ML17059B749
| ML17059B749 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 10/17/1997 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17059B747 | List: |
| References | |
| 50-220-97-80, 50-410-97-80, NUDOCS 9711030003 | |
| Download: ML17059B749 (82) | |
See also: IR 05000220/1997080
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION
I
Docket Nos.:
50-220; 50-410
Report No.:
97-80; 97-80
Licensee:
Niagara Mohawk Power Corporation
Facility:
Nine Mile Point
Location:
Oswego, New York
Dates:
August 4 - 22, 1997
Inspectors:
G. K. Hunegs, Senior Resident Inspector
G. S. Galletti, Human Factors Branch, NRR
C. W. Smith, Project Manager,
E. C. Knutson, Resident Inspector
R. A..Skokowski, Resident Inspector
Approved by:
~&et+>" ~
. l'~..~.
~~l<~~~~
Lawrence T. Doerflein, Chi f
Projects Branch
1
Division 'of Reactor Projects
97ii030003 9'7i024
ADOCK 05000220
6
pDR
ah
TABLE OF CONTENTS
TABLE OF CONTENTS
EXECUTIVE SUMMARY
IV
I ~ OPERATIONS
03
07
08
08.3
Operations
Procedures
and Documentation
03.1
Corrective Action Program Procedures.....
03.2
Operability Determination Procedures
Quality Assurance
in Operations
.
07.'I
Review of Deviation/Event Reports
07.2
Root Cause Analysis
07.3
Deviation/Event Report Program Summary Trend Report ..
~ ..
07.4
Corrective Action Program Quality Assurance Audits
07.5
Operating Experience Review Process
. ~....,
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07.6
Adverse Trend Identification .. ~.....
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.
07.7
Independent
Safety Engineering Group (ISEG)
07.8
Self Assessment
Program
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.
07.9
Corrective Action Program Related to Human Performance
Miscellaneous Operating Issues
08.1
Unresolved Item 50-410/95-25-03:
DERs Extended Without
Justification
08.2
(Closed) Inspector Follow Item 50-410/96-07-12:
Weaknesses
in the DER Process
(Closed) Inspector Followup Item (IFI) 50-410/96-07-13:
ISEG
Review of NRC Documents....
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1
1
1
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2
3
3
5
7
8
10
11
13
14
14
16
16
17
17
II. MAINTENANCE
M3
M8
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Conduct of Maintenance
M1.1
Emergent Maintenance
Maintenance
and Material Condition of Facilities and Equipment
M2.1
Material Condition Observations
M2.2
Unit 2 Drywell Cleanliness Controls...
~
M2.3
Unit 2 Residual Heat Removal System Flow Control Valve
Problem
M2.4
Unit 2 Steam Tunnel Door Seal
.
Maintenance
Procedures
and Documentation
~ .
M3.1
Problem Identification and Work Control Process
M3.2
Operator Work Arounds
Miscellaneous Maintenance
Issues
M8.1
(Closed) Unresolved Item 50-410/95-25-02:
Extended
Inoperability of the Unit 2 Loose Parts Monitor...........
M8.2
(Closed) Inspector Followup Items 50-220/96-07-17
and 50-
4'IO/96-07-17:
Extended Installation Period for a Service
Water System Temporary Modification
18
18
18
20
20
22
24
26
27
27
28
30
30
31
a5
Table of Contents (cont'd)
III~ ENGINEERING
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E7
Quality Assurance
in Engineering Activities
E7.1
50.59 Program Review
E8
Miscellaneous
Engineering
Issues
E8.1
IFI 50-220 5 410/96-07-14:
Weaknesses
Program
I
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in the 50.59
31
31
31
32
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32
V. MANAGEMENTMEETINGS
X1
Exit Meeting Summary...
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X2
Review of UFSAR Commitments...
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33
33
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33
ATTACHMENT
Attachment
1 - Partial List of Persons
Contacted
- Inspection Procedures
Used
- Items Opened,
Closed, and Discussed
- List of Acronyms Used
EXECUTIVE SUMMARY
Nine Mile Point Units
1 and 2
NRC Inspection Report Nos. 50-220; 50-410/97-80
~Oerations
The procedures
for implementing the corrective action program and operability
determination were generally good with some shortcomings
noted.
The use of the
validation test for root cause
and corrective actions was considered
a good aid for
verifying the quality of proposed corrective actions.
In general, the licensee analyzed and resolved problems.
However, shortcomings
were identified With the quality of root cause determinations,
corrective actions and
documentation.
Root causes
and apparent root causes
were generally good at
identifying the first level, technical causes
but tended to stop and not go to a
greater depth.
Therefore what was necessary
to prevent recurrence was not
always fully developed.
Several weaknesses
in the programs to identify and
address
human performance
issues were apparent.
Self assessment
and quality
assurance
activities were generally effective and improvement in these areas was
noted.
A violation was identified concerning the failure to justify the extension of
deviation/event
report (DER) due dates.
Furthermore,
the licensee's corrective
actions to prevent recurrence of this previously identified concern were ineffective.
Maintenance
The licensee was effective in resolving emergent maintenance
issues including the
Unit 2 reactor coolant system flexible hose failure, the Unit 2 service water makeup
control valve to the circulating water system malfunction, and the Unit 2 emergency
diesel generator
DC control power annunciator failure. The operations department
made significant contributions both to the identification of problems and control of
'plant conditions to support maintenance.
An inspector followup item concerning
the failed flex hose was documented
in a separate
NRC inspection report No. 50-
41 0/97-06.
The overall material condition of Unit 2 was good; however, inspector identification
of several material problems in the reactor building indicated that additional material
inspections
by the licensee could be productive.
The material condition of the
steam tunnel was assessed
to be poor.
Based on the material deficiencies that
were identified by the inspectors
in this area, it did not appear that the licensee was
taking full advantage
of the forced outage to inspect normally inaccessible
areas of
the plant for emergent material problems.
Drywell cleanliness was generally good; however, cleanliness requirements for the
drywell are not clearly established
in the governing procedure
especially with
respect to control of downcomer foreign material exclusion covers.
Executive Summary (cont'd)
Given the safety significant functions performed by the "B" residual heat removal
system full flow test valve, licensee investigation of the reported degraded
condition of the valve was slow. Additionally, the decision to start the 72 hr LCO
at 11:00 a.m. on August 19, rather than on the afternoon of August 18, when the
condition was reported, was not conservative.
The intermediate valve position
indication that occurred'n June 1997 was apparently
a missed opportunity to
identify the loose stem lock nut.
The temporary modification that installed a urethane
seal on the Unit 2 inner steam
tunnel door in 1992 was inadequate,
in that it failed to account for environmental
temperatures
that exceeded
the design temperature
of the seal material.
After seal
degradation
was identified, corrective actions were appropriate.
Use of the
~ inappropriate
seal material from 1992 until 1996 had the potential to cause
a failure
of secondary containment; however this did not occur, and the degraded
condition
,did not constitute
a violation of any other specific regulatory requirements.
Operability of the door as a fire barrier was not affected by the degraded
seal.
The problem identification (PID) system procedures
established
adequate
guidance
for work control.
However, the PID process
does not procedurally ensure the same
level of review and evaluation
as does the DER entry mechanism for the corrective
action program.
Adequate procedures
and processes
are in place for identification and correction of
operator work arounds.
Unit 2 has been effective in reducing the number of
operator work arounds
and longstanding tagouts.
Some items being carried on the
Unit 2 operator work around list apparently have no recourse remaining, and could
lessen the credibility of this corrective action mechanism.
~ncnineering
The quality of safety evaluations reviewed was good.
The improvement in quality
was attributed in part to good senior management
oversight of the program.
In
'
contrast to the quality of the safety evaluations,
the quality of applicability reviews
was mixed primarily due to the level of documentation.
In some cases,
documentation
was not sufficient to support the conclusions
reached.
Overview
Through the review of several licensee programs, performance indicators, material
condition deficiencies and discussions
with licensee personnel,
the inspectors evaluated
the effectiveness
of the licensee's controls for identifying, resolving, and preventing issues
that degrade the quality of plant operations
and safety.
The objective of the inspection
was to determine if the licensee's corrective action program resulted in problems getting
resolved.
I. OPERATIONS
03
Operations Procedures
and Documentation
03.1
Corrective Action Program Procedures
a.
Ins ection Sco
e
The team assessed
the licensee's corrective action program procedures to
determine whether adequate
controls are in place to facilitate an effective program.
Findin s and Observations
Niagara Mohawk Power Corporation's
(NMPC's) corrective action program was
controlled by Procedure
NIP-ECA-01, "Deviation/Event Report," Revision 11, with
additional guidance for deviation/event report (DER) dispositioning provided in
Procedure,
S-GUI-ECA-0101, "Guidelines for DER Disposition," Revision 00.
Although some shortcomings were noted, the implementing procedures
for the
corrective action program were generally good.
Particularly noteworthy was the
validation test to verify the quality of proposed corrective actions.
Furthermore, the
team noted that improved guidance regarding
10 Code of Federal Regulations
(CFR)
Part 21 reviews was incorporated
in Procedure
NIP-ECA-01 subsequent
to a
weakness
identified in this area in NRC Inspection Report (IR) 50-410/97-01.
The most significant shortcoming with the licensee's corrective action procedures
was that an acceptable
length of time to route a DER to the station shift supervisor
(SSS) was not specified.
Since the initiator may not be fully aware of the impact of
a concern with respect to plant conditions, and since the SSS is responsible for
making equipment operability determinations,
timely routing of DERs to the SSS is
critical.
Additional shortcomings with the DER procedures
included a lack of guidance on
evaluating the extent of the problem, such as verifying other susceptible
locations
for similar problems.
Nominal guidance was provided regarding specific reviews for
repeat failure and for the identification of adverse trends.
No guidance was
provided describing management's
expectations
regarding the branch managers
review of the quarterly'DER Trend Report.
Further details regarding these
shortcomings
are provided within the applicable sections of this report.
)
Conclusions
The procedures
for implementing the corrective action program were generally good
with some shortcomings
noted.
The use of the validation test for root cause and
corrective actions was considered
a good aid for verifying the quality of proposed
corrective actions.
03.2
Operability Determination Procedures
Ins ection Sco
e
The station shift supervisor
is responsible
for making decisions concerning
operability and may request that the NMPC engineering department provide an
analysis to provide technical justification for the decision.
The team assessed
the
.adequacy
of the licensee's
procedures
associated
with operability determinations
by
comparing the procedures
to the guidance provided in NRC Inspection Manual
Sections on Resolution of Degraded
and Nonconforming'Conditions
and Operability
as referred to by Generic Letter 91-18.
b.
