ML15118A331
| ML15118A331 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 03/18/1998 |
| From: | Ogle C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A329 | List: |
| References | |
| 50-269-98-01, 50-269-98-1, 50-270-98-01, 50-270-98-1, 50-287-98-01, 50-287-98-1, NUDOCS 9803270388 | |
| Download: ML15118A331 (30) | |
See also: IR 05000269/1998001
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04
License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503
Report No:
50-269/98-01, 50-270/98-01, 50-287/98-01
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
January 26 - February 5, 1998
Team Leader:
Darrell Roberts, Catawba Senior Resident Inspector
Inspectors:
Robert E. Carroll, Jr., Project Engineer
Rich C.
Chou, Reactor Inspector
M. Scott Freeman, Oconee esident Inspector
McKenzie Thomas, Senior Reactor Inspector
Approved by:
C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9803270388 980318
ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2. and 3
NRC Inspection Report 50-269/98-01,
50-270/98-01, and 50-287/98-01
This team inspection covered aspects of the licensee's corrective action
program as defined in Nuclear System Directive (NSD) 210; Corrective Action
Program Directive, Revision 1, and other related procedures, as it applied to
operations, maintenance, engineering, and plant support. The report covers a
two-week period of inspection by a team consisting of resident and regional
inspectors.
Operations
Generally, problem investigation process reports reviewed by'the
inspection team reflected appropriate screening, operability and
reportability determinations, with adequate documentation of the problem
and corrective actions. The inspection team identified instances of
non-compliance with Nuclear System Directive 208 which paralleled the
licensee's audit findings stemming from the Oconee Recovery Plan focus
on problem investigation process report quality improvements. The
licensee was actively pursuing corrective actions for the previously
identified problems with problem investigation process implementation.
(Section 07.1)
The reviewed licensee audits and assessments were performed in
accordance with NRC regulations and the licensee's quality assurance
program commitments and procedures. The audits and assessments were
effective in identifying continued weaknesses and areas for improvement
in problem investigation process report quality. The audit findings
generally reflected those identified by the inspection team and the
icensee was actively addressing the audit-related deficiencies during
the inspection period. (Section 07.2)
Plant Operations Review Committee activities were generally in
compliance with selected licensee commitments and licensee
administrative procedures. Related licensee-identified discrepancies
had been proper y addressed in the corrective action program. (Section
07.3)
The licensee's administrative procedures for the Nuclear Safety Review
Board contradicted Technical Specifications regarding review of Title 10
Code of Federal Regulations 50.59 safety evaluations. This was left
unresolved pending further NRC review of licensee changes to the review
process. (Section 07.4)
Maintenance
System and equipment reliability is a major focus area of the Oconee
Recovery Plan. Newly implemented under this Plan, the Top Equipment
Problem Resolution process has begun to focus attention on the
resolution of a considerable number of equipment/material condition
issues; some of which are long-standing. (Section M2.1)
Problem deficiency tags observed during plant tours, were generally only
around six months old. Some of the oldest deficiency tags observed
2
(October 1994 and August 1996), identified auxiliary service water
(tornado) pump supply valve seat leakage and noticeable operator oil
leakage. The licensee indicated that these problems, along with an
auxiliary service water pump seal leak that was beginning to cause pump
base corrosion, were scheduled for resolution during the upcoming Unit 2
refueling outage. (Section M2.1)
The licensee's newly implemented program to trend and analyze cause and
event code data from problem investigation process reports had yet to
produce auditable results. In conjunction with the licensee's
Engineering Support Program, the Failure Analysis and Trending program
and its associated semi-annual Equipment History Trend Report were
considered adequate tools for assisting engineering in identifying and
assessing plant equipment performance trends. An in-depth review of two
risk significant systems and associated components discerned that a
considerable length of time passed before arriving at viable solutions
for resolving repetitive problems. (Section M2.2)
A violation of Technical Specification 6.4.1.e was identified regarding
an inadequacy in maintenance procedure MP/0/A/1810/014. Specifically
the procedure did not provide sufficient instructions for limiting the
amount of purge paper to be used as weld damming material. As a result,
the drain line connected to the Unit 1 pressurizer surge line became
blocked following welding. The licensee had previous opportunities to
correct this procedural inadequacy from earlier related experiences
documented in problem investigation process reports.
(Section M3.1)
The inspection team concluded that not requiring Less Significant Event
Category 3 problem investigation process reports to be reviewed for
generic applicability was a weakness in Nuclear Site Directive NSD 208
and the problem investigation process. (Section M3.1)
Continuing problems in the area of Technical Specification surveillance
tracking and scheduling have not been resolved through the corrective
action program. The inspection team identified a number of clerical
errors and the licensee has documented problems with the tracking or
completion of surveillance activities in a number of problem
investigation process reports. Accordingly, more licensee management
attention is warranted in this area.
(Section M7.1)
Engineering
The Failure Analysis and Trending Program and Equipment History Trend
Reports for the evaluation of equipment performance were adequate.
However, the inspection team identified examples of incorrect
documentation of engineering responses.regarding failure analysis of
certain equipment. Accordingly, more attention to detail is warranted
in compiling engineering review comments in this area.
(Section E2.1)
(II
3
The inspection team concluded that the licensee conducted good reviews
during Phase 1 of the voluntary Updated Final Safety Analysis Report
Review Project. The licensee appropriately captured the majority of
identified UFSAR discrepancies into its corrective action program and
added those that were identified by the inspection team. One inspector
followup item was identified for further evaluation of startup thermal
transient number 23, associated with the reactor coolant system, and
incorporation of the related calculations into fatigue analyses.
(Section E7.1)
The Self-Initiated Technical Audit of the High Pressure Injection and
Low Pressure Injection systems and the High Pressure Injection System
Reliability Study were thorough and detailed efforts that effectively
identified equipment and programmatic issues, as well as provided
pertinent recommendations. These recommendations were appropriately
captured in the licensee's corrective action program.
(Section E7.2)
The inspection team concluded that operating experience information
reviewed by the team was being processed in accordance with the
licensee's procedures. However, as indicated by the violation
identified in Section M3.1 of this inspection report, not all of the
corrective actions identified through the operating experience program
reviews were being implemented by the Oconee site. Findings from
assessments of the operating experience program were documented and
tracked in the licensee's corrective action program. (Section E7.3)
S11
NII
Report Details
Summary of Plant Status
Unit 1 began the inspection period in hot shutdown on January 26. 1998, due to
continuing problems with the control rod drive system and was reduced to cold
shutdown on January 27, 1998, because of a leaking drain line on the
pressurizer surge line. The unit remained in cold shutdown for the remainder
of the period.
Unit 2 operated at 100% power for the duration of the inspection period..
Unit 3 operated at 100% power for the duration of the inspection period.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments'
While performing inspections discussed in this report, the inspection team
reviewed the applicable portions of the UFSAR that related to the areas
inspected. The inspection team verified that the UFSAR wording was consistent
with the observed plant practices, procedures, and parameters.
(See Section E7.1 for inspection findings related to the licensee's UFSAR
Review Project.)
I. Operations
07
Quality Assurance in Operations
.
07.1 Problem Identification and Resolution
a. Inspection Scope (40500, 71707)
The inspection team reviewed the licensee's process for identifying,
documenting, and responding to problems, as established under Nuclear
System Directive (NSD) 208. Problem Investigation Process (PIP).
Revision 16, dated November 17, 1997.
b. Observations and Findings
The licensee's method for documenting and resolving identified problems
is the PIP report. Because identified problems varied in significance.
each PIP report is screened, with respect to established significance
criteria (category 1 - 4), to differentiate between the more significant
events (MSE) and the less significant events (LSE). In accordance with
NSD 208, a MSE (category 1 or 2) requires a root cause analysis and
programmatic corrective actions to prevent recurrence. By comparison, a
LSE category 3 only requires an apparent cause and corrective actions to
fix the identified problem; thereby, providing a reasonable assurance of
preventing recurrence. Category 4 LSEs do not require any additional
corrective actions. To assure sufficient information is provided,
operability issues have not been overlooked, and consistency is
maintained in significance categorization, NSD 208 requires each PIP
report to be reviewed by a Centralized Screening Team (CST). The CST is
also tasked with assigning the group(s) responsible for evaluating the
cause and resolution, as appropriate. Any necessary evaluations and
corrective actions are addressed and concurred upon accordingly in the
PIP report.
