ML20128H695
| ML20128H695 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 10/02/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20128H654 | List: |
| References | |
| 50-369-96-07, 50-369-96-7, 50-370-96-07, 50-370-96-7, NUDOCS 9610100036 | |
| Download: ML20128H695 (22) | |
See also: IR 05000369/1996007
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U.S'. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket Nos:
50-369. 50-370
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Report No: 50-369/96-07, 50-370/96-07
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Licensee:
Duke Power Company
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Facility:
McGuire Generating Station. Units 1 & 2
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Location:
12700 Hagers Ferry Rd.
Huntersville NC 28078
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Dates:
July 28 - September 7. 1996
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Inspectors: S. Shaeffer. Senior Resident Inspector
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G. Maxwell. Senior Resident Inspector
M. Sykes Resident Inspector
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G. Harris. Resident Inspector
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S. Rudisail. Project Engineer
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Approved by:
L. Wert. Acting Chief
Projects Branch 1
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Division of Reactor Projects
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Enclosure 3
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9610100036 961002
ADOCK 05000369
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EXECUTIVE SUMMARY
McGuire Generating Station. Units 1 & 2
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NRC Inspection Report 50-369/96-07. 50-370/96-07
This integrated inspection included aspects of licensee operations, engineer-
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ing, maintenance, and plant support. The report covers a 6-week period of
resident inspection.
Ooerations
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Failure to perform TS required surveillance involving onsite Emergency
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AC Power was identified as Violation 50-369. 370/96-07-01
(paragraph 04.1).
A failure to monitor waste gas tank activity limits was identified as a
non-cited Violation. (paragraph 04.1)
Operator response to the initial indications of a Unit 1 steam generator
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tube leak were considered good (paragraph 04.2).
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Performance during the recent Emergency Drill identified that Operations
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was not able to activate the Standby Shutdown Facility within 10 minutes
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to preclude potential reactor coolant pump seal damage during a loss of
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all AC event.
Immediate corrective actions were taken which modified
operating procedures to immediately implement SSF activation procedures
during a loss of all AC event.
IFI 50-369.370/96-04-05 will remain open
for additional review (paragraph Pl.1).
Maintenance
The licensee identified a failed Unit 2 Train B Bypass Reactor Trip
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Breaker auxiliary switch connection during Solid State Protection System
testing.
The inspectors concluded that the replacement of the breaker
component was performed in an adequate manner. (paragraph M2.1)
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Potential improper electrical isolation for Post Accident Monitoring
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instrumentation was identified as URI 50-369.370/96-07-03 (paragraph
M7.1)
Enoineerina
An inadequate design of containment airlock door testing components was
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identified as a non-cited Violation. (paragraph E8.1)
Deviation 50- 369. 370/96-07-04 was identified for failing to meet an
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NRC commitment specified in the licensee's response to Generic Letter 88-03. Steam Binding of Auxiliary Feedwater Pumps.
Also, an additional
example of URI 50-369.370/96-04-02. FSAR Inconsistencies, was identified
related to the licensee's operation of the Auxiliary Feedwater system.
(paragraph E7.1)
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Executive Summary
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An inadequate 10 CFR 50.59 evaluation for the Unit 1 and Unit 2
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auxiliary feedwater system was identified as Violation 50-369. 370/96-
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07-05. The licensee failed to fully evaluate the effects of system
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voiding and also did not adequately address system temperatures
exceeding piping design limits.( paragraph E7.1)
Failure to take effective corrective action for an EDG fuel line failure
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was identified as a violation of 10 CFR50. Appendix B. Criterion XVI.
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This was identified as Violation 50-369. 370/96-07-07. (paragraph E8.2)
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A weakness was identified for not re-evaluating system operability when
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the root cause was established (paragraph 03),
The inspectors identified that the timeliness of actions to correct
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previously identified problems involving fuse replacement needed to be
re-evaluated based on recent failures which resulted in inoperable ECCS
sub-systems. (paragraph 02.1)
Plant Sucoort
A review of the August 5. Emergency Preparedness Table Top Exercise
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Drill concluded that the scenario was realistic and the overall
emergency preparedness training was conducted in a professional manner.
(paragraph Pl.1)
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Enclosure 3
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Reoort Details
Summary of Plant Status
Unit 1 operated at 100 percent power throughout the ins)ection period. On
August 30. the licensee identified a steam generator tu]e leak in the 1 B
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At the close of the inspection period, the leak rate
remained stable at approximately 6 gpd.
Unit 2 operated at 100 percent power throughout the period.
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I. Operations
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Conduct of Operations
01.1 Gene al Comments (71707)
Using Inspection Procedure 71707. the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below.
02
Operational Status of Facilities and Equipment (71707)
02.1 Fuse Failure in RN Modulatina Valve Reset Circuitry
a.
Insoection Scooe
On July 17 while conducting routine control board surveillance the
control room operators discovered that an indicating light in the RN
modulating valve circuitry was
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Further investigation
by the licensee revealed that a fuse had blown preventing a single train
of safety-related control valves in the service water, residual heat
removal, component cooling water, and control room ventilation systems
from moving to their safe position during accident conditions.
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position of the control valves are controlled by non-safety controllers
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and non-safety instrumentation.
b.
Observation and Findinas
The blown fuse was determined to be an FNQ type fuse.
These fuses had
earlier been determined to be suspectable to failure due to a known
design flaw.
The licensee had scheduled these fuses to be replaced
with FLQ type fuses under a station modification in 1997. The failure
of the fuse could significantly complicate the mitigation and recovery
from an accident if the fuse were to fail with the other safety train
components not available.
