ML15224A594
| ML15224A594 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/26/1989 |
| From: | Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A592 | List: |
| References | |
| 50-269-89-31, 50-270-89-31, 50-287-89-31, NUDOCS 8911130289 | |
| Download: ML15224A594 (13) | |
See also: IR 05000269/1989031
Text
V p
REGU4
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
9
ATLANTA, GEORGIA 30323
Report Nos:
50-269/89-31. 50-270/89-31. 50-287/89-31
Licensee: Duke Power Company
422 South Church Street
Charlotte. N.C. 28242
Docket Nos.:
50-269. 50-270. 50-287
License Nos.
.Facility Name:
Oconee Nuclear Station
Inspection Conducted:
September 17 - October 10. 1989
Inspectors
4
97
,
P. H. Skinner. Sen)or Resident Inspector
Mte Signed
L. D. Wert, Reside't Inspector
Dte igned
Approved by: ______________________
M. B. Shytrlock. Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine,
announced inspection involved resident inspection
on-site in the areas of operations. surveillance testinc. maintenance
activities. Quality Assurance observations, and inspection of open
items.
Results:
Two violations were identified during this period.
One violation
concerned Containment Penetration Testing (paragraph 3b.)
and is
under consideration for escalated enforcement.
The other violation
involved a failure to meet the requirements of TS 3.7 (Auxiliary
Electrical
Systems)
during maintenance or testing of certain
electrical switchyard components (paragraph 4b.).
Additionally, the inspectors identified a weakness on the part of the
Quality Assurance
(QA)
section.
Several instances in which QA
personnel had demonstrated a lack of sufficient attention to detail
had been noted (paragraph 5).
8911130289 891027
ADOCK 05000269
PNU
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- M. Tuckman. Station Manager
C. Boyd, Site Design Engineer Representative
- T. Curtis. Compliance Manager
- J. Davis. Technical Services Superintendent
- D. Deatherage. Operations Support Manager
W. Foster. Maintenance Superintendent
- D. Hubbard. Performance Enoineer
- E. LeGette. Assistant Engineer Compliance
H. Lowery. Chairman, Oconee Safety Review Group
- P. Morgan. Oconee Quality Assurance Director
- G. Rothenberger. Integrated Scheduling Superintendent
R. Sweigart. Operations Superintendent
- J. Warren. Oconee Quality Control Supervisor
Other licensee employees contacted included technicians.
operators.
mechanics. security force members, and staff engineers.
NRC Resident Inspectors:
P.H. Skinner
- L.D. Wert
- Attended exit interview.
2. Plant Operations (71707)
The inspectors reviewed plant operations throughout the reporting period
to
verify conformance with regulatory
requirements. Technical
Specifications (TS).
and administrative controls.
Control room logs.
shift turnover records, and equipment removal and restoration records were
reviewed routinely.
Discussions were conducted with plant operations.
maintenance. chemistry. health physics. instrument and electrical (I&E).
and performance personnel.
Activities within the control rooms were monitored on an almost daily
basis.
Inspections were conducted on both day and night shifts, during
week days and on weekends. Some inspections were made during shift change
in order to evaluate shift turnover performance.
Actions observed were
conducted as required by the Licensee's Administrative Procedures.
The
complement of licensed personnel on each shift inspected met or exceeded
the requirements of TS.
Operators were responsive to plant annunciator
alarms and were cognizant of plant conditions.
2
Plant tours were taken throughout the reporting period on a routine
basis. The areas toured included the following:
Turbine Building
Auxiliary Building
Units 1. 2 and 3 Electrical Equipment Rooms
Units 1. 2 and 3 Cable Spreading Rooms
Keowee Hydro Station
Station Yard Zone .Within the Protected Area
Standby Shutdown Facility
Units 1/2 Spent Fuel Pool Room
Unit 1 Reactor Building
During the plant tours. ongoing activities. housekeepir.
security.
equipment status, and radiation control practices were observed.
