ML20198P377
| ML20198P377 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 01/12/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20198P341 | List: |
| References | |
| 50-369-97-18, 50-370-97-18, NUDOCS 9801220095 | |
| Download: ML20198P377 (42) | |
See also: IR 05000369/1997018
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U.S. NUCLEAR REGULATORY' COMMISSION
REGION 11
Docket Nos: 50 369, 50 370-
License Nos: NPF-9, NPF-17-
Report No: 50 369/97-18, 50 370/97 18
Licensee: Duke Energy Corporation
Facility: .McGuire Nuclear Station Units 1 and 2
Location: 12700 Hagers Ferry Rd.
Huntersville, NC 28078
Dates: November 2 - December 13,1997
Inspectors: S. Shaeffer, Senior Resident Inspector
H. Sykes, Resident Inspector
M. Franovich, Resident inspector
N. Ecoriomos, Regional Inspector (Sections M1.2 M1.6)
R. Moore, Regional Inspector (Sections E2.1 and E7.1)
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-Approved by: C. Ogle Chief. Projects Branch 1
DivisioncfReactorProjects
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EXECUTIVE SUMi%RY
McGuire Nuclear Station. Units 1 and 2
NRC Inspection Report 50-369/97-18, 50-370/97-18
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covered a six week
period of resident inspection. In addition, it included the results of two
regional inspections reviewing Unit 2 outage modifications. Unit 2 steam
generator replacement project progress, and review of refueling water storage
tank design parameters.
Doerations
. The conduct of operations was professional and safety conscious
throughout the inspection period. Operations remained appropriately
focused throughout the Unit 2 No Mode period, during refueling, and
through initial heatup of Unit 2 from the outage. Dverallcontrolof
operations, which included turnovers, cognizance of ongoing activities,
and imalementation of conditional surveillances during this period was
cons <ed excellent, with few exceptions. (Section 01.1)
. The licensee's implementation and use of the newly established automated
operations narrative logging system was considered adequate to
effectively reconstruct, at a later date, details of significant plant
operational events. However, the inspectors noted varying logkeeping
practices among individuals which may indicate that more specific
guidance may be necessary. (Section 02.1)
- An Unresolved item was identified to review the root cause of the
mispositioning of a containment isolation valve during Unit 2 refueling
o)erations. Dperators missed several earlier opportunities to identify
t1e mispositioning during routine control board walkdowns. The
licensee's immediate corrective actions for the problem were appropriate
and overall containment integrity was determined not to have been4
compromised. (Section 02.2)
. The licensee identified a number of problems with initial operation of
the residual heat removal system during No Mode maintenance and testing.
Initial documentation of the problems was unclear: however, subsequent
engineering reviews determined no permanent damage was sustained by the
residual heat removal pumps. Subsequent system testing at the end of
the outage further verified system operability. Several procedural
revisions were identified to preclude future events. The inspectors
concluded that the overall coordination, procedure application, end
oversight of system operation during No Mode conditions was weak.
(Section 02.3)
- Reviews of licensee actions to implement cold weather preparations at
the site were acceptable. Nuclear System Directive 317 was issued which
provided additional structure and delineatd responsibilities for freeze
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protection. Procedures for verifying critical plant systems prior to l
exposure to predicted extreme cold weather and the monthly surveillance j
were good and provided additional assurance of operational readiness for 1
cold weather conditions. Construction of an enclosed and heated room
containing the new Unit 2 refueling water storage tank level
transmitters was a substantial improvement in refueling water storage l
Freeze
tank freeze protection reliability. initiated and completed in a timely manner. p
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Overall. the inspectors '
concluded that the licensee ~s efforts to effectively protect plant
equipment and systems from freezing conditions had improved. (Section
02.4)
. The inspectors concluded that the licensee's performance during core
alterations for McGuire Unit 2 Cycle 12 was good. Adequate training was
provided and appropriate emphasis was placed on nuclear and personnel
safety. Material condition of the fuel handling equipment supported a
safe core reload with minimal interruption. (Section 03.1)
Maintenance
. Routine testing activities were completed satisfactorily during the
inspection period. The successful completien of Unit 2 engineered
safety features testing was indicative of well performed outage
maintenance and excellent engineering test support functions. Overall
test coordination was considered good. (Section M1.1)
. Some progress was achieved in the fabrication of production welds during
this steam generator replacemert project. However, the relatively high
rejection rates and the appar M inability to use certain machine weld
processes, with good results, suggests that the licensee's technical
expertise in welding continues to be a weakness. (Section M1.2)
. Both film and radiographic quality were satisfactory. Indications were
evaluated correctly and properly documented. Housekeeping conditions in
the dark room were satisfactory as was the storage of unexposed film and
reagents. (Section M1.3)
. The licensee's nondestructive examination unit continued to perform in a
satisfactory manner. Technicians had a good knowledge of plant
equipment and procedural requirements. They performed their asrigned
tasks in a conscientious manner, and evaluated indications and
documented findings with accuracy and clarity, (Section M1.4)
. The main feedwater system welds were properly post-weld heat treated
following code and procedural requirements. Equipment was in