The licensee replaced the affected fuse and modified surveillance
requirements such that control room operators would monitor all ESF
Enclosure 3
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modulating valve reset indications to ensure associated circuitry was
functioning properly.
The licensee also prepared a training package to
inform operators of the effects of modulating valve circuitry power
failures. The inspector noted that the licensees immediate corrective
action did not include replacing similar fuses in the remaining RN
modulating valve circuits. The inspector discussed this concern with
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Engineering management.
By the end of the inspection period, the
l'censee indicated that a re-evaluation of the FNQ fuse replacement
schedule would be performed to eliminate other potential fuse failures
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that significantly impact plant safety.
c.
Conclusions
The inspectors concluded that the timeliness of corrective actions
involving fuse replacements to correct previously identified problems
needed to be re-evaluated based on recent failures which resulted in
inoperable ECCS sub-systems.
03
Operations Procedures and Documentation (71707)
During the inspection period, the inspector questioned the licensee
regarding the process for re-evaluating operability of degraded systems
and/or components after root cause determinations have been made.
Specifically, the inspector noted that a documented re-evaluation of
operability was not performed when a root cause for a EDG fuel line
failure was finally determined (subsequently discussed in paragraph
(E8.2). The ins)ector concluded that the licensee's process was weak,
such that, a metlod was not in place for ensuring that re-evaluations of
all operability aspects were made after the root causes were determined.
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The inspectors discussed this example with the licensee.
PIP 0-M-2156
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was initiated to review the inspectors concern for potential process
improvements to ensure operability assessments are performed when
necessary.
04
Operator Knowledge and Performance (71707)
04.1 Failure to Perform Technical Soecification Action Reauirements
a. -Insoection Scooe (93702)
During the inspection period, the licensee failed to perform the
requirements for Technical Specifications surveillance test within the
specified time interval.
These cases invMyed surveillance tests on an
EDG and a waste gas decay tank.
b.
Observations and Findinas
On July 17. 1996, the licensee declared the 1B RN train inoperable due
to a blown fuse in the modulating valve circuitry, which resulted the IB
diesel being declared inoperable (also discussed in paragraph 02.1). TS
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3.8.1.1 requires that if a diesel is declared inoperable. the opposite
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train emergency diesel generator be tested per TS 4.8.1.1.2a(4) and
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4.8.1.1.2a(5) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The Unit 1 Train B emergency diesel
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generator was declared inoperable when a fuse failed in modulating valve
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circuitry that affected several safety-related systems including the
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nuclear service water system. The opposite train diesel was not run
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within the required time period as required by TS.
However, a
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subsequent review by the licensee revealed that the nuclear service
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water system was operable but in a degraded condition. The inspector
noted that this determination did not take place until after the
surveillance period had expired for the test to have been performed on
the opposite train emergency diesel generator.
On August 6. 1995. RP 3ersonnel discr"', ed that a TS surveillance was
not performed within t1e required time period. Technical S>ecifications
surveillance 4.11.2.6 requires that the waste gas decay tants be
monitored once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to ensure proper curie content. The
activity limit of 49.000 curies is verified by the radiation protection
technicians measuring dose rates at designated locations outside the
waste gas decay tank room.
RP technicians subsequently performed the
surveillance and determined that the curie content of the tank did not
exceed the Technical Specification requirements. The failure to perform
the required monitoring of TS 4.11.2.6 is a violation.
This licensee
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identified and correcte'i violation is being treated as a Non-cited
Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy
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(50-369.370/96-07-02. Failure to Monitor Waste Gas Tank).
c.
Conclusion
The failure to conduct TS surveillance requirements within the specified
time interval is a Violation.
The Violation will be identified as
50/369.370 96-07-01. Failure to Perform Surveillance Testing within
Specified Time Interval for the Emergency Diesel Generator..
A NCV was
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identified for failure to monitor the waste gas decay tanks as required.
04.2 Unit 1 Steam Generator B Tube Leak Indication
a.
Insoection Scooe
On August 30, 1996, at approximately 5:00 p.m.. Unit 1 operators
responded to indications of a SG tube leak on the B SG.
The inspector
responded to the control room to monitor the plant indications and the
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operators response to the problem.
b.
Observations and Findinas
Initial indications of the tube leak were via annunciation of EMF-33.
Condenser Air Ejector Exhaust Radiation Monitor, followed by indications
of a change in the N-16 (Nitrogen 16) monitor for the B SG. The B loop
N-16 monitor (on main steam line B) indicated an approximate 20 to 25
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gpd leakage.
Immediate operator response to the problem included:
entered AP/1/A/550/10. Rev.2. Loss of ND or ND system Leakage: initiated
Emergency Coordinator for event: initiated trending of affected
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radiation monitors including SG blowdown: and initiating RCS leakage
calculations and chemistry sampling. Operator reviews of other control
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board parameters were performed and no other indications of tube leakage
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was observed. At approximately 6:30 p.m. , chemistry sampling confirmed
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that the leakage in the B SG and was approximately 5.8 gpd.
TS
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3.4.6.2.c requires that RCS leakage through any one SG be limited to 500
gpd. At the time of the event. the licensee's administrative limit (ie.
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to evaluate potential shutdown of the unit) was 50 gpd: therefore, no
other immediate actions were required.
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Other activities observed by the inspectors included the continued
monitoring of the Unit 1 tube leakage via chemistry sampling and leakage
calculations through the enri of the assessment )eriod. The leakage
estimate remained at approximately 6 GPD throug1 the end of the period.