2
In order to assess this process, the inspection team interviewed the
Safety Review Group (SRG) site PIP coordinator and group PIP
coordinators from Maintenance and Mechanical Systems Engineering:
attended several CST PIP report screening meetings and other.management
meetings where PIP reports are discussed: followed through portions of
the process for certain issues that occurred during the inspection
period: assessed the disposition of findings from assessments and audits
(e.g., SRG, Institute of Nuclear Power Operations (INPO), Nuclear Safety
Review Board (NSRB). Self-Initiated Technical Audits (SITA)); and
reviewed numerous PIP-reports. Generally, PIP reports reviewed by the
inspection .team reflected appropriate screening, operability and
reportability determinations, adequate problem documentation and
proposed or actual corrective actions. Some areas for attention and
associated findings from the inspection team's assessment were as
follows:
Problem Identification - Appendix 0 of NSD 208 indicates that the
findings or recommendations from group assessments, as well as
management attention items, observations and conclusions from NSRB
meetings, be captured in a PIP report for appropriate corrective action.
Addrelsed below are inspector identified examples where this was not
done:
Out of the 14 issues applicable to Oconee from the March 1997 NSRB
meeting minutes, 1 of 6 management attention items and 7 of 8
observations or conclusions were not captured in a PIP report.
Neither of the two management attention items nor any of the
observations or conclusions from the.July 1997 NSRB meeting
minutes were included in a PIP report.
None of the observations or conclusions from the September 1997
NSRB meeting minutes were captured in a PIP report.
As discussed in Section 07.3, a finding from SRG assessment SA-97
45, which could result in site specific changes to NSD 308, Plant
Operations Review Committee Review Requirements, was not captured
in a PIP report indicating its applicability to Oconee unti]
identified by the inspection team.
Aside from the above findings related to NSD 208. Appendix 0, the
inspection team found no other concerns related to problem
identification in the PIP report process. The licensee's threshold for
PIP report initiation was adequately established to facilitate the
identification and correction of low level issues or potential
precursors to more significant events.
Operability Determinations - NSD 208 required that any PIP report
requiring a technical evaluation for operability be classified as a MSE.
The operability determination would be completed in accordance with NSD
203, Operability. If the documented operability determination showed
the system to be operable, then the PIP report could be classified as a
LSE. Revision 9 of NSD 203, dated December 30, 1997, provided specific
guidelines and requirements for operability determination related to
timeliness, engineering evaluation considerations, and overall
.3
evaluation considerations. The NSD differentiated between "current"
operability evaluations and "past operability evaluations" and provided
timeliness guidelines for both. Generally, evaluations of systems,
structures, or components for current operability should be completed
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per the NSD, while those only being evaluated for past
operability (to support NRC reporting requirements in 10 CFR 50.73) were
given a guideline of 30 working days for completion. The NSD also
allowed that while a verifiable technical basis for past operability
determinations must be provided, engineering conservatism may be
decreased for past operability evaluations because there would be no
attendant duty of protecting the public. The inspection team verified
that revision 9 of NSD 203 incorporated recent guidance adopted by the
NRC as described in NRC Generic Letter 91-18, Revision 1.
The inspection team selected and reviewed several operability
determinations, including those documented in PIP reports 3-097-0216, 2
097-0069, and 0-097-0710. The PIP reports .were appropriately
categorized as MSEs and downgraded to LSEs when warranted. In general,
operability evaluations were documented adequately with proper
references to external calculations or documents containing engineering
assumptions. In a few cases, however, the inspection team noted a lack
of continuity of information provided in the PIP report to support the
operability determinations. Further discussions with engineers were
required to fill in the missing or implied information. The inspection
team informed licensee personnel that this was an area that warranted
further scrutiny since the PIP reports and associated operability
evaluations served as records of these activities.
The inspection team found cases where the timeliness for meeting NRC
reporting requirements was not always well-established. For PIP report
0-097-0710, regarding low temperature over-pressure protection (LTOP)
inoperability, a second train of LTOP was determined to be inoperable on
March 3, 1997, when the action to perform a "current" operability
evaluation had been assigned six days earlier on February 26. Further,
it
was not reported to the NRC in accordance with 10 CFR 50.72 until
April 17, 1997. These activities appeared to be in contrast with
requirements contained in NSD 203. However, upon further review and
discussions with licensee personnel, the inspection team learned that
the previous philosophy for current operability determinations was based
on 72 working hours, allowing time off for weekends. This philosophy
has since been revised to require continuous off-hours pursuit of
operability resolution, In accounting for the delayed report to the
NRC, the licensee had established compensatory measures as allowed in
Technical Specification 3.1.2.9.5.c for the second inoperable train of
LTOP. This action allowed the licensee (per its program) to pursue
operability and reportability from a "past" inoperable standpoint, and
make subsequent reports accordingly. The NRC report associated with
this issue was later retracted when further calculations were performed
using up-to-date pressure limits.
PIP Screening - As indicated above, NSD 208 requires each PIP report to
be reviewed by the CST in order to assure that sufficient information is
provided, operability issues have not been overlooked, and consistency
is maintained in significance categorization. Accordingly, NSD 208
indicates that the CST should consist of a representative from
4
Operations, Engineering, Maintenance and Safety Review, with others as
determined appropriate.
Inspector identified screening-related findings
are listed below:
The pressurizer drain line purge paper plugging event addressed in
Section M3.1 was initially screened by the CST as a category 3,
but later upgraded to a category 2. This repetitive Operating
Experience issue might have been initially screened a category 2
had the Maintenance organization been represented in the-.CST.
Security PIP reports were presented at the two CST meetings
attended by the inspection team. There was no Security
representative at either of these two meetings and the inspection
team noted that the subject PIPs appeared to be only receiving a
"cursory" review by the CST. When asked:'-the CST members informed
the inspection team that as a rule, Security is not represented at
the CST meetings and, because of the nature of security-type
issues, heavy reliance is placed on the screening/categorization
made at the time a security-related PIP report is initially put in
the system. From the inspection teams' review of audit report SA
97-04(ON)(RA) (addressed in Section 07.2). it
was evident that the
categorization of several security-related PIP reports were
brought into question.
As allowed by NSD 208, some PIP reports categorized as level 3
could be exempted from problem evaluation and proposed resolution
completion if they met certain criteria. Those PIP reports would
not have an apparent cause determination performed in
accordance
with NSD 212, Cause Analysis. Items falling in this category were
informally referred to by licensee personnel as "3-4 PIPs."
The
inspection team identified that PIP report 2-097-4392, documenting
a conflict identified in December 1997 between a Technical
Specification Surveillance refueling outage frequency due date and
the next Unit 2 refueling.outage, was screened as a 3-4 PIP. The
inspection team noted that the PIP report contained several
corrective actions, including reviewing procedures and the work
management system to ensure that TS surveillance requirements were
coded properly to preclude further conflicts in this area. Given
continuing problems at the Oconee station with TS surveillance
tracking and compliance, as well as the multitude of corrective
actions specified in the PIP report, the inspection team
considered that the PIP report was inappropriately screened as a
3-4. Licensee personnel stated that the information available to
them during the week of the inspection was not available at the
time the PIP was screened, but that the PIP would be re
categorized to require the problem evaluation and proposed
resolution fields to be completed.
Documented Problem Resolution - NSD 208 indicates that when closing a
PIP corrective action (CA), a cross reference (e.g., nuclear station
modification (NSM), minor modification (MM). work request (WR). etc.)
shall be provided. In the event that the NSM, MM or WR is canceled, the
PIP must be reopened (if
closed) or new corrective action created (if
PIP is open) to have corrective actions re-evaluated. Listed below are
5
inspector identified instances where this was not done [note: numbers in
brackets reflect the correct references]:
Incorrect NSM numbers were provided or referenced in CAs of PIP 1
095-0513 (incomplete NSM numbers - [112941 and [112901) and PIP 4
095-0257 (unrelated canceled NSM - 52955 [52918]).
PIP 1-095-0513 CA number 2 indicated NSM [1]2901 for corrective
modifications to the 1B second stage reheater drain tank and pipe
supports. This NSM was canceled on March 12, 1997 (scope
incorporated into NSM [1]2941), but CA number 2 was not revised or
reopened.