Unit 1 -
Unit 1 began the report period operating at 100% power.
On
September 19. 1989 power was reduced to 74% due to an oil
leak on the 122 Reactor Coolant Pump (PCP).
The pump was
secured and the unit continued operations with 3 RCPs until
September 21 when unit was shutdown to repair the oil leak.
On September 23 the unit was taken to cold shutdown to
repair a leak on the pressurizer heater bundle
(see
paragraph 4c).
On October 6. 1989. after the pressurizer
leak was repaired and containment isolation valve 1CS-5 was
successfully repaired,
the unit was returned to normal
operation. The unit reached 100% on October 8. 1989. and
continued there through the rest of this report period.
Unit 2 -
Unit 2 operated at 100% power level the entire report
period.
A small steam generator tube leak has been
detected. Condenser off Gas Radiation Monitor readings are
being trended closely and the leak appears to be stable at
approximately .01 gpm.
Unit 3 -
Unit 3 operated at 100% power for the entire report
period.
3. Surveillance Testing (61726)
a. Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy.
The completed tests reviewed
were examined for necessary test prerequisites.
instructions.
acceptance criteria, technical content, authorization to begin work.
data collection. independent verification where required. handling of
deficiencies noted,
and review of completed work.
The tests
witnessed, in whole or in part, were inspected to determine that
approved procedures were available. test equipment was calibrated.
prerequisites were met, tests were conducted according to procedure,
test results were acceptable and systems restoration was completed.
3
b.
Failure To Test Containment Penetrations
On September 22. at 4:00 p.m.
the licensee identified that the
surveillance testing required by TS 4.4.1. Containment Leakaae Test.
for containment penetration 53 ("A" Core Flood Tank nitrogen fill
line) had not been performed for all three units.
discussed in this report are shown on figure 6.2-6 of the Final
Safety Analysis Report (FSAR).
The piping on this penetration is one
inch schedule 80S stainless steel with a design pressure rating of
700 psig.
It is used during normal operation to add nitrogen from
the high pressure nitrogen system. as necessary, to pressurize the
nitrogen volume of the A Core Flood Tank to 600 + 25 psig. The test
of this penetration is required to be accomplished as part of the
integrated leak rate test (ILRT). per Licensee procedures Series PT
1.2.3/A/150/03.A.B.&C; for type A test as specified in 10 CFP 50.
Appendix J. This penetration is required to be vented to containment
atmosphere during the ILPT.
During a review of procedures associated with containment leak
testing the licensee identified an improperly positioned valve.
This
valve has. to be open to pressurize the outside containment isolation
valves associated with this penetration 53. This valve has been shut
on all units during all ILPT testing since 1982.
In 1982 the valve
was open for a Unit 3 test. but the procedure was subsequently
changed to require the valve to be shut. The reason for this change
has not been identified and is still under investigation by the
licensee.
This action prevented the proper testing of this
penetration and thus the penetration was technically inoperable.
The licensee requested that, since the penetrations required an ILRT
to be performed and had not been accomplished, that discretionary
enforcement be granted by NRC. The licensee provided the inspector a
verbal Justification for Continued Operation (JCO)
while a written
document was being prepared.
The inspector discussed this problem
with Regional and NRP management in conjunction with the associated
request. A review of the guidance provided in Generic Letter 87-09
identified that a plant shutdown due to a missed surveillance would
not be necessary.
Since the safety significance of this item was
minimal. the decision was made to allow the licensee to continue to
operate Units 2 and 3 (Unit 1 was already in a cold shutdown
condition due to a forced outage) until an in-depth evaluation could
be performed by the NPC. Discretionary enforcement was not granted.
The licensee modified penetration 53 on unit 1 to allow for local
leak rate testing (LLRT)
which is a Type C test per 10 CFP 50.
Appendix U. This modification will be completed on Units 2 and 3 at
the next available outage.
However, this test does not meet the TS
required test and the licensee requested an emergency TS amendment
4
on September 29.
1989.