calibration and personnel overseeing the activity were adequately
trained to perform their tasks. (Section M1.5)
. The licensee's extensive investigation to determine the apparent cause
of a wld failure was indicative of a questioning attitude and a desire
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to resolve problems in a well-planned and conservative manner (Section
M1.6)
. Inspections of the Unit 2 containment concluded that emergency sump area
cleanliness was adequate. Materials potentially susceptible to high
energy releases during a design basis event were adequately secured and
debris dams and screens were installed to prevent complete blockage of
containment sump screens. The licensee's material accountability and
foreign material controls were considered good, in addition, the
overall building material condition was considered good following the
Unit 2 refueling outage. (Section M2.1)
. The licensee's efforts to overhaul the emergency diesel generators and
improve onsite emergency power reliability was excellent. (Section
M2.2)
- Unit I containment isolation valve IVP8B was properly repaired and the
supporting temporary modifications were adequate. However, during their
review, the inspectors identified an Unresolved item regarding the use
of a sealant in the valve that may not have received appropriate reviews
for this application. Application of the sealant contributed to the
failure of valve IVP88. It also appeared that adequate corrective
actions may not have been taken when the same containment penetration
(M456) failed post-maintenance testing during the previous refueling
outage. (Section M2.3)
. Testing of the Unit 2 hydrogen igniters was Jerformed well. Maintenance
personnel possessed good system knowledge. )rocedure adequacy
execution,andoveralltestcoordinationwereconsideredexcelient. All
Unit 2 icniters exceeded the minimum temperature requirements of
Technical Specification 3/4.6.4.3(b). (Section M3.1)
Enaineerino
. A strength was noted for identification and resolution of refueling
water storage tank design issues. (Section E2.1)
. A weakness was identified for failure to address and resolve conflicting
design inputs in a design calculation. The licensee had dissenting
comments related to this observation. (Sections E2.1 and XI)
. A Violation was identified for inadequate independent review of design
calculations. (Section E2.1)
. A Non-Cited Violation was identified for failure to establish an
adequate procedure for solid state protection system loaic circuitry
testing to ensure proper operation of the system. Thelicensee's
response to the discovery was good. No circuits were determined to be
inoperable following additional logic testing. (Secticn E3.1)
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- A Non Cited Violation was identified for failure to meet in service
testing program prescribed test requirements due to an inadecuate
procedure and the failure of the licensee to review the valicity of
computer points used for stroke tirne testing. (Section E3.2)
- Engineering activities associated with the operator aid computer
replacement project were determined to have a)propriate design controls
with good overall engineering performance. 11e re)lacement should
im) rove the reliability of the computer system at McGuire and greatly
enlance the anount and clarity of information available to operators
about the operational status of the plant. The safe implementation of
the new com) uter system for both Units 1 and 2 was considered a
strength. Management attention throughout the project's implementation
was good. (Section E4.1)
- Unit 2 Steam Generator Replacement Project modifications were
implemented in accordance with the approved design control program.
Quality Assurance involvement and oversight were adequate. (Section
E/.1)
Plant Support
. The results of an unannounced emergency preparedness augmentation drill
identified that all facilities were manned within the required times. A
drill critique was performed and identified several minor areas for
improvement. The drill confirmed the licensee's ability to fully staff
the required emergency preparedness areas. (Section P4.1)
- Following identification of tampering at the Unit 2 containment
personnel airlock seals, the licensee performed inspections of vital
)lant areas. No additional indications of tampering were identified.
r urther reviews of this event were detailed in Inspection Report 50-
369.370/97-19. (Section 51.1)
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Report Details
Summary of Plant Status
Unit 1
Unit 1 operated at 100 percent power during the inspection period.
Unit 2
Unit 2 began the inspection period in a No Mode condition during the scheduled
1997, refueling and steam generator replacement outage. On December 1, 1997,
the unit entered Mode 6 and successfully completed refueling activities on
December 3, 1997. The unit entered Mode 5 on December 6. 1997. On December
8,1997, all steam generator replacement activities were essentially complete,
with the exception of containment cleanup, final insulation installation, and
planned mode related testing. On December 13, 1997, the last day of the
Inspection period, the unit entered Mode 4 and was continuing planned startup
activities.
Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments
While performing inspections discussed in this report. the inspectors reviewed
the applicable portions of the UFSAR that were related to the areas inspected.
The inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures, and parameters.
I. Operations
01 Conduct of Operations
01.1 General 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. Operations remained
appropriately focused throughout the Unit 2 No Mode period. Operator
focus was also considered appropriate during the refueling and initial
heatup of. Unit 2 from the outage. Overall control of operations which
included turnovers, cognizance of ongoing activities, and implementation
of conditional surveillances during this period was considered
excellent, with few exceptions. Specific events and noteworthy
observations are detailed in the sections which follow.
