarm condition, 
that RCP total seal flow remained stable, that the No. 2 RCP seal is 
designed for 100 hours of operation at full reactor coolant system 
pressure, and that as such, the condition of the No. 2 RCP seal was 
within its design basis.
    In addition, the licensee contended that the December 24 letter 
inaccurately stated that a number of other valves were subsequently 
determined to be degraded. In response, TVA noted that some of the 
valves containing the Buna-N material had signs of aging, but were 
capable of performing their intended safety function.
    The licensee further noted that the December 24 letter stated that 
TVA had been alerted to problems with Buna-N by NRC Bulletin 78-14 and 
Generic Letter 91-15, however; the licensee maintained that these 
documents did not specifically identify the problems that TVA 
experienced. The licensee noted that NRC Bulletin 78-14 discussed 
deterioration through natural aging and did not specifically address 
thermal degradation of the Buna-N materials. The licensee also stated 
that Generic Letter 91-15 discussed the reliability of solenoid valves 
used in safety applications and then stated that the RCP seal return 
isolation valve solenoid was not safety related.
    Finally, the licensee noted that PER SQPER930001 was initiated to 
address solenoid valves that were mounted directly to hot piping 
systems and that 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 system.
Violation A(3)
    This violation involved the licensee's failure to develop an 
adequate corrective action plan and the failure to implement adequate 
corrective actions for the inadvertent fire system deluge actuation in 
July 1996.
    In response, TVA noted that it had corrected the leaking water 
source, replaced the failed fire detector, and conducted a post-deluge 
walkdown of the area, but did not inspect the affected junction box. 
The licensee also noted that it would have been difficult to recognize 
the water intrusion path.
    The licensee concluded that given TVA's early identification and 
initiation of corrective actions and its several initiatives to upgrade 
the plant's material condition, sufficient bases exists for not 
imposing any civil penalty for the events associated with the October 
11, 1996, Unit 2 shutdown. The licensee concluded that the violations 
could more appropriately be cited as separate Severity Level IV 
violations or that enforcement discretion should be exercised based on 
credit for TVA's identification and comprehensive corrective action. 
TVA also noted that a civil penalty under the facts and circumstances 
at hand would serve no purpose other than to punish the licensee and 
would be in contrast to the enforcement policy's stated purpose which 
is to, among other things, focus on the current performance of the 
licensee.

NRC Evaluation of Licensee's Request for Reduction in Severity Level

    In reviewing the licensee's response, no additional information was 
provided that was not previously considered by the NRC in its 
deliberations regarding this matter.
    The NRC acknowledges the licensee's position that, individually, 
the safety consequences of these violations were not a major concern. 
However, based on the fact that the three equipment failures that 
resulted from failures to take adequate corrective action all 
complicated the recovery from one event, the NRC concludes the 
regulatory significance of failing to take adequate corrective action 
and the potential safety consequences of the resulting multiple 
equipment failures during an event represents a significant regulatory 
concern. As stated in Section IV.A of the Enforcement Policy (NUREG-
1600), a group of Severity Level IV violations may be evaluated in the 
aggregate and assigned a single, increased severity level, thereby 
resulting in a Severity Level III problem, if the violations have the 
same underlying cause or programmatic deficiencies. The purpose of 
aggregating violations is to focus the licensee's attention on the 
fundamental underlying causes for which enforcement action is warranted 
and to reflect the fact that several violations with a common cause may 
be more significant collectively than individually and may, therefore, 
warrant a more substantial enforcement action. In this case, the NRC 
determined that the violations have the same underlying cause: 
inadequate implementation of the corrective action program; and 
therefore, were considered to be a significant regulatory concern.
    The licensee's position that the NRC should exercise discretion for 
identifying corrective action program problems and the improvements 
initiated in September 1996 cannot be supported. The NRC recognizes 
that improvement steps have been taken. However, inadequate 
implementation of the corrective action program has been identified as 
a continuing problem. NRC-identified corrective action program 
implementation deficiencies were noted in multiple inspection reports 
and previous Systematic Assessments of Licensee Performance (SALP) 
reports, in addition to present findings from licensee audits 
indicating the need for further improvements. Specifically, the 
Sequoyah Quality Assurance (QA) organization recently published similar 
conclusions. QA's ``Sequoyah Executive Summary--First Quarter Fiscal 
Year 1997'' report identified that both the Maintenance and Engineering 
organizations had failed to correct long-standing issues. In addition, 
recent, continuing QA audits of the corrective action program have 
identified poor corrective action program implementation in that a 
significant number of PERs were being rejected due to inadequate root 
cause

