ML20057A298
| ML20057A298 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 09/10/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20057A291 | List: |
| References | |
| 50-313-93-07, 50-313-93-7, 50-368-93-07, 50-368-93-7, NUDOCS 9309130337 | |
| Download: ML20057A298 (14) | |
See also: IR 05000313/1993007
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APPENDIX B-
U.S. NUCLEAR REGULATORY COMMISSION i
REGION IV
Inspection Report: 50-313/93-07
50-368/93-07
Licenses: DPR-51
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Licensee: Entergy Operations, Inc.
Route 3, Box 137G :
Russellville, /rkansas 72801
Facility Name: Arkansas Nuclear One, Units 1 and 2
Inspection At: Russellville, Arkansas
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Inspection Conducted:- July 11 through August 21, 1993
Inspectors: L. Smith, Senior Resident Inspector
S. Campbell, Resident Inspector
A. Gaines, Resident Inspector :
M. Runyan, Reactor Inspector !
Accompanying Personnel: K. Weaver, Engineering Aide
Approved: 3 ,, s"; t" d
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'ffiomaf f'. Stetki, Chief, Sfoject SectieK D Bate' '
Inspection Summary -
Areas Inspected (Units 1 and 2): This routine, unannounced, resident
inspection addressed onsite event followup, operational safety verification,
monthly maintenance observation, observation of bimonthly surveillance,
followup, and onsite review of licensee event reports (LERs).
Results (Units 1 and 2): ,
- The operating staffs of both units effectively responded to the loss of
the 500 KV transmission line to Mabelvale (Section 2.1).
. .The licensee responded promptly and effectively to a reported condition
of a dump truck operating in the switchyard without a spotter
(Section 3.2). ;
- The licensee had developed a comprehensive program of valve repair to
correct high pressure safety injection system leakage problems that' :
affected inventory in the safety . injection tanks (Section 3.5)'. l
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9309130337 930910 EIY l
PDR ADOCK 05000313 M
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- Planning for the Unit 1 Refueling Outage IRll was risk based, used !
state-of-the-art computer modeling techniques, and was viewed.as a t
strength. No outage related job orders that_had been deferred to-
Refueling Outage IR-12 vere identified that would adversely impact plant ,
safety (Section 4).
- The failure to perform Unit 2 reactor coolant sampling as specified by
the procedure was determined to be a violation of Technical
Specification 6.8.1 (368/9307-01) (Section 5.1).
Summary of Inspection Findinos:
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- Inspection Followup Item (IFI) 313/9307-02; 368/9307-02 was opened
(Section 3.4).
IFI 313/9305-01 was referenced but not closed (Section 4.2).
- Violation 368/9307-01 was opened (Section 5.1).
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IFI 313/9133-01 was closed (Section 5.1).
- Licensee Event Reports (LER) 368/92-002 and 368/92-004 were closed
(Section 7). ,
LER 368/93-001 was reviewed but not closed (Section 7).
Attachments:
- Attachment - Persons Contacted and Exit Meeting ;
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DETAILS ;
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1 PLANT STATUS
l -.1 Unit 1
At the beginning of the inspection period, Unit I was at 100 percent power.
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On July 16 the unit reduced power to approximately 98 percent for turbine
i throttle / governor valve testing. The unit returned to 100 percent' power the-
same day. On August 3 the unit reduced power to approximately 98.5 percent
due to High Pressure Feedwater Heater E-1B level control valve sticking. The ,
unit returned to 100 percent power the same day. On August 8 the unit reduced
l power for turbine throttle / governor valve testing. The unit returned to ,
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100 percent power the same day. On August 9 the unit reduced power to
96 e cent for Governor Valve 3 linear variable differential transformer ,
repair. The cnit returned to 100 percent power the same day. On August 10
the unit reduced power to 95 percent for further repair and testing of
Governor Valve 3. The unit returned to 100 percent power the same day. On !
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August 13 the unit reduced power to 95 percent for throttle / governor valve ,
l testing, and returned to 100 percent power the same day. At the end of the r
inspection period the unit was at 100 percent power.
