ML18152A061
| ML18152A061 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/19/1996 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A062 | List: |
| References | |
| 50-280-96-02, 50-280-96-2, 50-281-96-02, 50-281-96-2, NUDOCS 9605130401 | |
| Download: ML18152A061 (27) | |
See also: IR 05000280/1996002
Text
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Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/96-02 and 50-281/96-02
Licensee:
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and S0-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
February 11 through March 23, 1996
Inspectors:
Approved by:
Scope:
D. M. Kern, Resident Inspector
W. K. Poertner, Resident Inspector
G.~e~ef
Reactor Projects Branch 5
Division of Reactor Projects
SUMMARY
¥-/1-~~
Date Signe
This routine resident inspection was conducted on site in the areas of nlant
operations which included plant status, Unit 2 re~ctor shutdown due to loss of
containment integrity, Unit 2 startup, quadrant power tilt requirements,
operation with a shut power operated relief valve block valve, Unit 2 letdown
line leak, and Root Cause Evaluation 96-0104 (Loss of Missile Shield
_
Prot~ction for 1-SW-P-lA); maintenance which included Unit 2 residual heat
removal containment penetration leak discovery and repairs, circulating water
expansion joint preventive maintenance program, Unit 2 main steam non-return
valve repair, inoperable Unit 1 pressurizer power operated relief valves,
elevated normal switchgear room temperatures, Unit 2 reactor coolant pump
motor oil leak, recirculation mode transfer relay replacement, service water
valve 2-SW-331 replacement, and station battery 2A test; engineering which
included Unit 2 pressurizer heater capacity evaluation; and plant support
960513040{ 960419
ADOCK 05000280
G
ENCLOSURE 3
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which included nuclear oversight corrective action process.
A review of
Updated Final Safety Analysis Report commitments was also conducted.
Results:
Plant Operations
- .'**
The requirements of Technical Specification 3.8.A and 10 CFR 50.72 were met
during the Unit 2 shutdown to repair a leaking containment penetration
(paragraph 2.2).
The February 26 Unit 2 startup was conducted adequately and operators
implemented appropriate procedures and maintained adequate communication
throughout the unit startup.
Problems encountered were properly resolved with
guidance from senior operations management (paragraph 2.3).
A non-cited violation was identified for not incorporating quadrant power tilt
requirements into unit startup and operating procedures (paragraph 2.4).
One of the Unit 2 power operated i~lief valve block valves was shut due to
power operated relief valve seat leakage.
The Technical Specification
requirements for continued operation were met (paragraph 2.5).
A weld leak inside containment on the Unit 2 letdown line resulted in
isolation of the letdown line and operation with excess letdown in service
until the failed weld could be replaced.
This same weld joint had failed in
December 1995 (paragraph 2.6).
Root Cause Evaluation 96-0104, Loss of Missile Shield Protection for
1-SW-P-lA, was thorough and the recommended corrective actions should prevent
recurrence (paragraph 2.7).
Maintenance
A Violation was identified associated with failure to follow procedure
requirements which resulted in Unit 2 operation for approximately five weeks
with a degraded containment penetration.
Failures involved, 1) not notifying
the Shift Supervisor of water leaks inside the radiological control area, 2)
failure to initiate a Deviation Report on degraded equipment as required, and
3) attempted use of the minor maintenance program to identify a defective weld
(paragraph 3.1).
Deviations from commitments, contained in the June 21, 1993, letter to the
NRC, to reduce core damage probability from flooding, were identified.
Specifically, vendor recommendations for internal inspections of circulating
water rubber expansion joints were not incorporated in the preventive
maintenance program and changes to the inspection and service life replacement
program were not reviewed by the Station Nuclear Safety and Operating
Committee as committed (paragraph 3.2) .
An Unresolved Item was identified associated with preventive maintenance
program deferral weaknesses.
Over half of the circulating water rubber
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expansion joint preventive maintenance tasks have been routinely deferred.
Technical justification to defer Unit 1 rubber expansion joints replacements
during the 1995 refueling outage was weak.
Several preventive maintenance
task deferrals were rescheduled to inappropriate dates (paragraph 3.2).
Electricians effectively replaced and retested the main steam non-return valve
2-MS-NRV-201A supply breaker.
Communications between the electricians and
control room operators during post maintenance testing were good.
Appropriate
actions were implemented to address an inspector identifi~d weakness in the
procedure change approval process (paragraph 3.3).
Repairs to the Unit 1 power operated relief valve air system were well planned
and were completed in a timely manner.
Maintenance personnel demonstrated
good foresight to preplan the relief valve replacement as a contingency
(paragraph 3 A).
Temporary spot coolers have continued to provide adequate cooling to control
rod drive cabinets while the normal switchgear rooms have experienced elevated
temperatures.
Plans .,are on schedule to complete air conditioning upgrades by
mid May 1996.
Compensatory measures are adequate to cool the control rod
drive cabinets through that period (paragraph 3.5).
The issue team performed effectively to evaluate.a Unit 2 reactor coolant pump
oil leak and implemented appropriate corrective action.
The management
decision to reduce .power during the leak investigation demonstrated sound
consideration for personnel radiation exposure (paragraph 3.6).
The recirculation mode transfer relay repl~cement work activity w~s
accomplished in accordance with the work order instructions and the 10 CFR
50.59 safety evaluation adequately justified placing the recirculation mode
transfer mode switch in Refuel (paragraph 3.7).
The service water valve 2-SW-331 work activity was well coordinated and was
expeditiously completed to return the service water system to ser~ice
(paragraph 3.8).
The semi-annual station battery 2A test was accomplished in accordance with
the procedure and the data was recorded and reviewed by the system engineer as
required by the procedure (paragraph 3.9)~
Engineering
The safety evaluation for operation with reduced Unit 2 pressurizer heater
capacity was technically sound (paragraph 4.1).
Two examples were found in which the Updated Final Safety Analysis Report
descriptions were inconsistent with actual plant configurations. Section
9.13.3.6, Control Room and Relay Room Ventilation, did not describe the system
as presently configured.
Tables 5.2.1.a and 5.2.1.b identified 1&2-RH-MOV-
100&200 as motor operated gate valves.
These valves are no l_onger motor
operated (paragraph 6) .
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Plant Support
Procedures being developed to-define*nuclear oversight activities, including
corrective action processing, were appropriate.
Management's decision to
independently assess nuclear oversight effectiveness prior to implementing
further organizational transition demonstrated an appropriate sensitivity to
change management (paragraph 5.1) .
REPORT DETAILS
- Acronyms used in this report are defined in paragraph 9.
1.0
PERSONS CONTACTED
Licensee Employees
Benthall, W., Supervisor, Procedures
- Blount, R., Superintendent of Maintenance
Christian, D., Station Manager
Crist, M., Superintendent of Operations
Erickson, D., Superintendent of Radiation Protection
- Garber, B., Licensing
- Hanson, S., Supervisor, Maintenance
- Hayes~ D., Supervisor of Administrative Services
Lovett, C., Supervisor, Licensing
Luffman, C., Superintendent of Security
- McCarthy, J., Assistant Station Manager, Operations & Maintenance
- McConnell, F., Materials
- Miller, G., Corporate, Licensing
- Patrick, J., Supervisor, Training
- Saunders, R., Vice President, Nuclear Operations
- Shriver, B., Assistant Station Manager, Nuclear Safety & Licensing
- Sloane, K., Superintendent of Outage and Planning
- Sowers, T., Superintendent of Engineering
- Stanley, B., Nuclear Oversight
- Swientonieski, J., Nuclear Safety and Licensing
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
2.0
PLANT OPERATIONS (40500, 71707)
2.1
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability.
Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
Plant Status
Unit 1 operated at 100 percent reactor power the entire reporting
period.
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2.2
2.3
2.4
2
Unit 2 operated at 100 percent reactor power until February 22 when the
unit was shutdown to repair a leaking containment penetration (paragraph
--- 2.2) .-
The unit was returned to power operation on February 26.
On
March 13 power was reduced to 30 percent to investigate a RCP oil leak
(paragraph 3.6). The unit operated at 100 percent power for the
remainder of the inspection period.
Unit 2 Reactor Shutdown due to Loss of Containment Integrity
On February 22, at 7:04 p.m., a reactor shutdown of Unit 2 was
commenced.
The shutdown was directed by TS 3.8.A, Containment
Integrity, due to the discovery that containment penetration No. 24 1;1:i.s
leaking and that containment integrity no longer existed for the RHR
containment penetration.
The inspectors were notified by station
management of the leaking containment penetration and that a unit
shutdown had commenced.
The inspectors re~ponded to the site and observed the Unit 2 shutdown.
The inspectors verified that the NRC notification pursuant to 10 CFR
50.72 requirements was made within the required time limits. The
licensee initially ramped the unit from 100 percent to approximately
25 percent reactor power and at 10:44 p.m., the power ramp was stopped
to determine the results of repair activities. The repair attempts
failed and the RO, at 11:47 p.m., recommenced the power ramp to hot
shutdown conditions.
The unit was in hot shutdown conditions at
12:47 a.m., on February 23, meeting the TS requirements.
The unit was
subsequently cooled down to the cold shutdown condition to allow repairs
to the containment penetration. This item is discussed further in
paragraph 3.1.
Unit 2 Startup
On February 26, a Unit 2 reactor startup was initiated following repairs
to the RHR containment penetration.
The inspectors monitored control
room activities throughout the startup and continuously monitored
control room activities from 2 percent power to 30 percent power.
During power escalation to 30 percent power, several problems occurred.
The main turbine did not latch as rapidly as expected due to the manual trip lever hanging up.
During main turbine front end checks, the
turbine tripped when the test lever was partially released by the
operator while a turbine trip condition existed on the trip block.
The
licensee initiated DRs on each of the items identified to document and
correct the problems during future startups.
The inspectors determined
that the startup was conducted adequately and that operators implemented
appropriate procedures and maintained adequate communication throughout
the unit startup.
The inspectors also noted that senior operations
management was present in the control room throughout the unit startup.
Quadrant Power Tilt Requirements
The inspectors reviewed the licensee's implementation of TS 3.12.B.5,
Quadrant Power Tilt.
TS 3.12.B.5 states that the allowable QPT is
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2 percent.
The inspectors determined that the licensee did not monitor
QPT below 50 percent p~wer and that the control room alarms indicating
that a QPT may be present are automatically blocked below SO percent
power.
The inspectors questioned the licensee about the applicability
of the TS requirement.
The licensee initially stated that QPT limits
only applied above 50 percent power.
Standard TSs only require QPT
limits above 50 percent power and the licensee stated that the TS was
interpreted to only apply above 50 percent power consistent with the
standard Westinghouse design philosophy and the accident analysis. This
item was discussed with NRC staff and, although not a safety issue, the
determination was made that the TS as written applies during power
operation (greater than 2 percent power).
This item was discussed with
the licensee and the licensee agreed to implement the TS at all times.
The licensee plans to submit a TS change request to recognize that the
QPT limit only applies above 50 percent power.
The licensee also plans
to revise the operating procedures to require that QPT limits be
monitored at all power levels until the TS change is approved.
The inspectors were unable to determine if QPT limits had been exceeded
during previous power operations below 50 percent power.
The inspectors
did identify that 2-GOP-1.5, Unit Startup, 2% Reactor Power to Maximum
Allowable Power, revision 11, was inadequate because TS 3.12.B.5 QPT
requirements were not incorporated. Specifically, the procedure did not
require continuous monitoring of QPT values while at power.
However,
the GOP as written, did incorporate the TS requirements as the licensee
had interpreted them, in that, step 5.5.10 verified that the installed
equipment to monitor QPT above 50 percent power was enabled after power
level passed through the 50 percent value.
The inspectors identified several instances where power was increased
above 60 percent prior to identifying that a QPT existed.
In the
instances identified, the upper and lower ion chamber deviation alarms,
which indicate a potential QPT, did not clear when power exceeded 50
percent.
The alarms remained illuminated during the power increases
above 50 percent, the point at which the deviation alarm is
automatically unblocked.
When a manual QPT calculation was performed by
the operators, the QPT was greater than 2 percent.
The inspectors were
unable to determine when QPT exceeded 2 percent.
However, the
inspectors could determine that from the time the operators became aware
of the condition, due to the deviation alarms, the time allowed in the
TS action statement was not exceeded.
The inspectors determined that the operations staff did not understand
the QPT requirements during previous unit startups.
The inspectors will
monitor implementation of the QPT TS requirements during future power
reductions and startups.
TS 6.4 requires that detailed procedures be provided and followed for
normal startup, operation, and shutdown of a unit.
Procedure 2-GOP-1.5,
as well as, the Unit 1 GOP did not contain instructions for monitoring
QPT below 50 percent reactor power as required by TS 3.12.B.5 and was
thereby inadequate. This failure constitutes a violation of minor
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significance and is being treated as a Non-cited Violation, consistent
with Section IV of the NRC Enforcement Policy.
This item is identified
- - as NCV 50-280, 281/96-02-01, Inadequate Unit Startup and Operating
Procedures.
2.5
Operation with a Shut PORV Block Valve
On February 27, the block valve for PORV 2-RC-PCV-2455C was shut to
determine if PORV 2-RC-PCV-2455C seat leakage was the source of elevated
PORV tailpipe temperatures following a Unit 2 restart. Prior to the
Unit shutdown, tailpipe temperature had been reading approximately 136
degrees F and following the return to 100 percent power, tailpipe
temperature had increased to approximately 195 degrees F.
Subsequent to
shutting the block valve, tailpipe temperature began to decrease and
gradually returned to approximately 136 degrees F over several shifts.
Based on this indication the licensee decided to operate with the PORV
inoperable and the associated block valve closed with *power available to
the block valve as allowed by TS 3.1.A.6.
The inspectors reviewed the
licensee's actions and verified that the requirements of TS 3.1.A.6 were
met.
The licensee initiated a WR to repair the PORV seat leakage at the next
refueling outage scheduled to commence in May 1996.
On March 22, the
PORV block valve was reopened to determine if valve seat leakage was
still present. Tailpipe temperature initially remained constant and
then slowly increased to 185 degrees F.
The PORV block valve was
reclosed on March 23.
2.6
Unit 2 Letdown Line Leak
At 2:05 a.m. on March 17, the operators identified that total RCS
leakage, un-identified leakage, and containment sump inleakage had
increased from previous values.
Based on this information the operators
increased monitoring of RCS leakage and requested that containment sump
and containment atmosphere samples be obtained.
Results of the backup
leakage calculations and the samples obtained indicated an RCS leak
inside containment. A containment entry, made at 6:17 a.m., identified
that the RCS leak was located on the normal letdown line at a weld
downstream of valve 2-CH-HCV-2200B.
Normal letdown was secured and
excess letdown was placed in service to isolate the normal letdown line.
The letdown line was manually isolated and the line was drained to allow
inspection and repair of the failed weld.
Leakage never exceeded TS
allowed values.
The inspection of the failed weld identified a 1/2-inch weld crack at a
tee connection downstream of the letdown orifice isolation valves.
Tr.1s
weld connection had previously failed on December 13, 1995 {See NRC
Inspection Reports Nos. 50-280/95-23 and 50-281/95-23).