Findin s and Observations
0 erabilit
Determinations
I
The Nine Mile Point Unit
1 (Unit 1) Procedure
N1-ODP-OPS-0103,
"Equipment
Revision 00, and Nine Mile Point Unit 2 (Unit 2)
Procedure
N2-ODP-OPS-0001,
"Conduct of Operations,"
Revision 8, are associated
with operability determinations.
The procedures
were found to be consistent with
each other and with the guidance provided in Generic Letter 91-18.
The procedures
provided the station shift supervision with a checklist to aid in operability
determinations
and guidance
in whether requesting
an engineering support analysis
(ESA) would be necessary.
During the team's review of DERs, no examples of improper operability
'determinations
were identified.
However, as described
above, the team noted that
the DER procedure
lacked positive controls to ensure that DERs would be routed to
the station shift supervisor in a timely manner.
The team identified one DER (1-97-
0002) associated
with core spray system design pressure
inaccuracies
in the
UFSAR that took six days from initiation until it reached the SSS.
Although the SSS
determined that the discrepancy
associated
with DER 1-97-0002 did not adversely
impact system operability, the excessive time for the DER to reach shift supervision
failed to meet licensee managemeiir, expectations.
En ineerin
Su
ortin
Anal sis
The team reviewed NMPC's Engineering
Guidelines entitled "Engineering Supporting
Analysis," NEG-1E-0006 and NEG-2S-010 for Units
1 and 2 respectively.
Both
procedures
contained essentially the same information and were consistent with
However, the team noted that the Unit 2 guidelines lacked
information regarding the level of supervision required for approval of ESAs.
Discussion with the Unit 2 Engineering Department Manager indicated that the first
level supervisor was responsible for ESA approval.
The team found this consistent
with the guidance for Unit
1 ESA approvals
and with the Unit 2 ESAs reviewed.
The team found the procedural guidance regarding ESAs appropriate.
C.
Conclusions
The procedural guidance regarding operability determinations
and ESAs were
consistent with the guidance provided in Generic Letter 91-18, and considered
appropriate.
07
Quality Assurance
in Operations
07.1
Review of Deviation/Event Reports
a
~
Ins ection Sco
e
The team reviewed selected
DERs for both units to assess
implementation adequacy
and technical quality.
b.
Findin
s and Observations
Im lementation Ade uac
Some minor implementation discrepancies
were noted.
These discrepancies
were
normally administrative in nature and did not impact the quality of the DER.
However, the team noted that a relatively large number of DERs were past the due
date without procedurally required extension requests,
this concern is described
in
detail in Section 08.1, "Unresolved.Item 95-25-03:
DERs Extended without
Justification."
The DER procedure
(NIP-ECA-01) requires the plant managers
to categorize
DERs
with respect to significance.
This allows issues of higher significance to receive
more stringent evaluation and quicker disposition.
The procedures
provided
a list of
examples to aid in determining the appropriate
DER category.
The team noted at
least six cases where DER categorization was questionable.
Although the category
determined for each case fit examples provided, the team considered
the DERs to
be better suited to the examples provided for the next higher category.
The questionable
categorization was common to two areas.
First, DERs associated
with potential common mode failure issues (for example DERs 1-97-0565 and 1-97-
1482 associated
with equipment response
to high energy line breaks, and DERs 2-
97-0498 and 2-97-1560, associated
with recurring failures of a component within
the Riley temperature switches as described
in Section 07.6), were category 2.
The team considered
category
1 to be more suitable for these
DERs since "common
mode failure" was specifically provided in the DER procedure
as an example of a
category
1 DER.
Second,
DERs associated
with adverse trend (for example
DER 2-
P
97-0203 regarding recurring Unit 2 Operations Department failure to comply with
administrative procedures
as described
in Section 07.6) were category 3; the team
considered
category 2 to be more suitable based
on the extensive nature of the
concerns.
Technical Qualit
The team reviewed
a representative
sample of DERs for technical quality, and
generally found that problems were analyzed and resolved.
However, some
shortcomings
were identified regarding root cause determination
and corrective
actions.
Concerns associated
with root cause analysis are included in Section
07.2.
The issues associated
with corrective actions include ineffective corrective
actions, corrective actions not addressing
the root cause, narrowly focused
corrective actions, and poorly documented
DER dispositions.
Examples of DERs with corrective actions that did not address
the root cause
included DER 2-96-2155, "QVSA - Adverse Trend 'Chemical Control'iolations of
NIP-CHE-01," which is described
in Section 07 .6, "Adverse Trend Identification."
Also, DER 1-97-1439 associated
with feedwater low flow control valve leakage
illustrated corrective actions not associated
with the root cause.
Although the
licensee determined the leakage not to be excess'ive,
the root cause of the leakage
was determined to be component
aging; however, no corrective actions were taken
to address the aging concern.
Furthermore, the closure summary of this DER
included
a recommendation
to reduce the differential pressure
across the valve to
minimize leakage; but, no means were in place to track this recommendation.
Narrowly focused corrective actions were noted in DERs 2-97-0203, 2-97-0201
and
1-97-1850.
DER 2-97-0203:
Adverse Trend in Operations Abilityto Implement
Administrative Requirements,
as described
in Section 07.6, "Averse Trend
Identification," in which the corrective actions only addressed
Unit 2 Operations
Department, when all departments
on site were susceptible to this problem.
The
corrective actions for DER 2-97-0201 associated
with a high frequency of valves
found out of position, only addressed
Unit 2, when the potential for similar concerns
existed at Unit 1.
DER 1-97-1850 associated
with a control room vent chiller
failure, as described
in Section 07.2, "Root Cause Analysis," determined the cause
of the failure to be the deferral of system periodic preventive maintenance.
However, the corrective actions only focused on the chiller that failed, no indication
was provided regarding the status of the preventive maintenance
for the other
division chiller, nor was an evaluation of the impact of deferred preventive
maintenance
for other equipment available.
In general, the team considered
the quality of the documentation
associated
with
DER dispositions to be acceptable.
Some of the better documented
dispositions
provided written answers to the root cause and corrective action validation test
described
by the licensee's
procedure.
However, the team considered
the
documentation oi some DERs to be poor.
In particular, the disposition for DER 1-
97-0697 regarding degraded
wiring in an emergency diesel generator
(EDG) relay
target coil was poor due to the limited information provided.
The team discussed
P
the issues with the relay and controls supervisor,
and obtained pertinent information
that was not provided within DER disposition.
Information, such as, that the similar
relays for the EDG were verified not to be degraded,
and the programmatic controls
in place to allow the licensee to identify similar problems with other relays.
Conclusions
ln general, the licensee analyzed and resolved problems.
Howe'ver, based on the
DERs reviewed, shortcomings
were identified in the following areas:
4quality of root cause determinations;
oeffectiveness
of corrective actions;
oadequacy
of corrective actions to address the root cause;
oscope of corrective actions;
odocumentation
of DER disposition;
ocategorization of DERs; and
oextension of DERs without required justification.
Root Cause Analysis
Ins ection Sco
e
The team reviewed recent root cause evaluations conducted
by the licensee.
In
accordance
with station procedures,
root cause evaluations
are required to be
performed on all Category
1 DERs and for other events meeting a licensee
established
threshold.
The team used these reviews to assess
the licensee's
capability to determine the root cause of events and the effectiveness
of the
preventive actions assigned
to the identified causes
at preventing
a recurrence.
The team reviewed recent root cause evaluations conducted at each unit.
Unit
1
1-97-1489
- sodium hypochlorite not being injected into waste water
1-97-150'I - failure to write a DER on a non-conforming condition
1-97-1647 - tom screen on condensate
demineralizer strainer basket,
1-97-1830 - failure of drywell drain isolation valve resulting in plant shut down
1-97-1850 - control room vent chiller failure
'I-97-2207 - discrepancy with dose rates for off site shipment
Unit 2
2-97-1570 - blown control power fuses
2-97-1696 - loss of electric power during control room fire
2-97-1698 - primary containment circuit breaker found out of position
2-97-1773 - inadvertent isolation of RWCU system
2-97-1960 - reverse flow failure of check valve 2CSH "V16
In addition, the team interviewed several qualified root cause evaluators
and
representatives
from the quality assurance
and training departments.
I
Findin s and Observations
The team found that the root cause evaluations
in most cases were adequate
at
determining the higher level, technical causes for an event but did not go into
sufficient depth to explore the potential for human error.
In some cases,
this led the
licensee to assigning preventive actions that provided additional procedural or
physical barriers to prevent recurrence rather than correcting the underlying human
performance
issues.
An example is the event and root cause determination, documented
in DER 1-97-
1830.
This event led to a plant shutdown
as a result of debris found in the seat of
a drywell isolation valve.
The root cause assigned
was failure to maintain adequate
The preventive actions assigned
included the use of
temporary screens
during future maintenance
activities, increased inspections of
floor drain sumps, awareness
training, and a revision to the procedure to consider
potential impacts of foreign material.
The root cause does not discuss why the,
existing procedural guidance on foreign materials control was inadequate
to prevent
this event.. There is no evidence that any personnel interviews were conducted to
determine why the individuals involved in planning and executing the precipitating
work activity did not consider the consequences
of their actions.
DER 1-97-1850 was associated
with a control room vent chiller. The licensee
determined the root cause to be the deferral of periodic preventive maintenance
on
the system.
The root cause evaluation was not thorough,
in that information was
not provided regarding the adequacy of the deferral decision, or the adequacy of the
preventive maintenance
deferral process.
Furthermore, the licensee's corrective
actions were narrowly focused in that an evaluation of the acceptability of the
preventive maintenance
for the other division chiller was not provided, nor was an
evaluation of the impact of deferred preventive maintenance
for other equipment
completed.
DER 2-95-1850 was associated
with a delay in Unit 2 plant startup due to a
significant number of non-safety related air-operated
valve failures within the
condensate
demineralizer system.
The licensee identified three different types of
-failures during their review.
The team's review of the DER concluded that the
licensee failed to identify the underlying cause of the problem, and that the
corrective actions were narrowly focused.
For example, the licensee determined
that a lack of periodic preventive maintenance
was a cause, but no reason for the
lack of periodic preventive maintenance
was provided.
Also, the corrective actions
were limited to incorporating preventive maintenance
for the valves in question, but
no consideration was given for the potential for a lack of periodic preventive
maintenance
on other equipment.
The licensee has self-identified similar inadequacies
with the quality of root cause
evaluations.
These are documented
in the Nuclear Quality Assurance department's
most recent audit of the corrective action program, NQA Audit 97004, Corrective
Action Program.
DER C-97-1538 was written based
on the audit report finding of a
failure to provide complete root cause evaluations for five of six Category
1 DERs
written from February 12, 1997 through May 12, 1997.
c.