PIP 5-095-0594 CA number 1 indicated resolution of leakage past
valve
1LPSW-134 would be pursued by WR-96080939. This WR was
canceled on June 11, 1997 (MM 9685 was established to add a valve
downstream of 1LPSW-134). but CA number 1 was not revised or
reopened.
The failures to revise or reopen PIP corrective actions that were
addressed above, are apparently not isolated cases. This is evidenced
by three other such examples identified in licensee corrective action
audit SA-96-02(ON)(RA). as well as by the occurrence documented in PIP
0-098-0365 that was identified by the licensee during the inspection
period.
c. Conclusion
Generally, PIP reports reviewed by the inspection team reflected
appropriate screening, operability and reportability determinations,
with adequate documentation of the problem and corrective actions. The
inspection team identified instances of non-compliance with NSD 208
which paralleled the licensee's audit findings stemming from the Oconee
Recovery Plan focus on PIP quality improvements, as addressed in Section
07.2. The licensee was actively pursuing corrective actions for the
previously identified problems with PIP program implementation.
07.2 Quality Assurance Audits and Assessments
a. Inspection Scope (40500)
Audit and assessment reports were reviewed for compliance with 10 CFR 50
Appendix B requirements, the Duke Power Company Quality Assurance
Program Topical Report (Duke-i-A), the ONS Technical Specifications
(TS). Nuclear System Directive (NSD) 208. Problem Investigation Process,
and NSD 607, Self Assessments. These audits and assessments were
performed on various corrective action program activities.
b. Observations and Findings
The inspection team reviewed selected audits and assessments performed
by the Regulatory Audit Group from the Nuclear Assessment and Issues
Division, and the Safety Review Group (SRG) from the Oconee Nuclear
Station (ONS) Safety Assurance Department. The following audits and
assessments were reviewed:
6
SA-96-06(ON)(RA)., Consolidated Performance Audit
SA-97-04(ON)(RA), Corrective Action
SA-97-08(ON)(RA), Corrective Action
SA-97-09(ON)(RA), Consolidated Performance Audit
SA-97.-10(ON)(SITA)(HPI/LPI), Self-Initiated Technical Audit (SITA)
High Pressure Injection and Low Pressure Injection
SA-97-21(ON)(SRG), Common Cause Analysis (97-1)
SA-97-30(ON)(SRG), Operating Experience Data Base Use for MSE PIP
Resolution
SA-97-50(ALL)(PA), ISEG/SRG Activities
SA-97-53(ON)(SRG), PORC Effectiveness
SA-97-61(ONS)(SRG), In-Plant Review of: Problem Investigation
Process (PIP) Compliance
SA-97-62(ALL)(PA), Operating Experience Program
SA-97-64(ONS)(SRG), Common Cause Analysis (97-2)
During review of the audit and assessment reports, the inspection team
noted that audit reports SA-97-04(ON)(RA) and SA-97-08(ON)(RA)
identified findings where PIPs needed to be re-opened to provide
clarification or address deviations from procedure NSD-208. Some of the
licensee-identified concerns included, but were not limited to:
corrective actions not being properly specified, corrective actions not
being completed as stated, apparent causes not being properly addressed.
PIP reports being inappropriately classified or downgraded to Category
4, and proposed resolutions not adequately addressing the problem. The
inspection team noted that .two of the PIP reports (4-097-0878[SEC] and
4-096-1985[SEC]) that were re-opened due to being improperly classified
as Category 4 PIPs instead of Category 3.PIPs were in the Security area.
The licensee initiated PIP reports to document the findings from audits
SA-97-04(ON)(RA) and SA-97-08(ON)(RA) in accordance with their
corrective action program. The inspection team further noted that, in
addition to these two audits, other licensee assessments and indicators
have found numerous examples of poor PIP quality and failure to comply
with NSD 208. As a resu t of the findings concerning poor PIP quality,
the licensee established an initiative in August 1997 to improve PIP
quality as part of the overall Oconee Site Recovery Plan. This
initiative was intended to raise the level of PIP quality to meet the
intent of NSD 208. On August 1, 1997, the SRG within the Oconee Safety
Assurance Department began a review of closed PIP activities for
compliance with NSD 208. PIPs were re-opened where improvements were
needed. This effort by the SRG was documented in assessment report SA
97-61(ONS)(SRG). The inspection team noted that the SRG review results
indicated a slight improvement in PIP quality, but the number of PIPs
re-opened was still above the licensee's goal.
The final goal would be
7
determined by an assessment performed by the General Office (corporate)
audit group. The inspection team noted that the General Office
assessment of PIP quality was in progress, but was not completed at the
conclusion of this inspection.
c. Conclusion
The inspection team concluded that the audits and assessments reviewed
were performed in accordance with. NRC regulations and the licensee's QA
program commitments a-nd procedures. The audits and assessments were
effective in identifying continued weaknesses and areas for improvement
in the licensee's corrective action program concerning PIP quality.
Findings identified during the audits and assessments were documented
and included in the licensee's corrective action program, including
those for the High Pressure Injection System Reliability Study.
07.3 Plant Operations Review Committee (PORC)
a. Inspection Scope (40500)
The iiispection team evaluated the performance of the PORC for the period
from June 1997, to February 1998, including compliance with selected
licensee commitments (SLC) and licensee administrative procedures.
b. Observations and Findings
The inspection team reviewed SLC 16.13-2 and 16.13-3: reviewed NSD 308.
Plant Operations Review Committee. Revision 3: reviewed self-assessment
SA-97-45, Comparison of SLC and NSD 308 PORC Review Requirements:
reviewed PORC minutes from June 23, 1997, to December 30. 1997; and
attended a PORC meeting on January 30, 1998.
The inspection team found that SA-97-45 accurately described the
discrepancies between the SLC and NSD 308, and these discrepancies were
addressed in a PIP report. The inspection team found, however, this PIP
report to be specific to the McGuire Station with no generic
applicability designated. The inspection team then reviewed the PIP
report (0-M97-3905) for any applicability to the Oconee Station.
Generally, the inspection team found that corrective actions stated in
the McGuire PIP Report would apply to the Oconee Station because the
corrective actions involved changes to NSD 308 which would be approved
by all Duke Power sites. However, the inspection team found that one
discrepancy addressed by PIP Report 0-M97-3905 did not apply equally to
the Oconee Station and the McGuire Station. PIP Report 0-M97-3905
addressed the discrepancy regarding the SLC 16.13-2e requirement for
PORC to review the investigations of incidents reportable pursuant to TS
by requiring a determination of which reports were included in the
requirement and a subsequent change to NSD 308. The inspection team
found that determining which McGuire Station reports were included would
not ensure that all Oconee Station reports would be included. This was
because Oconee Station TS contained different NRC reporting requirements
than did the McGuire TS. The licensee initiated Oconee PIP Report 0
098-0557 to address the discrepancy for Oconee Station.
8
c. Conclusion
The inspection team concluded that Plant Operations Review Committee
activities were generally in compliance with selected licensee
commitments and licensee administrative procedures. Related licensee
identified discrepancies had been properly addressed in the corrective
action program.
07.4 Nuclear Safety Review Board (NSRB)
a. Inspection Scope (40500)
The inspection team assessed the performance of the NSRB for the
previous three meetings, including compliance with the TS.
b. Observations and Findings
.
The inspection team reviewed TS 6.1.3; reviewed NSD 309, Nuclear Safety
Review Board. Revision 5: reviewed the resumes of all NSRB members;
reviewed minutes for the three most recent NSRB meetings; interviewed
the NSRB alternate director; and interviewed members of the NSRB staff.
The inspection team found the NSRB activities and related program
procedures to be in compliance with TS 6.1.3.1 and 6.1.3.2 regarding
function and organization. The inspection team also found NSD 309 to
agree with TS 6.1.3.1 and 6.1.3.2 except for the frequency of meetings.
T 6.1.3.2f required two meetings per year while NSD 309. Section
3.9.7.1 required NSRB to meet once per quarter. The NSRB held three
meetings during 1997.
The inspection team found the NSRB in compliance with TS 6.1.3.3
regarding review, except for review of safety evaluations completed
under 10 CFR 50.59. TS 6.1.3.3a required the NSRB to review safety
evaluations completed under the provisions of 10 CFR 50.59 to verify
such actions did not constitute an unreviewed safety question. TS 6.1.3.2g required a quorum of NSRB for the review functions specified in
the TS. NSD 309, Section 309.10.2.1, differed from the TS in that the
NSD allowed 10 CFR 50.59 safety evaluations to be reviewed by the NSRB
support staff and if the staff determined any were not significant the
staff was authorized to conclude no formal review by NSRB members was
required.