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1.2 Unit 2
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The unit remained at or near 100 percent power throughout most of the '
inspection period. Following the loss of a 500 kV transmission line on '
August 21, reactor power was reduced to approximately 47 percent to preserve
the remaining transmission lines. The transmission line was restored to
service, and the unit returned to full power the same day.
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2 ONSITE EVENT FOLLOWUP (93702)
2.1 Units 1 and 2 - Loss of 500 kV Transmission Line to Mabelvale on
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The inspectors observed operator response on both units due to the loss of the
500 kV transmission line to Mabelvale. As a result of the associated voltage
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spike, Unit 2 temporarily lost the computers that'are used to operate the core
operating limit supervisory system. Technical Specification Action 3.2.1.b !
and 3.2.4.b were correctly entered and exited when the core operating limit
supervisory system was placed back in service. In order to preserve the two
l- remaining transmission lines, Unit 2 initiated a power reduction at 3:59 p.m.
l at the dispatcher's request. At 4:43 p.m. the power reduction was halted when
the operators were notified that the Habelvale transmission line was back in ,
service. The reactor was at approximately 47 percent power. At 5:40 p.m. a l
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power increase at 3 percent per minute was initiated.
While the Mabelvale transmission line was out of service, Unit 'I also prepared
l to reduce power to 90 percent to protect the remaining transmission lines. A- l
crew brief was held to reiterate contingency measures necessary because of the l
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leak on Feedwater Heater E-1A. The Habelvale line was returned to service
before a Unit 1 power reduction was necessary.
l- 2.2 Conclusions ,
I The operating staffs of both units effectively responded to the loss of the -
, 500 kV transmission line to Mabelvale.
3 OPERATIONAL SAFETY VERIFICATION (71707)
3.1 Units 1 and 2 - Safety Review Committee Meetinq ;
The inspectors observed portions of the Arkansas Nuclear One Safety Review
Committee meeting held on July 22. A quorum was present at the meeting. !
During the meeting, senior management and the offsite members asked
challenging questions of the plant staff from both a regulatory and a safety ;
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perspective. The objectives of the committee were met.
3.2 Units 1 and 2 - Control of Switchyard Activities .
On July 28 the inspectors observed a dump truck backing up between the buswork
support structures without benefit of an active spotter. The dump truck was
being used in connection with modification activities. Following notification
that this was occurring, the licensee stopped work-in the switchyard:to
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reiterate the required controls. The truck was being driven by Arkansas Power-
and Light (AP&L) personnel. The AP&L safety manual required them to actively
use a spotter when moving a truck within the switchyard. Subsequent licensee
oversight of these activities was good, and no further problems were
identified by the inspectors.
3.3 Unit 1 - Pinhole Leak In Service Water Discharge from Decay Heat
Cooler E-35A ,
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On August 2 the licensee identified a pinhole leak, approximately the size of
a pencil lead, in the service water piping on the discharge of Decay Heat '
Cooler E-35A. Ultrasonic testing was used to determine the size of the leak
and to assess piping integrity. The' inspectors reviewed the ultrasonic test
results. The leak was a localized pit. The licensee installed a rubber patch
for housekeeping purposes while a temporary noncode repair was planned. The
piping was determined to be operable even with the full leak in progress,
since structural integrity of the pipe was demonstrated; the leak was well
within the makeup capability of the service water pumps, and no nearby
equipment was susceptable to spray damage. No credit was taken for the
temporary rubber patch in this analysis.
As a part of the service water. Integrity program, the licensee has planned i
long range replacement of service water piping. This section of pipe was i
tentatively planned for replacement in Refueling Outage IR12 when a complete i
defuel is scheduled. A code repair is required to be performed during the
next Refueling Outage IRll. A core off-load was not scheduled for :
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Refueling Outage IR11. The pinhole leak was on a return header which was not
isolable and was normally in service when fuel was in the vessel. Further
inspection is planr.ed to evaluate the methodology for performing this repair.