02 Operational Status of Facilities and Equipment
02.1 Automated Doerational loaaina
a. Insnection Stone (71707)
The inspectors reviewed and evaluated the licensee's use of the recently
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established automated loaging system to evaluate the completeness and
accuracy of operational logs.
b. Observations and Findinos
The inspectors verified that the licensee's logging >ractices adequately
conformed to guidelines identified in Chapter 6 of tie McGuire
Operations Managenent Procedures. Although sufficient entries were made
to provide an accurate record of operational occurrences.
inconsistencies were identified in level of detail. Significant
operational events were listed with adequate explanation for the
particular plant conditions. Significant abnormalities in system
parameters, reactivity issues and electrical load changes were logged.
hever less significant and routine occurrences that could play a
major role in the reconstruction of events were not consistently logged.
The inspectors verified proper record retentian of operations narrative
logbooks.
c. Conclusions
The inspectors concluded that the licensee's implementation and use of
the newly established automated operations narrative logging system was
considered adequate to effectively reconstruct, at a later date, details
of significant plant operational events. However, the inspectors noted
varying logkeeping practices among individuals which may indicate that
more specific guidance may be necessary.
02.2 disoositioned Containment Isolation Valve Durina Reft:elina Ooerations
a. Insoection Scone (71707)
The inspectors reviewed the events surrounding the licensee's
identification of a containment isolation valve found out of the
required position to support containment integrity during refueling
operations.
'b. Observations and Findinos
On December 2. 1997 operators identified that the outboard containment
isolation valve for pressurizer relief tank (PRT) spray, 2NC568 was in
the o>en position despite a yellow isolated tagging device being
attacled to the control board switch for the valve. Credit was taken
for 2NC56B being closed to support containment integrity requirements
for refueling operations.
In response to this observation, the operator took immediate actions to
close the valve and document the discrepancy. Operators were dispatched
to the inboard isolation valve for the same penetration (M 216) to
verify its position. The inboard isolation valve was found intact and
in the closed position. The PRT number 2 spray isolation test
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connection. 2NC120 was also verified to be isolated. The licensee >
concluded that the overall containment penetration was not breached.
The inspectors discussed the configuration control issue with operations ,
management. Documentation revealed that the containment integrity [
yenetration status sheet in PT/2/A/4200/002C Containment .
Closure / Integrity, for penetration M 216 had verified 2NC56B closed on
November 29. 1997, at 2:45 a.m. Review of the operator aid computer -
point-for 2NC56B indicated that the valve was reopened for unknown
reasons on November 29, 1997, at 10:11 p.m.. and remained in that i'
position until it was closed on December 2.1997, at 3:40 a.m. The
inspectors were concerned that operating shifts failed to recognize the
incorrect alignment during shift turnovers and routine board walkdowns
during this interval. ,
c. Conclusions
An Unresolved item (URI) was identified to review the root cause of the :
mispositioning of a containment isolation valve during Unit 2 refueling
operations. Operators missed several opportunities to identify the
mispositioning during routine control board walkdowns. The licensee's
immediate corrective actions for the problem were appropriate and
overall containment integrity was not compromised. This issue is
identified as URI 50-370/97 18 01. Hispositioned Containment Isolation
Valve During Unit 2 Refueling Operations, pending further review of the ,
root cause of the mispositioning.
02.3 Review of Residual Heat Removal (RHR) Pumn Abnormal Ooeration Durina No
iode Conditions
a. Insnection Stone (71707)
During No Mode, the licensee operated the Unit 2 RHR pumps to support
maintenance and testing evolutions. The inspectors reviewed
investigation reports surrounding the licensee's identification of
potential air binding and unexpected system operation encountered while
starting the Unit 2 RHR pumps during No Mode conditions.
b. Obwrvatjons and Findinas
McGuire PIP 2 M97-4464 .
Specifically, during filling and venting of the system. OP/2/A/650 documente
8, RHR Pump 0)eration in "No Mode", was used to start the 2B pump while
in No Mode. 3ecause of the system alignment, a pump run was necessary
for complete fill and vent. Operators were aware of the possibility of
residual air in the system due to incomplete venting and were prepared
to take appropriate-actions to trip the RHR pump during initial pump
runs. During pump o
recirculation valve.peration,
2ND678.operators cycled the
to ensure adequate B train
mixing for RHR
a boron
sample, Operators noted abnormal pump indications and after
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approximately six seconds, tripped the pump. The system was vented in
accordance with PT/2/A/4200/36. Periodic Venting of RHR System. A large
amount of air was vented. The licensee determtaed that the system had i
not been thoroughly vented prior to cycling of the recirculation valve. :
An additional aroblem was documented via PIP 2 M97-4462 concerning
operation of tie 2B RHR pump. Specifically, the PIP identified
potential differences between OP/2/A/6100/50 8 and other procedures ;
including the abnormal procedure for a loss of residual heat removal, in
that the throttling of the RHR discharge valve may not be consistent.
The variation in throttled positions contributed to unexpected flow
rates during No Mode testing. The flow rates did not exceed pump runout
conditions.