The December
1995 failure was attributed to lack of fusion between the weld passes.
A weld repair was made and the letdown line was returned to service .
The licensee determined that the probable cause of the second failure
was improper setback in the tc2 connection resulting in high residual
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stresses in the socket weld joint. The licensee ground otit the entire
weld and separated the connection approximately 1/8-inch to ensure
proper setback and then rewelded the connection. -During the NOE
inspections following the welding activities further indications were
identified on the piping adjacent to the original weld area.
The
license~ decided to cut out approximately 1.5 feet of piping and replace
it with new pipe.
The removed piping was saved to allow further
inspection and to determine the failure mechanism.
The licensee was
still evaluating this item at the end of the inspection period.
The
letdown piping was replaced, tested, and the letdown line was returned
to service at 10:03 p.m. on March 20.
The unit remained at 100 percent
power throughout the repair activity.
RCE 96-0104, Loss of Missile Shield Protection for 1-SW-P-lA
The inspectors reviewed RCE 96-0104, Loss of Missile Shield Protection
for 1-SW-P-lA.
This event is discussed in NRC Inspection Reports
50-280/96-01 and 50-281/96-01.
The licensee determined that the primary
cause of the loss of missile protection was personnel error associated
with the field change process and that a contributing factor was a lack
of barriers in the procedures controlling excavations.
The inspectors
reviewed the RCE and the recommendations that resulted from the
evaluation.
The inspectors also verified that the recommendations had
been incorporated into the licensee's commitment tracking system.
96-0104 was thorough and the recommended corrective actions should
prevent recurrence.
One NCV was identified.
3.0
MAINTENANCE (61726, 62703)
During the reporting period, the inspectors reviewed the following
maintenance and surveillance activities to assure compliance with the
appropriate procedures and TS requirements.
3.1
Unit 2 RHR Containment Penetration Leak Discovery and Repairs
3.1.1 Discovery of Defect
On February 22, during a review of maintenance work by the Nuclear
Oversight Department, a Deficiency Card identifying a crack in the
Unit 2 RHR piping, 6
11 -RH-120-152, -was identified.
Local visual
inspection of the outside surface of the piping by station engineers
found a through-wall leak in the outside isolation barrier of
containment piping penetration No. 24 (RHR to RWST).
The leakage was
estimated at one drop every ten minutes.
The SS was notified and DR
S96-0369 was submitted.
Engineering initiated a series of activities to assess the safety
significance of the event.
The guidance contained within GL 91-18,
Resolution of Degraded and Nonconforming Conditions and on Operability,
was followed.
The significance of the flaw was unknown and could not be
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determined without a flaw evaluation and structural assessment.
Therefore, this ASME,Section XI, Class 2 piping was declared fnoperable
in accordance with the guidance provided in GL 91-18.
At 5:55 p.m. on February 22, the SRO declared that containment integrity
as d~fined in TS 3.8.A and TS section 1 was being violated on Unit 2.
This declaration was based on the SS's review of DR S-96-0369 which
documented the discovery of the weld leak on containment penetration
No. 24.
TS 3.8.A.1 required that containment integrity be
re-established within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit shutdown to hot shutdown
conditions within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Additionally, the TS required that
after unit shutdown a cool down to cold sh~tdown be completed within 30 _
hours.
3.1.2 Attempted Repairs
After declaring containment penetration No. 24 inoperable, the licensee
initiated repairs to the penetration piping in an attempt to restore
containment integrity. The leak had been observed at a structural, (non~
pressure barrier) saddle weld for piping support H-31.
Valve isolation
was verified and the pip{ng was drained.
The visual crack was ground
out and NOE was performed to ensure defect removal.
Weld repairs were
attempted followed by the required NOE.
After two unsuccessful attempts
to repair the cracked weld, the licensee abandoned their initial efforts
and continued with plant shutdown and cooldown .
3.1.3 Piping Penetration Repairs and Testing
After Unit 2 was in cold shutdown, Code repairs were made to correct the
cracked piping and weld defect.
The inspectors reviewed the work
associated with the repairs to containment penetration No. 24.
Approximat~ly 4 feet of the leaking penetration piping (schedule _10 SS)
was replaced with thicker wall piping. After the licensee determined
that all NOE was completed satisfactorily, the piping welds were tested
at system operating pressure to verify no leakage. A hydrostatic test
of the piping and welds was not conducted because the licensee applied
ASME Code Case N-416-1 which allowed a system pressure test in-lieu of a
hydrostatic test. Additionally, a 46 psig air test was conducted on the
piping to satisfy 10 CFR Part 50 Appendix J containment leak check
requirements.
The inspectors reviewed the applicability of ASME Code
Case N-416-1 to this repair.
The NRC approved the use of this Code Case
at Surry in a letter dated October 14, 1994.
The inspectors also
witnessed the 46 psig air test of the penetration and verified that
acceptance criteria for an acceptable test were met.
The inspectors
also reviewed the radiological controls of the area during radiographic
testing of the new weld joints.
3.1.4 Safety Significance of Event
Engineering calculations performed on February 22 quantified .the
through-wall leakage to have an estimated 10 CFR 50, Appendix J, Type C
leakage rate of .0036 SCFH.
This value when added to previously known
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penetration leakage was well within leakage limits for the containment
penetrations as allowed by 10 CFR 50, Appendix J, Type C leakage
criteria. However, the guidance provided in GL 91-18 required that
ASME,Section XI, Class 2 components be declared inoperable if they are
observed to have through-wall leakage.
The containment penetration
piping through-wall leak was considered a loss of containment integrity.
The affected portion of the RHR piping is normally isolated and not used
during power operation, shutdown, or accident conditions when
containment integrity is required.
The piping constitutes a portion of
the containment isolation system.
Subatmospheric containment conditions
were maintained and containment penetration No. 24 remained isolated
throughout the event with no abnormal indications of containment
leakage.
UFSAR Section 5.2, Table 5.2.1.b, describes containment penetration
No. 24 containment isolation barriers.
The table lists 2~RH-29 as the
inside manual gate valve and indicates that it is not 10 CFR 50 Appendix J leak.tested.
The outside containment isolation valve,
2-RH-MOV-200, is listed as requiring a leak test and is described as a
motor operated gate valve.
The motor has been electrically disconnected
and this valve is now essentially a manually operated gate valve. This
UFSAR inconsistency also exists in Table 5.2.1.a for the Unit 1
application.
The licensee was notified of this UFSAR discrepancy.
With
the inside barrier providing containment isolation, containment
penetration No. 24 remained isolated throughout this event.
Upon
completion of a full evaluation and structural assessment, the licensee
determined that the integrity of containment penetration No. 24 had been
maintained and the containment penetration would have performed its
intended safety function if a postulated accident had occurred.
3.1.6 Regulatory Issues
After successfully repa1r1ng and .testing the containment penetration,
the licensee prepared a JCO in accordance with 10 CFR 50.59.
The
purpose of the JCO was to ensure that structural integrity of the piping
that was not replaced was acceptable pending the results of the ongoing
failure analysis.
Field UT examinations confirmed that the existing
piping wall thickness was greater than the minimum requirements and
assured structural integrity. The inspectors closely monitored the
licensee's activities in this area.
On March 4, additional UT examinations and visual inspections were
performed on piping associated with the similar penetration located in
Unit 1.
No external leakage and no unacceptable wall thinning were
identified.
The Unit 1 piping penetration is fabricated from seamless
pipe and does not have any welded supports within the outside
containment isolation boundary.
Based on these examinations and
observations, the licensee's engineering department concluded that
Unit 1 was not subject to the failure mechanisms contributing to the
Unit 2 leak.