3.4 Units 1 and 2 - Post Accident Samplina System
On August 9 the 100 psi rupture disk in the Unit 2 postaccident liquid +
sampling system (PASS) ruptured. The PASS was declared inoperable. On
August 11 the PASS was declared operable on the basis that the rupture disk
was not required for system operabilitv. The licensee considered the original
inoperability declaration to have been overly conservative.
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The inspectors requested the licensee to explain the basis for PASS
operability without the rupture disk in place. Additionally, the licensee was
requested to present a summary of any actions taken to improve the reliability .
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of this system. The latter request was based on the high frequency of PASS
problems that have 'ccurred on both units over the past several years.
The PASS rupture disk provides an internal pressure relieving function within
a 3/8-inch relief line that tees off the main PASS process line. The 100 psi
internal rupture disk was positioned upstream of a 75 psi relief valve that
relieves to the auxiliary building sump. The purpose of the relief line was-
to protect PASS instrumentation from overpressurization. The licensee
considered it unlikely that the pressure in the relief line reached 100 psi on-
August 9, but stated that it has been their experience that when cyclic loads y
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are placed on the rupture disk it could rupture _at a lower pressure. The
licensee stated that the PASS overpressure protection provided by the 75 psi
relief valve was sufficient to protect the system and that the rupture disk
being opened did not interfere with the pressure relieving function of the
line. The inspectors accepted the licensee's position.
During 1992, the licensee stated the Unit 1 PASS was out of service
(inoperable) for 3.75 percent of the time. Over the same period, the
Unit 2 PASS was out of service for 5.08 percent of the time. To address
Pass system concerns associated with the solenoid valves,-including leaking
seats and coil problems, the licensee issued Condition Report 1-93-0206 with a
corrective action due date of July 9, 1994. In addition, the licensee was
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pursuing system enhancements with various engi.,eering action requests.
To assess the historical reliability of the PASS, the licensee had recently
performed an internal Quality Assurance Surveillance Report, SR-93-034,
" PASS Operability / Reliability." The conclusion of this report was that the. j
. PASS reliability was satisfactory. Included in this surveillance was a
favorable assessment of the training and procedures associated with the ;
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system.
The reactor coolant system sampling observations documented in Paragraph 5.1
do not support this conclusion. Further inspection is planned to confirm that i
future operating practices of the chemists will'not have an adverse effect on j
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the reliability of the PASS. This inspection will be tracked as
IFI'313/9307-02; 368/9307-02.
3.5 Unit 2 - Safety Injection Tank Leakage
During the inspection period, Safety Injection Tank 2T-2A was. leaking out ->
slightly less than 1 percent per day. The licensee performed various
troubleshooting activities. They were able to reduce the leakage to
approximately .4 percent per day by isolating High Pressure Safety Injection
Pump 2P-89C Discharge _ Check Valve 2SI-10C. Pump 2P-89C was a swing pump and,
therefore, could be isolated without violating the Technical Specifications. . l
The licensee planned to replace Check Valve 2SI-10C on August 30. Additional
leakage was known to be coming from Thermal Relief Valve 2PSV-3110. The
licensee also planned to replace this valve at power and as soon as possible. ,
Procurement was in process for a replacement valve. The licensee planned .
additional review for smaller leaks after repair of the larger leaks. In '
addition, the licensee identified slight in-leakage to Safety Injection Tank
2T-2C and increased sampling to ensure the boron concentration remained .
acceptable. -l
Other leaking valves have been identified which will be replaced or repaired '
during the next outage: Valves 2SI-13A, 2SI-15C, 2SI-16C, 2CV-5015-1,
2CV-5016-2, 2CV-5055-1, and 2CV-5056-2. The licensee plans an improved high ,
' pressure injection valve design which will separate the throttling function-
and the isolation function. Two valves will be installed to replace each high !
pressure safety injection valve. The licensee plans to stagger the
installation of this modification over the next two outages.
The licensee was adequately monitoring the safety injection tank leakage and l
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had implemented appropriate compensatory measures. Repairs have been
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appropriately prioritized. !