The inspector considered that the monitoring was performed in a
conservative manner and of a higher frequency than that required by
plant procedures. Management concern with the problem was apparent
The McGuire Unit 1 SG's are scheduled to be replaced during a refueiing
outage scheduled to begin February 1,1997.
c.
Conclusion
The inspector concluded that the operators response to and subsequent
monitoring of the Unit 1 SG B tube leakage was good.
08
Miscellaneous Operations Issues (92901)
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08.1
(CLOSED) LER 50-370/95-01
Past Inocerability of Unit 2 Containment
On February 8,1995, the hcensee determined that the
degraded piping at the Excess Letdown Heat Exchanger had rendered the
associated penetrations 2-M2117 and 2-M2118, inoperable.
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penetrations depend on the piping integrity to act as a second boundary
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instead of having a redundant isolation valves.
Because the crack was
located in a section of component cooling water piping between the
penetrations, the licensee determined that the loss of component cooling
water system integrity may have prevented the penetrations from
fulfillment of their safety function.
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The inspectors reviewed and evaluated the licensee's corrective actions
and determined that the licensee's actions have been completed in
accordance with the established schedule.
The corrective actions
included extensive ultrasonic testing of the component cooling water
system piping and adjustments to system water chemistry to reduce tne
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likelihood of additional nitrate induced intergranular attack.
Based on
the inspectors evaluation of the corrective actions and the absence of
additional component cooling water system piping failures attributed to
stress corrosion cracking, the inspectors concluded that the licensee's
actions were appropriate. This item is closed.
08.2 (CLOSED) LER 50-369.370/95-04:
Manually Initiated Actuation of Both
Unit 2 Motor Driven Auxiliary Feedwater Pumos Due to Loss of Auxiliary
Steam Suoolv to the Main Feedwater Pumo Turbine:
This LER documented
the loss of steam flow from the Auxiliary Electric Boilers to Unit 2
resulting in reduced main feedwater pump output.
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Corrective actions included revisions to the Breaking Vacuum procedure
and procedures OP/2/A/6100/02, Controlling Procedure for Unit Shutdown
and OP/0/B/6250/07A, Auxiliary System Alignment.
The inspector verified
the revisions to these procedures were adequate to correct the
deficiency.
This LER is closed.
II. Maintenance
M1
Conduct of Haintenance
M1.1 General Comments (61726 and 62703)
a.
Insoection Scope
The inspectors observed all or portions of the following work
activities:
PT/2/A/4204/01
RHR Pump Performance Test
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IP/0/A/3250/12
Train A Diesel Sequencer Timer Calibration
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PT/1/A/4350/17
EDG Fuel Oil Transfer Pump Performance
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Test
PT/2/A/4600/01
RCCA Movement Test
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PT/0/A/4601/08
SSPS Train B Periodic Test With NC System
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Pressure > 1955 PSIG
PT/2/A/4350/15
Diesel Generator Periodic Test
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PT/2/A/4202/04
Spent Fuel Pool Pump 2B Air Handling Unit
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Performance Test
PT/0/A/4457/01
Control Room Chilled Water Pump #2
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Performance Test
IP/0/A/3050/13
RWST Class 1E Level Transmitter
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Calibration
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b.
Observations and Findinas
The inspectors witnessed selected surveillance tests to verify that
approved procedures were available and in use, test equipment in use was
calibrated, test prerequisites were met, system restoration was
completed, and acceptance criteria were met.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Reactor Trio Bvoass Breaker 2B
a.
Insoection Scooe
During Solid State Protection System functional testing, the P-4 Turbine
Trip on Reactor Trip interlock on the Unit 2 B Train Bypass Reactor Trip
breaker (RTB) failed to function as expected.
The licensee was in the
3rocess of verifying a direct short circuit across a closed contact;
lowever, resistance measurements were too high to be indicative of a
direct short. The high resistance values indicated that the contact was
not closed as expected.
Since the contacts associated with the P-4
circuit could not be visually examined with the breaker racked in, the
licensee terminated the test, racked in the Train B normal RTB. and
removed the bypass RTB for inspection. Once the Train B Main RTB was
racked in and closed, the B Train was declared fully operable.
b.
Observations and Findinas
After removal of the bypass RTB from the cubicle, no visible damage was
identified however, circuit resistance measurements continued to
indicate higher than ex>ected. The breaker was quarantined for further
evaluation and troubles 1ooting.
In an effort to isolate and identify
the open contact, the licensee measured resistances throughout the
circuitry including the secondary contact disconnect assembly. The
licensee concluded that the open contact was most likely located
internal to the auxiliary conta,t assembly block.
The licensee was
unable to confirm this conclusion, because during the troubleshooting
activities. the high resistance measurements returned to normal. The
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licensee removed the auxiliary switch assembly for additional analysis
and a new assembly was installed and tested on the breaker in accordance
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with work order WO96062149. The breaker was verified to respond
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properly and was returned to its ) retest cubicle position.
The licensee
postulated that the cause of the ligh resistance was a poor connection
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through the auxiliary switch contact.
The licensee stated that the
resistance measurements observed were not indicative of an open circuit:
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however, it did exhibit a higher than expected resistance.