Conclusion
Root causes
and apparent root causes were generally good at identifying the first
level, technical causes
but tended to stop and not go to a greater depth.
Therefore
what is necessary
to prevent recurrence
is not always fully developed.
07.3
Deviation/Event Report Program Summary Trend Report
a.
Ins ection Sco
e
The team reviewed the last four quarterly DER Program Trend Summary Reports to
-evaluate the usefulness
of the reports in assessing
the types of problems occurring
at the Nine Mile Point (NMP) station, and in the identification of adverse trends at
the station.
The team discussed
the use of the trend reports with the plant
managers,
and selected branch managers.
Also, the team evaluated the accuracy
of the information contained within the trend report by comparing
DER data to the
information provided within the reports.
b.
Findin s and Observations
The team found the quarterly DER Program Trend Reports contained
a large amount
of raw data, including, number of DERs sorted by department,
cause code and
system, number of adverse trend DERS initiated, number of DERs open greater than
one and two years, and the number of DER implementation due date extensions
sorted by department.
The report also included information regarding personnel
error rate for each department,
in which the error rate was based on work practice
cause code per 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> worked.
Although the team considered
the amount of
information provided within the Trend Report to be significant, no information
regarding repeat failures was provided." Furthermore,
no assessment
of the
information was provided.
Through discussion with members of the licensee's
senior management,
the team
ascertained
that the licensee's
senior management
reviewed the Trend Report, and
that each branch manager was responsible to review the Trend Report for
information pertaining to their respective branch.
Since there was no procedural-
guidance prescribing NMPC's expectation for branch manager review of the Trend
Report, the team discussed
the assessment
of the Trend Report with branch
managers
from both units.
The team noted that the methodology used to assess
the Trend Report varied for each branch manager,
and that no documented
assessment
of the Trend Report was required.
In general, the branch managers
interviewed had reviewed the Trend Reports to determine if their branch was an
outlier with respect to the rest of the site.
Additionally, all branch managers
interviewed noted that the personnel error rate was a valuable indicator of branch
performance.
The team concluded that although the DER Program Trend Report
was reviewed by licensee management,
the quality and methodology of the
8
reviewed varied, and that documented
assessment
of the data from the DER
Program Trend Report was lacking.
The team noted that approximately two percent of all DERs listed in the licensee's
database
were not assigned
the correct category due to data entry errors.
Additionally, the team noted that only adverse trend DERs that include the words
"Adverse Trend" in the title were included within the DER Program Trend Report.
The team discussed
this discrepancy with QA and the Plant Managers.
Based on
these discussions,
the team concluded that there was a lack of communication
between QA and the plarits regarding the adverse trend documentation
and
trending.
Discrepancies with the DER database
were noted previously by QA in
DER C-97-1611, the specific issues identified by the team were noted by the
licensee in DER C-97-2494.
C.
.Conclusions
The amount of raw data provided within the quarterly DER Program Trend Report
was significant; however, no information regarding repeat, failures was provided.
Although the DER Program Trend Report was reviewed by licensee management,
the review varied, and that documented
assessment
of the data from the DER
Program Trend Report was lacking.
Data-entry errors associated
with DER category
were identified.
Furthermore,
a lack of communications
between QA and the units
resulted in a failure to trend all adverse trend DERs in the DER Program Trend
Report.
07.4
Corrective Action Program Quality Assurance Audits
a 0
Ins ection Sco
e
The team reviewed the last three corrective action program audits performed by
Quality Assurance
(QA) to assess
the quality of the findings and the effectiveness
of the licensee's
actions taken to address
identified discrepancies.
b.
Findin s and Observations
The Unit
1 and Unit 2 Technical Specifications
(TS) required that an audit of the
corrective action program be performed every six months.
The team verified that
the last three corrective action program audits were completed according to the TS
requirement.
QA Audit 96008 was completed
in May 1996 and concluded that the corrective
action program was overall satisfactory with some areas in need of improvement
noted.
The areas in need of improvement were addressed
in two existing DERs (C-
94-2560 and C-96-0600); therefore, no additional DERs were generated
as a result
of the QA audit.
The NRC considered that QA Audit 96008 emphasized
the
findings of previous assessments
and provided little independent
evaluation.
QA's
review of corrective action program effectiveness
indicated the corrective actions
were effective, however, the team considered
the sample size to be too small and
narrowly focused on QA identified issues to provide and accurate assessment.
QA Audit 96020 was completed November 1996 and focused on the effectiveness
of management's
efforts to address
previously identified discrepancies
related to the
corrective action program.
Particularly, QA reviewed the effectiveness of the
corrective actions taken through DERs C-94-2560 and C-96-0600.
In addition, QA
reviewed
a sample of DERs for compliance and effectiveness
of corrective actions.
Assessments
of the operating experience
(OE) process
and Branch self-assessments
were also included in the audit.
QA concluded that the corrective action program
was being effectively implemented with some exceptions.
The team found QA Audit 96020 to be more thorough than the previous audit, in
that it contained more independent
review.
However, shortcomings
were noted by
,the team; in particular, QA reviewed 29 significant DERs for compliance with the
controlling procedure,
but only 3 DERs (C-94-2560, C-96-0600 and 2-95-3187)
were reviewed for effectiveness of corrective actions and discrepancies
were noted
in each case.
The team considered
the number of items reviewed for effectiveness
of corrective actions to be small and the scope of the audit was not increased
even
though the results indicated that the corrective actions were not completely
effective.
The team also noted that the executive summary and the conclusion section of QA
Audit 96020 did not reflect the shortcomings
described within the details of the
audit.
This concern was discussed
with the QA manager and the Chief Nuclear
Officer (CNO) and it was ascertained
that the licensee
had recognized this and
expressed
the concern to QA management.
QA Audit 97004 was completed in May 1997 and focused on a review of DERs for
administrative and fundamental soundness.
Of the 61 DERs reviewed, QA
concluded that 62% acceptably implemented the program requirements
and that
75% acceptably identified and corrected the underlying cause.
The QA audit team
concluded that the overall effectiveness
and implementation of the CA program was
marginally acceptable
and that problems existed with DER procedure
adherence
and
root cause determination.
As a result of the audit, QA initiated five DERs to
address
specific concerns,
most notable was DER C-97-1680, "Audit 97004:
Results of Corrective Actions to Improve Quality of DER Dispositions not in
Accordance with Managements'xpectations."
The team considered Audit 97004 to be critical. The review of DERs included
a
sufficient sample size to provide a credible indication of the overall program status.
The checklist used by the QA auditors to evaluate the DERs was found to be good.
The separation of the fundamental
and administrative soundness,
provides the
licensee's
management
the nature and extent of the discrepancies.
The actions taken by the licensee to address
concerns identified with the corrective
actions program have not been completely effective as evidenced
by the recurrent
failures to implement DERs in accordance
with the procedure,
and failures to
10
adequately identify the underlying cause of problems noted by QA Audits and the
NRC team's review of DERs as described
in Section 07.1, "Review of
Deviation/Event Reports," and Section 07.2, "Root Cause Analysis."
C.
Conclusions
Weaknesses
were identified in both QA Audits of the corrective action program
completed
in 1996.
The weaknesses
included:
limited independent
assessment,
small and narrowly focused samples,
and not clearly representing
audit findings in
the executive summary.
Significant improvement in all areas was noted within the
latest QA audit, w'hich included a critical assessment
of licensee's corrective action
program.
However, the licensee's corrective actions to address
previously identified
QA audit weaknesses
had not been completely effective as evidenced
by recurring
discrepancies
in implementing the corrective action program and in determining the
underlying cause of problems.
07.5
Operating Experience
Review Process
a.
Ins ection Sco
e
The team assessed
the licensee's
process for evaluating operating experience
(OE)
information including a review of the controlling procedures,
and selected
information.
b.
Findin
s and Observations
NMPC controlled their review of OE through Procedure
NIP-ECA-01, "Deviation
/Event Report," Revision 11.
The procedure
allowed for QA, Licensing, and
Engineering Departments to determine the applicability of incoming OE information.
The responsible
departments
were required to maintain a record of OE documents
received, and to review and document the applicability of the OE information to the
NMP station.
For OE information found to be applicable to the NMP station,
a DER
would be initiated for review by the appropriate department.
The team considered
the licensee's controls for evaluating
OE information to be appropriate.
The team reviewed the NMPC Licensing Department records for OE items received
in 1997, and the associated
statements
of applicability.
The items were
appropriately reviewed and documented.
The team also reviewed selected
DERs for
both units pertaining to NRC Information Notices (INs), General Electric Service
Information Letters (SILs), and Title 10 of the Code of Federal Regulations
Part 21
notifications, and determined them to be acceptable.
C.
Conclusions
The licensee's controls for evaluating
OE information were appropriate.
The OE-
related DERs reviewed were found to be acceptable.
11
07.6
Adverse Trend Identification
'ns
ection Sco
e
The team assessed
the licensee's
process and effectiveness for identifying adverse
trends.
Applicable portions of the licensee's
procedures,
trending information
regarding adverse trend DERs and selected adverse trend DERs were reviewed.
In
addition, the team reviewed the DER history for selected
areas in which the
potential for an adverse trend existed to determine if adverse trends were properly
identified by the licensee.
Findin
s and Observations
Although no guidance
is provided within the licensee's
procedure controlling the
DER process
(NIP-ECA-01), the licensee has been initiating DERs for situations
where adverse trends were identified. Additionally, a listing of 'adverse trend DERs
was provided in the quarterly DER Program Trend Summary Report.
Discussions
with the QA manager indicated that the concept of adverse trend DERs as used at
the NMP Station is approximately one year. old. A review of the trend report
indicated that the use of adverse trend DERs had increased
over the last year and
that most departments
were currently involved in the identification of adverse trend
DERs.
The team reviewed
a list of the adverse trend DERs from July 1, 1996, through
August 1, 1997.
During that period the licensee initiated approximately 45 adverse
trend DERS.
The types of issues described
by the adverse trend DERS included:
equipment issues (13), training issues
(5), foreign material exclusion (FME) control
issues (2), procedural noncompliance
issues (14), DER timeliness and quality-related
issues (5), and miscellaneous
issues (5).
The team reviewed the thirteen adverse trend DERs associated
with equipment
issues and noted that five of the DERs were with non-safety-related
equipment.
Another five DERs were associated
with the Unit 2 safety-related unit coolers
performance test problems.
The five adverse trend DERs associated
with the
coolers were reviewed by the team and considered to be technically sound with
good justifications to support adequacy of the root cause
and proposed corrective
actions as provided in the form of validation test questions described
in the DER
procedure.
However, three of the five DERs were approximately one month late for
disposition without an extension.