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A preliminary laboratory report based on inhouse electron microscope
scanning of the removed piping samples identified localized indications
of general intergranular attack on the inside surface of the piping.
This general attack was greater at the point of failure.
Evidence of
arc strikes and cold lap were also identified in the failure area.
The
resultant stiffness of the fixed, welded, saddle support concentrated
piping stresses in the overlapping welds resulting in a localized
through-wall leak after approximately 23 years of service.
Additionally, piping samples were sent to an off-site vendor for
independently analysis which will include chemical analysis,
characterization of mechanical properties, and microstructure and
surface analyses.
The inspectors reviewed the issues associated with identification and
resolution of this condition adverse to quality.
The leaking
penetration was initially identified by*a decontamination technician
performing routine duties on January 16, 1996.
A DC was submitted on
the same day to document the leak.
VPAP 2002, Work Request and Work
Order Tasks, revision 5-PSI including PAR 5-PS-2, specified the~ethod
to be used when a maintenance deficiency was identified.
Paragraph
6.2.b specified that any leakage identified in the RCA be reported to
the SS.
Additionally, paragraphs 6.2 and 6.9 defined what methods are
to be used to document maintenance deficiencies.
Two methods were
Paragraph 6.9.1 described corrective
maintenance activities that can be covered by a DC as minor maintenance .
Attachment 11 of VPAP 2002 listed examples of minor maintenance
activities that can be controlled by the DC system.
Repairs of a
cracked and leaking piping weld are not included as minor maintenance.
Neither a DC or a WR are used as vehicles to promptly notify the control
room or SS of deficient conditions that may impact equipment or system *
operability.
The licensee contended that the DR system, described in
VPAP 1501, Deviation Reports, revision 4-PSl, is the vehicle used to
alert the control room and SS of deficiencies that may impact
operability.
When the leak was identified on January 16, 1996, a DC was
improperly used to document the deficiency, the control room was not
notified as required, and a DR was not submitted.
The inspectors
discussed the problems associated with the identification and correction
of the described condition adverse to quality with the Superintendent of
Operations and both ASMs.
Subsequent to the inspectors' discussions,
DR S96-0413 was submitted on February 28, to address the delay in
correcting a condition adverse to quality. A subsequent review of all
open DCs by the licensee verified that there were no other conditions
that compromised compliance with TSs.
Corrective actions in response to
DR S96-0413 should assure that plant conditions having the potential to
affect compliance with TSs are promptly identified in accordance with
station administrative procedures.
TS 6.4 requires that detailed written procedures be provided and
followed for preventive or corrective maintenance operations which would
have an effect on safety of the reactor.
VPAP 2002, Work Request and
Work Order Tasks, revision 5-PSI including PAR 5-PS-2 specifies the
3.2
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method to be used when a maintenance deficiency is identified.
Paragraph 6.2.b specifies that any leakage identified int.he RCA be.
reported to the SS.
Additionally, -paragraphs 6.2 and 6.9 defines what
method is to be used to document maintenance deficiencies.
VPAP 1501,
Deviation Reports, revision 4-PSl requires that deviations be reported
on a DR.
When the leak was identified on January 16, 1996, a DC in-lieu
of a WR was improperly used to document the deficiency, the control room
was not notified as required, and a DR was not submitted.
These
failures to follow procedures are identified as VIO 50-281/96-02-02,
Failure to Follow Procedures Resulting in Degraded Containment
Circulation Water Expansion Joint PM Program
The Surry response to NRC GL 88-20, IPE for Severe Accident
Vulnerabilities, identified a l.lE-3 per year CDF associated with
internal flooding*.
Several compensatory actions and plant modifications
were promptly implemented to reduce the likelihood and mitigate the
consequences of internal flooding.
NRC Inspection Report Nos.
50-280/91-31, 50-281/91-31, 50-280/91-33, and 50-281/91-33 documented
initial actions taken to address internal flooding.
VEPCO letter
92-299A dated October 30, 1992, reevaluated the CDF for internal
flooding at 2.3E-5 per year based upon completing planned modifications.
The turbine building SW and CW REJ inspection and replacement PM program
was a significant factor in reducing the CDF.
The inspectors reviewed
this program to determine whether appropriate actions were implemented
to maintain the reduced CDF associated with internal flooding.
3.2.1 PM Program Scope
The SW and CW REJ PM program included periodic inspections and
replacement PMs for 52 REJs located in the turbine building ..
The
inspectors reviewed system drawings, the PM scheduling data base,
procedure O-MCM-1003-01, Expansion Joint Removal, Inspection, and
Installation, revision 6, and recent WOs for completed REJ inspections.
The inspectors. concluded that O-MCM-1003-01 was well written and fully
incorporated vendor recommendations for external REJ inspections.
Recent exterior inspection results were documented in good detail and
the PM program scope incorporated all REJs which could be significant
contributors to turbine building flooding.
The inspectors observed that the PM program did not incorporate internal
REJ inspections which were recommended in the vendor manuals as a means
to detect symptoms of premature failure. A recent (December 1995)
catastrophic REJ failure at a similar nuclear power plant resulted from
internal erosion.
External inspections performed shortly before the REJ
failure had not identified symptoms of REJ degradation.
Internal
failure prior to external degradation was not previously considered as a
viable REJ failure mechanism in the Surry SW and CW REJ PM program.
The inspectors questioned whether external inspections alone were
adequate to properly evaluate REJ condition.
System engineers informed
,:
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10
the inspectors that internal inspections had been previously
recommended, but were not formally added to the PM program.
Informal
internal CW REJ inspections were performed during the last three
refueling outages with satisfactory results.
The inspectors reviewed
the last two Engineering Outage Summary Reports and confirmed that 13 of
the 24 CW REJs were internally inspected with no indication of
degradation.
The Maintenance Superintendent informed the inspectors
that PMs for internal REJ inspection were being developed and would be
added to the PM program based on the recent industry operating
experience review.
3.2.2 Current REJ Age/Condition
The twentyfour 96-inch CW REJs associated with the main condensers were
the largest in the PM program.
The inspectors reviewed completed work
documents and confirmed that 16 of these REJs (1-REJ-CW-lOOA/8/C/D,
1-REJ-CW-106A/B/C/D, 2-REJ-CW-200A/B/C/D, and 2-REJ-CW-206A/B/C/D) were
replaced during 1988-1989.
Purchase documents and engineering
evaluations specified an eight year service life for these REJs.
Based
on observed degradation, the remaining eight CW REJs (1-REJ-CW-
lOlA/B/C/D and 2-REJ-CW-201A/B/C/D) were replaced in 1992.
Purchase
documents specified a 10 year service life for these REJs.
The
procurement specifications precisely identified CW system configuration,
pressures, and CW water chemistry to which the REJs would be exposed.
Although the CW system is non-safety related, the CW REJs were procured
as safety related components to assure high quality standards were
maintained.
The inspectors concluded that good quality controls were
applied through the procurement and installation process. All 24 CW
REJs were within their vendor recommended service life period at the
close of this report period.
3.2.3 REJ Inspection/Replacement Status and Deferrals
The CW -REJ PM program was initially established in 1992 ~1th REJ
inspection required every RFO and REJ replacement required every five
RFOs.
The inspectors reviewed maintenance records and noted that over
60 percent of scheduled CW inspection PMs were deferred.
SW inspection
and replacement PMs were current.
Five of the oldest 16 CW REJs have
not been inspected since installation in the 1988-1989 timeframe.
Three
or the five CW REJs not inspected (1-REJ-CW-106A/B/C) will exceed their
specified service life prior to the next scheduled Unit 1 RFO.
The-inspectors expressed concern that an inordinate number of CW REJ PMs
were being deferred and that planning and evaluation for CW REJ
replacement prior to the end of specified service life appeared to be
slow.