As a result of the surveillance finding, the licensee concluded that
when the breaker was in the connect position, the P-4 interlock was not
operalle through B Train (P-4 interlock generates a turbine trip on a
reactor trip). Although the turbine trip on reactor trip would not have
functioned, this function is a non-safety-related function to prevent
overcooling of the reactor coolant system and the auxiliary switch
contact associated with the trip circuitry had no impact on the bypass
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RTB's ability to open upon receipt of a manual or automatic reactor trip
signal.
c.
Conclusions
The inspectors reviewed the licensee's response to the surveillance test
finding and determined that the licensee's actions were appropriate and
completed within a reasonable time.
The inspectors evaluated the
potential reportability of this test failure and determined that since
this failure did not involve a failure of the shunt or undervoltage
coils, the failure was not reportable. The inspectors also recognized
increased licensee efforts to resolve the issue in a timely manner.
M7
Quality Assurance in Maintenance Activities (92903)
M7.1
Inadequate Electrical Isolation of Post Accident Monitoring Circuitry
a.
Insoection Scooe
On June 6. while troubleshooting the operator aid computer point for RCS
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wide range cold leg temperature the licensee determined that a minor
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modification implemented in the mid 1980s to ensure proper isolation of
the safety-related post accident monitoring instrumentation from non-
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safety circuitry was not properly completed. The original Nuclear
Safety Modification (NSM) required the addition of isolation devices and
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assecuted input and output wiring changes.
b.
Observation and Findinas
An investigation by the licensee revealed that the output wiring changes
were not adequately implemented resulting in improper isolation of the
PAM recorder and computer point.
Use of the wide range cold leg
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temperature indication is referenced both in abnormal and emergency
operating procedures.
Station FSAR section 1.11.5.1.3.1. requires that
for each process variable the recorded channels be enhanced through the
addition of isolators such that the control board recorders will not
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share isolators with the non-safety plant computer.
The licensee
promptly completed the modification and successfully performed
functional testing.
c.
Conclusions
The inspectors questioned why implementation instructions and quality
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assurance verifications did not ensure the modification was properly
installed. The inspectors reviewed the engineering instructions and
noted deficiencies that could have contributed to improper installation
of the isolators. The inspectors reviewed the licensee's corrective
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action and noted that adequate controls were currently in place to
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prevent recurrence. The inspectors verified that other similar
modifications were installed properly. In addition to the above. the
inspectors questioned the licensees determination of past operability
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and reportability of the issue.
Based on the above. the ins)ectors will
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continue to evaluate the issue via URI 50-369.370/96-07-03.
)AM Recorder
Isolator Wiring Modification.
Resolution of this issue will be based on
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determination of root cause, additional analysis of the significance of
the event, and other items as discussed.
III. Enaineerina
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E2
Engineering Support of Facilities and Equipment (37551)
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E2.1 Engineering Evaluation of Letdown Orifice Isolation Va'lve
a. Insoection Scop.g
The inspector reviewed the licensee's assessment of letdown orifice
isolation valve 2NV-458A operability and the compensatory measures
established for this leaking valve.
b. Observations and Findinas
During the inspection period valve 2NV-458A was determined to have seat
leakage.
The licensee identified this problem during an attempt to swap
letdown orifices to reduce radiation levels in the Unit 2 Lower
Containment Pipe Chase for a containment entry. The licensee evaluated
operability of the valve problem with respect to the containment
isolation function of the valve and determined that the isolation
function was operable.
Based on NRC questioning if additional
operability evaluations were needed for other scenarios, the licensee
identified a second evaluation was necessary to evaluate the potential
effects of high temperature letdown fluid passing through the tube side
of the LDHTEX and heating the KC system shell side (non-essential
header).
The KC system Auxiliary Building Non-essential header is
isolated by a safety injection signal.
The evaluation concluded that
the safety-related portion of the KC system and associated equipment
would not be impacted by steam voiding which could occur in the
Auxiliary building non-essential header at the LDHTEX.
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The licensee determined that the containment inlation function of the
valve was operable.
The isolation of the piping was also considered
operable. but degraded. Compensatory measures were subsequently
established to mitigate the possible consequences of this degraded
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condition.
c.
Conclusion
The inspector reviewed the licensee evaluation of the valve leakage.
The inspector determined that the evaluation was conservative: however.
NRC questioning resulted in more in-de]th operability review.
Compensatory measures planned and esta)lished were adequate.
E7
Quality Assurance in Engineering Activities (37551, 92903)
F7.1 Auxiliary Feedwater System Temperature Monitoring
a.
Insoection Scooe
On July 19, while investigating Unit 1 auxiliary feedwater injection
line temperature alarms, the licensee determined that the RTD
temperature indications were non-conservative. -The RTDs were reading
30-40 degrees less than the actual piping temperature measured using
portable monitoring equipment.
The RTD s installed in response to
Generic Letter 88-03. Steam Binding of Auxiliary Feedwater Pumps, had
been used to measure auxiliary feedwater system piping temperatures to
detect the presence of steam voids that could lead to steam binding of
auxiliary feedwater pumps. These RTDs continuously monitor and provide
computer alarms to warn control room operators of higher than expected
system temperatures.
Operators are directed to take specific actions
based on high piping surface temperatures.
The licensee subsequently
determined that the installed RTDs were not the correct type.
They were
intended for use in a thermowell rather than a strap-on surface mounted
application.
b.
Observation and Findinas
The licensee implemented compensatory measures to monitor piping surface
temperatures once daily during the period of peak ambient temperatures
using a' portable hand held measuring device.