Further discussion
regarding
DER extensions
is
provided in Section 08.1 of this report.
The team reviewed two of the fourteen adverse trend DERs associated
with
procedural noncompliance.
DER 2-97-0203, "Adverse Trend in Operations Ability
to Implement Administrative Requirements,"
was generated
as a result of a Unit 2
Operations Department'self-assessment.
Although no formal root cause analysis of
the issue was completed, the team considered the apparent cause determination to
be thorough,
and the proposed
corrective actions to be sound.
However, the
licensee's
review and proposed
corrective actions focused only on Unit 2
tf
12
Operations Department.
The team considered this to be narrowly focused,
as
evidenced
by the significant number of other adverse trend DERs associated
with
, procedural noncompliance
issues.
The second procedure noncompliance-related
adverse trend DER the team reviewed
was DER 2-96-2155, "QVSA - Adverse Trend 'Chemical Control'iolations of NIP-
CHE-01." This DER noted nine DERs from April 4, through September
10, 1996,
associated
with Unit 2 failures to implemented Procedure
NIP-CHE-01, "Chemistry
Control Program."
The teams's review of DER 2-96-2155 noted that the root cause
of inadequate
corrective actions to previously identified problems was not
addressed
as part of the corrective actions.
Furthermore,
based
on the limited
information provided within the DER, the team was unable to assess
the proposed
corrective actions.
The team reviewed the DER history of selected
areas in which the potential for an
adverse trend existed to assess
the licensee's performance
in identifying adverse
trend conditions.
The areas selected were FME, unexpected
and Riley
temperature
switches.
For FME issues, the licensee had generated two adverse
trend DERs, for unexpected
half scrams, the team noted eight Unit 1 DERs
associated
with unexpected
half scrams within the last year.
Discussions with the
Unit
1 system engineering staff indicated that the causes of the half scrams were
generally unrelated that no adverse trend could be established.
Based on the
discussion with system engineering
and
a review of applicable DERs the team found
the licensee's conclusion acceptable.
With respect to Riley temperature
switches, the team noted eight DERs related to
Riley Temperature switch failure at Unit 2 over the last three years.
Discussion with
members of the Unit 2 Instrumentation
and Controls (IS.C) Department and a review
of the applicable DERs indicated that the trend associated
with the temperature
switch failures was being addressed.
Although some minor implementation issues
were noted, the team considered
the licensee's
evaluation of the issue as provided
in DERs 2-97-0498 and 2-97-1560 to be technically sound.
The licensee classified
these
DERs as category 2, but the team considered
the potential for the problem to
be a common failure made them more suitable to be classified as category
1.
Based on the teams review, the licensee,
appears to identify and evaluate adverse
trend conditions.
However, during the review of these and other DERs, the team
noted
a not all DERs associated
with adverse trends were included in the quarterly
DER Program Summary Report, this observation was described
in Section 07.3,
"Deviation/Event Report Program Summary Trend Report."
Conclusions
Although no procedural guidance was provided for reporting adverse trends, the
licensee appeared to be identifying and evaluating adverse trend conditions.
Based
on the team's review of the procedural noncompliance-related
adverse trend DERs,
the team considered
the corrective actions taken to address
human performance
issues to be narrowly focused and not completely effective as evidenced
by the
13
significant number of adverse trend DERs associated
with procedural noncompliance
issues.
Independent
Safety Engineering
Group (ISEG)
Ins ection Sco
e
Technical Specification 6.2.3 defines the function, composition,
and responsibility
of ISEG.
This technical specification is only applicable to Unit 2. The technical
specification states
in part that ISEG shall function to examine unit operating
characteristics,
NRC issuances,
industry advisories,
license event reports and other
sources of operating experience
and make detailed recommendations
for improving
unit safety to the Vice President
- Nuclear Safety Assessment
and Support.
The
team evaluated
ISEG's performance
in carrying out these responsibilities.
The team interviewed the ISEG Director, ISEG members,
and personnel from the
plant staff to assess
ISEG's performance
in carrying out its responsibilities.
The
team also reviewed ISEG activity reports for the last twelve months and the two
most recent self assessments
prepared
by the ISEG Director.
Findin s and Observations
Overall, the team found that ISEG was functioning adequately to carry out its
responsibilities
as defined in Technical Specification 6.2.3.
The team noted
improvement over the last several months in ISEG's use of industry operating
experience
and NRC issuances
for assessment
planning.
In the past, ISEG was
more focused on providing follow-up assessments
to site specific events rather than
taking a more proactive approach utilizing industry operating experience.
ISEG has
also recently begun to perform broader range programmatic assessments
rather than
focussing on isolated issues
and events.
These are both positive trends that need
to continue for ISEG to have a greater impact on improving safety.
The self assessments
prepared
by the ISEG Director identified areas for
improvement that have not been followed through on.
A self assessment
recommendation
was made in June 1996 and again in December 1996 for ISEG to
perform team assessments
on a pre-planned
list of topics to provide broader
oversights of functional areas including Operations,
Engineering,
Maintenance,
and
Technical Support.
The team found no evidence that this recommendation
had
been implemented.
Additionally, the December 1996 self assessment
repeated the
assessment
results and program enhancements
made in the previous self
assessment
completed in June 1996.
One of the ISEG responsibilities listed in the Technical Specifications is to examine
unit operating characteristics.
ISEG currently carries out this function through daily
reviews of operating logs and plant parameters.
There was no evidence of ISEG
performing, or being provided with, any long term trends of unit operating
characteristics to allow for a more thorough review and assessment
of safety
significant parameters.
c.
Conclusions
Overall, ISEG was functioning adequately to carry out its responsibilities
as defined
in Technical Specifications.
Although ISEG had performed self assessments
and
identified areas for imp'rovement, follow through on the recommendations
for
~ improvement has been limited.
07.8
Self Assessment
Program
a.
Ins ection Sco
e
The team reviewed the licensee's
self-assessment
(SA) program including
procedures,
interviewed licensee personnel
and evaluated selected self assessments
from engineering,
operations,
and maintenance.
b.
Observations
and Findin s
Administrative procedure
NIP-ECA-05, "Self-Assessment,"
Revision 00, provided
adequate
guidance for the self assessment
program.
A sample of SA reports were
reviewed and it was determined that the level of detail with respect to identifying
performance
weaknesses
and planned or implemented corrective actions varied
greatly between reports.
Specific SA weaknesses
included: (1) SAs which lacked
specific criterion against which performance was judged, (2) Some SAs were
essentially
a summary of documents
reviewed (e.g., tabulation of DERs, NRC
reports, and QA assessments),
(3) Some branches
do not have
a method for
capturing routine performance observations
for inclusion in the SA programs,
and
(4) Some SAs either lacked specific recommendations
or did not provide a
mechanism to formally track what was being done with recommendations.
In
addition, management
expectations with respect to developing
a two-year schedule
of branch SAs, maintaining the timeliness of SAs (i.e., at least one within a six
month period), and including a section within the SAs which assesses
the
adequacy'f
past corrective actions, have not been met by various branch organizations.
Conclusions
Overall the licensee had an adequate
program for self-assessment
activities.
However, several weaknesses
with the program implementation limit the
effectiveness of the overall SA program, and may lead to missed opportunities to
implement useful recommendations
in a timely manner.
07.9
Corrective Action Program Related to Human Performance
a.
Ins ection Sco
e
The team reviewed aspects of the licensee's
corrective action programs and
conducted
personnel interviews to determine if the licensee's
programs were
adequately
identifying and addressing
human performance
issues.
15
Findin
s and Observations
The primary method for identifying, tracking and dispositioning human performance
issues
is through the DER process.
DER data is tabulated quarterly by the Quality
Assurance
(QA) department
and provided as a report to each branch for further
evaluation and corrective action.
The team reviewed the QA DER Program Trend
Summary Report for the second quarter of 1997 and a QA report to the Senior
Management
Team which characterized
the 1997 significant DERS attributed to
personnel
errors, dated August 8, 1997, to determine what performance
weaknesses
were being identified.
The licensee reports indicated that significant
contributors to performance weaknesses
appear to be concentrated
in the areas of
self-checking, required verifications not performed, and procedures
not followed
correctly.
Results of these performance weaknesses
have manifested themselves
as plant equipment found out of expected position, work performed on plant
equipment using inappropriate materials or equipment,
and inadequate
operability
determination calculations.
In response
to the human performance
issues identified in the DERs, the licensee
often counseled
the individuals involved in the event and made changes to
administrative or plant procedures.
While these actions appear to be effective in
minimizing the possibility of a repeat of a particular incident, the continued
observation of personnel
errors is indicative of the need to evaluate the underlying
causes of these errors more broadly.
The team also reviewed
a sample of DERs, recent RCAs, self-assessments,
and
various branch performance observation forms to determine if human performance
issues were being identified.
In most cases,
these reporting methods did identify
human performance
issues contributing to events, but the team did note some
exceptions.
In at least one case, the licensee identified a lack of human
performance contributors as a r'esult of a DER review and initiated a second
DER to
address
the human performance
issues.
A recent Quality Assurance
Branch
assessment
of significant personnel
errors noted that recent root cause analyses
do
not adequately
evaluate the contribution of human performance to the events being
analyzed,
and DER C-97-1538 was written to address
the issue.
The team noted some positive initiatives such as the Unit 2 Operations observation
card system which contain performance observations
generated
by operations
supervision of their respective crews.
The observations
are entered into a database
which can be sorted on a variety of evaluation criteria and used as input into the
self-assessment
process.
However, the team noted that some other branches
did
not have any method for capturing performance
observations
and in some cases,
other branches
had apparently stopped
using existing observation processes
contrary to management
expectations.
The licensee appears to recognize that human performance weaknesses
persist and
has implemented initiatives to address the situations'ncluding:
delineating
management
expectations
for error free performance,
increased
supervisory
0
16
oversight of activities, increased
emphasis
on peer-checking,
and performance.
reinforcement during training.
C.
Conclusions
Overall, the licensee had an adequate
program for identifying human performance
errors.
However several weaknesses
in the programs to identify and address
human performance
issues were apparent.
08
Miscellaneous Operating Issues
08.1
Unresolved Item 50-410/95-25-03:
DERs Extended Without Justification
Ins ection Sco
e
During NRC Inspection 50-410/95-25
NRC inspectors identified examples of Unit 2
DERs assigned to both engineering
and technical support departments that failed to
contain justification for the extension of implementation
as required by Procedure
NIP-ECA-01. Additionally, the inspectors noted that documentation
of extension
requests
varied widely. The team reviewed the licensee's
actions taken in response
to this concern, including the DER written to address
the issue,
a QA surveillance
performed by the licensee to determine the extent of the problem, and resulting
changes
made to the DER procedure.