Maintenance management informed the inspecto~s that the initially
established frequency for REJ inspection was too aggressive.
In
addition, each inspection required REJ flood shield removal which in
turn introduced some minor risk of flooding.
PM task evaluations were
processed in January 1996 to revise the inspection frequency to every
other RFO.
The -inspectors determined that the justification to revise
CW inspection frequency was adequate.
However, the inspectors noted
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that the PM task evaluation was approved without SNSOC concurrence.
VEPCO letter 93-163A, dated June 21, 1993, stated that future chang~s to
- inspection and replacement activities will be made based on engineering
evaluation and be reviewed by the SNSOC as appropriate. This issue is
discussed further in the paragraph 3.2.5 below.
Replacement PMs for seven CW REJs and thre~ safety related SW REJs were
deferred in July 1995 using PM deferral 95-088.
Three of the CW REJs
will exceed their service life prior to the next Unit 1 RFO.
One
additional CW REJ (l-CW-REJ-1068) will exceed its service life prior to
the next Unit 1 RFO, but has not been deferred.
The inspectors reviewed
PM deferral 95-088 and noted that several deferred REJs had never been
inspected.
No Unit 1 CW REJ internal inspections had been documented at
the time the deferral was approved.
The inspectors concluded that the
PM deferral justification was weak.
The inspectors reviewed the PM database and observed that deferral 95-088 rescheduled the seven CW and three SW REJ replacements from 1995
to 2003 (RFO 19). Therefore the replacement PM for these REJs would not
come due for evaluation or performance for an additional eight years.
Additionally, l-SW-REJ-1028 which was not included in this deferral had
also been rescheduled for RFO 19.
The inspectors also noted that a
recent 1-CW-REJ-lOOA inspection PM had been closed to a replacement PM
(308591-01) which was deferred and therefore the inspection was not
performed.
Upon further follow-up the inspectors identified weaknesses
in PM deferral process.
The res pons i bil ity and method to specify the
next scheduled PM performance date was not clearly described in
VPAP-0803, Preventive Maintenance Program, revision 4, or consistently
understood within the Maintenance Department.
The inspectors reviewed
several more recent PM deferrals, and noted that maintenance engineers
had added a data field to their deferral justification which more
clearly specified the next scheduled date.
The new field clearly
identified the new performance date, but had not been incorporated into
VPAP-0803.
The inspectors discussed these observations with the
Maintenance Superintendent.
He informed the inspectors that the
inspectors' identified scheduling discrepancies had been corrected.
The
inspectors questioned whether additional PMs were improperly scheduled
in the PM data base.
The Maintenance Superintendent stated he would
consider reviewing this question.
The Unit 2 RFO is currently scheduled for May 1996.
Eight CW REJs were
due for replacement per the PM schedule.
Although the outage scope was
not finalized., the inspectors noted that no work orders had been written
or materials ordered for these jobs by mid-February.
The Maintenance
Support Supervisor informed the inspectors that the replacement PMs were
being reviewed for possible deferrals.
The inspectors questioned
whether there was sufficient lead time to procure replacement REJs and
plan the WOs in the event the deferrals were not justified. The REJ
replacement PMs represented a significant cost and work scope impact on
the RFO schedule.
Station management directed that the eight
replacement PM WOs be added to the Unit 2 RFO work scope.
The
Maintenance Superintendent informed the inspectors that these PMs would
12
be performed during the upcoming Unit 2 RFO unless an acceptable
technical basis for deferral was developed.
The inspectors determined
--that planning for the CW REJ replacements was-slow to develop.
Maintenance management appeared to be planning the RFO work scope to
exclude the CW REJ replacements prior to initiating the PM deferral
process.
Management resolution to add the PMs to the RFO work scope
pending deferral justification and approval was appropriate.
3.2.4 Level 1 Management SW And CW REJ PM Program Review
Engineering perso~nel had previously raised concerns regarding ihe
apparent large number of SW and CW REJ PM program deferrals.
Management
Level 1 review No. 1164 was performed to evaluate the SW and CW REJ
inspection/replacement PM program.
The inspectors discussed the Level 1
report with the Maintenance Support Department manager.
Recommendations
included (1) replace the eight scheduled CW REJs during the May 1996
RFO, (2) establish a formal PM for. CW REJ internal inspections, and (3)
contract the vendor to perform hydrostatic and destructive testing on
two removed CW REJs to provide additional data to support possible
service life extension.: The Level I report was scheduled for SNSOC.
review at the close of the inspection period.
In addition, maintenance
engineers initiated an operating experience review to assess
applicability from the December 1995 reported industry REJ failure
event.
During this inspection period station management also directed
station engineering to perform an independent SW and CW REJ PM program
review.
3.2.5 Conclusion
A Deviation from two commitments, contained in the June 21, 1993, letter
to the NRC, to reduce core damage probability from flooding, was
identified.
First, the licensee's letter stated that their REJ
inspection process would include manufacturer's recommendations.
Manufacturer's technical information recommended that an internal
inspection be included as an important element of an inspection pr6gram.
However, the formal preventive maintenance inspection program did not
include provisions for internal inspections of CW REJ.
The second
deviation involved SNSOC not reviewing changes to the inspection and
service life replacement program as committed.
Specifically, PM task
evaluations were processed in January 1996 to revise the inspection
frequency of the REJ to every other RFO and this PM task evaluation was
not reviewed by SNSOC as required.
This item is identified as
DEV 50-280, 281/96-02-03, Deviation from Commitments Involving Internal
Flooding.
The inspectors noted several conditions that warrant management's
attention.
Over half of CW REJ PMs have been routinely deferred.
Planning and evaluation for CW REJ replacements prior to the end of
their specified service life were slow.
Technical justification to
defer Unit 1 CW REJ replacements during the 1995 RFO was weak.
Several
PM deferrals were rescheduled to inappropriate dates. These conditions
in the PM deferral process may indicate inadequate controls for
3.3
13
scheduling PMs.
This issue is identified as URI 50-280, 281/96-02-04,
Review Preventive Maintenance Program Deferral Process.
Unit 2 Main Steam Non-Return Valve Repair
Each main steam header contains a NRV which functions as a check valve
to prevent reverse flow from the other SGs when a steam line break
occurs upstream of the NRV.
A motor operator provides backup capability
to shut the NRV from the control room in the event that the check valve
does not fully seat upon reverse flow.
The inspectors verified that the
NRVs were installed and functioned as described in the UFSAR.
On
February 26, during unit startup verifications, the supply breaker for.
NRV 2-MS-NRV-201A tripped while attempting to close the valve.
The SS
initiated a priority I WR to repair and retest 2-MS-NRV-201A.
This work
activity was a critical path item for unit startup.
The inspectors
interviewed personnel, reviewed work documents, and observed work
activities to evaluate the breaker repair.
El ect.ri ci ans meggered the valve motor with satisfactory results and
reset the NRV breaker.
The breaker tripped again when operators
attempted to shut the valve a second time.
Electricians observed that
motor current had remained within the breaker rating and determined that
the breaker should be replaced. A replacement breaker was tested and
installed using WO 337079 and procedure O-ECM-0306-02, Motof Control
Center Maintenance, revision 12.
The inspectors reviewed the WO,
discussed the job with the work crew, and observed breaker replacement
and retest activities. The WO contained appropriately detailed
instruction for the breaker repair. The electricians clearly understood
their work activities and performed the breaker replacement and PMT in
an acceptable manner.
Communications between the electricians and
control room operators during the PMT were good.
Procedure O-ECM-0306-02 is a general procedure which can be used to
perform maintenance on a variety of 480 volt MCC cubicals, breakers, and
thermal overload devices.