The 2A RHR pump also ex3erienced problems during testing. McGuire PIP
2 M97 4480 documented t1at personnel heard evidence of potential water
hammer conditions, which included check valve hammering, during initial
operation of the 2A RHR pum). The test procedures were placed on '
administrative hold until c1anges were incorporated to include
consistent discharge valve throttling.
The inspectors reviewed the potential impact of these events on long-
term system reliability. Initial documentation of the issues in the
subject PIPS was poor. Operator actions upon identification of the
problems were adequate and operation of the pumps under abnormal
operating conditions appears to have been limited. Engineering
walkdowns of the systems following potential system waterhammer and pump
cavitation were adequate to verify no adverse impact that could affect
future operability of the system. The inspectors performed independent
reviews of the Unit 2 RHR pumps and subject system piping. No evidence
of significant system degradation was identified.
c. Conclusions
The licensee identified a number of problems with initial operation of
the RHR system during No Mode maintenance and testing. Initial
documentation of the problems was unclear; however, subsequent
engineering reviews determined no permanent damage was sustained by the
RHR pumps. System testing at the end of the outage further verified
system operability. Several procedural revisions were identified to
preclude future events: however, the inspectors concluded that the '
overall coordination, procedure application, and oversight of initial
RHR system operation during no mode conditions was weak.
02.4 Cold Weather Protection PreDarations
a. Jespection Stone (71714)
Reviews were conducted of the facility's readiness for cold weather.
The inspector reviewed Nuclear System Directive (NSD) 317. Freeze
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Protection Program. Revision 1 and interviewed the Freeze Protection
Coordinator. Procedures and work orders were reviewed to determine what
actions had been taken to prepare for cold weather. Selected >ortions
of critical plant structures. systems, and components (SSCs) tlat were
considered vulnerable in freezing conditions were also independently
inspected,
b. Observations and Findinas
In response to previous freeze protection 3rogram deficiencies, the
licensee revised NSD 317 in March 1997. T1e NSD governs the freeze
)rotection plans at all three Duke Energy Cor) oration nuclear stations.
)uring the previous cold weather season, the iSD had not been finalized
and a formal program was not in place for ensuring that effective
measures were being implemented to protect plant equipment and systems
from sub freezing conditions. The inspectors considered the completion
of the NSD necessary to define the structure of the freeze protection
program at the nuclear stations and the responsibilities of various
organizations in ensuring that the program was effectively implemented.
A McGuire freeze protection coordinator was assigned to monitor the !
status of cold weather preparation activities. An equipment freeze
protection program was developed at McGuire to identify SSCs that may be
subjected to freezing temperatures during the cold weather season. The
freeze protection plan includes a surveillance procedure to inspect
SSCs. considered to be critical to plant operation on a monthly
interval. For extreme cold weather (predicted temperatures below 20
degrees Fahrenheit (*F) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) the licensee also developed
PT/0/B/4700/070, On Demand Freeze Protection Verification Checklist, to
verify operation and status of SSCs that provide freeze protection and
can affect equipment reliability. This procedure featured verification
of plant area temperatures, electrical breaker alignment for heaters and
heat tracing, and instructed operators to place the refueling water
storage tank (RWST) and reactor makeup water storage tank (RMWST) in a
recirculation mode. The )rocedure also had been appropriately updated
to reflect plant design c1anges such as the addition of another
auxiliary feedwater storage tank and replacement and relocation of the
Unit 2 RWST level transmitters and associated heaters and control
system.
A design modification to improve protection for Unit 2 RWST
instrumentation against freezing conditions had been completed during
the inspection period under modification NSM MG 22496. The licensee
constructed an enclosed, temperature controlled area within the RWST's
missile shield that contains the temperature transmitters and the new
Unit 2 level transmitters (see Section E2.1). Temperature monitoring
and redundant' space heating was provided in the area as well as an
operatoraidcomputer(OAC)temperaturealarmforroomtemperature. A
similar modification is scheduled for implementation on Unit 1 during
the next scheduled refueling outage.
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The inspectors discussed the status of freeze protection preparations
with the freeze )rotection coordinator. The annual planned maintenance
(PM) activities lad been completed. Pre seasonal checkouts were
executed via various work orders for inspection and testing of
electrical heat trace and instrument box heaters. The freeze
protection coordinator had performed inspections of vulnerable areas and
worked with maintenance personnel to resolve deficiencies.
c. Conclusions
Reviews of licensee actions to implement cold weather preparations at
the site were acceptable. Nuclear System Directive 317 was issued which
provided additional structure and delineated responsibilities for freeze
protection. Procedures for verifying critical plant systems prior to
exposure to predicted extreme cold weather and the monthly surveillance
were good and provided additional assurance of operational readiness for
cold weather conditions. Construction of an enclosed and heated room
containing the new Unit 2 refueling water storage tank level
transmitters was a substantial improvement in refueling water storage
tank freeze protection reliability. Freeze protection activities were
initiated and completed in a timely manner. Overall, the inspectors
concluded that the licensee's efforts to effectively protect plant
equipment and systems from freezing conditions had improved.