When questioned by the inspection team, the NSRB alternate director and
staff both indicated that each 10 CFR 50.59 safety evaluation was
reviewed by one NSRB member with any objections or problems discussed at
the full board meeting. The reviews were documented in a nuclear safety
evaluation review log. The inspection team reviewed the log and found
that for each 10 CFR 50.59 safety evaluation issued since July 1997 one
NSRB member signed the log as having reviewed the safety evaluation.
The licensee also indicated TS 6.1.3 would be relocated as part of the
Improved Technical Specification Submittal and would be changed to
clarify how 10 CFR 50.59 safety evaluations would be reviewed. The
licensee subsequently initiated PIP report 0-G98-0025 to track the
changes.
9
The circumstances surrounding this issue will be tracked as Unresolved
Item (URI) 50-269,270,287/98-01-01, NSRB Review of 10 CFR 50.59 Safety
Evaluations, pending:
(1)
the resolution of differences between TS 6.1.3 and NSD 309 regarding review of 10 CFR 50.59 safety evaluations;
and (2)
further NRC review of how NSRB members currently review 10 CFR
50.59 safety evaluations.
c. Conclusion
The inspection team identified that licensee administrative procedures
for the Nuclear Safety Review Board contradicted Technical
Specifications regarding review of 10 CFR 50.59 safety evaluations.
This was left unresolved pending further NRC review of licensee changes
to the review process.
II.
Maintenance
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Material Condition of Facility
a. Inspection Scope (40500, 71707)
The inspection team assessed material condition of the facility to gain
some insight as to the effectiveness of the licensee's corrective action
program to identify and correct equipment-related problems. This
assessment was accomplished through walkdowns of various plant areas and
by reviews of System Assessment (Health) Reports, the Operator
Workaround list and the Top 15 Major Equipment Problem Resolution (MEPR)
list.
b. Observations and Findings
During the course of the inspection, the inspection team conducted tours
of the control rooms and various areas of the turbine building,
auxiliary buildings and standby shutdown facility. In these areas of
the plant, most of the hanging problem deficiency (PD) tags were only
around six months old. Exceptions to this were as follows:
February 1997 PQ tag identifying the Unit 1 turbine driven
emergency feedwater pump steam supply relief as leaking. [The
licensee indicated that the work was done during the recent Unit 1
refueling outage, but the tag was not removed as required.].
October 1994 and August 1996 PD tags identifying the auxiliary
service water (tornado) pump condenser circulating water (CCW)
supply valve CCW-99 as having a seat leak and operator oil leak
that was very noticeable. The tornado pump's obvious seal leak,
which was beginning to cause signs of pump base corrosion, was
captured on a September 1997 PD tag. [The licensee indicated that
the work was tied to the upcoming Unit 2 refueling outage.]
July 1995 PD tag identifying a cracked fuse block for the 3A CCW
pump breaker. [The licensee indicated that the fuse block had
been on order.]
10
Additionally, during tours of the Unit 3 auxiliary building, the
inspection team identified what appeared to be Teflon tape on various
joints of the seal water lines for the 3B and 3C low pressure injection
pumps. The licensee captured this issue in a PIP report for evaluation.
Further followup of this issue was accomplished by the resident
inspectors and documented in Inspection Report 50-269,270,287/97-18.
As part of the licensee's focus on system and equi pment reliability
under the Oconee Recovery Plan, the Top Equipment Problem Resolution
(TEPR) process was recently implemented. Parts of this process included
the Operator Workaround and MEPR lists. A review of these two lists
revealed that-a considerable number of equipment material condition
issues have been identified for resolution; some of which, like the
CRDMs discussed in Section M2.2, have been long-standing issues. Based
on the Recovery Plan, a licensee self-assessment of the TEPR process is
scheduled for May 1998. Further review of this process by the resident
inspection staff is currently planned for later this year.
c. Conclusion
System and equipment reliability is a major focus area of the Oconee
Recovery Plan. Newly implemented under this Plan, the Top Equipment
Problem Resolution process has begun to focus attention on the
resolution of a considerable number of equipment material condition
issues; some of which are long-standing.
Problem deficiency tags observed during plant tours/walkdowns, were
generally only around six months old. Some of the oldest deficiency
tags observed (October 1994 and August 1996), identified auxiliary
service water (tornado) pump supply valve seat leakage and noticeable
operator oil leakage. The icensee indicated that these problems, along
with an auxiliary service water pump seal leak that was beginning to
cause pump base corrosion, were scheduled for resolution during the
upcoming Unit 2 refueling outage.
M2.2 Trending
a. Inspection Scope (40500)
The inspection team conducted a review of the licensee's processes for
identifying potentially negative trends and evaluating them for
appropriate corrective actions. These processes included those
established under Nuclear System Directive (NSD) 223, Trending of PIP
Data, and Engineering Directives Manual (EDM) 201, Engineering Support
Program, which references EDM 215, Failure Analysis and Trending.
b. Observations and Findings
As part of the review of NSD 223, the inspection team interviewed the
Safety Review Group (SRG) site trend evaluator, as well as group trend
evaluators from Maintenance and Mechanical Systems Engineering. NSD 223
requires the site and group evaluators to perform quarterly PIP data
trending of events and causes at the site and group levels,
respectively. The site evaluator is
also required to do semi-annual
11
common cause trending, focusing on causes that involve human error or
program or process deficiencies. The inspection team discussed
preliminary findings and trending difficulties with the evaluators; but,
since NSD 233 was implemented on September 16, 1997, the first quarterly
reports were not yet issued. However, the inspectors were able to
review SRG common cause analysis reports SA-97-21(ONS)(SRG) and SA-97
64(ONS)(SRG) for the periods of September 1, 1996, - March 31. 1997, and
April 1, 1997, - October 30. 1997, respectively. Assessing cause code
PIP data over their respective periods, these SRG reports .addressed both
site and individual groups with respect to human error types; human
error/inappropriate action failure mode: organizational and programmatic
failure mode; work process review; and key activity review. Skill-based
error continued to be the leading site human error type, showing an
increase in the later report from 39% to 43%. The inspection team
verified that the identified problems and recommendations were captured
in PIPs for corrective action resolution.
The Failure Analysis and Trending (FAT) program established under EDM
215-, used equipment history records to identify problem equipment and
adverse trends in equipment. Discussed in detail in Section E2.2, the
inspection team found the FAT program and its associated semi-annual
Equipment History Trend Report to be an adequate tool for assisting
Engineering in identifying and assessing plant equipment performance
trends.
To further assess the effectiveness of Engineering's trending processes,
the inspection team interviewed system and component engineers and
reviewed Engineering Support Program system health reports and PIPs
associated with selected equipment and components from three risk
significant systems (i.e., standby shutdown facility diesel, control rod
drive mechanisms, and Keowee-Westinghouse DB breakers). The results of
this assessment were as follows:
Standby Shutdown Facility (SSF) - SSF reliability appeared as item
number 11 on the Top 15 Major Equipment Problem Resolution List.
Reflective of this, the SSF diesel generator (DG) A super system
(DG and supporting equipment and systems) was declared (a)(1)
under the maintenance rule on June 10, 1997, due to a number of
non-repetitive Maintenance Preventable Functional Failures (MPFFs)
and potentially falling below the maintenance rule availability
goal.
From a review of PIPs over the last four years, the
inspection team discerned a potentially negative trend involving a
March 1996 failure of the SSF DGB fuel oil return line and a June
1997 SSF DGA fuel oil primer line. Further review revealed that
after the second failure, the licensee determined that these lines
were susceptible to cracking (caused by vibration induced high
cycle fatigue) at around 300 hours0.00347 days <br />0.0833 hours <br />4.960317e-4 weeks <br />1.1415e-4 months <br /> of DG operation and replaced
the fuel oil return and primer lines on both diesels. The
inspection team verified that DG run times were being tracked to
ensure integrity of these newly installed lines until minor
modification ONOE-10584 is implemented to install flexible type
lines. Scheduled for a non-outage period in March 1998, ON0E
10584 is one of several prerequisites addressed in PIP 1-097-1746
to return the SSF DGA super system to (a)(2) status under the
maintenance rule. Similarly, various unrelated SSF heating
12
ventilation and air conditioning (HVAC) system refrigerant leaks
identified in PIPs over the last two years were collectively
addressed in PIP 1-097-1746 for appropriate resolution.