The work crew initiated a PAR to modify the
overload trip device test duration and manual valve positioning
requirements specified in O-ECM-0306-02.
The PAR process may be used to
implement procedure changes in a shorter time period than is needed by
the formal procedure revision process.
Both procedure changes and
procedure revisions are discussed in VPAP-0502, Procedure Process
Control, revision 7.
The proposed changes were intended to shorten the
work activity duration by several hours.
The inspectors determined that
the PAR was technically justified for the 2-MS-NRV-201A repair activity.
The work crew demonstrated good initiative to develop the PAR and
processed the procedure change in accordance with VPAP-0502.
The category B procedure change was authorized by the Maintenance
Superintendent.
The inspectors questioned who else was authorized to
approve this Category B (change of intent) procedure change.
The
electrical supervisor informed the inspectors that either the
Maintenance Superintendent, the designated MMOC in the absence of the
Maintenance Superintendent, or SNSOC could approve the change.
The
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3.4
3.5
14
MMOCs, who was identified by the crew as an acceptable approval
authority was.not on the SNSOC approved manager list to approve Category
-B PARs.
The Maintenance Superintendent st~ted that he would reemphasize
his PAR approval expectations with all department personnel.
SNSOC also
revised the approved manager list to permit MMOCs who are qualified as
Maintenance Department SNSOC alternates to approve Category B PARS/ The
inspectors concluded that these actions were adequate to ensure proper
procedure revision approval.
Maintenance engineers determined that the 2-MS-NRV-201A breaker thermal
trip element had degraded due to age.
This breaker was original plant
equipment.
PM schedulers informed the inspectors that non-safety
related molded case circuit breakers, such as 2-MS-NRV-201A, are not
included in the PM program.
The Maintenance Superintendent informed the
inspectors that this item would be evaluated as part of an ongoing
breaker PM scope review.
The inspectors determined that this action was
appropriate.
Inoperable Unit 1 PZR PORVs
At 6:42 a.m. on February )o, the PZR PORV low air pressure alarm was
received in the Unit I control room.
Operators declared both PORVs
inoperable and shut the PORV block valves as required by TS 3.1.A.6.b.
Technicians promptly entered containment and determined that the
pressure regulator from the backup air supply bottles to PZR PORV
I-RC-PCV-1456 had failed.
The unaffected PORV was promptly restored.
The regulator failure caused the air line relief valve to lift and
depressurize the air bottles.
WO 336760 was initiated to replace
I-IA-PCV-102 and return the backup bottle air supply system to service.
The inspectors observed work activities to evaluate repair timeliness
and effectiveness.
The inspectors reviewed WO 336760 and attended the work prebriefings~
Briefings were detailed and radiological considerations were clearly
understood by the work crew.
Technicians also prepared contingency
materials to replace the downstream relief valve, l-IA-RV-127, in the
event it failed to properly reseat. After replacing l-IA-PCV-102
technicians pressurized the air line and determined that the relief
valve had not fully reseated.
The relief valve was promptly replaced,
l-IA-PCV-102 was adjusted, and l-RC-PCV-1456 was restored to service.
Coordination between maintenance and operations personnel was good.
The
inspectors concluded that repairs to the PORV backup air system were
well planned and completed in a timely manner.
Maintenance personnel
demonstrated good foresight to preplan the relief valve replacement as a
contingency.
Elevated Normal Switchgear Room Temperatures
Four DRs initiated during this report period identified elevated
temperatures in the Unit 1 normal switchgear room.
Room temperature
reached a high of 94 degrees on March 5.
Room temperatures exceeded 90
degrees F again on March 14 when the Unit I normal switchgear room air
15
conditioning unit became inoperable.
Prolonged exposure to elevated
temperatures had previously degraded CRD circuit cards which
- necessitated two manual reactor trips in 1995.
Corrective actions
included CRD circuit card replacements, circuit card testing, and
planned ventilation modifications. Spot coolers were installed in May
1995 as a temporary modification to supplement normal room cooling to
the CRD power cabinets.
The inspectors verified that the spot coolers
continued to operate throughout this report period.
The inspectors
reviewed the scheduling status for the planned permanent air
conditioning upgrade to determine whether appropriate actions were being
taken prior to the onset of the hot weather period.
DCP 95-19 was written to upgrade the Unit 1 and Unit 2 normal switchgear
room air conditioning capacity to 80 tons per room.
WOs 333007 and
333008 were written to implement the air co~ditioning upgrade.
The
inspectors walked down the intended modification in the field and
discussed WO status with work planners and schedulers.
Materials for
DCP 95-19 were scheduled to arrive on-site on March 16 and work was
scheduled to begin the following week.
Planners estim~ted that the work
would take eight weeks to complete, with projected completion in mid May
1996.
The inspectors concluded that the schedule to complete the air
conditioning upgrade by mid May was adequate.
Although warm
temperatures may be experienced earlier, the temporary spot coolers and
existing temperature monitoring during operator tours is adequate for
that period.
Planners were knowledgeab1e regarding ventilation system
design.
3.6
Unit 2 Reactor Coolant Pump Motor Oil Leak
On March 5, electricians entered containment to investigate a RCP IA oil
reservoir hi-low level alarm.
RCP upper thrust bearing temperature
remained normal.
Technicians observed that oil level was low and added
21 gallons of oil to restore the reservoir to the normal indicated
level.
The same RCP motor experienced oil loss and elevated upper
thrust bearing temperatures in December 1995 as documented in NRC
Inspection Report Nos. 50-280/95-23 and 50-281/95-23.
The inspectors
monitored licensee actions to evaluate and address the RCP oil loss.
After reviewing related maintenance history and discussions with the
vendor, the ongoing RCE team determined that an active RCP IA oil leak
existed.
Further, the RCP IA oil level indicator and low level alarm
were unreliable due to suspected partial blockage in a level standpipe
drain hole.
While each continued to provide some information, accuracy
was questionable and results were not always repeatable.
The inspectors
noted that the RCP oil leak rate appeared to have increased following
the RCP IA start on February 25 during the preparations for unit
startup.
The RCE team postulated that the most likely locations for a
leak were associated with the RCP bearing lift pump supply line from the
upper RCP oil reservoir or the oil cooler.
Subsequent observations and
oil additions confirmed that the leak rate had changed from 0.3 gpd to
about 2.5 gpd.
3.7
16
A separate RCP oil leak issue team was established and SE 96-021 was
written to evaluate continued reactor operation with the existing RCP IA
- oil leak.
The evaluation considered the leak -rate, compensatory
measures including increased RCP bearing temperature monitoring,
remaining volume available in the RCP oil collection tank, and ability
to add oil to the RCP upper oil reservoir. Management concluded that an
unreviewed safety question did not exist.
The inspectors determined
that SE 96-021 was technically sound.
The issue team determined that based on the existing leak rate, the oil
collection tank did not have sufficient volume to support continued RCP
operation beyond mid-March.
The team established a plan of action to
install a TM to drain the oil collect tank, perform inspections to
verify the leak location, and add oil to maintain sufficient bearing
cooling.
The inspectors observed team activities and discussed the leak
identification plan with the team.
The team maintained a good focus on
both equipment and personnel safety.
RWP 96-2-1129 was established to support RCP oil leak investigation and
associated maintenance activities.
Eleven containment entries wire made
from March 4 through March 13.
Reactor power was temporarily reduced to
30 percent to reduce personnel exposure during a series of five entries
on March 13.
Radiation levels in the vicinity of the oil collection
tank were reduced by a factor of 3. Total personnel exposure for this
job during the March 4-13 period was 3.247 REM.
The inspectors reviewed
the RWP, discussed radiological precautions with workers, and concluded
that the work activities were well planned with appropriate
considerations for personnel exposure.