This request would allow the return to
operation of Unit 1 and continue operation of Units 2 and 3.
One of
the letters of September 29 also requested a temporary waiver of
compliance for all three units until the attached proposed TS
amendment could be approved. On September 29, 1989. NRP granted the
licensee a temporary waiver of compliance associated with TS 3.6.3.c
and Table 4.4.1 to allow continued operation of Unit 2 and 3 and to
restart Unit 1.
On October 3. after a review by cognizant licensee personnel of the
data base associated with each containment penetration identified in
TS Table 4.4-1 that does not require a local leak test, and is
required to be vented to containment atmosphere during ILPT. the
station manager notified the inspectors that the following additional
penetrations were technically inoperable due to inadequate testing:
Unit 1 -
Penetration 39 -
valves CA-29 and N-131 had been cutout
and replaced
Penetration 53 - CF-42 had been refurbished
Penetration 59 - the motor operators on CF-3 and CF-4 had
been refurbished
Unit 2 -
Penetration 39 - valve CF-44 had been replaced with an
improved design valve, but no subsequent testing had been
performed.
The inspectors were informed by the licensee
late on October 2. 1989 of this particular finding.
After
discussions with NRR and regional management it was decided
it
was reasonable to allow continued operation of Unit 2
provided the licensee's compensatory actions taken or unit
1 for penetration 53 would be applied to this penetration.
Penetration 53 - Valve CF-42 had been replaced
Penetration 56 - valve SF-81 had been repaired
Penetration 39 - valve N-131 was replaced
Unit 3 -
Penetration 39 - valve CF-44 had been replaced with an
improved design valve
Penetration 59 - motor operators for CF-3 and CF-4 had been
refurbished
The licensee identified the following actions that had been taken or
were proposed for these problems:
On Unit 1. since the plant was in shutdown. a LLPT was performed
with satisfactory reSu!ts on penetrations 53 and 59
The outside isolation valves in penetration 39 were leak rate
tested using a modified LLRT to quantify leakage
Penetration 39 will be modified during the next refueling outage
to allow LLRT as was recently completed on unit 1 penetration 53
and discussed in their letter dated October 4. 1989
On Unit 2 the licensee will modify penetration 39 and
penetration 53 as discussed above.
Penetration 56 has been
isolated as required by TS 3.6.3.c
On Unit 3. the licensee will modify penetration 39 and 53 as
discussed above.
In addition. penetration 59 has been isolated
as required by TS 3.6.3.c. The licensee has indicated that this
penetration. which is used to sample the Core Flood Tanks should
not require use prior to the upcoming outage scheduled to begin
November 8. 1989
On Units 2 and 3 the licensee will do a modified LLRT to
quantify any leakage on penetrations 39 and 53.
To allow
continued operation of Units 2 and 3. which would require the
periodic use of penetration 39.
the licensee requested a
temporary waiver of compliance on. October 4.1989 to allow the
use of this penetration pending approval of the emergency TS
amendment.
This temporary waiver of compliance was approved by
NRR on October 5.1989.
The deficiencies identified associated with penetrations 39 and 59
were associated with maintenance and modifications.
Additionally,
maintenance and modifications were performed on some of the valves
associated with penetration 39 and 53 that were not appropriately
tested. TS 4.4.1.3 states that any major modification or replacement
of components affecting Peactor Building integrity shall be followed
by either an integrated leak rate test or a local leak rate test as
appropriate.
Oconee Nuclear Station Directive (SD) 3.2.1. Work Request. dated
2/28/89 Section 6.2 Retest. requires identification of specific
functional testing to be included on the work request. To identify
the specific functional
testing this procedure contains two
attachments (attachments #5 and #6) identifying on a component basis.
the type of test that should be conducted.
A review of these
attachments identified the following problems:
-
Some valves associated with containment penetrations are
not specified in these attachments such as check valves
N-131, N-129. CF-41 and CF-47
6
-
Several valves are specified to be tested in conjunction
with the ILRT. but no guidance is provided if the ILRT is
not scheduled for several years.