3.6 Unit 1 - General Employee Trainina
The inspectors attended a general employee training session that was being j
provided for new contract outage personnel. The training was thorough and i
incorporated the licensees expectations and requirements in such areas as l
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security measures, housekeeping controls, and_ radiatio'n protection. The
training also provided a practical hands on session th.t required simulated
entry into a contaminated area. The simulation included a comprehensive
review of radiation worker practices and radiation work permit requirements. !
3.7 Conclusions
Observed operational activities were conducted safely in accordance with the !
regulations.
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4 MONTHLY MAINTENANCE OBSERVATION (62703)
4.1 Unit 1 - Planning for Refuelinq Outage 1Rll
On July 19 the inspectors attended a licensee presentation regarding the
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planning for Refueling Outage IRll. Included a the presentation was a
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description of the computer modeling process us'd to assess outage risk so
that outage plans could be adjusted to minimize risk. The licensee's shutdown
operations protection plan was generally-conservative. The licensee had
stated their intent to have two emergency diesel generators' (EDGs) available
during reduced inventory conditions; however, the plan did not clearly
indicate that two EDGs would be available during the second reduced inventory
period. On August 18 Unit 1 outage management addressed the NRC concern
regarding EDG availability during the second reduced inventory period. The
licensee stated that EDG K-4A would be fully operable and that EDG K-4B would-
be completing a 24-hour endurance run which did not affect its availability in
an emergency. Overall, the licensee's use of state-of-the-art computer driven
risk assessment technology was viewed as a strength.
4.2 Unit 1 - Review of items Deferred to Refuelino Outage IR12
The licensee provided the inspectors a list of outage related job orders which
would be deferred to Refueling Outage IR12. The inspectors reviewed the list
to identify items which should not be deferred because they were required code
repairs, items which would adversely impact control board indication, items
which would adversely impact the containment isolation function, leakage which
was likely to increase beyond analysis limits, leakage which could cause
thermal stratification beyond design analysis, . required testing and items
which would significantly affect plant reliability. Some items date back to
1986. Most of the older items involved design changes which appeared to be
enhancements. However, the repair of leakage from Sodium Hydroxide Tank
Discharge Valve CA-49 has been listed as a required task since 1987. The
licensee deferred this item because they plan to eliminate this system in a
future outage. Further review of the effect of the accumulation of sodium
hydroxide on Valve CA-49 was previously identified as IFI 313/9305-01 which
will remain open. No deferred items were identified that would' adversely
impact plant safety.
4.3 Unit 2 - Control of Maintenance on Control Room Annunciators
During a routine tour of the control room, the inspectors observed an operator
pulling an annunciator card, which had failed, for troubleshooting purposes.
Procedure 2015.028, " Operations Annunciator Control," and a facsimile of the
routine job order used to replace annunciator cards were reviewed to confirm
adequate control:: for annunciator card replacement were prescribed. No
problems were identified.
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4.4 Conclusions
Planning for the Unit 1 Refueling Outage was risk based, used state-of-the-art
computer modeling techniques, and was viewed as a strength. No outage related
job orders that had been deferred to Refueling Outage IR12 were identified
that would adversely impact plant safety.
5 BIMONTHLY SURVEILLANCE OBSERVATION (61726)
5.1 Units 1 and 2 - Reactor Coolant System Samplino
On August 18 the inspectors observed a chemist preparing to take reactor
coolant system samples. When the chemist arrived, the continuous air monitor
in the Unit 1 primary sample room was in alarm. He entered the Unit 1 primary
sample room to check valve alignments without notifying health physics the
monitor was in alarm. This was contrary to the guidelines presented in
General Employee Training 2. A second chemist contacted health physics. He
suggested that the work be delayed until after health physics personnel had an
opportunity to reset the continuous air monitor.
The chemist proceeded to the Unit 2 primary sample room. He set up the
required portable air monitoring device and began preparations for sampling.