On March 13, electricians identified a packing leak from a drain valve
on the oil supply line from the RCP upper oil reservoir to the lube oil
cooler.
The packing was tightened which reduced the oil leakrate. Oil
was drained from the collection tank and eight gallons of oil was added
to restore normal upper reservoir level. Operators plan to continue
enhanced bearing temperature monitoring and the team plans to continue
oil leak evaluation. Outage plans were modified to schedule the RCP IA
motor for replacement during the upcoming Unit 2 refueling outage.
The
inspectors concluded that the RCP oil leak issue team performed
effectively to evaluate the oil leak and initiated appropriate
corrective action.
Recirculation Mode Transfer Relay Replacement
On March 9, during the performance of procedure l-PT-8.6, RMT Logic,
revision 7, several unanticipated annunciators were received and relay
actuation were heard when the test switch was being manipulated to test
the-channel 1 and 3 matrix.
Testing was stopped to evaluate the
discrepancy.
The licensee determined that the channel 1 RWST level
relay R-CS-100A2 was not functioning properly.
The channel was declared
inoperable and the channel was placed in bypass per TS Table 3.7-2
Action 7.a .
3.8
3.9
17
Relay R-CS-100A2 was replaced on March 12 per WO 00337953.
The
inspectors reviewed the WO, the associated 50.59 evaluation to place the
~ssociated RMT mode switch in Refuel during the relay replacement, ~nd
observed work activities in progress.
The inspectors also verified that
the associated TS requirements and post maintenance testing activities
were met.
The work activity was accomplished in accordance with the WO
instructions and the 50.59 evaluation adequately justified placing the
RMT mode switch in Refuel.
Service Water Valve 2-SW-331 Replacement
On March 12, the licensee replaced valve 2-SW-331 due to seat leakage.
Valve replacement required that one of two service water flow paths to
the charging pump service water subsystem and the main control and
emergency switchgear room air conditioning condensers be removed from
service.
The maintenance activity placed both units in a 24-hour LCO
action statement per TS 3.14, Circulating and Service Water Systems.
The LCO action statement was entered at 4:58 a.m. on March 12.
Valve
2-SW-331 was replaced and the service water system was returned to
service at 1:05 p.m. on March 12.
The inspectors monitored the valve
replacement activities, verified that the TS requirements were met and
verified that the system isolation was adequate.
The work activity was
well coordinated and was expeditiously completed to return the service
water system to service .
The inspectors reviewed UFSAR section 9.13.3.6, Control Room and Relay
Room Ventilation.
During the review the inspectors determined that the
UFSAR did not describe the system as presently configured.
The UFSAR
stated that three refrigeration chillers serve the ventilation system
and that all three chillers are located in MER-3.
The actual
configuration of the refrigeration chillers had been modified by a
design change to add two additional chillers located in a ~eparate MER
called MER-5.
This design change added redundancy and separation to the
refrigeration chiller system.
This item was identified to the licensee
for resolution.
The licensee stated that an UFSAR change was being
pursued to change the UFSAR section but had not been completed prior to
the inspectors review.
The licensee presently plans to submit the UFSAR
change in April 1996.
Station Battery 2A Test
On February 29, the inspectors observed the performance of procedure
O-EPT-0104-01, Semi-Annual Station Battery Test, revision 2, conducted
on station battery* 2A.
This surveillance procedure implements the
requirements of TS 4.6.C.1.d.
TS 4.6.C.1.d requires that twice a year,
during normal operation, the battery charger be turned off for
approximately five minutes and the battery voltage and current be
recorded at the beginning and end of the test. The TS states that the
test shall be considered satisfactory if the new data when compared to
the old data indicates no signs of abuse or deterioration and the
battery performs within acceptable limits as established by the
manufacturer's discharge characteristic curves.
The inspectors verified
18
that the activity was accomplished in accordance with the procedure and
that the data was recorded as required.
The system engineer reviewed
the data 1mmediately following the performance of the procedure and
stated that the values obtained were consistent with previous tests and
that no battery degradation had occurred from the previous performance
of the procedure.
The inspectors reviewed UFSAR Section 8.4.4, 125V Direct Current System,
and Section 8.6, Tests and Inspections.
The inspectors determined that
the UFSAR *adequately described the 125 VDC system with respect to the
semi-annual battery test.
One violation and one deviation was identified.
4.0
ENGINEERING (37551)
4.1
Unit 2 PZR Heater Capacity Evaluation
On February 24, PZR heaters 64, 65, and 66 were determined to be
inoperable due to an electrical ground.
Due to these heater failures,
the heater output available from the J emergency bus was reduced to 150
KW.
This was less than the 200 KW heater design capacity identified in
UFSAR section 4.2.2.2.
SE 96-114 was prepared to assess continued
operation and reactor startup with the three PZR heaters inoperable.
The inspectors attended the SNSOC SE review to determine whether the
evaluation scope and conclusions were appropriate.
TS 3.1.A.5.a requires at least 125 KW of heaters be available from an
emergency bus to assure natural circulation capability during a loss of
off-site power event.
In response to NUREG-0737, Clarification of TMI
Action Plan Requirements, the licensee committed to maintain at least
125 KW PZR heater capacity available on each emergency bus (Hand J
buses).
The SE noted that the remaining PZR heater capacity satisfied
license requirements and sufficient heater capacity would be available
to maintain natural circulation in the event either the J or H emergency
bus became deenergized.
The remaining PZR heaters can be isolated from
the main control room and controlled from the alternate shutdown panel.
Therefore the capability to establish natural circulation and achieve
safe shutdown conditions following a fire was maintained.
The SNSOC
concluded that continued operation with 150 KW heater capacity on the
J emergency bus satisfied license requirements and did not pose an
unreviewed safety question.
The inspectors-determined that SE 96-114
was technically sound and that the SNSOC reviewed the issue in
appropriate detail.
No violations or deviations were identified.
5.0
PLANT SUPPORT (71750)
The inspectors conducted facility tours, work activity observations,
personnel interviews, and documentation reviews to determine whether
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19
license programs met regulatory requirements in the areas of oversight,
radiological *protection, security and fire protection.
Nuclear Oversight Corrective Action Process
The Surry Station Nuclear Oversight Organization was established
November 1, 1995, as part of the Virginia Power QA reengineering
project.
The station organization consists of the Director, nine
auditors who perform formal audits as directed by the VEPCO audit
coordinator, and four nuclear specialists.
VPAP-1801, Nuclear Oversight
Internal Audit Program, revision 3, provides guidance for QA audit
finding resolution.
However, specialists do not perform audits.
The
inspectors have monitored nuclear oversight specialist activities and
noted that the specific roles, responsibilities, and oversight processes
are not formally defined.
The inspectors observed that nuclear
specialists have actively tracked day to day performance in the field,
but questioned how specialists initiated and tracked corrective actions
to problems which they observed.
The inspectors met with the Director SNOS, to discuss the methods by
which SNOS resolves observed performance problems.
Currently,
specialists track performance observations using the QATTS system and
meet with the Director SNOS weekly to discuss perceived weaknesses or
trends.
The Director SNOS then drafts a list of current oversight
issues and informally discussei them with the Station Director weekly .
Specialists formally use the DR process to initiate corrective actions
for significant problems they identify.
The inspectors noted that DR
corrective action closure does not require SNOS involvement and
questioned how SNOS tracks issue closure.
The Director SNOS said that
as a temporary measure, he and the specialists currently review all DR
closures for issues they initiated. The inspectors determined that
although this practice was not proceduralized, corrective action closure
was adequately tracked.
The Director SNOS stated that oversight roles and processes were in
transition and that procedures would be formalized shortly.