However, the inspectors
noted that the licensee did not proceduralize the temperature monitoring
process to ensure consistency in the technique used to gather piping
tem]erature data and initially used less sensitive temperature measuring
pro)es to collect data. The licensee initiated a temporary modification
to change an RTD on the piping with the hottest temperatures to a new
strap-cn surface mounted type correct for the application.
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Following installation, on August 5,1996, the readings from the new RTD
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showed piping temperatures in excess of the procedural temperature
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limits recuiring operator action. The temperature exceeded the piping
design anc saturation temperature of the system, prompting the licensee
to conclude that steam voids existed in the piping.
The presence of
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steam voids could create a potential for water hammer and subsequent
pipe damage.
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As a result, operators immediately declared the 1A MDAFW pump
inoperable. Subsequently, the TDAFW pump was also declared inoperable.
Control room operators immediately took actions in accordance with
procedures to cool the piping. These actions included closing the
affected line isolation valve and running the AFW pumps.
Compen.3 tory measures were subsequently revised to monitor the CA pump
discharge piping once per shift to ensure that the temperature was below
required limits.
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The inspectors reviewed the operability determinations made to address
the identified steam void pro)lems. To validate their o)erability
decision, the licensee conducted a test to demonstrate tlat no water
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hammer would result even with the presence of steam voids. The steam
voiding initially was determined to be caused by direct heating of the
CA injection check valves from CA tempering flow and some minor back
leakage through the check valves. To create the test conditions the
licensee allowed the CA piping to heatup and create steam void
conditions.
The licensee then o)erated the motor driven CA pump with
the CA isolation valve closed. T1e licensee did not observe any
indications of a water hammer event.
The inspectors reviewed the evolution and determined that although the
licensee had conducted some preliminary technical evaluations prior to
conducting the test, an inadequate 50.59 evaluation was performed to
determine whether or not an unreviewed safety question existed. The
licensee )erformed the test and demonstrated that no water hammer would
occur wit 1 the presence of steam voids.
The licensee also subsequently
conducted an 50.59 evaluation to confirm that no unreviewed safety
question existed under the test conditions.
In addition, the inspectors
questioned the licensee concerning continued operation with steam
voiding in the auxiliary feedwater piping.
As a result, the licensee
expanded the evaluation and concluded that with the presence of steam
voiding an unreviewed safety question did not exist.
The inspectors noted other discrepancies.
Updates to the FSAR were not
performed to reflect the installation of the RTDs and CA system drawings
depicting placement of the RTDs were not consistent.
The licensee conducted an evaluation and determined that despite
exceeding piping design temperatures, the piping was operable.
The
inspectors reviewed the evaluation and concluded it was adecuate. The
licensee conducted ultrasonic examinations of the piping anc determined
that the extent of voiding in the piping was greater than the original
estimate. The cause of the voiding was determined to be backleakage
Enclosure 3
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_
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.
. - - - .
. - - . - - - - .
- - - _ _ _ - - - - - - - - - . -
!
.
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.
i
11
through the injection line check valves. As a result, additional
i
compensatory measures were implemented to maintain system operability.
4
By the end of the ins)ection period. the licensee had replaced all
existing RTDs with tie new strap on surface mounted type.
The licensee
'
also increased the OAC alarm setpoints and revised o)erating procedures.
The inspectors conducted field walkdowns of the new RTD to verify
4
i
correct installation.
In addition, the licensee began engineering
evaluations to eliminate tempering flow in the CA injection line. This
4
!
function will also be permanently eliminated.during the upcoming SG
j
replacement projects on both units.
l
c.
Conclusions
a
The inspectors concluded the licensees immediate corrective action was
good.
Corrective action such as replacing the RTDs and evaluation of
i
the elimination of tempering flow were also good.
However, some
deficiencies in problem assessment caused delays in the formulation and
.
implementation of adecuate compensatory measures and problem resolution.
'
The inspectors concluced that the licensee installed the wrong type RTDs
which deviated from the response to commitments for Generic Letter 88-
03. Steam Binding of Auxiliary Feedwater Pumps to continuously monitor
i
the discharge piping, provide alarms. 0AC graphics and applicable
procedures to prevent steam binding of auxiliary feedwater pumps.
'
I
In addition initial compensatory measures to manually take AFW piping
temperatures were inadequate due to poor technique and/or wrong
'
temperature ) robe application.
The inspectors noted that the licensee
maintained tie requirements to monitor piping by touching AFW pump
piping during NLO rounds.
j
i
l
The failure to comply with the requirements of this commitment is
i
identified as a Deviation. 369. 370/96-07-04 Failure to Comply with
l
Commitments in Response to Generic Letter 88-03. Steam Binding of
j
Auxiliary Feedwater Pumps.
!
The inspectors also determined that the licensee's failure to perform an
,
adequate 50.59 evaluation to fully evaluate the effects of AFW system
!
steam voiding prior to conducting a test was a Violation. 50-369/370.
96-07-05. Failure to Perform a 50.59 Evaluation prior to Conducting a
i
i
Test.
The failure to update the FSAR to reflect the installation of the
'
i
RTDs will be identified as an additional example of URI 96-04-02. FSAR
j
Inconsistencies,
f
E7.2 Grinnell Hydraulic Snubber Desian Inadeouacies
1
!
a.
Insoection Scooe
}
The licensee determined that hydraulic snubbers manufactured by Grinnell
!
would not meet post accident environmental cualification specifications
!
that included requirements for radiation anc temperature.
Specifically,
j
procurement specification MCS-1206.00-04-0003. Rev. 2 requires that the
snuobers ue capable of performing their safety function under radiation
conditions equal to 7X10E8 rads and 350 degrees F.
i
Enclosure 3
!