[[Page 30352]]

determination or insufficient corrective actions. The most recent NRC 
SALP report, NRC Inspection Report (IR) 50-327 and 50-328/96-99, dated 
September 6, 1996, also stated that corrective actions were untimely 
and not fully effective in many cases. Prior to that, the 1995 NRC SALP 
report, IR 95-99, dated February 21, 1995, noted several instances 
where ineffective corrective actions were observed. IRs 327, 328/96-09, 
96-08, 96-01, and 95-26 identified various ineffective corrective 
action issues or violations. In addition, IR 327, 328/95-25, the Final 
Integrated Performance Assessment Process Report, noted in the area of 
Engineering, a ``Weakness'' in Problem Identification/Problem 
Resolution and in the area of Safety Assessment/Corrective Action, 
noted a ``Significant Weakness'' in the area of Problem Resolution. 
These problems with the corrective action program indicated continuing 
weak program implementation and weak expectations regarding equipment 
failure trending, which related to a lack of management oversight and 
control of the corrective action program. Accordingly, enforcement 
discretion is not warranted.
    A discussion of the licensee's specific comments on each violation 
is described in detail below:
Violation A(1)
    Enclosure 1 of the NOV cited TVA's failure to perform adequate 
evaluations or to take adequate corrective actions for MFIV failures in 
January 1989, September 1990, September 1994, and April 1995. The 
licensee stated ``this listing of MFIV failures oversimplified the 
maintenance history of the subject MFIV.'' The licensee provided a 
short history of each of the brake failures, and noted that the MFIV 
only failed to stroke on two occasions. In addition, the licensee 
stated: ``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.''
    The NRC does not disagree with the licensee's clarification 
regarding the number of times the MFIV failed to stroke. However, the 
licensee has not provided a sufficient basis to support its conclusion 
that the April 1995 MFIV failure was due to an electrical short 
circuit, and the NRC does not agree with the licensee's evaluation. The 
work order associated with the April 1995 failure listed an 
``electrical ground'' as the cause of the failure, not an electrical 
short. A grounded lead would not have affected the functioning of the 
MFIV. A circuit short would have caused the motor brake assembly 
circuit fuses to blow, which was not documented. Regardless, neither an 
electrical ground nor a short circuit would have prevented the 
operation of the MFIV. The inspectors were informed by the licensee 
that the motor is designed to override the brake assembly and to close 
the valve if the brake does not electrically release. In addition, the 
inspectors noted that the brake assembly was discarded due to a 
grounded lead, which did not appear to be reasonable for an expensive 
piece of equipment, and that an evaluation or root cause determination 
of the brake assembly was not performed. In addition, maintenance 
workers extensively applied a sealant to the brake assembly housing, 
indicating that water intrusion was a known problem for this valve. 
This was especially apparent since none of the other seven MFIVs had 
any sealant applications.
    In this example, the NRC violation specifically cited the 
licensee's failure to perform adequate evaluations of deficient 