03 Operations Procedures and Documentation
03.1 Unit 2 Cycle 12 Core Reload
a. Jnspection Scoce (71707)
The inspectors evaluated the licensee's preparation and performance in
reloading the reactor core for McGuire Unit 2 Cycle 12 operation and
installation of upper reactor vessel internals,
b. Observations and Fin.djnas
The inspectors witnessed selected portions of the core reload. The
inspectors verified adecuate source range detector operability and
audible source range incication were provided for refueling personnel,
Appropriate communications were maintained between the reactor building
and spent fuel building crews performing the reload and control room
operators monitoring plant systems. The inspectors verified that
engineering support personnel were assigned to the control room and the
refueling areas to monitor performance and to provide technical support
when necessary.
Prior to the fuel reload, video cameras were used to inspect the lower
vessel internals for foreign material and the subsequent preparations
for core reload. The inspectors noted that equipment performance was
good with minimal delays due to equipment malfunctions or abnormalities.
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No structural damage to reactor vessel internals or significant amounts '
of debris were identified. Fuel assembly identification numbers and
core reload locations were being verified by the licensee.
c. Conclusions
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The inspectors concluded that the licensee's performance during core
alterations for McGuire Unit 2 Cycle 12 was good. Adequate training was
provided and appropriate emphasis was placed on nuclear and personnel
safety. Material condition of the fuel handling equipment supported a
safe core reload with minimal interruption. Reviewed procedures were
adequate to control the evolutions.
08 Miscellaneous Operations Issues
08.1 IClosed) Licensee Event Report (LER) 50 369.370/97-02. Revision 0 and
Revision 1: Reactor 1 rip Due to Reactor Coolant Pump Motor Failure
The inspectors reviewed and evaluated the licensee's actions in response
to failure of the Unit 2 0 reactor coolant pump motor. The licensee
responded by replacing the damaged motor stator with a spare stator.
Post maintenance testing included an uncoupled run of the reactor
coolant pump motor. Temperature and vibration measurements were taken
and determined to be acceptable for continued operation. In the initial
LER. the licensee committed to replacing the Unit 2 B reactor coolant
pump during the Unit 2 EOC 11 outage: however, after further evaluation
of the motor condition, the licensee decided to operate the pump for one
additional o)erating cycle. A revised LER was issued documenting the
commitment clange. Additionally. the licensee performed visual
inspections and electrical testing of the Unit 2 B motor during the Unit
2 steam generator replacement outage. Motor performance met station
acceptance criteria and the motor was returned to service. The
inspectors concluded that the licensee's actions following the failure
of the Unit 2 0 reactor coolant pump motor were adequate. This item is
closed.
08.2 (Closed) LER 50-369/97-06: Unit 1 Engineered Safety Feature (ESF)
Actuation Due to 1 ripping of the Main Feedwater Pumps
This event involved an Engineered Safety Feature (ESF) actuation which
occurred when the main feedwater pumps tri aped, causing an automatic
start of the auxiliary feedwater pumps on )oth trains. The unit was in
Mode 3 at the time of the event and required minimal feedwater;
therefore, no transient to the plant resulted from the ESF actuation.
Operator response to the problem was prompt and found to be in
accordance with the applicable abnormal procedure. The licensee
identified that the main feedwater pumps received a trip signal from the
level trip devices providing high high water level protection for the
outboard main steam valve vault. It was determined that a spurious
actuation of one channel combined with an already closed channel due to
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manufacturing / installation deficiency satisfied the 2 of 3 logic for
the actuation. Workers were identified in the general area of the level
switches at the time of the event. which was the probable cause of the
spurious actuation of one channel.
The licensee reviewed in detail the as-found level trip devices and
sent the suspect components to the vendor for analysis. The licensee
concluded that it was most likely an installation problem which allowed
one of the three switches to be not properly reset after the final post-
installation testing was performed. However, the licensee also
concluded that the level device was very susceptible to mechanical
jarring which could lead to )artial make-up of the logic circuitry. All
components would have been a)le to 3erform their safety-related
function. Corrective actions for t1e event included verification of the
condition of the other valve vault switches and improved procedural
guidance for testing with regard to full functional verification of
these components after maintenance has been performed. including the
reset function. The inspectors discussed the event with maintenance
personnel and inspected the components which initiated the event. The
inspectors concluded that the licensee'*s response to the event was
adequate, the utilization of vendor support appropriate. and the root
cause followup good. This LER is closed.
08.3 .( Closed) URI 50-369/97-08-01: Root Cause of Main Steam Valve Vault
Level Actuation
Based on satisfactory review of LER 50 369/97-06. Unit 1 Engineered
Safety Features (ESF) Actuation Due to Tripping of the Main Feedwater
Pumps, the inspectors considered that the licensee took adequate actions
to obtain a plausible root cause for the inadvertent actuation of the
main steam valve vault level trip devices. Although the post-
installation condition of the devices left the unit more susceptible to
spurious actuation. the devices would have performed their safety-
related function in the event of valve vault flooding due to pipe break.
lhis URI is closed.