This would result in a
failure to test the valve following maintenance as required
by TS.
Several valves are identified to be tested but are not
challanged by the ILRT since the ILPT may only challange an
inside valve. This could allow maintenance to be performed
on an outside valve without the valve being tested if the
inside valve was aligned to be challanged.
The lack of information on some containment penetrations and the lack
of guidance contained in the SD have resulted in numerous work
request on containment penetrations having been performed without a
subsequent retest. This retest would have assured that the integrity
of the penetration was still maintained as required by TS 4.4.1.3.
As discussed above, the failure to adequately test penetration 53 on
all units was due to an inadequate procedure.
TS 4.4.1 requires the
frequency and type of testing necessary to assure containment
integrity. Due to this error in the procedure. proper penetration 53
testing has not been preformed as required by TS 4.4.1.
This error.
in conjunction with the deficiencies identified in SD 3.2.1, resulted
in a failure to perform the requirements associated with TS 4.4.1
(including 4.4.1.3).
These problems indicate a breakdown in the
licensEes program associated with containment penetration integrity
testing following maintenance or modifications and a significant lack
of attention to detail regarding these requirements.
This item is
identified as
an apparent Violation 50-269.270.287/89-31-01:
inadeouate Program
to Control
Containment Penetration Testing
Following Maintenance and/or Modifications.
This violation is under
consideration for escalated enforcement and will be subsequently
addressed in separate correspondence.
4. Maintenance Activities (62703)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures in use adequately described
work that was rot within the skill of the trade.
Activities.
procedures
and work requests were examined to verify proper
authorization to begin work.
provisions for fire. cleanliness, and
exposure control,
proper return of equipment to service. and that
limiting conditions for operation were met.
7
Maintenance reviewed and witnessed in whole or in part:
WR 24008C Investigate/Repair 2B Hot Leg Temperature
Channel One
WR 24171C Replace Torque Switch on 1CS-5
b. Keowee Overhead Emergency Power Path Inoperability Due To Improper
Operation Of The External Grid Trouble Protective System (EGTPS)
Oconee utilizes the two unit Keowee Hydro Station as its emergency
power source.
On a loss of power from normal generator output and
the 230KV switchyard.
the Keowee units supply power through two
separate paths.
One path is an underground feeder via transformer
CT-4 to the 4160V standby buses. The other power path is via a 230KV
line to the switchyard through the safety related yellow bus to each
unit's startup transformer. On an emergency start signal both Keowee
hydro units are started. The underground circuit is energized as the
hydro unit connected to it starts. The Keowee unit not connected to
the underground path runs on standby and connects to the 230KV yellow
bus only after that bus is isolated from the remainder of the
In the case of a loss of the external grid or a
switchyard casualty. both Keowees are started automatically and the
underground circuit is again energized as the hydro unit connected to
it starts.
The other hydro unit is connected automatically to the
230KV switchyare yellow bus by its generator output breaker (ACB-1 or
2) closing after the yellow bus is isolated from the remainder of the
grid by automatic tripping of specific switchyard PCBs.
The EGTPS monitors the voltage and frequency on the two 230KV
switchyard buses (designated red and yellow).
If a degraded voltage
or frequency is detected the EGTPS will automatically isolate the
swit.chyard. start both Keowee units and allow closure of four PCBs to
connect the overhead
power
path to the three unit startup
transformers.
The switchyard isolation confirmed portion of the
EGTPS specifically provides a permissive signal to the closing
circuits of Keowee generator output breakers (ACB-1 and ACB-2) which
connect the hydro unit to the overhead path.
On September 21.
1989.
the licensee identified that the Oconee
electrical distribution system had.
in the past, been placed in a
condition which resulted in inoperability of the Keowee Hydro Station
overhead power path without the appropriate TS limiting condition for
operation (LCO) being entered. This condition was caused by improper
operation of the "Switchyard Isolation Confirmed" portion of the
EGTPS during maintenance on certain 230KV switchyard Power Circuit
Breakers (PCPs). This "Switchyard Isolation Confirmed" circuitry was
not being aligned to send the close permissive signal to the Keowee
8
output breaker.