conditions. Although the actual root cause of the April 1995 failure, 
is unknown and debatable, the inspectors concluded that the licensee's 
documented root cause, ``grounded lead,'' would not have resulted in 
the observed failure. Therefore, the NRC concluded that the licensee 
failed to perform an adequate evaluation for the April 1995, failure 
and subsequently did not identify appropriate corrective actions.
    Nevertheless, the NRC continues to believe numerous opportunities 
existed to identify this particular component as problematic and to 
perform the necessary evaluation to identify the MFIV moisture 
intrusion problem. TVA failed to identify the root cause and take 
adequate corrective actions for the recurring failures.
Violation A(2)
    The licensee indicated that the NRC December 24, 1996 letter 
statement, `` * * * the failure of the ASCO solenoid valve caused 
excessive RCP seal leakage,'' was not accurate. The licensee took 
exception to the word ``excessive'' and then stated, ``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 hours of operation at 
full RCS pressure to allow operators time to react. As such, the 
condition to which the No. 2 seal was subjected was within the design 
condition for that seal.''
    The inspectors noted that, on October 11, 1996, a seal leakoff low 
flow alarm for the No. 4 RCP annunciated, followed shortly by the RCP 
standpipe alarm high/low annunciation. The operators entered Abnormal 
Operating Procedure R.04, ``Reactor Coolant Pump Malfunctions,'' 
Section 2.3, ``RCP #1 Seal Leakoff Low Flow.'' Step 6 of Section 2.3, 
``Verify RCP #2 seal leakoff less than or equal to 0.5 gpm,'' directed 
the operators to Section 2.4, ``RCP #2 Seal Leakoff High Flow.'' A note 
in Section 2.4 states, ``A leakoff of greater than 0.5 gpm indicates 
that a seal problem exists.'' Step 3 of Section 2.4 directs the 
operators to ``Monitor RCP #2 seal Intact: Verify RCP #2 seal leakoff 
less than or equal to 0.5 gpm. * * * '' If RCP #2 seal is greater than 
0.5 gpm, the operators are directed to perform a plant shutdown within 
8 hours. Also, Summary Report, Failure of 2-FCV-62-48, RCP #4 Seal Leak 
Off Isolation Valve, stated, ``An entry was made in containment to 
check the Loop 4 No. 1 Seal Leak Off Isolation valve and it was found 
to be closed, resulting in abnormally high leak off from the No. 2 
seals. * * * ''
    The NRC realizes that total seal leakage for this event was not 
significant when based on overall RCS inventory. However, based on 
leakage that exceeded the alarm setpoint and which required a plant 
shutdown, the NRC still considers the term ``excessive'' to be 
appropriate as used in this context.
    The licensee indicated that the December 24 NRC letter inaccurately 
stated that `` * * * a number of other valves were subsequently 
determined to be degraded.'' The licensee stated, ``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, 
these solenoid valves were replaced. The replaced solenoid valves were 
capable of performing their intended function in their `as-found' 
condition.''
    The NRC disagrees with this licensee position. The NRC's statement 
was based on information provided to the NRC by the licensee which 
indicated that several of the valves were determined to be ``leaking 
through'' and/or had reduced o-ring elastomer resiliency. The NRC 
considers these ``signs of aging'' to be indications of