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i
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. - - ~ _ - . - .
--
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.
'
1
3
.
1
12
b.
Observations and Findinas
,
The manufacturer confirmed that the Grinnell snubbers re)lacement parts
4
that included seals, polycarbonate reservoirs and fluid lad not been
qualified for these environmental conditions.
The hydraulic snubbers
.
were designed to " lock up" and restrain the pipe movement during a
j
dynamic loading condition. The snubbers also allow for slow movement
j
caused by thermal expansion. The dynamic loading conditions include
events such as a Safe Shutdown Earthquake and pipe ruptures associated
'
I
with a Main Steam Line Break (MSLB) or a Loss of Coolant Accident. The
licensee determined that the worse case dynamic loading conditions
occurred during a (MSLB) accident with lower containment temperatures
j
exceeding 325 degrees F for more than 8 minutes. However, under these
accident dynamic loadings conditions, the snubbers immediately performed
the function to " lockup" and restrain the ruptured pipe.
Subsequently.
.
the high containment temperatures resulting from the main steam line
.
pipe rupture cause a significant distortion of the polycarbonate
!
reservoirs containing the hydraulic fluid. This results in some
leakage.
The licensee also determined that despite leakage and
'
subsequent increase in fluid viscosity caused by post accident
conditions, the snubbers would function to allow thermal expansion of
l
the ruptured piping. The ins)ectors reviewed the operability
determination and concluded tlat it was adequate. The inspectors also
'
performed an inspection of selected safety systems to examine snubbers
for existing defects and snubber inoperability.
No deficiencies were
!
identified.
1
c.
Conclusions
The licensee determined that although the Grinnel snubbers have not been
qualified to meet the environmental accident conditions per McGuire's
procurement specification. the snubbers will perform their design
4
function and are acceptable.
The licensee is currently evaluating
,
changes to procurement specifications. pipe support and restraint design
'
specifications, and is revising the FSAR to clarify the snubber post
,
i
accident environmental temperatures and radiation level requirements.
In addition, the vendor is currently evaluating whether a Part 21
'
j
notification should be issued on the subject.
4
E8
Miscellaneous Engineering Issues (92902)
'
E8.1
(CLOSED) URI 50-369.370/96-06-04: Personnel Airlock Leakaae Detection
'
System Desian Deficiency:
The inspectors evaluated the licensee's
,
res)onse to deficiencies identified in the airlock seal automatic
leacage detection system deeign to ensure pro)er performance of the
upper and lower personnel ai r locks for both Jnit 1 and Unit 2 personnel
!
airlocks. The Volumetric, Model 14330 Automatic Leakage Rate Monitor
(LRM) had been declared inoperable due to design deficiencies discovered
4
i
during bench testing. The automatic LRM would provide accurate door
seal leakage measurements up to the calibrated maximum flow range value
,
(1000 sccm) but was found to count back during overrange conditions.
'
I
J
Enclosure 3
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.
'
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l
13
,
i
Once the LRM was declared inoperable, the licensee performed manual
airlock door seal testing on a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> frequency to satisfy TS
i
requirements.
'
ll
The licensee contacted the equipment manufacturer to discuss options to
correct the equipment deficiency. The vendor recommended replacement of
the flow sensors. Once the replacement aarts were procured. the
licensee implemented Minor Modification iGMM-8568 to install the
{
replacement components in each of the LRMs.
The modification was tested
and functioned properly up to 2000 sccm.
The Volumetrics units were
!
then declared operable. The airlock was also determined to have been
past o)erable.
The licensee completed reviews of previous manual
.
i
airlocc seal test data and confirmed that actual leak rates were well
'
below the maximum calibrated range of the system and the leakage values
did not approach overrange conditions.
The inspectors concluded that testing of the equipment following the
original installation was not adequate.
However, based on the
licensee *s identification of this design defect during bench testing,
the prompt corrective action taken to ensure equipment operability, and
the perceived safety significance, the inspectors determined that this
licensee-identified and corrected violation will be treated as a Non-
Cited Violation. 50-369.370/96-07-06: Personnel Airlock Leakage
Detection System Deficiency, consistent with Section VII.B.1 of the NRC
E8.2 (CLOSED) URI 50-369.370/96-06-01:
Failure Analysis for 1B EDG Fuel Line
Failure:
During the previous inspection period, on June 19. 1996, the
licensee experienced a failure of the 4R cylinder fuel line on the IB
EDG. The subject URI was identified to review the licensee's root cause
evaluation of the failure to determine the adequacy of the corrective
actions taken for all the EDGs. On July 18, 1996. the licensee issued a
root cause evaluation report of the IB EDG fuel line failure on the 4R
cylinder.
The failure was attributed to tube pullout of the 4R cylinder
fuel injection line to fuel pump connection.
Specifically, the report
concluded the line had ejected from the ferrule connection due to
inadequate crimping of the ferrule to the tube. All the fuel lines on
the Unit 1 EDGs had been u> graded to a new double-walled tube design in
i
December 1995 to prevent t1 rough wall crack propagation. The Unit 2
EDGs fuel lines were previously replaced (all but four were upgraded
double-wall) during earlier unit refueling cycles and had not
'
experienced any failures. Corrective actions were developed to recrimp
i
all a>plicable EDG fuel lines on Unit 1 and the four selected fuel lines
'
for t1e Unit 2 EDGs.
These actions were scheduled to occur concurrent
with the routinely scheduled EDG outage days (ie. one EDG per month) to
minimize unavailability.