The team also reviewed selected
DERs to
assess
the effectiveness of the licensee's corrective actions to remedy the problem.
Findin s and Observations
NMPC generated
DER 2-96-0211 to address the concern related to DER extensions.
As part of the disposition, QA completed
a surveillance of the justifications provided
for DER extensions.
The results of the QA surveillance (Report 96-0039-C)
identified that the only group to consistently justify DER extensions was Unit 1
Engineering Department.
The licensee identified the root cause to be ineffective
change management
for Revision 8 to NIP-ECA-01, which incorporated the
requirement for justifying DER extensions.
Corrective actions included informing all
branch managers
through a memorandum
of the requirements to justify DER
extensions,
and training on DER extensions
was to be included for "DER
coordinator" training.
In addition, the DER procedure was enhanced
to clarify the
requirements for justifying and documenting
DER extensions.
The team reviewed the licensee's corrective actions.
The team considered that the
procedure
changes facilitate the use of DER extension requests.
The team
considered
this enhancement
to be good, and the DER extension requests reviewed
by the team consistently used the extension forms and assessed
the impact on
safety.
Although the procedure
changes
were considered to be good, the process
was not consistently being used.
There were currently 687 DERs open for
disposition with 165 greater than ten days overdue without an extension request
(51 were greater than 50 days overdue,
and 16 were greater than 100 days
overdue).
With respect to implementation of the DER corrective actions, 1622
17
DERs were open with 72 DERs greater than ten days overdue without an extension
request (29 were greater than 50 days overdue,
and five were greater than 100
days overdue).
The failure to justify the extension of DER disposition and
implementation due dates was not in compliance with licensee Procedure
NIP-ECA-
01, and was considered
a violation of TS 6.8.1.
(VIO 50-220/97-80-01
and 50-
410/97-80-01)
Furthermore,
based on the numbers
DERs currently overdue without
justification, the team considered
the licensee's
actions described
in DER 2-96-0211
ineffective to prevent recurrence.
Based on this violation, Unresolved Item (URI)
50-410/95-25-03
is closed.
Conclusions
The continuing failure to justify the extension of DER due dates
as required by
licensee procedure was a violation of TS 6.8.1.
Furthermore, the licensee's
corrective actions to prevent recurrence of this previously identified concern were
ineffective.
(Closed) Inspector Follow Item 50-410/96-07-12:
Weaknesses
in the DER Process
This item was opened
in response
to a finding during the 1996 Integrated
Performance Assessment
Process
(IPAP) team inspection (NRC IR 50-220/96-201
and 50-410/96-201),
in which weaknesses
were identified within the DER process.
The particular concerns were in the areas of trending, root cause analysis, adequacy
of corrective actions to prevent recurrence,
and root cause analysis training.
Also,
the implementation of corrective actions associated
with self-assessments,
ISEG,
and QA recommendations
were not verified sufficiently to assure that the required
actions were effective.
During the course of this inspection, the team assessed
all the areas of concerns
identified within this Inspector Follow Item (IFI). The team's assessments
were
included in the applicable sections of this inspection report, and any continuing
weaknesses
requiring follow up were noted as such.
In addition, subsequent
to
issuing
IFI 96-07-12, Notice of Violations (NOVs) associated
with the corrective
action program were issued,
as described
in Escalated
Enforcement Letter dated
April 10, 1997; any continuing weaknesses
oertaining to the corrective action
program will be review as part of the NOV closures.
Therefore,
IFI 96-07-12 is
administratively closed.
(Closed) Inspector Followup Item (IFI) 50-410/96-07-13:
ISEG Review of NRC
Documents
The May 1996 IPAP report noted that ISEG was not carrying out its responsibility to
review NRC issuances.
This function was being performed by different branches
other than ISEG.
ISEG has taken actions to correct this situation and the team
reviewed ISEG's functions with respect to this issue.
A member of ISEG routinely
reviews a complete listing of NRC issuances
for applicability and safety significance.
Selected items are flagged for a follow-up assessment
by ISEG to determine if the
issue is being properly addressed.
The team reviewed ISEG activity reports for the
18
last twelve months and found evidence of these actions being taken and that
meaningful feedback was being supplied by ISEG to responsible
plant organizations.
II. MAINTENANCE
M1
Conduct of Maintenance
M1.1
Emergent Maintenance
a.
Ins ection Sco
e
The inspector observed
various aspects
of the licensee's
response
to emergent
conditions that required corrective maintenance.
b.
Findin s and Observations
Unit 2 Reactor Coolant S stem Flexible Hose Failure
On August 4, 1997 Unit 2 was shutdown
in response
to an elevated drywell floor
drain leak rate.
The source of the leakage was a 3/4 inch flexible metallic hose,
2RCS" HOSE40, connected to the drain line of the B recirculation loop flow control
valve, 2RCS" HYV17B. The leak was at the bottom of the flexible hose where the
stainless steel braid is connected
to the end ferrule.
The team followed the
licensee's
response
to the event as it related to implementation of the plant's
corrective action program.
This was the second occurrence of a failed flex hose at Unit 2.
On March 30, 1991
a flexible hose of similar design in the reactor coolant sample system failed, also
resulting in a plant shut down.
In response
to the previous event, the licensee sent
the failed flex hose off site for failure analysis.
The cause of the failure was
determined to be pitting attack and subsequent
fatigue failure as a result of
exposure to an aggressive
environment prior to the hose being placed in service.
The source and characterization
of the aggressive
environment were never
established.
The Licensee Event Report (LER) 91-01 submitted in response to this
event committed to evaluating flex hoses removed
in future outages for signs of
metal fatigue.
Only one of twelve flex hoses removed in the next refueling outage
was subsequently
examined.
No evidence of metal fatigue was found in the sole
flex hose that was examined.
The team does not consider the examination of only
one additional flex hose to have met the intent of the LER commitment to determine
the extent of the failure mechanism.
The team determined that the licensee did not
have a sufficient enough understanding
of the failure mechanism
and contributing
environment for the flex hose that failed in March 1991 to consider the failure to be
an isolated event with no generic implications as stated in the LER.
The team assessed
the licensee's
response
to the most recent flex hose failure.
The team observed
meetings of the root cause evaluation team, routine outage
planning meetings,
SORC meetings, interviewed personnel
involved with responding
19
to the event, and walked down the location of the failed flex hose in the dry well ~
The team found the lice'nsee's
response
to the event to be appropriate.
The
licensee removed the failed flex hose from the valve body and capped
and seal
welded the connections.
Visual inspections were conducted
on the remaining flex
hoses.
The licensee recognized the limitations of the visual inspections at
identifying fatigued hoses prior to failure and made an appropriate safety
assessment
justifying plant restart.
The licensee's
preventive actions for the most recent flex hose failure include
prioritizing a list of flex hoses most susceptible to failure; identifying flex hoses for
replacement,
modification, or inspection in the next scheduled
refueling outage; and
performing a failure analysis on the failed flex hose and other selected flex hoses to
establish
a failure mechanism.
The team considered
the March 30, 1991 event a
missed opportunity for the licensee to pursue the cause of the failed flex hose and
establish appropriate corrective actions to prevent recurrence.
The licensee
considered
several preventive actions in response
to the March 1991 flex hose
failure, but did not follow through on them.
An inspector follow item, 50-410/97-
06-02, was established
to track the resolution of the most recent event.
Failure of Unit 2 Service Water Makeu
Control Valve to the
Circulatin
On August 18, while conducting activities involving the service water (SW) system,
an operator noted that the hydraulic positioning unit for the SW loop B makeup
control valve to the cooling tower was malfunctioning.
Specifically, the hydraulic
pump was running continuously; normally, it operates
only as necessary
to support
valve operations
and to maintain an accumulator full. The accumulator serves as a
backup power source to the hydraulic pump, to allow the valve to isolate the non
safety-related
cooling tower from the safety related portions of the SW system.
Continuous pump operation with no corresponding
valve operations indicated that
the accumulator was not holding pressure,
and therefore could not be relied on to
perform its safety function.
As a result, SW loop B was declared inoperable, which
placed the Unit 2 in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> shutdown action statement.
Due to the malfunction, switching SW loops for makeup to the cooling tower by the
existing procedure would have temporarily resulted in two loops of SW being
To avoid this, a one-time use procedure
change was prepared.
The
inspector observed preparations
in the control room to perform this procedure.
Following individual review of the change,
operators discussed
problems that could
be encountered
during the shift.
Based on the sequence
of procedural actions,
parameters
were established
that would give early indications of a problem, as well
as actions to be taken if problems did develop.
However, due to the lateness of the
shift and other required activities, the decision was made to defer conduct of the
operation to the oncoming shift.
Based on turnover discussions
of the procedure,
the oncoming operations shift
discussed
the evolution in overview during the turnover brief. The pre-job brief was
deferred until after completion of normal shiftly rounds and to allow the control
0
20
room operators to thoroughly review the procedure
change.
The inspector observed
the shift turnover brief and noted that the auxiliary operators were active and
'nowledgeable
participants
in discussion of the upcoming SW evolution.
Unit 2 Emer enc
Diesel Generator
DC Control Power Annunciator Failure
On August 18, operators
received an alarm on main control board annunciator 319,
"EDG2 DC Control Power Failure."
Loss of DC control power for an emergency
diesel generator
(EDG) renders that EDG inoperable.
Loss of EDG2 at that time
would have been particularly significant, in that scheduled
LCO maintenance
on
division
1 equipment was in progress.
An operator was dispatched to investigate
the condition and, from local indications, it was determined that the EDG2 DC
control power was still operable.
As an interim measure,
an individual was
stationed to monitor local indications while maintaining communication v ".h the
.control room.
Troubleshooting
revealed that the cause of the alarm was a failed
relay in the annunciator circuit. The relay was replaced and the annunciator was
returned to service later the same day.
The inspector observed activities associated
with the annunciator circuit relay
replacement from the control room.
The maintenance
activity was thoroughly
discussed,
including expected
alarms, prior to commencing work. Post maintenance
testing was technically appropriate
and was well controlled.
Following restoration
of the annunciator circuit and approval by the operations supervisor, the local watch
was secured.
The inspector concluded that use of a watchstander
for this function
had been acceptable,
given that the affected circuit provided no functions other
.
than alarm.
C.
Conclusions
The licensee effectively dealt with these emergent maintenance
issues.
The
operations department
made significant contributions both to the identification of
problems and control of plant conditions to support maintenance.
An IFI concerning
the failed flex hose was documented
in a separate
NRC inspection report 50-
41 0/97-06-02.