During maintenance activities the PCB is removed
from service and control power is removed.
The switchyard isolate
circuity relies on auxiliary switch contacts in the breaker which may
be removed from the circuit when the breaker is removed from service.
This condition would rendered the overhead power path from Keowee
inoperable during those maintenance periods.
TS 3.7.2(a) permits one of the two emergency power paths to be
inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for test or maintenance, provided the
alternate path is verified operable within one hour of the loss and
every eight hours thereafter.
Investigation by the inspectors
indicated that this 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO has been exceeded on several
occasions in the past. notably by startup transformer work during
unit refueling outages.
When a unit is less than 200 degrees F, most
of TS 3.7 is not applicable
to the unit in the outage condition, but
the condition that had been established to perform maintenance nr
certain specific PCBs affected the other two units power path.
Regular preventive maintenance of the involved switchyard breakers is
scheduled for 5 year intervals and typically takes four days to
complete. It was identified that during this maintenance the EGTPS
would be inoperable only for a specific conditions (for example if
the breaker was required to be open to isolate the switchyard and the
workers closed it
during the maintenance).
While it
is not
impossible,
it
is unlikely that the underground circuit was
inoperable at the same time as the overhead was inadvertently removed
from service.
Transformer CT-4 work, which is the primary cause of
underground path inoperability for any significant length of time. is
normally scheduled during Unit I refueling outages and prior to this
work, the backup emergency power supply (a 100KV line via transformer
CT-5 to the standby buses) is placed in service.
However. LEP
269/89-10 documented that this path did not meet the
recuirements
for protective relaying necessary to be used as an offsite power
source.
The TS required testinc of the alternate power path was not
performed.
The inspectors have been closely following the licensee's Self
Initiated Technical Audit (SITA) and Design Bases Documentation (DBD)
Analysis programs concerning the electrical distribution system and
the Emergency Power Switching Logic (EPSL).
Recently. as a result of
several problems discovered during the SITA and .DBD efforts the
licensee submitted a proposal to revise TS 3.7.
During review of
this submittal and followup on Keowee
power path concerns the
inspectors had questioned the licensee about EGTPS and the switchyard
isolation system in regards to operability of the overhead power
path.
The inspectors had noted instances where a channel of EGTPS
had been removed from service and no TS LCO was entered (EGTPS is
currently not addressed by TS 3.7).
The inspectors discussed with
several operators as well as management the relationship between the
9
"Switchyard Isolation System"
and operability of the overhead
emergency power path. The licensee is currently considering whether
EGTPS/Switchyard Isolation System should be specifically addressed in
TS.
The inspectors had discussed that proper operation of the
isolation system is required to cause closure of the Keowee units
output breaker to the overhead path but were not aware that the
Transmissions department was affecting this system during PCB work.
This aspect was discovered by the licensee during followup of
operators questions concerning a related Keowee issue.
Comments by
the operators involved indicated that the recent training sessions on
the EPSL (an
NRC commitment)
had heightened their sensitivity and
contributed to the discovery. A SITA has just been completed on the
Oconee Emergency Power Distribution System including EPSL.
This
problem was not identified during this audit. apparently because the
230KV switchgear issues will be covered in a later DBD effort.
During followup investigation. the inspectors were informed that some
personnel in the Transmissions department were aware that this
problem could occur.
The Nuclear Station Modification (NSM)
procedure utilized to replace the switchyard PCBs with an upgraded
design contained proper procedures to prevent EGTPS inoperability.
(The
EGTPS has a test switch which can be utilized to bypass a
breakers signal to the switchyard isolation circuitry and effectively
input a breaker open signal.)
Apparently some Transmissions
personnel assumed that operations personnel were aware of this
situation and were taking the necessary actions when Transmissions
requested to work on a PCB.