He performed the steps from memory. When questioned, the chemist did not
initially know which section of Procedure 2607.001, " Unit II~ Reactor Coolant
System Sampling," he was using. Section 9.1.3 was determined to be the
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appropriate section, however he did not perform the task as specified by the
procedure. Initial valve alignments were not performed as required by the -
procedure. The flush rate of 1-1.5 liters per minute was not properly
established until after the inspectors questioned the chemist. The valve
adjustment that was performed to adjust the flush rate was performed using a
valve that was not indicated in the procedure.
Procedure 1052.023, Revision 3, " Conduct of Chemistry," required that "Where
there is an approved procedure that covers an activity, that activity shall be I
performed in accordance with the provisions of the applicable !
procedure . . . . When not directly referencing the procedure, the chemist is l
still responsible for performing the task as specified by the procedure." The
failure to perform the task as specified by the procedure was determined to be
a violation of Technical Specification 6.8.1 (368/9307-01).
The procedure deviations were of concern because they could result in samples l
being taken that were not representative of the reactor coolant system. )
Because of the failure to establish the valve alignment in the order described I
in the procedure, the chemist was not able to open a solenoid valve in the
postaccident sampling system. While the problem was being diagnosed, the
chemist left the handswitch in the on position; i.e., the coil was continually
energized for several minutes. The licensee initially believed an upstream
valve interlock had not been made up but later determined the solenoid valve
would not open until pressure was relieved by the spening of upstream valves.
l See Section 3.4 for additional inspection that is planned to evaluate the
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relationship between chemist training and qualification and postaccident !
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sampling system reliability.
The licensee completed the following corrective actions: .
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- A memorandum from the chemistry supervisor was provided to all personnel :
which emphasized management's performance expectations at the
supervisory and craft levels. j
-* The individual involved was counseled.
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The licensee planned the following corrective actions to be completed by
August 31, 1993
- Crew briefs to discuss lessons learned from this event and management's >
expectations concerning procedural implementation and adherence.
- Revision of Procedure 1052.023, " Conduct of Chemistry," to clarify. *
management's expectations regarding procedural compliance. .<
- Revision of the Chemistry Supervisory Desk Guide to address expectations
on supervisory performance standards and chemist procedural ~ adherence. ;
- Finalization of the Chemistry Initial Job Observation Program to
implement and provide feedback to management for satisfying performance
expectations.
The licensee planned the following corrective actions to be completed by
October 31, 1993:
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- Complete core on-the-job training card review to identify tha basic ;
kncwledge requirements for improved training consistency when qualifying . ,
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- Review frequently performed chemistry procedures to ensure the
appropriate level of detail exists. i
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5.2 Unit 2 - Refuelina Water Tank Samplino 1
On August 18 the inspectors observed sampling of Refueling Water Tank 2T-3.
The sampling was conducted in accordance with the procedure.
5.3 Conclusions
The failure to perform Unit 2 reactor coolant sampling as specified by the
procedure was determined to be a violation of Technical Specification 6.8.1
(368/9307-01). l
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6 FOLLOWUP (92701)
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6.1 (Closed) IFI 313/9133-01: High Pressure Injection (HPI) Room Cooler /HPI
Pump Operability ,
As a result of a misapplication of environmental qualification (EQ) data, the
licensee had mistakenly concluded that the Unit I high pressure injection
HPI pumps (also referred to as makeup pumps) could operate successfully under '
design accident conditions without any of the three installed service ;
water-cooled pump room coolers in operation. The error entailed the use of ;
maximum (peak) temperatures from EQ accident tests as an acceptable continuous
temperature for extended durations. The licensee had determined that current
and past operability of the HPI pumps had not been affected by this error
because there had always been at least one cooler available, the components in
question were inherently rugged, and the duration of elevated room ,
temperatures following a design-basis event would be short. The licensee was ;
in the process of determining the number of HPI room coolers necessary for +
HPI pump operability and evaluating the generic implications of using EQ data
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incorrectly.