VPAP-1601,
Corrective Action, revision 3, and VPAP-1801 are being revised to
specifically provide an independent process for SNOS specialists to
initiate corrective action to oversight issues and to escalate findings
as needed.
A new SNOS department procedure is being written to define
the oversight mission, specialist responsibilities, and internal
processes to identify and resolve oversight issues and observations.
The inspectors reviewed recent*oversight issues with the Director SNOS
and concluded that the issues being identified indicated a good level of
oversight involvement.
Processes being developed to better define SNOS
activities including methods to independently initiate and track
corrective actions were appropriate.
The revised procedures for Nuclear Oversight are anticipated to be
issued and implemented in early Spring.
MSRC members recently discussed
the QA reorganization with the inspectors and with station management.
The station director indicated that nuclear oversight organization
20
effectiveness would be independently evaluated prior to implementing the
next stages of the Vision 2000 reengineering program at Surry Station.
- This would be done to ensure the oversight organization was ready to
provide appropriate independent assessment during further organizational
transition.
The inspectors concluded that this decision was appropriate
to maintain sound independent oversight capability.
No violations or deviations were identified.
6.0
REVIEW OF UFSAR COMMITMENTS (61726, 71707)
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special*
focused review that compares plant practices, procedures, and/or
parameters to the UFSAR descriptions. During this inspection period
(February 11 through March 23, 1996) the inspectors reviewed the
applicable sections of the UFSAR that related to the inspection areas
discussed in this report to ensure that UFSAR wording was consistent
with the observed plant practices, procedures, and/or parameters. Jhe
following inconsistencies were noted:
UFSAR section 9.13.3.6, Control Room and Relay Room Ventilation,
stated that three refrigeration chillers serve the ventilation
system and that all three chillers are located in MER-3.
The
actual configuration of the refrigeration chillers had been
modified by a design change to add two additional chillers located
in a separate MER called MER-5.
This design change added
redundancy and separation to the refrigeration chiller system.
The licensee stated that an UFSAR change was being pursued to
change the UFSAR section but had not been completed.
The licensee
presently plans to submit the UFSAR change in April 1996.
UFSAR Table 5.2.1.b, describes containment penetration No. 24
containment isolation barriers. The outside containment isolation
valve, 2-RH-MOV-200, is described as~ motor operated gate valve.
The motor has been electrically disconnected and this valve is now
a manually operated gate valve.
This inconsistency also exists in
Table 5.2.1.a for the Unit 1 application.
The licensee was
notified of this minor UFSAR discrepancy for their resolution.
7.0
OTHER NRC PERSONNEL ON SITE
On February 13, the NRC Chairman, Dr. Shirley A. Jackson, visited the
site. Dr. Jackson toured the plant, met with licensee management and
the inspectors to discuss plant status and current issues at the
facility and held a press conference.
There were no local officials in
attendance.
Dr. Jackson was accompanied by members of her staff and the
Region II Regional Administrator, Mr. Stewart Ebneter.
On March 8 and 9, Mr. B. Buckley, Senior Project Manager, NRR, and
E. Imbro, Project Director, NRR, were on site to review the design basis
for spent fuel storage and corp off-load practices.
-. *
8.0
9.0
21
On March 19, Mr. W. Gloersen, a Region II inspector, and a three man
NMSS Team visited the site for the purpose of touring the Independent
-Spent Fuel Storage Installation and to review cast loading and unloading
practices and procedures.
On March 21, Mr. J. Johnson, Deputy Director of Reactor Projects, and
Mr. G. Belisle, Branch Chief, both from Region II, visited the site.
Mr. Johnson and Mr. Belisle toured the plant and met with licensee
management and the inspectors to discuss plant status and current issues
at the facility.
While on site, Mr. Johnson and Mr. Belisle attended
the IPAP exit.
On March 21, Mr. P. Koltay, IPAP Team Leader, visited the site for the
purpose of conducting the IPAP exit.
EXIT
The inspection scope and findings were summarized on March 27, 1996, by
M. W. Branch with those persons indicated by an asterisk in paragraph 1.
The inspectors d~scribed the areas inspected and discussed in detail the
inspection results.
On April 18, 1996, M. W. Branch discussed the NCV
with the Assistant Station Manager for Operations and Maintenance. A
listing of inspection findings is provided.
Proprietary information is
not contained in this report.
Dissenting comments were not received
from the licensee .
~ Item Number
Status
Description and Reference
50-280, 281/96-02-01
Closed
Inadequate Unit Startup and
Operating Procedures
(paragraph 2.4)
50-281/96-02-02
Open
Failure to Follow Procedures
Resulting in Degraded
Containment Penetration
(paragraph 3.1.6).
DEV
50-280, 281/96-02-03
Open
.Deviation From Commitment to
Reduce Probability of Cor0
Damage From Flooding
(paragraph 3.2.5).
50-280, 281/96-02-04
Open
Review Preventive Maintenance
Program Deferral Process
(paragraph 3.2.5).
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
ASSISTANT STATION MANAGER
CFR
CODE OF FEDERAL REGULATIONS
CORE DAMAGE FREQUENCY
i I
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"
1
f *
22
CONTROL ROD DRIVE
cw
CIRCULATING WATER
DEV
DEVIATION
DEFICIENCY CARD
DESIGN CHANGE PROGRAM
DR
DEVIATION REPORT
F
FAHRENHEIT
GL
GENERIC LETTER
GENERAL OPERATING PROCEDURE
GPO
GALLONS PER DAY
!PAP
INTEGRATED PERFORMANCE ASSESSMENT PROCESS
INDIVIDUAL PLANT EXAMINATION
JCO
JUSTIFICATION FOR CONTINUED OPERATION
KW
KILOWATT
LCO
LIMITING CONDITION FOR OPERATION
MOTOR CONTROL CENTER
MER
MECHANICAL EQUIPMENT ROOM
MMOC
MAINTENANCE MANAGER ON CALL
MSRC
MANAGEMENT SAFETY'.~EVIEW COMMITTEE
NUCLEAR MATERIALS SAFETY & SAFEGUARDS
NRC
NUCLEAR REGULATORY COMMISSION
NRV
NONRETURN VALVE
PROCEDURE ACTION REQUEST
PUBLIC DOCUMENT ROOM
PREVENTIVE MAINTENANCE
POWER OPERATED RELIEF VALVE
Psig
POUNDS PER SQUARE INCH GAGE
PZR
PRESSURIZER
QUALITY ASSURANCE
QPT
QUADRANT POWER TILT
QATTS
QUALITY ASSURANCE TRACKING AND TRENDING SYSTEM
RADIATION CONTROL AREA
ROOT CAUSE EVALUATION
REACTOR COOLANT PUMP
REJ
RUBBER EXPANSION JOINT
ROENTGEN EQUIVALENT MAN
RFD
REFUELING OUTAGE
RMT
RECIRCULATION MODE TRANSFER
REACTOR OPERATOR
RADIATION WORK PERMIT
REFUELING WATER STORAGE TANK
SCFH
STANDARD CUBIC FEET PER HOUR
SAFETY EVALUATION
SNOS
STATION NUCLEAR OVERSIGHT
SNSOC
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SENIOR REACTOR OPERATOR
.
. ,....;-,
'1 *
ss
TM
TS
voe
VPAP
SHIFT SUPERVISOR
THREE MILE ISLAND
TECHNICAL SPECIFICATION
UPDATED FINAL SAFET°Y ANALYSIS REPORT
UNRESOLVED ITEM
ULTRASONIC TEST
VOLT DIRECT CURRENT
VIRGINIA ELECTRIC AND POWER COMPANY
VIOLATION
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
. WORK ORDER
WORK REQUEST