Control Rod Drive Mechanisms (CRDMs) - CRDM reliability was item
number 3 on the Top 15 Major Equipment Problem Resolution List.
Based on a review of CRDM-related PIPs over the last five years,
it became apparent that an adverse trend existed with respect to
rod/group out limit problems. A considerable number of these PIPs
concerned losses of a group's rod out limit, resulting in
unnecessary integrated control system (ICS) runbacks that
challenged the lant and control room operators. In a September
1995 update to PIP 3-0930475, reliance on operator action to
terminate these unnecessary runbacks was considered acceptable due
to an unrelated reduction in the ICS runback rate from 30%/min to
5%/min (and later 1%/min associated with a preplanned ICS
replacement). Because of continuing problems (particularly in
Unit 2). the loss of CRDM out limit was recognized on the Unit 2
control room operator workaround list in February 1997, where it
remained at the time of this inspection. Minor modification ON0E
11229 (reflective of an early Three Mile Island design change) was
being developed to add an asymmetric rod interlock to the ICS
runback circuitry; thereby eliminating spurious runbacks caused by
a loss of the group out limit. Considering the number and age of
PIP reports related to CRDM rod/group out limits, the inspection
team concluded that the licensee's planned permanent resolution of
recurring problems had been untimely.
In addition to the out limit problems, there were also several
PIPs concerning rod latching-related problems similar to the most
recent occurrences in Unit 1. The subject of three different PIPs
(1-097-1236, 0-097-4595 and 1-098-0259), Group 5 Rod 7 experienced
latching problems on three separate occasions since April 1997;
the last of which in January 1998 resulted in considerable restart
delays due to CRDM replacement. Long-term plans (based on
obsolescence and slow.rod issues) to replace/upgrade CRDMs
(including stators and position indicator tubes) under Nuclear
Station Modifications 13032 and 23032, should have a positive
impact on resolving these latching-related problems, as well as on
reducing the actual causes for .rod out limit problems.
Keowee Westinghouse DB Breakers - The inspection team found seven
PIP reports that dealt with failures in safety-related switchgear
at Keowee (KHU) during 1993 and 1994. Each of these failures
involved the control power fuse or closing coil in a Westinghouse
Model DB breaker. These failures were attributed to a variety of
causes including component aging, improper coil, and excessive
use. The last report of the seven, PIP report 0-094-1753,
described an event in December 1994 where the close coil of the
field breaker in KHU-1 overheated and burned out because the
breaker received a close signal followed almost immediately by a
trip signal.
The anti-pump logic on the breaker consisted of one auxiliary
relay (X-relay) and one time delay relay (Y-timer and relay) wired
13
such that on a close signal the X-relay energized the breaker
closing coil.
When the breaker closed the Y-relay energized,
which after a short time delay caused the X-relay and closing coil
to deenergize. In the case described in PIP report 0-094-1753, a
trip signal occurred before the Y-timer could complete its timing;
therefore, the X-relay and closing coil remained energized. With
the closing coil energized, the continuous current either caused
the coil to overheat and burn or caused the control power fuse to
fail.
One corrective action for PIP report 0-094-1753 specified a review
of the X and Y-relays to resolve the problem of the closing coil
remaining energized. This corrective action was proposed in
January 1995 with a due date of June 1996. A later corrective
action changed the due date to January 1997. A third corrective
action again changed the due date to April 1998.
In June 1997, (PIP report 0-097-1927) and again in September 1997
-
(PIP report 0-097-2983), two more incidents occurred that involved
the failure of a control power fuse or closing coil in a Keowee
Westinghouse Model DB breaker. The cause of both of these
incidents was attributed to a random failure of the Y-timer. In
each case, the failure of the Y-timer caused the X-relay and
closing coil to remain energized. A corrective action for PIP
report 0-097-2983 again specified a review of the X and Y-relays
to determine if the Y-timer should be replaced. The licensee's
due date for this action was March 15, 1998. An augmented
inspection team investigated the June event and documented
findings in Inspection Report 50-269.270.287/97-11.
The inspection team found another PIP report (0-097-2362) which
documented the recommendations to address the failure of the KHU-1
field flashing breaker in June 1997. This failure was a separate
failure from the Y-timer failure documented in PIP report
0-097-1927, but did involve a Westinghouse breaker. PIP report
0-097-2362 recommended that all Keowee Westinghouse Model DB
breakers be replaced, specifying that half be done in 1998 and the
remainder in 1999. Each of these three PIP reports reached the
same cause and eventually specified the same corrective action.
However, two additional failures occurred before the licensee
reached the correct root cause, and the corrective actions have
yet to be implemented.
c. Conclusion
As reflected in the Oconee Nuclear Site Recovery Plan and Safety Review
Group Assessments, the licensee has been focusing on human performance;
however, their newly implemented program to trend and analysis cause and
event code data from Problem Investigation Process reports had yet to
produce auditable results. In conjunction with the licensee's
ngineering Support Program, the Failure Analysis and Trending program
and its associated semi-annual Equipment History Trend Report were
considered adequate tools for assisting Engineering in identifying and
assessing plant equipment performance trends. An in-depth review of two
risk significant systems/components discerned that a considerable length
14
of time passed before arriving at viable solutions for resolving
repetitive problems involving losses of control rod group out limits and
failures of the X/Y anti-pump relays in Keowee Westinghouse Model DB
breakers.
M3
Maintenance Procedures and Documentation
M3.1 Maintenance Procedures/Documentation
a. Inspection Scope (40500)
The inspection team reviewed PIPs related to maintenance activities to
determine if deficiencies were documented and processed in accordance
with NRC regulations and licensee QA program commitments and'procedures.
b. Observations and Findings
The inspection team reviewed PIP 1-098-0493, which was initiated to
document a problem with the use of purge paper during welding activities
on Unit 1. The inspection team noted that the welding was performed in
accordance with maintenance procedure MP/0/A/1810/014, Valves and Piping
- Welded - Removal and Replacement - Class A Through F. Revision 26,
dated September 18, 1997. The inspection team reviewed the activities
for compliance with 10 CFR 50 Appendix B, the Duke Power Company Topical
Report (Duke-i-A), the ONS TS, and procedure NSD 208. The inspection
team made the following observations:
On January 31, 1998, licensee maintenance personnel used purge
paper as damming material to keep condensate water isolated to
allow a weld to be completed on a drain line that was connected to
the Unit 1 pressurizer surge line. After the weld was completed,
attempts to flush the purge paper from the drain line on
February 2, 1998, were unsuccessful because the purge paper failed
to dissolve as intended. The drain line was subsequently cut to
allow retrieval of the purge paper. Failure of the purge paper to
dissolve was due, in part, to the excessive amount of purge paper
that was used. The inspection team noted that a similar industry
event had occurred in the past and was the subject of NRC
Information Notice (IN) 93-63, Improper Use of Soluble Weld Purge
Dam Material, dated August 11, 1993. The IN indicated that the
length of the purge dam material should not be more than one pipe
diameter to ensure that the material dissolved completely.
The inspection team noted that the licensee had reviewed this IN
through their Operating Experience Program (0EP) and provided
corrective actions for the Oconee station via PIP 0-G93-0064 dated
September 8, 1993, and PIP 0-095-0200 dated February 9, 1995.
Both of these PIPs specified that plant specific maintenance
procedures be revised to provide instructions limiting the amount
of purge paper to be used. These PIPs were initiated by .the
licensee's Operating Experience Assessment Section in the General
Office to address IN 93-63. The inspection team noted that the
ONS maintenance personnel provided a response in PIP 0-095-0200
which stated that no specific corrective actions were required as
a result of IN 93-63. Similar events had occurred previously at
15
Oconee and the' respective procedures had been changed to address
the appropriate use of purge paper along with guidelines for
actions to take if there was a deviation in the use of purge
paper.