II. Maintenance
M1 Conduct of Maintenance
M1.1 General Comments
a. Insoection Stone (61726 and 62707)
lhe inspectors observed all or portions of a variety of work activities
performed by the licensee during the inspection period. Focus of the
activities was on testing required to support restart of Unit 2.
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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. In addition, the
inspectors reviewed or witnessed routine maintenance activities to
verify, where applicable. that approved procedures were available and in
use: prerequisites were met: equipment rc foration was completed: and
maintenance results were adequate.
Performance of Unit 2 ESF testing was considered good. Control of the
testing activities was accomplished in accordance with applicable
procedures. Pre-job briefings and overall test coordination was
considered good. The performance of the required testing identified no
major equipment malfunctions. The performance was indicative of well
performed outage maintenance and engineering test support functions,
c. Conclusion
The inspectors concluded that the routine activities were completed-
satisfactorily. The successful completion of Unit 2 ESF testing was
indicative of well performed outage maintenance and engineering test
support functions. Overall test coordination was good.
M1.2 Steam Generator Replacement Proiect (SGRP) In-Process Weldina (Unit 2)
a. inspection Scone (50001)
The inspector observed and evaluated the adequacy of in process welding
of main feedwater (CF) main steam (SM), and reactor coolant (NC) piping
as mciated with the SGRP. The applicable code for the fabrication.
examination and testing of welds in the systems was the American Society
of Mechanical Engineers (ASME) Section Ill. 1971 Edition and
Section XI.1989 Edition.
b. Observation and Findinas
The applicable code for the fabrication examination and testing of
welds in the above-mentioned systems was the American Society of
Mechanical Engineers (ASME). Section Ill. 1971 Edition and Section XI,
1989 Edition. Welds selected at random for observation and review of
weld and process control records were as follows:
Weld No. System Size (inches) Remarks
SM2F-22 SG "A" nozzle 32 x 1.5 Welding ccmpleted,
new weld was
Enclosure 2
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10
undergoing
grinding to remove
fabrication flaws.
SM2FW50-1 SG "A". riser 34 x 1.429 Welding completed.
SM2FW51 1 SG *B*, riser 34 x 1.429 Welding in
progress. Good
weld 3ractices
were )eing
followed.
SM2F 48 SG "B", nozzle 32 x 1.5 Root and hot
) asses welded.
Jeld appeared
satisfactory.
SM2F 100 SG "D" nozzle 32 x 1.5 Welding out. rom
and hot pass
completed.
Appearance was
satisfactory.
SM2FW53 1 SG "0" riser 34 x 1.49 Welding out. Root
and hot pass
completed.
Appearance was
satisfactory.
SG "A"
NC2F1-2 Hot Leg Rejected for
shrink cracks
associated with
construction base-
metal repairs.
NC2F1-3 Crossover Welding out.
NC2F2-2 Hot Leg Weld completed
prepping for
radiography.
NC2F2-3 Crossover Leg Completed weld
radiographed (RT),
acceptable.
Enclosure 2
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SG "C"
NC2F3 2 Hot Leg Weld fitups
completed.
Fabrication
started during the
night shift.
NC2F3 3 Crossover Leg Weld fitups
completed.
Welding started
during night
shift.
$ "D"
NC2F4 2 Hot Leg Welding final pass
before capping
joint.
NC2F4-3 Crossover Leg in process of
completing weld
may require one
more shift to
complete.
MAIN FEEnWATER
CF2FW62-31 SG ~B" pipe 16 x.844 Weld fitup was in
to elbow progress.
Within these areas, the inspector observed weld Ibrication attributes.
(i.e.. starts, stops, cleanliness) control of preneat, interpass
temperatures, and control of issued filler metal. Process control
records ere reviewed for completeness and accuracy. Quality records
for fillei metal traceability and welder qualification were reviewed and
found to be satisfactory.
- Weldina and Renairs of NC Pine Welds
Within these areas the inspector determined that a linear indication had
been identified in NC weld NC 2F12 on the hot leg of SG 2A. The
indication was first observed by weld machine operators when the weld
groove was about 1/4" from being completed. Following extensive
grinding and investigation with special radiographic techniques, the
licensee determined that the indication / flaw was a crack with tear like
characteristics. The flaw was located at or near the elbow side of the
Enclosure 2
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12
weld fusion line, between the new narrow groove weld and the base metal.
The flaw was located in radiographic interval 7-8. This flaw indication
was about 2.25 inches deep and 15.5 inches long in a circumferential
direction. A second and similar indication was identified by
radiography at the adjacent interval 6-7. This indication was about
1.875 inches deep and about 8.75 inches long. A third and significantly
smaller indication was identified by radiography in interval 8 9.
Radiographs depicting the remaining length / circumference of the subject
weld joint, showed no evidence of similar flaws and/or rejectable type
indications.