[[Page 30353]]

degradation. In addition, the ASCO solenoid valves with the Buna-N 
material were only qualified for environmental conditions of less than 
125 degrees F. However, they were installed where area temperatures 
exceeded 125 degrees F, which greatly reduced their qualified life. The 
licensee documented that the valves remained in service for extended 
periods past their qualified life and as a result, showed signs of 
aging.
    The licensee quoted a statement in the NRC December 24 letter 
accompanying the violation 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);'' and stated that ``Listing these documents 
gives the impression that each document directly addressed the problem 
at hand. This is not the case.''
    The NRC's intent in listing these documents was to indicate that 
generic information was available on thermal aging of Buna-N that 
should have been implemented into Sequoyah's corrective action program. 
Generic communications are not intended to address every possible 
failure mechanism. However, in this case Generic Letter 91-15 
referenced NUREG-1275, Vol. 6, Operating Experience Feedback Report--
Solenoid-Operated Valve Problems, which focused on solenoid operated 
valve (SOV) failures from 1984 through 1989. Section 5.1.1.3 of NUREG-
1275 discussed localized ``hot spots'' in containment and reductions in 
qualified life of the SOVs, which was the precise condition TVA 
experienced. In addition, based on Generic Letter 91-15, in December 
1993, TVA developed corrective actions to implement the Generic Letter 
concerns (PER SQPER930001), which if broadly implemented had the 
potential to identify and correct the adverse Buna-N condition; 
however, at the time of the event, the corrective actions had not been 
implemented. The NRC's conclusions regarding the ASCO solenoid valve 
failure were based on the licensee's root cause investigation, which 
stated that TVA never implemented the action plan developed in 1993.
    Further, the NRC noted that following the event, PER No. SQ962633 
was initiated and stated, ``Although this type of failure had occurred 
previously at Sequoyah and had been addressed in an NRC Generic Letter, 
actions were not taken by plant personnel to prevent future similar 
failures. The root cause of the valve failure is ineffective 
application of plant and industry operating experience.'' Based on this 
documented statement, the licensee's contention that they had not been 
alerted to the problem is inconsistent with what was said previously in 
PER No. SQ962633.
Violation A(3)
    The licensee's interpretation noted that TVA had corrected the 
leaking water source, replaced the failed fire detector, conducted a 
post-deluge walkdown of the area but did not inspect the affected 
junction box. TVA also noted that it would have been difficult to 
recognize the water intrusion path.
    The NRC was aware of the immediate corrective action plan initiated 
by the licensee in response to the high-pressure fire protection system 
deluge header actuation in the Unit 2 turbine building which occurred 
on July 16, 1996. However, that action plan was not thorough in that it 
did not consider water intrusion into junction boxes. The licensee 
stated in their reply to the Notice of Violation that, subsequent to 
the Unit 2 turbine runback and trip on October 11, 1996, a total of 66 
Unit 2 local instrument panels and 70 Unit 1 junction boxes were 
inspected and evaluated, and repairs were either completed during the 
forced outage or scheduled within the work scheduling process. During 
that review, additional junction boxes in the turbine buildings for 
both units were identified where previous water intrusion was evident. 
The NRC concluded that a thorough corrective action plan following the 
July 1996 deluge event would have at least considered the possibility 
of water intrusion into junction boxes and instrument panels.
    In sum, the failure to take appropriate corrective actions as 
demonstrated by the three violations represent a significant regulatory 
concern as the inadequate corrective actions contributed to plant 
events. The licensee has not provided an adequate bases to modify the 
Severity Level determination.

Summary of Licensee's Request for Mitigation of Civil Penalty

    The licensee believes the civil penalty should be mitigated in its 
entirety because the current site management team was ``keenly aware'' 
that the quality of past corrective actions was still impacting current 
performance. In addition, the problems associated with the corrective 
action program were being aggressively addressed by ongoing improvement 
initiatives. TVA noted that the comprehensive actions greatly mitigated 
any regulatory significance that might otherwise exist in this area. 
TVA requested the NRC to view events in the broader perspective of the 
improved corrective action program and plant material condition 
upgrades in exercising discretion to mitigate the civil penalty 
associated with these violations.

NRC Evaluation of Licensee's Request for Mitigation of Civil Penalty

    The NRC does not fully agree with the licensee's position that TVA 
identified the corrective action program implementation problems and 
then took comprehensive actions in September 1996. Previous inspection 
reports and SALP reports noted corrective action program implementation 
problems. However, the licensee did not fully address the problems in 
September 1996, and significant corrective action program problems are 
still being identified. The problems with the corrective action program 
indicated continuing weak program implementation and weak expectations 
regarding equipment failure trending, which related to a lack of 
management oversight and control of the corrective action program.
    Contrary to the licensee's statements, the NRC did consider the 
licensee's efforts to improve the corrective action program's 
effectiveness prior to the October 11, 1996 event. However, as 
evidenced by the violations cited in the Notice and the specific 
circumstances surrounding them, as described in the inspection report, 
the NRC concluded that (1) the licensee's corrective actions prior to 
the equipment failures associated with the October 11, 1996 Unit 2 
shutdown, were not fully effective in assuring adequate resolution of 
repetitive equipment failures and avoiding additional non-compliances, 
and (2) the violations were the result of ineffective corrective action 
program implementation. Specifically, the examples of inadequate 
corrective actions identified in Violations A(1), A(2) and A(3) 
indicate that previous initiatives had not achieved the desired 
results.
    The guidance described in Section VI.B.2.b of the Enforcement 
Policy was used to evaluate the licensee's actions related to the 
factor of Identification. Specifically, the NRC concluded that 
Violations A(1), A(2) and A(3) were revealed through an event. The 
three violations were identified as a result of the failure of the 
components involved during the October 11, 1996 event. When violations 
are identified through an event, Section VI.B.2.b of the Enforcement 
Policy states that the decision on whether to give the licensee