The maintenance response referenced PIP 3-094-0270.
uring further review of PIP 3-094-0270, the inspection team noted
that one such problem with purge paper not dissol ving after being
used for welding activities had occurred at Oconee Unit 3 in
February 1994. The inspection team reviewed maintenance procedure
MP/0/A/1810/014 and noted that the corrective actions from PIP 3
094-0270 had been incorporated into the procedure. However, the
team noted that procedure MP/0/A/1810/014 did not contain the
specific instructions or precautions from PIP 0-095-0200 or the IN
on limiting the amount of purge paper to be used as damming
material. The inspection team concluded that procedure
MP/0/A/1810/014 was inadequate in that it-did not provide
sufficient limitations on purge paper usage. The team informed
the licensee that the procedure did not meet the requirements of
ONS TS 6.4.1.e and this issue would be identified as Violation
(VIO) 50-269/98-01-02, Maintenance Procedure MP/0/A/1810/014
Provided Inadequate Instructions for the Use of Purge Paper as
Weld Damming Material.
During further review of PIP 1-098-0493, the inspection team noted
that this PIP was initially screened as a less significant event
(LSE) Category 3 PIP by the centralized screening team. This
classification was later changed to a more significant event (MSE)
Category 2 PIP and the licensee was performing a root cause
analysis of the purge paper problem. The root cause analysis had
not been completed at the end of the inspection. The inspection
team noted t at the maintenance representative was not present at
the screening committee meeting when this PIP was initially
reviewed and screened as a Category 3 PIP. The inspection team
considered that this PIP might have been initially classified as
Category 2 instead of Category 3 if the maintenance representative
had been present at the screening meeting to provide the proper
perspective on this problem.
The inspection team noted that PIP 1-098-0493 stated that a
generic applicability review was not required for this PIP. The
inspection team questioned the basis for this statement, given
that purge paper was used at the other Duke Energy Corporation
nuclear plants (Catawba and McGuire). Licensee personnel
indicated that, per procedure NSD 208, the statement regarding no
generic applicability review being required was automatically
entered for all LSE PIPs. Only MSE PIPs required a review for
generic applicability. The inspection team noted that some of the
issues documented as LSE Category 3 PIPs had generic implications.
PIP 1-098-0493 was an example that was initially screened as a LSE
Category 3 PIP which had generic implications applicable to the
other two Duke nuclear plants. The inspection team reviewed the
licensee's Daily OEA Review of Site and Industry Issues for the
period February 2-5, 1998, and observed that PIP 1-098-0493 was
not identified as a significant generic issue, even though the
purge paper problem had occurred more than once at ONS and each
time had resulted in delaying plant startup. The inspection team
16
concluded that not requiring LSE Category 3 PIPs to be reviewed
for generic applicability was a weakness in NSD 208 and the PIP
process. The inspection team discussed this issue with licensee
RG personnel who acknowledged that this weakness had been
recognized, and stated that NSD 208 was being reviewed for
possible resolution of the weakness in the next revision to NSD
208.
c. Conclusion
A violation of Technical Specification 6.4.1.e was identified regarding
an inadequacy in maintenance procedure MP/0/A/1810/014. Specifically,
the procedure did not provide sufficient instructions for limiting the
amount of purge paper to be used as weld damming material. As a result,
the drain line connected to the Unit 1 pressuri-zer surge line became
blocked. The licensee had previous opportunities to correct this
procedural inadequacy from earlier rel ated experiences documented in PIP
reports.
The inspection team concluded that not requiring Less Significant Event
Category 3 PIPs reports to be reviewed for generic applicability was a
weakness in NSD 208 and the problem investigation process.
M7
Quality Assurance in Maintenance Activities
M7.1 Recurring Problems with TS Surveillance Completion and Tracking
a. Inspection Scope (40500)
The inspection team reviewed the licensee's actions to address recurring
problems in the area of TS surveillance requirement tracking and
completion. The inspection team reviewed several PIP reports
documenting missed surveillances or near-misses, associated corrective
actions, and evaluated the licensee's implementation of its surveillance
tracking program for overall effectiveness.
b. Observations and Findings
The team reviewed PIP reports 2-097-4392, 0-098-0233. K-098-0276, and 2
098-0433; all of which documented either missed surveillances or those
whose next due dates would expire before the next available performance
date, requiring temporary TS changes. As described in Section 07.1 of
this report, PIP 2-097-4392 (generated on December 4, 1997) documented a
pending conflict between surveillance due dates and the next available
performance window during the planned Unit 2 refueling outage. The
inspection team concluded that the PIP was inappropriately screened as
category "3-4", given the multitude and complexity of issues surrounding
the identified problem. During the inspection, licensee personnel
indicated that the PIP would be upgraded to Category 3. Several
corrective actions associated with this PIP and others were planned,
including reviews of procedures and the work management system database
to verify that surveillance requirements were properly flagged. The
licensee generated PIP 0-098-0233 on January 15, 1998, after more
examples of pending schedule and TS conflicts were identified. This PIP
identified that there was not a single group that had the responsibility
17
for ensuring that all TS surveillances were reviewed to verify
compliance. The PIP was screened as Action Category 1 (MSE) requiring a
root cause evaluation to be performed to determine the fundamental
causal factor for the recurring problems in this area. As indicated by
the number of PIP reports, recurring problems in the area of TS
surveillance tracking and scheduling have not been resolved through the
corrective action program.
The inspection team reviewed the licensee's current program for
scheduling and tracki-ng completion of TS surveillance activities.
The
station's program for controlling surveillance activities was outlined
in Oconee Nuclear Site Directive 4.1.1, Duke Power Company - Oconee
Nuclear Site - Station Surveillance Program, dated May 8, 1996. The
licensee primarily relied on its station Work Management System (WMS) to
track and schedule these activities, as delineated in the site
directive. TS surveillance requirements were flagged in the WMS to
distinguish them from non-TS work activities. Site Directive 4.1.1
indicated that individual group superintendents and managers were
responsible for implementation and documentation of surveillance testing
assigned to their respective groups as no.ted in Tables 1 - 6 (of the
directive).
The inspection team selected several surveillance requirements listed in
Table 4, "Radiation Protection Responsibility", and checked the WMS to
verify their completion. The team identified a monthly TS surveillance
requirement for radiation instrument checks that had not been updated
since November 1997. A semi-annual requirement to perform a radioactive
sealed source leakage test had not been updated as having been performed
since May 1997. Another procedure listed in Table 4 was listed in WMS
as having been suspended since January 1993. The inspection team was
later provided documentation demonstrating that the surveillance
requirements of concern had been completed, and that the above
identified omissions were merely clerical errors. In the radiation
protection area, surveillances were primarily being tracked using task
sheets contained in Procedure HP/O/B/1000/54. Duke Power Company
Oconee Nuclear Station - Plant Radiological Status, which outlined the
major duties and responsibilities of the radiation protection shifts.
This system appeared to compensate for the tracking errors identified by
the inspection team.
Other work groups, including the Chemistry organization, also relied on
other means (besides the WMS) to effectively track and schedule
surveillance activities. The inspection team considered the methods
available to licensee personnel to track and schedule TS requirements to
be numerous and could potentially be a major contributor to problems the
licensee is having in this area. As mentioned above, the licensee had
identified this concern as a factor in PIP 0-098-0233 for which a root
cause investigation was pending at the end of the inspection.
c. Conclusion
Continuing problems in the area of Technical Specification surveillance
tracking and scheduling have not been resolved through the corrective
action program. The inspection team identified a number of clerical
errors and the licensee has documented problems with the tracking or
18
completion of surveillance activities in a number of problem
investigation process reports. Accordingly, more licensee management
attention is warranted in this area.
III. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1 Failure Analysis and Trending (FAT) Program
a. Inspection Scope (40500)
The inspection team reviewed Equipment History Trend Reports to assess
the adequacy and effectiveness of the licensee's FAT program
implementation.
b. Observations and Findings
The- FAT Program was a tool used by engineering to identify repetitive
equipment failures. The FAT program used equipment modification and
maintenance records to identify problem equipment. It also provided
details and processes for documenting and reviewing equipment failures.
The FAT group generated semi-annual Equipment History Trend Reports .over
an 18-month period from the Work Management System (WMS) based on three
criteria, as listed below; reviewed the report; and sorted the items
needing engineering reviews., forwarding them to the accountable
engineers for review. If necessary, the accountable engineers would
generate a PIP for further evaluation. The FAT group then collected the
engineering responses (complete with engineering evaluation and proposed
problem resolution) and added the engineering review comments to the
trend report.