The licensee immediately initiated corrective actions to insure that
the "Switchyard Isolated Circuity" will be able to perform its
intended function.
The actions included instructions to operating
personnel .
training, changes to Transmissions procedures
and
installing caution tags on all switchyard isolate PCBs requiring
Shift Supervisor or Switchyard Coordinator notification prior to
work. Operations is writing specific instructions for the removal and
restoration of switchyard isolate PCB's which will be part of the
Auxiliary Electrical System Removal and Restoration Procedure. The
inoperability of the Keowee Overhead Path without entry into the
appropriate TS LCO is identified as Violation 269.270,287/89-31-02:
Keowee Overhead Emergency Power Path Inoperability Due to Improper
Operation of the Switchyard Isolation System.
The safety
significance of this violation is reduced due to the low probability
of a Loss of Coolant Accident/Loss of Offsite Power (LOCA/LOOP)
occurring during the time periods when the switchyard isolation
system was inoperable along with a simultaneous single failure of the
alternate emergency (underground) power path.
However. the lack of
knowledge of the operations staff of this system continues to be a
concern to the inspectors.
10
c.
Pressurizer Heater Leak On Unit I
On September 21. the unit was removed from service to repair an oil
leak on the 182 RCP motor.
During this shutdown a small steam leak
was identified on a pressurizer heater bundle which required cooldown
and draining of the pressurizer.
Following cooldown maintenance
personnel removed the hold down fasteners from the. cover plate on the
heater bundle, installed guide studs and moved the cover plate back
to expose the seal weld area (diaphragm to pressurizer)
at the
penetration into the pressurizer.
No visual indication of the leak
could be observed. A non-destructive examination (NDE) was performed
on the entire seal area.
No indications were identified. A second
NDE was performed with the same results. The engineering group then
decided to remove a 90 degree section of the seal that was the most
probable leak area,
performing NDE testing as each layer of weld
material was removed.
This was accomplished but this did not
identify any flaw. The licensee made a decision to reweld the seal
area and continue return of the unit to operation.
On September 30.
the pressurizer was filled and pressurized to 30 psig with nitrogen.
Visual inspection of the heater bundle area indicated a small leak at
the seal weld again. The pressure was reduced to atmospheric and the
pressurizer drained.
The flaw was identified in the heat effected
area of the weld on the diaphragm plate. The flaw was ground out and
weld repair made.
The inspectors discussed this process with a
Region II specialist in the NDE area.
The material used for this
This problem was discussed in detail
with Babcock and Wilcox and DPC Design Engineering personnel during
the repair process.
On October 2. the pressurizer was refilled and
no leakage was observed.
The licensee also monitored for leakage
during the subsequent heat up and repressurization activities, and no
leakage was observed.
5. Observaticrs Concerning Quality Assurance Activities
During the past several report periods the inspectors have noted several
instances in which performance by Quality Assurance
(QA)
personnel
indicates a lack of attention to detail.
Examples include;
During observation of hydrostatic testing of a portion of the 2B Low
Pressure Injection (LPI) line (WR 051328. April 1989). the inspector
noted that corrected test pressure
(CTP)
had been calculated
incorrectly. A value of 644 psi was entered in the procedure as CTP,
the correct value was 639 psi.
An error had been made when applying
the correction for elevation differences in the line being tested.
This error was not detected by QA despite a required review of the
calculation.
K.
11
-
During observation of torau
switch replacement
on containment
isolation valve 1CS-5
(WP 24171C.
September
29.
1989)
another
discrepancy was noted.
The inspector determined, after questioning
the QA technician specifically tasked with verification of the torque
switch settings. that the technician was not sure how to identify the
closing setting from the.
opening setting in this particular
instance.
-
In late June, 1989. the inspectors toured the Unit 2 Peactor Building
just prior to startup following a refueling outage.
The inspectors
noted extraneous foreign material in the emergency sump and several
Temporary Modifications still installed.