IVI2
Maintenance and IVlaterial Condition of Facilities and Equipment
M2.1
Material Condition Observations
Ins ection Sco
e
The inspector toured portions of the plants to assess
the effectiveness of the
corrective action process with respect to identifying and correcting material
discrepancies.
21
Findin
s and Observations
Unit 2 Material Condition
During the first week of onsite inspection (August 4), unit 2 was shut down due to
a reactor coolant leak from a flexible hose in the drywell. As a result, the
inspectors were able to tour areas that are normally inaccessible
during power
operations.
~Dr well
The main steam isolation valves appeared
to be in g'ood material condition; nitrogen
flexible hoses were not crimped and actuator venting was not obstructed.
No
problems were noted with the mounting of piping and electrical conduit runs, nor
.with seismic restraints.
No temporary storage of equipment or materials was noted,
and no temporary postings were observed.
Drywell coatings appeared to be in
good condition, and no peeling was noted.
Overall, the inspectors considered that
the material condition of the drywell was good; drywell cleanliness
is discussed
in
section M2.2 below.
Steam Tunnel
The inspectors
noted several previously unidentified deficiencies that had occurred
during'the preceding plant operations.
For example,
a valve packing leak had
developed which created
a puddle of water on top of one of the room coolers.
Also, a flange leak on a steam pipe had melted the surrounding insulation.
In
addition, the inspectors noted several maintenance-related
material deficiencies.
Examples included:
the inlet screens/filters were not in place on one of the room
coolers; one of four baseplate
fasteners was not made up for a seismic strut;
frayed, crumpled fire wrap material; and a long ladder that was being stored upright
without adequate
restraint.
Overall, the inspectors
assessed
the material condition
of the steam tunnel to be poor.
A-Feedwater Heater Ba
No significant problems were noted, overall material condition and housekeeping
appeared
to be good.
Unit 2 Reactor Buildin
The inspectors
also toured the reactor building during the course of the inspection,
and made the following observations:
Control rod drive system relief valve 2RDS" RV1B (RDS pump 1B suction relief) had
an open threaded
port on the valve bonnet; the inspector noted that this port for the
1A RDS pump suction relief valve was plugged and lockwired. The licensee
initiated a DER (2-97-2455) to investigate this inconsistency.
The licensee
determined that the plug was supposed
to be installed, but that it did not affect
22
valve operability; the bonnet is vented to the valve discharge
side by an internal
passage,
and the valve relieves to atmospheric
pressure.
A plug was promptly
installed in 2RDS "RV18.
Gas treatment system valve GTS-PV104 (AOV-101 bypass line pressure
controller)
position switch actuator on the valve stem was rotated so that it was out of
alignment and made minimal contact with the limit switches.
The licensee initiated
a problem identification report to correct the problem.
The discharge flexible coupling for reactor building closed loop cooling pump CCP-
P1A had several radial tears in the outer covering.
As compared to the other pumps
in the system, the coupling appeared
to be slightly deformed, suggesting
that the
cause of the tears was an inadequate fit. Although a work order existed to replace
this flexible coupling, the reason for the work order was listed as preventive
maintenance,
indicating that the tears apparently had not been previously identified.
c.
Conclusions
The overall material condition of Unit 2 was good; however, inspector identification
of several material problems in the reactor building indicated that additional material
inspections
by the licensee could be productive.
The material condition of the
steam tunnel was assessed
to be poor.
Based on the material deficiencies that
were identified by the inspectors
in this area, it did not appear that the licensee was
taking full advantage
of the forced outage to inspect normally inaccessible
areas of
the plant for emergent material problems.
M2.2
Unit 2 Drywell Cleanliness Controls
a.
Ins ection Sco
e
During an inspection of the Unit 2 drywell, the inspectors identified some foreign
materials in out-of-the-way locations.
As a result, the inspectors reviewed the
licensee's
cleanliness control requirements for the drywell.
Findin
s and Observations
The Unit 2 drywell was opened
during the forced outage to support repair of the
failed reactor coolant system flexible hose, but w'as not open for general access.
In
discussions
with plant personnel
during entry preparations,
the inspectors were
informed that the drywell was a I~vel 3 cleanliness
area, and that foreign material
exclusion (FME) requirements
were in effect.
The general standard for area
cleanliness
requirements
is ANSI N45.2.3, "Housekeeping
During the Construction
Phase of Nuclear Power Plants," and the requirements
for level 3 cleanliness
as
specified in this ANSI standard
are relatively stringent.
Area cleanliness
classifications for Unit 2 are established
by procedure
GAP-HSC-02, "Local Work
Zones and System Cleanliness Controls," and basically parallel the requirements of
23
During inspection of drywell, the inspectors noted that the overall cleanliness of the
drywell was good.
However, the inspectors observed that numerous
open-ended
square steel structural braces were collecting points for debris (for example, tie
wraps, wire, and contamination swipes), as well as some tools (the inspectors
found two pens and two screwdrivers).
The inspectors considered that these
conditions were not consistent with level 3 cleanliness requirements.
However, in
reviewing GAP-HSC-02, the inspector noted 'that the cleanliness
level of the drywell
was not specified.
The procedure
does discuss the use of FME controls (material
accountability log and capturing of loose items) for the drywell; since FME controls
are normally established
for systems requiring a high degree of cleanliness
(level 1,
2, or 3), this could imply that the drywell was a level 3 area.
However, in this case,
the use of FME controls is to maintain drywell cleanliness at the level established
during the previous closeout inspection and thereby preclude the need for a drywell
closeout inspection following a short duration outage.
In addition, the inspector was informed that heavy fabric cleanliness covers were
used to maintain FME control of the drywell-to-suppression
pool downcomers.
While this is an effective mechanism for maintaining cleanliness,
the inspector was
concerned that, were they to be inadvertently left in place while primary
containment was required, they would have
a significant effect on the ability of the
containment to perform its design functions; specifically, while in place, they
defeated the steam quenching function of the suppression
pool, and if dislodged,
could produce significant blockage of water to the ECCS pumps.
The inspector was
informed that the downcomer covers were used as deemed
necessary
by the
drywell coordinator,
and that installation and removal was documented
by the
material accountability log. The inspector considered
that more stringent controls
over installation and removal of these covers would be appropriate,
due to the major
impact they could have on containment operability.
'I
The requirement to perform a drywell closeout inspection prior to plant startup is
established
by procedure
N2-OP-101A, "Plant Startup."
As a prerequisite to the
procedure,
either the master or short form startup checklist (Attachments
1 and 2)
must be completed,
and both require that a drywell inspection be performed if a
drywell entry had been made.
However, GAP-HSC-02 specifies that, for short
outages,
FME controls may be used in lieu of a final inspection.
It was not clear
how this provision is intended to be implemented.
The inspector was concerned,
because
the N2-OP-101A drywell closeout checklist is the source of the
requirement for final verification that the downcomer covers have been removed;
were it to be interpreted
as not being required, then this final verification would not
be performed.
The inspector noted that GAP-HSC-02 specifies that installation and removal of the
downcomer covers is to be performed under work order control.
The inspector
considered
this to be an appropriate
level of administrative control for use of the
downcomer covers.
The inspector verified that a work order (97-00852-03) had
been used to control use of the downcomer covers during the August 4 forced
outage; however, it was a general work order for drywell FME control, titled, "FME
Control Accountability of Material in the Drywell During Forced Outage," rather than
24
a work order specifically for the installation and removal of downcomer FME covers.
Additionally, the work order did not specify which downcomers were to be covered,
but rather, had blanks for the worker to record the identification numbers of the
affected downcomers.
The inspector noted that the completed work permit did not
provide rigorous accountability for pfacem'ent of the covers.
For example, removal
of four covers was documented
by having lined out the numbers that had been
recorded
in the "installation" section, with a note that they were removed and
reinstalled at the locations listed on the next line; this removal had not been
recorded
in the "removal" section of the work permit.
In the same example, one of
the downcomers
listed as having its cover removed is also listed on the next line as
having a cover installed.
Finally, in the "removal" section, it would not be possible
to determine whether one of the numbers was "6" or "8" (due to a write-over)
without referring to the "installation" section to find out which it should be.
Conclusions
Drywell cleanliness
was generally good, however, cleanliness requirements for the
drywell are not clearly established
in the governing procedure,
GAP-HSC-02.
Given
that this procedure provides allowance for not performing a drywell inspection prior
to plant startup, and that the plant startup procedure,
N2-OP-101A, does not
address
how this allowance is to be implemented, interpretation could result in
omission of the final verification that the downcomer FME covers have been
removed.
Work order control of installation and removal of the downcomer FME
covers is appropriate, given the significant impact they could have on containment
operability if inadvertently left in place.
However, the work order used to
accomplish this during the August 4 forced outage was general in nature and did
not provide rigorous accountability for installation and removal of these covers.
Unit 2 Residual Heat Removal System Flow Control Valve Problem
Ins ection Sco
e
The inspector noted
a mechanical problem with a residual heat removal (RHR)
system valve, and observed the licensee's
actions to disposition the deficiency.
Findin s and Observations
During an inspection of the Unit 2 reactor building, the inspector noted that a
split ring lock washer between
a nut and the anti-rotation device on the stem of
valve RHS" FV388 ("8" RHR full flow test) was not compressed.
The inspector
reported this condition to the station shift supervisor
(SSS) late in the afternoon of
August 18.
Licensee investigation of the condition the following day identified the
valve as having a two piece stern, and that the nut and lock washer in question
were the mechanical fasteners that locked the two threaded stem pieces together.
The condition of the valve was assessed
to be indeterminate.
At 11:00 a.m. on
August 19, the valve was declared inoperable,
along with the associated
loop of the
RHR system.
This placed the licensee in a 72-hour shutdown action statement
per
25
technical specification 3.6.2.3.
DER 2-97-2451 was initiated to document the
condition in the corrective action program and initiate corrective action.
The condition of valve RHS "FV38B was evaluated
by an engineering
supporting
analysis (ESB2M970760).
The analysis indicated that the functions of the valve
included initiating and terminating suppression
pool cooling during normal plant
operations
and accident conditions,
and as an RHR pump minimum flow valve
operated
from the remote shutdown panel in case of control room evacuation
due to
fire. The evaluation concluded that the valve position was currently known, but
that, with continued operation, the lower stem could loosen and back out of its
connection with the upper stem, resulting in inability to open the valve.
Licensee review revealed that there had been
a problem had with valve
RHS "FV38B
in June 1997.
Specifically, the valve position indication had been intermediate
when the valve was fully closed.
This condition was corrected with a minor
adjustment of the valve position limit switch. At the time, the problem was
believed to be due to the switch having been set too close to the maximum closed
tolerance.
However, in light of the loose lock nut, it was considered
likely that the
intermediate position indication had been due to increased
stem length, as a result
of the lower stem beginning to back out of the upper stem.
