[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.
[[Page 30350]]
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