The inspectors then
reviewed the QA "Housekeeping Verification Report" of June 26. 1989
(documented the results of the QA inspecticn of the RB)
which was
performed prior to the inspectors tour.
None of the discrepancies
noted by the inspectors were recorded on this document.
Since QA is being relied upon as part of the overall process to ensure
that maintenance and testing of safety related components is being
properly performed. the inspectors expressed concern over these examples.
While QA is not specifically responsible for ensuring errors are not made
during maintenance,
it
is counted on to provide valuable measures to
control the quality of the work performed.
Some discussion with OA
management concerning this type of issue had been held several months ago
due to earlier examples;
-
Inspection Report 269.270.287/89-05 (February
1989) described an
incident where improperly connected wiring during a NSM was signed
off as verified correct by a QA inspector. the incorrect wiring
resulted in a Unit 2 reactor trip.
-
During work on valve 2MS-89
(WP 92768C.
June 1989)
the bolting of
the valve's bonnet during assembly was apparently not performed
properly.
(The valve leaked during unit startup and was retorqued.
Discussions with the maintenance personnel involved with the retorque
indicate that significant fastener movement was attained with the
wrench set at normal torque value and that the leak was reduced to a
wisp by torquing to the normal value.)
A QA inspector had verified
the torQuing had been completed as required.
The inspectors expressed their concerns to Station and QA manacement. QA
management concurred that a lack of sufficient attention to detail was
involved and indicated that corrective actions would be initiated. This
overall issue is considered a weakness and the licensee's actions will be
closely followed.
12
6.
Inspection of Open Items (92700)
The following open items are being closed based on review of licensee
reports,
inspection.
record review.
and discussions with licensee
personnel. as appropriate:
a.
(Closed)
LER 269/88-10:
Missed Snubber Surveillance Results In A
Condition Prohibited by Technical Specifications Due To A Management
Deficiency.
This LER was addressed in correspondence to the NRC
dated August 5. 1988. The planned corrective action for this LER was
reviewed by the inspectors. A specific corrective action was to add
a note to a specific data sheet to provide clarification that both a
mechanical and hydraulic snubber was at this location.
In lieu of
the note. the drawings included as part of the data sheets were
annotated to satisfy this action since that was the mechanism
normally used by the procedure writers.
Based on this review, this
item is closed.
b.
(Closed)
LER 270/89-GL:
Violation of Emergency Power Technical
Specifications Due To Management Deficiency and Defective Procedure.
This LER was reported in correspondence dated February 16. 1989.
The
corrective action for this .FR have been reviewed by the inspectors.
The modification to the Lee Steam Station (NSM 52799) was completed
for all three units and tested on June 22. 1989.
Based on the
action, this item is closed.
c.
(Closed) LEP 287/85-05:
Anticipatory Peactor Trip on Loss of Main
This LEP described the loss of main feedwater due to a
failure of the auxiliary steam regulator.
The corrective action
required a modification to the regulating valve associated with the
auxiliary steam supply. Nuclear Station Modifications 12742. 22742
and 32742, have been accomplished on all units.
There have been no
additional losses of main feedwater attributed to this problem.
Pased on a review of the licensees action. this item is closed.
d.
(Closed)
Violation 50-269/87-02.
50-270/87-02.
and 50-287/87-02:
These violations were originally classified a Severity Level III.
On
July 17.
1989.
the NRC notified Duke Power Company (DPC)
that the
severity level had been reduced to a Level
IV based on the
clarifications provided in a DPC letter dated April 20. 1988. and the
results of an in-depth Office of Nuclear Reactor Regulation (NR)
review of the issue.
A region based inspector reviewed the
corrective actions taken by DPC to correct the violation.
A Nuclear Station Modification (NSM)
No.
NMS 1/2/3 2667 was issued
that directed the reroutirg of the cables for Valves 1/2/3 HP-4
through the West Penetration Room to provide the necessary separation
and reduce tc possibility of fire induced spurious operations.
The
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