Repair of valve RHS" FV38B was performed under work order 97-12724-00,
and
consisted of tightening the loose nut.
Acceptance testing was to stroke time the
valve and verify proper valve position indication.
During this testing, the valve
again exhibited dual indication, indicating that the stem had continued to back out
since June.
The problem was again corrected by minor adjustment of the valve
position limit switch, and valve stroke time was demonstrated
to be satisfactory.
Valve RHS" FV38B and RHR system loop B were declared operable on August 20.
Additionally, the licensee verified that similarly designed
valves in safety systems
did not exhibit the same problem.
Conclusions
Given the safety significant functions performed by valve
RHS "FV38B, licensee
investigation of the reported degraded
condition of the valve was slow.
Additionally, the decision to start the 72 hr LCO at 11:00 a.m. on August 19, rather
than on the afternoon of August 18 (when the condition was reported to the SSS)
was not conservative.
The intermediate valve position indication that occurred in
June 1997 was apparently
a missed opportunity to identify the loose stem lock nut.
Pending engineering evaluation of the as-left, partially unthreaded
condition of the
lower valve stem and review of the completed
DER, this-item remains open. (IFI 50-
410/97-80-02)
26
M2.4
Unit 2 Steam Tunnel Door Seal
a o
Ins ection Sco
e
The inspectors reviewed the adequacy of a temporary modification of the Unit 2
steam tunnel door seal that was in place from 1992 to 1996.
b.
Findin s and Observations
The entrance to the Unit 2 steam tunnel consists of two doors, separated
by a short
passage
way.
The outer door is a single latch security door, and the inner door is a
multiple latched metal door with an elastomer seal around the edge; together, the
doors form a portion of the secondary containment boundary.
During an inspection
of the steam tunnel, the inspectors noted
a puddle of sticky liquid on the floor of
-the passage
way between the two doors.
The licensee determined that the material
was elastomer door seal material
~ The inner door seal had been replaced during the
1996 refueling outage; some of the old seal material had been inadvertently left in
the passage
way and had decomposed.
The inspector was concerned that the
elastomer might not be appropriate for use as a steam tunnel door seal.
The inspector determined that a DER (2-96-0836) had been written on March 29,
1996 concerning degradation
of the inner steam tunnel door seal.
The DER
indicated that the door seal was melting, that there were puddles of seal material on
the floor, and that air was bubbling through the seal area.
The problem had
previously been documented
in a problem identification report (11716) on
February 18, 1996.
The DER also indicated that the problem had happened
before
and that the seal had last been replaced
in March 1992.
The resolution to DER 2-96-0836 provided
a history of problems with the inner
steam tunnel door seal
~ Melting of the seal was first noted in 1991 and
documented
in DER 2-91-Q-0755.
The condition was evaluated
as being due to
use of an incompatible cleaning solvent.
Corrective action was to replace the
existing neoprene
seal with an urethane
seal.
This was performed as a temporary
modification (91-068) in 1992.
The urethane
seal had a five year life, but a design
temperature
of only 90 degrees
Fahrenheit
(
F); the actual environmental
temperature
can be as high as 130~F.
As a result, the seal was deteriorating
(melting) after four years of service.
DER 2-96-0836 concluded that the door was
in its degraded
condition, because
it was still able to hold a seal.
The root
cause of the door seal degradation
was an inadequate
design evaluation of the
urethane
seal material for environmental conditions.
The cause of the inadequate
design evaluation was indeterminate.
As corrective action, an engineering
design change (2F00373A) was developed to
replace the urethane
seal with a more suitable material.. An interim corrective
action, to install a new seal of the same material during a forced outage, was never
performed because
there were no forced outages prior to shutdown for refueling.
The design change was implemented during the ".996 refueling outage,
and installed
a seal composed
of E401
EPDM compound.
'
27
One of the functions of the inner steam tunnel door is to act as a portion of the
secondary containment boundary.
Per technical specification 3/4.6.5.1, secondary
containment integrity is demonstrated
by the ability to maintain at least 0.25 inches
of vacuum (water gauge) within the secondary containment; there are no
requirements for leak tightness of individual boundaries.
Given that the required
vacuum was maintained from the time the degraded
condition was identified until
the plant was shutdown for refueling outage, the inspector concluded that the inner
steam tunnel door seal was adequate
to perform its secondary containment
function, even though it was progressively degrading.
DER 2-96-0836 states that the inner steam tunnel door is also a class C (thr'ee hour)
fire door.
The DER indicates that engineering determined that the urethane
seal
does not sustain
a fire and is a proper door material to have in a fire boundary to
maintain a three hour fire rating.
The inspector was concerned that this
determination suggested
that there was a requirement for the seal to function as a
portion of the fire barrier.
However, in discussions
on this matter, the licensee
indicated that the seal served no fire protection function, and that the recess for the
seal formed a baffle which directed fire away from the gap between the door and
the frame.
Therefore, the inspector concluded that the fire protection function of
the door had not been degraded
by the inadequate
door seal.
Conclusions
The temporary modification that installed a urethane
seal on the inner steam tunnel
door in 1992 was inadequate,
in that it failed to account for environmental
temperatures
that exceeded
the design temperature
of the seal material.
After seal
degradation
was identified, corrective actions were appropriate.
Use of the
inappropriate
seal material from 1992 until 1996 had the potential to cause
a failure
of secondary containment; however this did not occur, and the degraded
condition
did not constitute
a violation of any other specific regulatory requirements.
Operability of the door as a fire barrier was not affected by the degraded
seal
~
'3
Maintenance Procedures
and Documentation
M3.1
Problem Identification and Work Control Process
a 0
Ins ection Sco
e
Applicable work control procedures
were reviewed to determine the effectiveness
of
problem identification processes.
b.
Findin s and Observations
Procedure
GAP-PSH-01, "Work Control" establishes
the procedure for entering
equipment/material
problems into the corrective action program.
Problems are
entered into the program by the identifying individual using a problem identification
(PID) report.
PIDs that involve plant equipment or operations
are initially reviewed
28
by the SSS for operability/reportability.
A PID ultimately causes
a work order to be
generated
to correct the identified problem.
In reviewing GAP-PSH-01, the inspector noted that it did not provide guidance
concerning equipment problems that should also be reported under the DER system.
On the other hand, procedure
NIP-EAC-01, "Deviation/Event Report," does refer to
'he use of PIDs in parallel with DERs.
The inspector considered that material
problems identified by a PID might not receive the same level of management
attention and evaluation (for example, root cause evaluation) as if a DER had been
used.
Also, the inspector noted that newly submitted
every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The inspector considered that this could delay operability issues.
from being recognized,
although no instances
of this were noted.
Finally, the
inspector noted that GAP-PSH-01 discusses
the use of deficiency tags, however
none were observed
to be posted during plant tours.
The licensee acknow'~aged
.the inspector's observations
but indicated that the approach of using the computer
data base to enter and track PIDs in lieu of using deficiency tags meets
management
expectations.
Conclusions
The problem identification system procedures
established
adequate
guidance for
work control.
However, the PID process does not procedurally ensure the same
level of review and evaluation as does the DER entry mechanism for the corrective
action program.
M3.2 Operator Work Arounds
Ins ection Sco
e
The inspector reviewed licensee processes
for identifying, tracking, and correcting
operator work around items.
Findin s and Observations
The governing procedure for tracking control room deficiencies at Unit 1 is N1-ODG-
04, "Control Room Deficiencies Guideline."
The procedure
establishes
basic
classifications of deficiencies, including corrective maintenance
deficiencies,
defeated annunciators,
extended
markups and holdouts, configuration control
holdouts, longstanding
control room operator aids, and invalid and nuisance
alarms.
The control room deficiency log is maintained by the shift technical advisor and is
reviewed monthly by the operations manager.
At the time of this inspection, the
Unit 1 control room deficiency list contained 20 items.
Control room deficiencies at Unit 2 are tracked in accordance
with N2-ODP-0001,
"Conduct of Operations," section 3.3.8.
Other than markups, control room
deficiencies are documented
by PIDs. At the time of this inspection, the Unit 2
control room deficiency list contained 35 items.
v
0
29
Operator work arounds at Unit 2 are tracked in accordance
with procedure N2-ODI-
5.70, "Work Arounds and Longstanding Tagouts."
Items are identified as operator
work arounds using a Work Around Tracking Form, and tagouts greater than six
month old are designated
as longstanding.
Based on two year trending presented
by the licensee, this procedure
appears to be effective; work arounds have been
reduced from about 40 in mid-1995 to 19 at the time of this inspection, and
longstanding
tagouts have been reduced'from about 100 to about 30.
In reviewing the work around list, the inspector noted that some items that had
been examined
and were apparently resolved, were still being carried on the list.
For example, the requirement for operators to open specific circuit breakers for
some Appendix R fire scenarios was listed as a work around in January 1996.
However, the issue was addressed
in DER 2-94-0202, and as a result, the
requirements
have been incorporated into the appropriate
procedures,
and the FSAR
.has been updated to indicate this strategy.
In another example, operator action to
run emergency fans during the summer to maintain EDG room temperatures
less
than 95'F was added in July 1996.
However, in discussions
with system
engineering,
the inspector was informed that the emergency fans start automatically
when the associated
EDGs start, and that there were no room temperature
issues
that affected EDG operability; the identified work around was considered to be a
habitability issue and no action was being taken to address
it. The inspector
considered that continuing to carry such item could lessen the credibility of the
operator work around list.
The inspector reviewed the operator work around list for Unit 1 and noted that it
included five items.
From discussions
with the coordinator of the operator work
around list, the inspector determined that a procedure was being developed to
incorporate enhancements
such as prioritization of corrective actions.
Improving
the effectiveness of the operator work around list appeared
to have significant
management
attention.
Conclusions
Adequate procedures
and processes
are in place for identification and.correction of
operator work arounds.
Unit 2 has been effective in reducing the number of
operator work arounds
and longstanding tagouts.
Some items being carried on the
Unit 2 operator work around list apparently have no recourse remaining, and could
lessen the credibility of this corrective action mechanism.
30
Miscellaneous Maintenance Issues
(Closed) Unresolved Item 50-410/95-25-02:
Extended Inoperability of the Unit 2
Loose Parts Monitor
~Back round
This item concerned
the inoperability of the loose parts monitor (LPM) from July
1991 until it was noted by the NRC resident inspector in December 1995.
As
discussed
in inspection report 50-410/95-25, the inspectors were concerned with
the weak organizational attention that had allowed the LPM to be inoperable for so
long.
The licensee initiated DER 2-95-3455 to investigate this situation.
Findin s and Observations
The inspector reviewed DER 2-95-3455, "Timeliness of restoration and reporting for
LPM system inoperability."