. Held Reoair and Investication
The licensee removed a sample of material containing the flaw for a
metallurgical investigation by the on site metallurgical facility. The
licensee s repair plan called for removing the flaw indications by arc
gouging and grinding. Once the flaw was removed and sound metal was
verified by surface and volumetric examinations. the licensee proceeded
with the weld repair. The gouged out sections on the elbow side were
weld repaired, using the manual shielded metal arc process with
stainless steel 308 filler metal material and the stringer bead
technique. Each layer of weld metal deposited was examined for
soundness using liquid penetrant (PT) and radiography Following
completion of the base metal repair. the licensee welded out the joint
using narrow groove technique with the gas tungsten arc welding
(machine) process. Radiography and ultrasonic examination showed the
completed weld met applicable code acceptance criteria. The repair work
was performed under Work Order No. 96093313 02 and documented on Detail
Process Cortrol Form MWP-3. Rev. O and Weld Process Control Form MWP-1
Rev. O. The entire weld was completed and accepted by radiography and
ultrasonic examination on November 19. 1997.
. Metalluraical Examination Results and Conclusions
By examination of the metallurgical samples, discussions with technical
)ersornel, and a review of Metallurgical Analysis Report No. 2268, dated
)ecember 5.1997 the inspector verified, inde)endent of the licensee's
previous determination, tlat the component (el)ow) where the subject
flaws were identified, was the hot leg of SG 2A. The elbow measured
approximately 31 inches on the inside diameter and had a wall thickness
of approximately 2.54 inches. The licensee identified the elbow as
being produced from SA-351. CF8A static cast stainless steel material.
This elbow had been weld repaired in 1978 when the original SG was
initially installed. The present crack indication was observed in the
proximity of the 1978 weld-repair and it appeared that flaws (micro
fissures) in the weld metal deposit of the repair were responsible for
the present cracking condition. Fine porosity was observed in the base
metal of the elbow. The crack appeared to have propagated by linking up
with these porosity indications. The micro fissures were more numerous
in other metallurgical samples near the fracture surface of the old weld
Enclosure 2
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13
repair material and in the region associated with the heat affected zone
of the narrow groove weld joint. Based on these observations and the
document review, the inspector verified that micro f,ssures in the weld
metal of the old base metal repair, were probably formed in local
ferrite free areas at the time of the 1978 repair. These were
exacerbated by weld shrinkage and other associated stresses from
fabrication of the narrow groove weld joint. These micro fissures were
most likely responsible for crack initiation and propagation in this
area. It appeared that during machining, the old weld repair material
was exposed to and became a 3 art of the narrow groove joint wall near
the top of the weld joint. )re existing micro fissuring in the old weld
metal repair coupled with welding stresses from fabrication of the
narrow groove weld most likely resulted in the initiation of cracking
near the top of the weld joint observed by welding operators.
following completion of the first week of this inspection on
November 14. 1997, the licensee determined that the rejection rate of SM
welds had exceeded the previously established performance acceptance
criteria of 90%. This was evidenced by the fact that the length of
rejectable weld metal deposited in five out of a total of eight SM
welds, varied between 5.5 and 25.4 inches. The remaining three welds
were accepted by radiography without the need for re) airs. The
licensee's evaluation of the problem. documented in )roblem
Investigation Process (PIP) Report 2 M97-4336. disclosed that the
relatively high rejection rate was the result of two factors involving
the use of flux core arc welding (FCAW) machines. These factors
included: 1) inattention to detail and: 2) a lack of operator expertise
in the operation of the flux core machines.
The licensee's investigation disclosed that 1) the shielding gas flow at
the FCAW welding gun was erratic: 2) the amperage setting on the FCAW
machines was 50 amps less than optimum, and: 3) certain welders with
high expertise in the process were not available for the Unit 2 SGRP.
Because corrective actions taken to address the identified problems
failed to reverse this negative trend, the licensee discontinued the use
of the flux core process and switched over to the shielded metal arc
welding (SMAW) process.
The SHAW process was used to repair welds with rejectable indications
and to finish welding partially completed joints. When the licensee
made the decirion to switch from the FCAW process to the SMAW process,
the records showed that six of the eight SM welds had been welded with
the FCAW process. Of these six. only one weld was free of code
rejectableindications,
In general, the licensee's integrated welding performance assessment or
success rate for all safety related pipe systems associated with SGRP
welding was relatively good. However, this good success rate was
Enclosure 2
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14
attributed to the contractors. (i.e.. Wachs and Framatome) who had the
highest success rate of weld acceptability based on radiography
acceptance following completion nf tho weld ioint. The weld performance
success rates were as follows:
Welding % RT Accept
S.yit.ca Oraanization on First Shot
Main Feedwater (CF) Duke 68.00%
Main Steam (SM) Duke 37.50%
Auxiliary Feedwater (CA) Wachs 90.00%
SG Wet Layup (BW) Wachs 100.00%
Reactor Coolant (NC) Framatome 87.50%
The suc:ess rates suggests that the licensee had made some progress in
the area of welding. However, the inspector determined that the
licensee continued ta experience significant difficulties when
attempting to make use of welding 3rocesses requiring higher level of
expertise (i.e.. FCAW and GTAW-mac11ne). This lack of expertise was
evident during this SGRP. For example. the licensee's welding
organization could not fabricate acceptable production welds without the
need of multiple repairs using the aforementioned processes. Also, when
av the licensee decided to use the aforementioned welding processes,
production results suggested that the welding organization did not take
appropriate actions to assure its success. When problems surfaced
during weld productions. the welding organizations again appeared to
lack the necessary expertise to diagnose and correct the problem in a
satisfactory cnd timeiy manner.