,
The proposed recrimping schedule was based. in part, on a perceived
ability to predict a failure of the lines via analysis of cylinder
i
exhaust temperature.
Specifically, a review of historical exhaust
temperature data prior to the first failure indicated that the 4R
j
cylinder had been experiencing a slow decrease in temperature which was
an indication of a small, undetectable fuel leak.
Secondly, the
Enclosure 3
.
-
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14
I
licensee had previously performed a torsional analysis evaluation on the
,
McGuire Nordberg EDG crankshafts which concluded that operation of the
EDG could continue with the failure of a cylinder fuel line.
The study
indicated that the fuel sup)1y to a failed cylinder could be shut off
and with the exception of t1e number 1 cylinder (furthest from the
flywheel) the EDG would perform adecuately under full load.
'
Additionally, the licensee performec a visual inspection of all the fuel
lines with no evidence of pullout or misalignment observed.
During the current inspection period on July 30. 1996, the licensee
experienced an additional failure of the 1B EDG 4R cylinder, prior to
performing the recrimping as discussed above.
Based on the second
failure at the same location, the licensee expanded their original root
cause investigation process and obtained the services of two separate
vendors to act as oversight for the failure analysis and to provide
technical expertise.
The second revision to the root cause analysis
concluded that the most likely cause of the second failure was improper
crimping of the sleeve onto the fuel line, possibly aggravated by some
pressure increase at the fuel pump outlet.
The increased fuel pressure
may have been caused by slight fouling of the injector nozzles.
Additional contributing factors may have included: reduced delivery
,
valve holder assembly torque introduced as a corrective action to PIP 1-
M94-1022 which reduced the ability to make-up for the inadequate
manufacturing crimping process: and excessive fuel line extending past
the ferrule which could cause the line to bottom into the delivery valve
heider. The inspectors noted that the licensee also concluded that the
i
monitoring of cylinder exhaust temperatures was not as good of a failure
indicator as previously expected.
Based on the revised root cause, the licensee performed significantly
expanded their corrective actions. These PORC reviewed actions
included:
'
-
For the 1B EDG, fuel lines were recrimped, fuel line ends were
machined for pr Sper ferrule positioning, and a 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> run
,
performed to verify the recrimping process.
'
-
Replaced both injector and fuel pump on the 4R cylinder and
inspected the two additional injectors for contamination.
No
contamination was identified.
-
Ferrule connections and the crimping process was reviewed by an
industry expert.
Removed, recrimped, machined tube ends, and reinstalled all fuel
-
injection lines for the 1A, 2A, and 2B EDGs in an expedited
manner.
The inspectors reviewed the licensee's final root cause analym:; report
dated August 30. 1996. and discussed the corrective actions and
conclusions with the licensee.
Based on the inspectors monitoring the
implementation of the subsequent corrective actions, attending PORC
reviews of the event, and visually inspecting the fuel line repairs the
Enclosure 3
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15
1
inspectors concluded that the current root cause review was thorough.
4
However, based on the occurrence of the second failure. the inspectors
'
also concluded that the corrective actions for the first fuel line
failure were inadequate to preclude an additional failure from
occurring.
This issue will be identified as Violation 369. 370/96-07-
07. Failure to take Adequate Corrective Action for EDG Fuel Line
Failure.
The URI concerning this issue is closed.
IV. Plant Support
t
R1
Radiological Protection and Chemistry Controls (71750)
4
Plant support activities were observed and reviewed to er.sure that
programs were-implemented in conformance with facility policies and
I
procedures and in compliance with regulatory requirements. Activities
reviewed included radiological controls, physical security, emergency
j
preparedness, and fire protection.
!
R1.1 Radiation Monitors Survey
!
The inspectors performed a survey of TS radiation monitors.
The
'
inspectors reviewed radiation monitor unavailability data. The data
'
showed that the unavailability for TS radiation monitors was low. All
radiation monitors were operable at the time of the survey.
The
i
inspectors verified the operability of the TS related radiation monitors
by reviewing control room logs. TSAIL entries and control room
,
indications.
l
The inspectors concluded that TS radiation monitor unavailability for
l
the period reviewed was good.
P1
Conduct of EP Activities
Pl.1 EP Drill Observation (71750)
q
l
a.
Insoection Scooe
!
The inspectors reviewed an Emergency Table To) Exercise Scenario that
was scheduled to be performed on August 5.
T1e scenario was found to be
very realistic and re3 resented portions of a plant condition that
actually occurred on Jnit 1 during the month of June 1996.
On August 5.
"
the inspectors toured the Technical Su) port Center. Control Room, and
i
the Operational Support Center while tie Emergency Exercise Scenario was
,
being conducted.
b.
Observations and Findinos
j
The Table Top Exercise began with Unit 1 at 100% power and both EDGs
inoperable. The 1A EDG could be available in 10-12 hours and 1B EDG was
expected to be back in service in 4-5 hours.
A severe thunderstorm was
in the vicinity of the plant. A lightning strike resulted in a total
loss of offsite power for Unit 1.
With both Unit 1 EDGs inoperable and
Enclosure 3
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.
I
e
16
tagged out, a loss of all AC power was experienced on Unit 1.
The
reactor tripped and plant conditions worsened until a " Site Area
Emergency" was declared.
During the exercise. )lant conditions existed
that required the Standby Shutdown Facility (SS ) to be activated. The
!
critical time for activating the SSF is limited to a maximum time of 10
minutes. The basis for this time limit is to assure that the reactor
coolant pumps seals do not fail. The inspectors noted that it took 11
minutes after notification before the SSF was properly activated.