The inspectors reviewed Calculation 87-E-0011-02, " Makeup Pump Room
Temperature with One Cooler," Revision 0, during this inspection period. i
Using conservative initial conditions, the licensee determined that the HPI !
room temperature would reach 138.3*F with two pumps and one cooler in - i
operation. The licensee determined that the limiting components with respect
to heat resistance were the sleeve bearings of the pump motors. The licensee -
consulted the motor vendor (Westinghouse) and received concurrence that the i
motor bearings could withstand the calculated teniperatures for the approximate i
1 to 2-day duration during which elevated temperatures would be expected to
exist following an accident. The licensee, therefore, concluded that at least ,
one HPI room cooler was necessary to ensure'the capability of the HPI pumps to l
perform their safety function. Considering single-failure criteria, at least .!!
two HPI coolers must be operable to ensure acceptable cooling cepacity. The
licensee revised the Unit 1 Safety Analysis Report, Amendment 10, .
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Section 9.7.2, to state, in part, "Two cooling units are required to be
operable (fans running, service water supplied) when makeup pumps are required
to be operable (for single failure considerations)." The previous safety .
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analysis report amendment had stated that the makeup pump motors were expected
to remain operable without any of the unit coolers in operation, a position l
that was based on the incorrect EQ interpretation. The inspectors questioned ;
whether the operating condition of the room coolers would be considered in ,
determining the Technical Specification operability of the HPI pumps (the
Technical Specification does not address the room coolers). The licensee !
stated that Procedure 1104.002, " Makeup and Purification System Operation," !
Supplement 3, requires that two of the three room coolers must be running to i
declare a given train of the system operable. Therefore, with less than two
coolers operable, the -licensee would enter the associated Technical !
Specification limiting condition for operation. The inspectors considered the ,
licensee's position-to be conservative.
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As Action Item 10 to Condition Report 1-91-0304, the licensee documented an
investigation into other areas where EQ data had been used to justify
i equipment operation. A total of seven calculations were determined to have ,
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been affected by an invalid application of EQ data. However, no additional
j operability impacts were identified. The licensee stated that the affected
l calculations would be corrected by October 1993 The inspectors found the
l licensee's actions to be acceptable.
7 ONSITE REVIEW OF LERS (92700)
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7.1 (Closed) LER 368/92-002: " Eddy Current Anal.ysis Personnel Error Results
in Inadeauate Steam Generator Tube Technical Specification Surveillance"
This LER involved the discovery by the licensee that a steam generator tube
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defect indicated by eddy current test data had not been identified due to
personnel error. On March 9, 1992, a 0.25 gpm primary to secondary leak in '
the Unit 2 "A" steam generator was isolated to the hot leg side of Tube 67-
109. Based on a review of eddy current data from'the previous refueling
outage in 1991, the licensee determined that an indication had been present on
Tube 67-109 which, if analyzed properly, would have_ required further
evaluation. The root cause of this event was determined to be personnel error
on the part of two contractor personnel who evaluated the eddy current test
results from the Unit 2 "A" steam generator. The licensee discovered six
additional indications from the cddy current data that had not been properly
identified and evaluated.
The licensee performed extensive eddy current testing to determine the
condition of the "A" and "B" stea.n generator tubes. Prior to restart of the
unit, 392 tubes were sleeved and 29 tubes were plugged in the "A" steam
generator. On the "B" steam generator, 56 tubes were sleeved and 11 tubes
were plugged. i
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The licensee identified three contributing causes to the personnel error that 1
precipitated this event. First, there was a lack of training for the eddy
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current analysts in site specific guidelines identifying damage mechanisms
specific to ANO as well as other sites. Second, there was no' requirement for
the analysts to demonstrate proficiency using historical eddy current data.
Third, the location of the indications at the upper edge of the tubesheet is ;
an inherently difficult portion of the tube to analyze. l
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The licensee issued Procedure HES-29, "ANO-2 Steam Generator ECT Performance
Demonstration," Revision 0, on September 10, 1992. This procedure provided l
requirements for conducting performance demonstration testing of steam l
generator eddy current data analysts. The procedure requires each analyst to
pass both a written and a practical test for a certification not to exceed
15 months.
The inspectors considered the licensee to have satisfactorily addressed both 4
the training and material problems associated with this item.