The DER indicated that the long'standing system
inoperability was the result of repeated
attempts to correct system lockups that
occurred during plant 'operations at less than full power.
The system lockups were
due to alarms, caused
by increased
background
noise, from the LPM channels that
monitored the recirculation loops.
The licensee addressed
this hardware issue by
transferring it to another
DER, 2-95-2128, while DER 2-95-3455 went on to
address
additional reportability requirements
and the lack of timely corrective action.
The root cause evaluation concluded that the cause of this event was managerial
methods,
based
on the repetitive problems and that managements
response
to the
problems were untimely and ineffective.
However, the evaluation proposed
no
corrective actions.
The root cause verification noted that the problem would
not'ecur
if the root cause was eliminated, because,
"appropriate management
oversight
on long standing hardware issues will prevent similar occurrences
in the future."
However, the mechanism
by which this is supposed
to occur is not identified.
The
evaluation went on to indicate that a system engineer has been assigned to the LPM
system, which the inspector considered
to be a substantive
'measure to prevent
recurrence.
The hardware problem with the LPM system was corrected by disabling the alarm
function for the recirculation loop detectors
(four of the 10 channels
in the system).
The technical acceptability of thas approach
is discussed
in safety evaluation 96-
089.
The system modification was completed during the 1996 refueling outage and
was reported to the NRC in a letter from the licensee,
NMP2L 1678, dated
December 6, 1996.
As of this inspection, the LPM system remained operable.
Conclusions
The extended
inoperability of the LPM system was due to ineffective management
oversight of efforts to resolve
a technical issue.
The licensee's root cause
evaluation did not specify corrective actions, and the mechanism
by which
increased management
oversight will be maintained was not clear.
However, given
0
31
that the longstanding
hardware problems with the LPM system have been
addressed
and that the system has been returped to service, this item is closed.
M8.2
(Closed) Inspector Followup Items 50-220/96-07-17
and 50-410/96-07-17:
Extended
Installation Period for a Service Water System Temporary Modification
This item concerned
temporary modification 91-107, which installed a corrosion
monitoring station for the Unit 2 service water system.
The modification consisted
of rack mounted corrosion coupons which were used to assess
the effectiveness
of
biocides at controlling microbiologically induced corrosion and biofouling.
Per
discussions'with the licensee, the long installation period was required to develop
and verify the long term effectiveness
of what would become
a permanent chemical
treatment system.
This temporary modification was subsequently
incorporated
as
part of a permanent modification (design change N2-94-007) which installed the
service water chemical treatment system.
Design change N2-94-007 was
completed on August 8, 1997, therefore, this item is closed.
III. ENGINEERING
E7
Quality Assurance in Engineering Activities
E7.1
50.59 Program Review
a.
Ins ection Sco
e
The team reviewed safety evaluations
and applicability reviews prepared
by the
licensee in support of changes,
tests, and experiments
made in accordance
with
The licensee uses applicability reviews -:or a preliminary screening
to determine if 10 CFR 50.59 is applicable to the proposed
change.
The team
measured
the licensee's
performance
by the quality of the safety evaluations
and
applicability reviews.
The team reviewed the following safety evaluations
prepared for each unit.
Unit 1
97-021, Draft E, Rev. 0
97-024, Draft C, Rev. 0
97-108, Draft A, Rev.
1
97-119, Draft A, Rev. 0
97-114, Draft B, Rev. 0
Unit 2
97-046, Draft C, Rev. 0
97-050, Draft A, Rev. 0
97-057, Draft A, Rev. 0
97-060, Draft A, Rev. 2
97-062, Draft A, Rev. 0
97-070, Draft A,'Rev. 0
In addition, the team reviewed 26 applicability reviews conducted at Unit 1 and 16
applicability reviews conducted at Unit 2. The team reviewed SORC and SRAB
meeting minutes for the past six months to assess
the management
oversight of the
50.59 program and also interviewed qualified preparers of safety evaluations
and
applicability reviews.
\\
Oi~
V
32
b.
Findin s and Observations
The team found the quality of the safety evaluations to be good.
The increased
quality of the safety evaluations
can be attributed, in part, to good senior
management
oversight of the program.
The SORC and SRAB meeting minutes
show evidence of detailed reviews of safety evaluations
by senior management.
Good feedback was provided to the preparers of safety evaluations.
The team found the quality of applicability reviews to be mixed.
The applicability
reviews prepared
by individuals experienced
in the 50.59 process were of good
quality.
Applicability reviews prepared
by individuals less experienced
in the 50.59
process were of lesser quality.
The team had comments concerning the amount of
detail provided in the description of the proposed
change for 6 of the 26 Unit 1
applicability reviews and 6 of the 16 Unit 2 applicability reviews that were
presented.
In some cases the written responses
provided for justification of the
answers to the five screening questions were not of sufficient detail to support the
preparer's
conclusions.
In no case did the team find the applicability review
conclusion to be incorrect.
The team noted that the licensee's
procedures
do not
require supervisory approval of completed applicability reviews, and there was no
evidence provided that any site organization conducted
routine periodic reviews of
completed applicability reviews for adherence
to plant procedures.
C.
Conclusions
The quality of safety evaluations were good and could be attributed in part to good
. senior management
oversight of the program.
In contrast to the quality of the
safety evaluations,
the quality of applicability reviews was mixed primarily due to
the level of documentation.
In some cases,
documentation
was not sufficient to
support the conclusions.
E8
IVllscellaneous Engineering Issues
E8.1
IFI 50-220 5 410/96-07-14:
Weaknesses
in the 50.59 Program
The May 1996 IPAP report noted that the quality of safety evaluations
and
applicability reviews prepared
by plant personnel
needed improvement.
This
comment was made in part based
on the number of safety evaluations that were
being rejected by the two management
review committees.
Since the IPAP report was published, plant management
has made a significant
effort to improve the quality of safety evaluations.
A review of recent SRAB and
SORC meeting minutes indicate that the rejection rate is near zero and the
committee members have continued to ask challenging questions of the preparers.
The team independently
review'ed the five most recent safety evaluations completed
at both units and found the quality to be good.
33
V. MANAGEMENTIVIEETINGS
X1
Exit lVleeting Summary
The inspectors
presented
the inspection results to members of the licensee
management
at the conclusion of the inspection on August 22, 1997.
The licensee
acknowledged
the findings presented.
The inspectors
asked the licensee whether
any materials examined during the inspection should be considered
proprietary.
No
proprietary information was identified.
X2
Review of UFSAR Commitments
A recerit discovery of a licensee operating their facility in a manner contrary to the
Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a
special focused review that compares plant practices, procedures
and/or parameters
to the UFSAR description.
While performing the inspections discussed
in this
report, the inspector reviewed the applicable portions of the UFSAR that related to
the areas inspected.
The inspector verified that the UFSAR wording was consistent
with the observed plant practices, procedure,and/or
parameters.
ATTACHMENT1
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Abbott, Unit
1 Plant Manager
D. Baker, Licensing Supervisor
C. Beckham, Manager, Quality Assurance
J. Burton, Director, ISEG
W. Connolly, QA Audit Supervisor
J. Conway, V.P. Nuclear Engineering
G. Corell, Mgr., Chemistry-U1
R. Dean, Manager, Unit 2 Engineering
A. DeGracia, Mgr., WC/Outage-U1
M. Dooley, Operations Support Unit 1
S. Doty, Maintenance
Manager-U1
J. Dryfuss, General Supervisor Operations Support
T. Fiorenza, Technical Support
J. Forderkonz,
Refueling Floor Coordinator Unit
1
D. Goodney, Electrical Engr. Supv.-U1
G. Gresock, Licensing Engineer
R. Hall, Director HRD
G. Helker, Unit 2 WC/OMG
B. Holloway, NMPC U1-Chemistry
K. Johnson,
Engineer
A. Jolka, Supervisor,
Unit 2 Electrical Engineering
M. Kalsi, Unit 2 Electrical Engineering
G. Kahn, ISEG-U2
D. Lundeen, Maintenance
Support Unit
1
J. Mancuso, Operations Support
P. Mazzaferro, Mgr., Tech Support-U1
R. McCoy, Operations Support Unit 1
B. Murtha, Operations
Manager Unit
1
D. Pike, Project Management
Unit
1
M. Pisano, Maintenance
Manager, Unit 2
N. Rademacher,
Executive Staff
A. Raju, Unit 2 Electrical Engineering
B. Smith, Operations Manager Unit 1
R. Strusinski, Operations Supervisor
J. Swenszhowski,
Director, 01P
K. Sweet, Unit 1 Technical Support Manager
R. Sylvia, NMPC Exec. V.P.
R. Tessier, Training Manager
C. Terry, Vice President NSAS
A. Vierling, General Supervisor,
Fuel and Analysis
C. Wave, Chemistry Manager
G. Whitaker, Engineer,
ISEG
B. Wolken, Maintenance-U2
D. Wolniak, Manager of Licensing
Attachment
1
NRC
T. Beltz, Resident Inspector
L. Doerflein, Chief, Reactor Projects Branch
1
B. Norris, Senior Resident Inspector
INSPECTION PROCEDURES USED
40500
Effectiveness of Licensee Controls in Identifying, Resolving,
and Preveriting Problems
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-220 5. 410/97-80-01
Failure to Justify the Extension of DER Disposition
50-410/97-80-02
Closed
50-410/95-25-02
50-410/95-25-03
IFI
Engineering
Evaluation and Corrective Actions
Concerning
Degraded
"B" RHR Full Flow Test Valve
Extended Inoperability of the Unit 2 Loose Parts Monitor
DERs Extended Without Justification
50-220 5 410/96-07-12
IFI
Weaknesses
in the DER Process
50-410/96-07-1 3
IFI
ISEG Review of NRC Documents
50-220 5. 410/96-07-14
IFI
Weaknesses
in the 50.59 Program
50-220 5 410/96-07-17
IFI
Extended Installation Period for a Service Water System
Discussed
None
C'
0
Attachment
1
3
LIST OF ACRONYIVIS USED
CFR
DER
IFI
IN
IPAP
ISEG
TS
Unit 1
Unit 2
Code of Federal Regulations
Deviation/Event Report
Emergency
Diesel Generator
Engineering Support Analysis
Instrumentation
and Controls
Inspector Followup Item
Information Notice
Integrated Performance Assessment
Process
Independent
Safety Engineering Group
Nine Mile Point
Niagara Mohawk Power Corporation
Problem Identification
Quality Assurance
Self-Assessment
Service Information Letter
Station Shift Supervisor
Technical Specification
Updated Final Safety Analysis Report
Nine Mile Point Unit 1
Nine Mile Point Unit 2
0