!
An exercise critique was conducted by the licensee drill evaluators
after the drill was completed. The evaluators discussed the
circumstances and conditions that resulted in the SSF not being
activated within the allowed time.
Plant management directed operations
to revise the Controlling Emergency Procedures and to require activation
of the SSF at an earlier step in the procedure.
Also, engineering was
directed to determine if the Westinghouse pump seals may have a grea'.er
failure time margin for the seals,
c.
Conclusions
The inspectors concluded that the training performed in support of
i
emergency 3reparedness was generally professional and thorough. The
scenario clallenged the operators and was effective in accomplishing
espected results.
However, during the drill a weakness was identified
in Operations ability to activate the Standby Shutdown Facility within
10 minutes as required by plant procedures to preclude potential reactor
coolant pump seal damage during a loss of all AC. The ins)ector will
continue to evaluate the significance of the problem via I I 50-
369.370/96-04-05. which was previously identified regarding the
licensee's ability to man the SSF within the allotted time.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspection on September 10. 1996.
The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
identified.
Enclosure 3
w
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.
.
17
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Boyle, J. , Manage". Safety Assurance (Acting)
Cross
R., Regulatory Compliance
Geddie. E., Manager. McGuire Nuclear Station
Herran, P., Manager. Engineering
Johnson, G., Training. Nuclear Generation Department
Loucks L., Radiation Protection Manager (Acting)
McNeekin.
T., Vice President. McGuire Nuclear Station
Nazar. M., Superintendent. Maintenance
Silver. J.. Manager. Operations Support
Snyder
J.. Manager. Regulatory Compliance
Thomas, K., Superintendent. Work Control
i
Thrasher. J., Manager Modification Engineering
i
Travis
B., Manager. Mechanical / Civil Equipment Engineering
Young. A. . Engineering. Nuclear Production Department
NRC
G. Maxwell. Senior Resident Inspector. McGuire
S. Shaeffer. Senior Resident Inspector McGuire
M. Sykes Resident Inspector. McGuire
G. Harris Resident Inspector McGuire
S. Rudisail. Project Engineer RII
i
Enclosure 3
x
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18
INSPECTION PROCEDURES USED
IP 92901:
Operations Followup
IP 92902:
Maintenance Followup
IP 92903:
Engineering Followup
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
IP 71707:
Plant of Operations
IP 71750:
Plant Support
IP 62703:
Maintenance Observations
IP 61726:
Surveillance Observations
IP 40500:
Effectiveness of Licensee Controls in Identifying, resolving , and
Identifying Problems
IP 37551:
Onsite Engineering
ITEMS OPENED. CLOSED, AND DISCUSSED
Ooened
VIO 50-369.370/96-07-01
Failure to Perform Surveillance on Emergency
Diesel Generators
NCV 50-369.370/96-07-02
Failure to Monitor Waste Gas Tank
j
URI 50-369.370/96-07-03
PAM Recorder Isolator Wiring Modification
DEV 50-369.370/96-07-04-
Failure to Comply with Commitments in Response
to Generic Letter 88 03. Steam Binding of
Auxiliary Feedwater Pumps
.
i
VIO 50-369.370/96-07-05
Failure to Perform a 10 CFR 50.59 Evaluation
Prior to Conducting a Test
NCV 50-369.370/96-07-06
Personnel Airlock Leakage Detection System
Design Deficiency
VIO 50-369.370/96-07-07
Failure to Take Adequate Corrective Action for
EDG Fuel Line Failure
Closed
i
LER 50-370/95-01
Past Inoperability of Unit 2 Containment
LER 50-369.370/95-04
Manually Initiated Actuation of Both Unit 2
Motor Driven Auxiliary Feedwater Pumps Due to
Loss of Auxiliary Steam Supply to the Main
Feedwater Pump Turbine
URI 50-369.370/96-06-04
Personnel Airlock Leakage Detection System
Design Deficiency
Enclosure 3
. . _ . _ . _ _ _ _ _ . _ . _ . _ _ _ . - _ _
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19
URI 50-369,370/96-06-01
Failure Analysis for 1B EDG Fuel Line Failure
Discussed
URI 50-369.370/96-04-02
FSAR Inconsistencies
LIST OF ACRONYMS USED
DEV
Deviation
Engineered Safety Feature
Final Safety Analysis Report
gpd
gallons per day
IFI
Inspector Followup Item
IR
Inspection Report
KC
Component Cooling System
LER
Licensee Event Report
Leakage Rate Monitor
Motor Driven Auxiliary Feedwater Pump
Non-cited Violation
Non-licensed Operator
NRC
Nuclear Regulatory Commission
Office of Nuclear Reactor Regulation
NSM
Nuclear Station Modification
OAC
Operator Aided Computer
Plant Operations Review Committee
Problem Investigation Process
Performance Test
RCCA
Rod Control Cluster Assembly
Reactor Coolant Pump
R0
Reactor Operator
Radiation Protection
'
RTB
Reactor Trip Breaker
j
Resistance Temperature Detector
Refueling Water Storage Tank
.
Spent Fuel Pool
)
'
SR0
Senior Reactor Operator
SSF
Standby Shutdown Facility
Standby Shutdown System
1
Turbine Driven Auxiliary Feedwater Pump
TS
Technical Specifications
TSAIL
TS Action Item List
Unresolved Item
i
Violation
Enclosure 3
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