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7.2 (Closed) LER 368/92-004: " Foreign Material in Emergency Diesel
Generator Fuel Oil Day Tank Due to Cleanliness Control
Deficiencies Resulted in Operation Prohibited By Technical
Specifications"
This LER involved a calculated incapability of the Unit 2 emergency diesel
generator (EDG) 2K-4A to sustain full load for the duration of a design basis
accident. The EDG's degraded condition was due to low fuel oil header
pressure caused by a blockage of the foot valve suction strainer in the fuel
oil storage day tank. The strainer had been blocked by an oil absorber
material that -is used only in the cleaning of oil spills. The licensee
believed that the oil absorber material had entered the system in October
1991, during cleaning of the fuel oil transfer pump suction strainer. The
licensee concluded that the cleanliness and foreign materials exclusion
controls employed during this work had not been inadequate.
The EDG 2K-4A had been inoperable for an indeterminate period of time during
which the EDG 2K-4B was periodically removed from service. Since the relevant
required actions of Technical Specifications 3.8.1.1 and 3.8.1.2 were not
taken, the licensee reported the event pursuant to 10 CFR 50.73(a)(2)(1)(B).
The licensee evaluated the actual safety _ significance as minor becausc the
time during which both EDGs may have been inoperable was limited and the fact
that the EDG 2K-4A was only partially incapacitated.
The licensee inspected and cleaned all vulnerable areas of the Unit 2 EDG-fuel
oil system, but found no additional deposits of oil absorber material. All
fuel oil systems were determined to be operating properly. The event was
reviewed with Unit 2 mechanical and instrumentation and control personnel,
mechanical maintenance planners, and quality control inspectors.
A quality action team was assembled to review cleanliness controls and
housekeeping programs. Several actions resulted from the recommendations of
this team. Procedure 1025.019. " System Cleanliness Controls During
Modification and Maintenance," was cor.pletely revised to provide enhanced
control s. Likewise, Procedure 2402.028, " Unit 2 EDG Fuel Oil Tanks 2T-30A&B
and 2T-57A&B Cleaning and Inspection," was upgraded. A " dynamic issues"
report was issued to alert job order package reviewers to add cleanliness
quality control holdpoints or notifications in job order packages related to
activities involving opening or closing either unit's EDG fuel oil system.
The inspectors considered the licensee to have satisfactorily addressed the
. issues involved in this event.
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7.3' (0 pen)-LER 368/93-001:' "Confiouration Error Results in Technical
Specification Reauired Action For One Inoperable Reactor Vessel
' Level Monitor Not Beinq Accomplished"
'
Thellicensee' discovered that one channel.of the reactor vessel level
monitoring system had been inoperable, since the probe'was replaced in.
October 1992.' -The-licensee determined'that design configuration;was not
adequately updated, following the previous installation of' probes with
reversed polarity in'1986. The 1992 installation was believed to.be ai
like-for-like replacement when it was not. Postmaintenance testing was
reviewed and found to meet' acceptable standards for replacing like-for-like
items. Because of the history of inconsistericies with probe polarity, the -
licensee planned to develop an enhanced. functional test' method to verify
operability of. the reactor vessel level monitoring system following future
probe replacements. Further inspection is planned to review the. enhanced
functional test.
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- ATTACHMENT
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1 PERSONS CONTACTED
[ Licensee Personnel
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S. Boncleff, Licensing Specialist
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D. Provencher, Quality Assurance Supervisor
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R. Douet, Unit 1 Maintenance Manager
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R. Edington, Unit 2 Plant Manager
M. Frala, Chemistry Supervisor
M. Harris, Unit 2 Maintenance Manager :
R. King, Licensing Supervisor
W. McKelvy, Chamistry Supervisor
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M. Sellman, Plant Operations General Manager
J. Vandergrift, Unit 1 Plant Manager
J. Yelverton, Vice President Operations
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The personnel listed above attended the exit meeting. In addition to the
l personnel listed above, the inspectors contacted other personnel during this _;
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inspection period.
2 EXIT MEETING
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An exit meeting was conducted on August 20, 1993. During this meeting, the '
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inspectors reviewed the scope and findings of the report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
inspectors.
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