[[Page 30354]]

credit for actions related to identification normally should consider: 
(1) the ease of discovery; (2) whether the event occurred as the result 
of a licensee self-monitoring effort; (3) the degree of licensee 
initiative in identifying the problem or problems requiring corrective 
action, and (4) whether prior opportunities existed to identify the 
problem. Enforcement Policy Section VI.B.2.b further states that any of 
these considerations may be overriding if particularly noteworthy or 
particularly egregious.
    With regard to ease of discovery and prior opportunities, the NRC 
believes that sufficient information was available to the licensee in 
each case that led to a violation to indicate that a problem existed. 
The failure to consider adequately the potential scope of the problems 
indicated by previous equipment failures and generic communications was 
an overriding reason to deny credit for identification.
    With regard to the degree of licensee initiative in identifying the 
problem, the fact that TVA had previously recognized the shortcomings 
of the corrective action program as early as 1995 but failed to 
identify the violations was of concern to the NRC. In the licensee 
response, the highlighted corrective actions only addressed actions to 
ensure future identification of problems and did not address correction 
of previous failures of the corrective action program to resolve 
deficiencies.
    The event did not occur as a result of a licensee self-monitoring 
activity; therefore, the NRC concluded, as stated in the December 24, 
1996 letter, that credit was not warranted for the factor of 
Identification. The licensee has not provided an adequate argument to 
mitigate the civil penalty based on the identification factor.
    The NRC did conclude in the December 24, 1996 letter that credit 
was warranted for the factor of Corrective Action, based on the 
extensive corrective actions outlined by the licensee at the December 
16, 1996 predecisional enforcement conference to improve (1) plant 
material conditions, (2) management effectiveness, and (3) 
implementation of the corrective action program. The NRC acknowledged 
that the licensee had taken and proposed steps, at the time of the 
predecisional enforcement conference, to improve corrective actions at 
Sequoyah. However, based on subsequent QA findings, it appears that 
even TVA's most recent efforts to improve the corrective action program 
have not been fully effective. While the NRC is not reconsidering the 
decision to grant Corrective Action credit, the NRC remains concerned 
and emphasizes again the importance of prompt and comprehensive 
corrective action.

NRC Conclusion

    The NRC concludes that the violations occurred as stated and that 
collectively they represent a Severity Level III problem. The licensee 
had opportunities to resolve the issues, in some cases multiple 
opportunities, however, the deficiencies remained until clearly 
identified as a result of the October 11, 1996, plant event. Therefore, 
the NRC has concluded that, neither an adequate basis for a reduction 
of the severity level nor for mitigation of the civil penalty were 
provided by the licensee. Consequently, the proposed civil penalty in 
the amount of $50,000 should be imposed.

Response to Licensee Comments on Violations B(1), B(2) and B(3)