The inspection team reviewed Oconee Nuclear Station Units 1, 2, and 3
Equipment History Trend Reports for a period from January 1, 1996, to
June 30, 1997. The reports were generated based on the plant equipment
qualification (EQ) or identification numbers. The three criteria used
to sort the equipment failures for review are as follows:
Criteria A
Criteria B
Criteria C
AFFR > .25
Increasing Failure
> 3 corrective W/Os
- W/Os> 10
Rate Over Last 2
Originated During the
Hours >200
Trend Periods
Trend Period
Notes:
AFFR -
Average Failure Frequency Ratio
- W/Os - Numbers of Work Orders
- Hours - Numbers of Hours Spent (Repair)
During the above review period, there were 253 items which exceeded at
least one of the three criteria. The majority of them were from
Criteria C. After reviewing all the items, the FAT group determined
that 114 items were valid and required further engineering review.
19
Eighty-four items were already being addressed by a PIP or were resolved
by other means or programs. Two items required further review per the
FAT group. PIPs 0-97-2949 and 0-97-3323 had been issued for further
evaluation of these two items. The balance was determined by the
licensee to be insignificant for trending.
The inspection team reviewed the FAT group and engineering review
comments and discussed them with cognizant plant personnel. The.
inspection team considered that the trending reports, evaluation, and
resolutions were adequate reflections of equipment conditions.
During the trend report reviews, the team found that Feedwater Pump 1A,
Feedwater Pump lB. and Feedwater Pump 3B had identical responses from
the same engineer. The response stated that some equipment was removed
from the pumps because the equipment was not needed or no longer
required for service. The inspection team reviewed descriptions of
associated work orders for the pumps, but could not find where any
equipment had been removed from the pumps. The FAT group personnel
talked to the accountable engineer and found a minor modification that
had removed the equipment from one of the three pumps. The other two
pumps did not have any equipment removed during the failure analysis
trending period. The FAT group personnel explained, after discussions
with the accountable engineer, that the response actually applied to one
pump and no written engineering responses had been provided for the
other two. The accountable engineer stated that he had previously
informed the FAT group personnel that the trends for the other two pumps
were.insignificant and that no response would be provided. However, the
FAT group personnel erroneously documented the same response for the
other two pumps as they had for the first, because they did not have the
associated required written responses from accountable engineers.
The inspection team considered the FAT group's practices to be poor in
this case because they did not obtain actual written responses from the
accountable engineers to support statements annotated in the trend
report for the other two pumps. The team was concerned that potentially
inadequate failure trending report reviews and responses from
accountable engineers could impact the trending accuracy and the benefit
provided by the failure trending program would be lost. The inspection
team discussed this with FAT group personnel, who agreed that it
was
important to obtain review/evaluation comments for each item from the
accountable engineers and input them appropriately into equipment
failure trend reports. More attention to detail may be warranted in
this area.
c. Conclusion
The Failure Analysis and Trending Program and Equipment History Trend
Reports for the evaluation of equipment performance were adequate.
However, the inspection team identified examples of incorrect
documentation of engineering responses regarding failure analysis of
certain equipment. Accordingly, more attention to detail is warranted
in compiling engineering review comments in this area.
20
E7
Quality Assurance in
Engineering Activities
E7.1 Review of Licensee's UFSAR Review Project Phase 1
a. Inspection Scope (40500)
The inspection team reviewed the licensee's activities for the Updated
Final Safety Analysis Report (UFSAR) Review Project, Phase 1, to verify
the adequacy of the licensee's review and to determine if identified
deficiencies were being captured in the licensee's correctivelaction
program.
b. Observations and Findings
The licensee voluntarily performed the UFSAR Review Project in order to
identify and correct any inadequacy and inconsistency between the UFSAR,
the current plant design, and plant design documents. This activity was
being conducted.in accordance with the licensee's response to Federal
Register 61 FR54461 on NRC NUREG-1600, "Policy and Procedure for
Enforcement Actions Departures From FSAR," published on October 18,
1996. The summary in the Federal Re ister on this subject stated that
the Nuclear Regulatory Commission (NRC) is amending its general
statement of Policy and Procedure for Enforcement Actions (Enforcement
Policy) to address issues associated with departures from the Final
Safety Analysis Report (FSAR).
The main purpose of this Federal Register was to grant a two-year
eriod, starting from October 18. 1996, to encourage reactor operation
icensees to conduct a detailed review and make amendments to their FSAR
or UFSAR to accurately reflect the plant design and operation conditions
and comply with the licenses.
The licensee submitted a response dated June 16, 1997, to the NRC. The
submittal included scope, methods of verification for accuracy and
completeness, resolution of discrepancies to be found, and schedule for
review and implementation of the incorporation or modification. A
supplemental licensee response was submitted on January 4, 1998,
regarding the latest schedule for its planned completion of the review.
The team reviewed Oconee Nuclear Station UFSAR Review Project Phase 1,
UFSAR Chapter 5 Review, dated November 6, 1997. Chapter 5 was the only
chapter reviewed during Phase 1 in order to determine the feasibility of
the schedule; evaluate time and resource expenditures: and determine
thoroughness, accuracy, and completeness for lessons learned to be
applied during future reviews on other chapters. The review was
performed by Duke Engineering and Service (DE&S), Atlanta, Georgia, a
subsidiary of Duke Energy Corp. The Phase 1 documentation review
included scope, methodology, evaluation, problem areas/lessons learned,
and Appendix A to D. These actions met the response outlines submitted
by the licensee to the NRC. The processes used for the licensee's
review were as follows:
Divided statements, tables, or figures contained in the UFSAR
Chapter into a single sentence, set of sentences, a paragraph, set
of paragraphs, a table, or a figure; as convenient or if related;
into "review units."
21
Assigned an identification number called "review unit number" for
each unit.
Verified those review units with the applicable documents such as
calculations, drawings, procedures, and specifications including
Technical Specification.
Resolved the discrepancies through the corrective action program
by generating PIPs to document and track either closing out the
discrepancies or for further review to resolve the discrepancies.
Revised the UFSAR or other documents.
The inspection team concentrated on the licensee's methods used to
verify the accuracy, resolution of the discrepancies, and proper
documentation of the closed items or items for further review. Overall,
-
-the
team considered that the review performed by the licensee was good.
The inspection team found in some cases that the licensee used the.
origina] FSAR, NRC Safety Evaluation Report (SER), or various
correspondence between the licensee and the NRC as a method for
verification of the accuracy of the UFSAR statements, without.comparing
the review units to actual design documents, calculations, or current
plant configuration. After discussions with the inspection team, the
licensee recognized that the contents in the original FSAR itself may
not be accurate, and that the SER and letters from the NRC normally
reflected what the licensee submitted in its original FSAR and other
correspondence. The licensee recognized that in some cases, comparing
the UFSAR to statements contained in these documents may not provide for
a thorough review and indicated that it would revise the methods used to
verify the accuracy of the UFSAR by reviewing current design
documentation, calculations, procedures, or technical specifications as
indicated in its response to the Federal Register notice.
The inspection team found 13 discrepancies not identified by the
licensee's engineers during its review of Phase 1 of the UFSAR review.
The licensee either revised existing PIPs 97-3723 and 97-3724, or
generated new PIP 98-0561 to incorporate the discrepancies found by the
inspection team.
During the Phase 1 review, the inspection team found that review item
05.T5-2 shown on the evaluation summary was for Table 5-2, "Transient
Cycles for RCS [Reactor Coolant System] Components Except Pressurizer
Surge Line."
The transient cycles were stated in Specification No. 18
1130828-04, "Reactor Coolant System for Oconee Units 1, 2, and 3."
Babcock and Wilcox (B&W), the plant's nuclear steam supply system
vendor, originated this specification during the plant s initial fuel
operating cycle and issued Revision 4 to the licensee on February 22,
1991, to delete transient number 13 and add transient number 23 to the
specification. The vendor listed the transient deletion and addition as
an open item for the licensee to include transient number 23 in fatigue
analyses for impacts of the specification on licensees. However,
current licensee calculations OSC-6647 and 1815 were not updated to
include transient number 23 in their fatigue analyses. Transient number
22
23 was for temperature changes on the RCS during startup. Transient
number 23 was not considered in the original specification. The
licensee was requested to evaluate transient number 23 and update the
related calculations. Pending the licensee's actions and further review
by the NRC, this item is identified as Inspector Followup Item (IFI) 50
269,270,287/98-01-03, Reactor Coolant System Transient Number 23
Resolution.
c. Conclusion
The inspection team concluded that the licensee conducted good reviews
during Phase 1 of the voluntary UFSAR Review Project. The licensee
appropriately captured the majority of identified UFSAR discrepancies
into its corrective action program and added those that were identified
by the inspection team. One inspector followup item was identified for
further evaluation of startup thermal transient number 23 associated
with the reactor coolant system, and incorporation of the related
- -
calculations into fatigue analyses.