    In its response of January 23, 1997, TVA expressed the following 
concerns with the descriptions of violations B(1), B(2), and B(3) in 
the NOV.
    1. The licensee noted that the December 24, 1996 NRC letter 
identified one of the root causes of the violations as poor 
communications among Operations, Maintenance, and Engineering, and the 
licensee also noted that it could be inferred that poor communication 
was prevalent throughout the event. In addition, the licensee stated 
its belief that the poor communications were limited to the subsequent 
analysis of the equipment condition.
    The December 24 letter statement was intended to be a general 
statement and was not intended to infer that poor communications were 
``prevalent'' throughout the event. However, NRC findings indicated 
that poor communication was not limited only to the subsequent analysis 
of the condition. Interviews indicated that the Shift Manager, Unit 
Shift Supervisor and operators had concerns with operability of the 
reactor trip breaker; however, the differences between Operations and 
Maintenance/Engineering were not resolved without management 
intervention, which resulted in the Limiting Condition for Operation 
(LCO) being exceeded. This was considered to be a communications issue. 
In addition, the initial PER did not identify in writing the issue 
regarding the P-4 turbine trip function, that was later added to the 
PER due to the Shift Manager's request the following day. This was also 
considered to be a communications issue. These issues, i.e., the fact 
that the event review team knew that the disconnected reactor trip 
breaker contacts affected the operability of the breaker, Technical 
Support had evaluated the disconnected contact condition, compliance 
personnel had evaluated the disconnected contacts, management was not 
notified of the adverse condition and, the event review did not 
document the adverse condition, were collectively considered to 
represent poor communications.
    2. The licensee noted that the December 24, 1996 NRC letter 
identified non-conservative decision making as one of the root causes 
of the violations. This was based on Operations' failure to remove the 
suspect reactor trip breaker (RTB) for a number of hours. An early, 
conservative decision on RTB operability could have precluded exceeding 
the LCO. The licensee stated that at the time the LCO expired, 
available information/data, did not indicate any abnormality beyond a 
set of dirty contacts or a loose connection associated with the RTB 
computer input circuit, and a ``conservative decision'' was made 
``not'' to remove the RTB until: (1) An evaluation was made related to 
the potential for a transient and (2) the breaker was determined to be 
the most likely cause of the alarm.
    The intent of the December 24 letter comment was to put the 
licensee on notice that a conservative decision ``could'' have 
prevented exceeding the LCO. In this case, when the breaker abnormality 
was indicated by an alarm following refurbishment activities, it was 
not a conservative decision to assume the cause prematurely and leave 
the breaker in place. A conservative decision would have been instead 
to remove the suspect equipment until further testing could be 
completed to ensure operability.
    3. The licensee noted that the December 24, 1996 NRC letter stated 
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 licensee stated 
that this NRC comment was based on the licensee staff proposal to 
troubleshoot the RTB and to ``dummy'' a signal to the computer. In the 
TVA clarification, the licensee stated that there were no indications 
that more than one contact was suspect and that the dummied computer 
value allowed continuous rod deviation monitoring which relieved 
operators from additional LCO actions. In addition, the licensee stated 
that it considered the insertion of the dummied value to be more 
conservative and that the activity was not performed to mask the alarm 
condition. The

[[Page 30355]]

licensee also stated that it did not agree with the NRC's statement 
that resources were diverted for insertion of a value into the computer 
in order to clear the alarm.
    It is the NRC's conclusion that the licensee failed to recognize 
the significance of the rod deviation alarm. The licensee stated that 
there were no indications that more than one contact was involved, 
however, two previous Westinghouse letters from 1979 and 1987, 
available to the licensee, identified that the reactor trip breaker P-4 
circuitry contained potentially undetectable failures, and in fact 
several contacts were involved with this event and they were 
``undetectable'' without the proper testing. Had appropriate actions in 
response to the Westinghouse letters been taken, this event potentially 
would have been avoided. With regard to the ``dummied'' computer input, 
during initial NRC interviews with the Shift Manager, Unit Shift 
Supervisor and other control room personnel, the inspector noted that 
it was the control room staff's belief that, if the computer point 
could have been readily fixed, no further action would be necessary. In 
addition, the control room staff expressed an opinion that they had 
performed above and beyond normal just to get the faulty breaker out of 
the cubicle. The inspector noted that the insertion of a dummied signal 
eliminated relatively minor surveillance activities which did not 
appear to be warranted until the cause for the alarm was positively 
identified.

[FR Doc. 97-14397 Filed 6-2-97; 8:45 am]
BILLING CODE 7590-01-P