E7.2 Quality Assurance Audits and'Assessments
a. Inspection Scope (40500)
The inspection team reviewed the licensee's high pressure injection
(HPI)/low pressure (LPI) self-initiated technical audit (SITA) review
and the HPI reliability study to determine whether these activities were
performed in accordance with the licensee's quality assurance (QA)
program commitments and procedures. The findings from these assessments
were reviewed to determine whether or not they were appropriately
captured by the licensee's corrective action program.
b. Observations and Findings
The inspection team reviewed audit SA-97-10(ON)(SITA)(HPI/LPI), Self
Initiated Technical Audit High Pressure Injection and Low Pressure
Injection. This SITA was performed during the period from November 10,
1997. through December 11, 1997.. The SITA was performed by the
Regulatory Audit Group of the Nuclear Assessment and Issues Division in
the General Office. The purpose of this SITA was to assess the
operational readiness and functionality of the HPI and LPI systems,
including interconnecting systems. The inspection team noted that the
SITA identified 41 findings and 7.recommendations. The audit findings
were documented through the ONS PIP process. Some of the SITA findings
indicated that the corrective action program, including operating
experience, was ineffective in preventing recurrence of several
equipment and programmatic issues. The SITA concluded that, although
numerous findings were identified, the HPI and LPI systems were operated
consistent with their design bases and were capable of performing their
- safety functions. The inspection team determined that the HPI/LPI SITA
was performed in accordance with licensee procedures NSD 208 and NSD
607.
The HPI system 'reliability study was completed in December 1997
following several system operational issues in 1997. The study was
performed to incorporate new insights regarding the system's operation
23
(including lessons learned from previous events, operating experience
program, and revised failure statistics) into a probabilistic risk
assessment model.
The study was comprehensive and generated three
recommendations for plant consideration. All three were documented in
PIP 0-097-4546 with corrective actions assigned for each. Corrective
action number 1, to continue monitoring the system's performance against
goals for unavailability and reliability was actively performed under
the licensee's system health and Maintenance Rule programs; therefore,
no further actions were required for that item. The team concluded that
the recommendations from the reliability study were appropriately
captured in the licensee's corrective action program.
c. Conclusion
The SITA and the HPI System Reliability Study were thorough and detailed
efforts that effectively identified equipment and programmatic issues,
as well as provided pertinent recommendations. These issues and
recommendations were appropriately captured in the licensee's corrective
action program.
E7.3 Operating Experience Program
a. Inspection Scope (40500)
The inspection team reviewed the licensee's operating experience program
(OEP) in order to determine if the program was being implemented in
accordance with licensee commitments and procedures.
b. Observations and Findings
The licensee's OEP is described in procedure NSD 204. Operating
Experience Program Description. The purpose of the program is to ensure
that operating experience information is effectively collected:
communicated to those areas affected by the information: evaluated for
applicability toDuke Nuclear units with the resulting corrective
actions tracked to completion: and considered in problem solving and/or
preventive measures. The Operating Experience Assessment (OEA) Section
of the Nuclear Assessments and Issues Division in the General Office was
responsible for the receipt, evaluation, and resolution of in-house and
industry OEP documents.
The inspection team reviewed selected NRC Generic Letters, Bulletins.
Information Notices (IN), and other industry OEP documents. The team
verified that the documents were included in the licensee's operating
experience data base (OEDB) and the items had either been evaluated or
were assigned to OEA Section personnel for evaluation. The inspection
team also verified that in-house OEP documents such as PIPs were
included in the OEDB and were being tracked. The team verified that
issues were documented in PIPs in accordance with NSD 208 and included
in the corrective action program. The inspection team noted that NRC IN 93-63 and the related PIPs (discussed in Section M3.1 of this inspection
report) were included in the OEDB. However, the inspection team noted
in Section M3.1. not all of the corrective actions identified in PIP
reports through the operating experience program reviews were being
implemented by the Oconee site. The inspection team also reviewed the
24
licensee's Daily Operating Experience Significant Items Report for
selected dates in January 1998 and February 1998. This report was part
of the Daily OEA Review of Site and Industry Issues. As discussed in
Section M3.1 of this inspection report, the inspection team observed
that PIP 1-098-0493 was not identified as a significant generic issue in
the Daily Operating Experience Significant Items Report that was
prepared by the OEA Section, even though the purge paper problem had
occurred more than once at ONS and each time had del ayed plant startup:
and purge paper.was also used at the other two Duke Power nuclear
plants. The ihspection team also reviewed assessments SA-97-30(ON)(SRG)
and SA-97-62(ALL)(PA) that were performed to review OEP activities.
Findings from these assessments were'documented in PIPs in accordance
with NSD 208.
c. Conclusion
The inspection team concluded that operating experience information
reviewed by the team was being processed in accordance with the
licensee's procedures. However, as indicated by the violation
identified in Section M3.1 of this inspection report, not all of the
corrective actions identified through the operating experience program
reviews were being implemented by the Oconee site. Findings from
assessments of the operating experience program were documented and
tracked in the licensee's corrective action program.
V. Management Meetings
X1
Exit Meeting Summary
The inspector team presented the inspection results to members of
licensee management at the conclusion of the inspection on February 5,
1998.. The licensee acknowledged the findings presented.
The inspection team asked the licensee whether any materials examined
during the inspection should be considered proprietary. No proprietary
information was identified.
Partial List of Persons Contacted
Licensee
R. Bond. Safety Review Group
E. Burchfield,.Regulatory Compliance Manager
T. Coutu, Scheduling Manager
D. Coyle. Mechanical Systems Engineering Manager
T. Curtis, Operations Superintendent
B. Dobson, Mechanical/Civil Engineering Manager
W. Foster. Safety Assurance Manager
R. Henderson, System Engineer
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Engineering Manager
W. McCollum, Vice President, Oconee Site
M. Nazar, Manager of Engineering
A. Park, System Engineer
25
B. Peele, Station Manager
E. Price, Licensing Engineer
J. Smith, Regulatory Compliance
J. Twiggs, Manager, Radiation Protection
Other licensee employees contacted during the inspection included technicians,
maintenance personnel, and administrative personnel.
NRC
C. Ogle
M. Scott
INSPECTION PROCEDURES USED
Effectiveness of Licensee Controls In Identifying and Preventing
Problems
IP 71707 -
Plant Operations
Items Opened, Closed, and Discussed
Opened
50-269,270,287/98-01-01 URI
NSRB Review of 10 CFR 50.59 Safety
Evaluations (Section 07.4)
50-269/98-01-02
Maintenance Procedure MP/0/A/1810/014
Provided Inadequate Instructions for the
Use of Purge Paper as Weld Damming
Material (Section M3.1)
50-269,270.287/98-01-03 IFI
Resolution of Reactor Coolant System
Transient Number 23 (Section E7.1)
LIST OF ACRONYMS
CFR
Code of Federal Regulations
Condenser Circulating Water
Control Rod Drive Mechanism
Diesel Generator "A"
DGB
Diesel Generator "B"
Engineering Directives Manual
Final Safety Analysis Report
Heating Ventilation and Air Conditioning
Integrated Control System
IFI
Inspector Followup Item
Institute for Nuclear Power Operations
IR
Inspection Report
KHP
Keowee Hydro-electric Plant
LSE
Less Significant Events
MEPR
Major Equipment Problem Resolution
MM
Minor Modification
26
Maintenance Preventable Functional Failure
MSE
More Si gnificant Events
NRC
Nuclear Regulatory Commission
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
Nuclear Safety Review Board
Oconee Nuclear Station
Problem Deficiency
Public Document Room
Problem Investigation Process
Safety Evaluation Report
SITA
Self-Initiated Technical Audit
SRG
Safety Review Grou
SSF
Safe Shutdown Facility
TEPR
Top Equipment Problem Resolution
Updated Final Safety Analysis Report
Unresolved Item
Violation
Work Request