C. Conclusion,J:
Some progress had been achieved in production welding during the SGRP.
However, based on the relatively high weld rejection rates and the
inability to use certain weld processes with good results. the
licensee's technical expertise in welding continued to demonstrate a
weakness.
M1.3 Radicarachic (RT) Examination of SGR Welds
a. Inspection Stone (500011
Safety-related pipe welds, fabricated onsite, were radiographed to
verify weld integrity and satisfy applicable code requirements. The
licensee's code implementing procedure for this examination was NDE-10.
Rev. 19. General Radiographic Procedure, which referenced ASME Code.
Sections V and XI. 1989 Edition. The inspectors reviewed radiographs of
completed LC. CF and SM welds to verify use of proper penetrameter type,
size and placement: sensitivity, film density, identification, quality
and coverage.
Enclosure 2
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15
b. Observation and Findinas
Welds selected for this work effort were as folless:
Weld No. System Size (inches) Remarks
SM2FW50-1 Riser 34 x 1,49 Rejected and repaired
twice for lack of fusion
(LOF) slag and porosity.
Accepted November 23,
1997.
SM2F100* Nozzle 32 x 1.5 Rejected for slag on
November 20 and 26.
Accept on November 28,
1997.
SM2F74* Nozzle 32 x 1.5 No repairs required.
SM2F48* Nozzle 32 x 1.5 Same as above.
SM2F22* Nozzle 32 x 1.5 Rejected twice on
November 11 and November
16 for LOF and slag.
Accepted on November 19.
,
criteria to satisfy construction and preservice inspection (PSI)
requirements.
NC2F1-2 Hot leg 31 x 2.54 Extensive crack on
radiograph interval 6-7
and 7-8. See writeup in
this report for details.
NC2F2 3 Crossover 31 x 2.54 No repair required.
NC2F3-2 Hot Leg 31 x 2.5 No repair required.
NC2F3 3 Crossover 31 x 2.54 One minor c a
rejectableindication.
Accepted on November 19.
NC2F4-2 Hot Leg 31 x 2,54 No repair required.
,
Enclosure 2
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NC2F4 3 Crossover 31 x 2.54 No repair required.
Main Feedwater i
CF2FW61 5 Horizontal 18 x .938 No repair required.
Elbow to Pipe
CF2FW63 3 Pipe to Ell 18 x .938 Original rejected on
November 13. Accepted '
November 17.
CF2FW64-3 Pipe to Ell 18 x .938 No repair required.
CF2FW61-31 Ell. to Nozzle 18 x .938 Repaired twice for t.0F.
Accepted November 13,
c, Conclusions: ,
Both film and radiographic quality were satisfactory. Indications were
evaluated correctly and properly documented. Housekeeping conditions in
the dark room were satisfactory as was the storage of unexposed film and
reagents.
M1.4 Preservice Inspection of Reactor Coolant Welds
a. insoection Stone (50001).
As required by the applicable ASME Code Section, the licensee performed
a preservice ultrasonic ex6mination or replacement reactor coolant pipe
welds. The controlling procedure used for this examination was NDE-610.
Ultrasonic Examination of Dissimilar Metal and Cast Austenitic Welds
Using Refracted Longitudinal Wave. Rev 4 with Field Change 97-01,
in that this procedure had been reviewed and found satisfactory on
previous inservice inspections. this review concentrated on the latest
revision presently in use. This review revealed that the revisions and
Field Change 97 01 were consistent with applicable code requirements.
At the time of this inspection. all preservice exa..Inations on
replacement NC welds hd been completed. As an alternate, the
. inspectors 9 viewed and evaluated examination results. Welds reviewed
for this purpose were: NC2F1-2 and -3. NC2F2-2 and -3, NCRF3-2 and 3,
NC2F4-2 and 3. ,
b. Observation and Findinos
This records review revealed that the welds were adequately examined and
all indications were documented and evaluated as requireJ per applicable '
code requirements. Examiners who performed these examinations were
adequately trained, knowledgeable and performed these examinations and
Enclosure 2
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subsequent evaluations with attention to detail and applicable code
requirements. Equipment used was calibrated and material traceability
was satisfactory.
c. Conclusions:
The licensee's nondestructive examination unit continued to perform in a
satisfactory manner. Technicians had a good knowledge of plant
equipment, and of procedural requirements. They performed their
assigned tasks in a conscientious manner, and evaluated indications and
documented findings with accuracy and clarity.
M1.5 Postweld Heat Treatment of Completed CF Welds
a. Insoection Scooe (50001)
The requirement for postweld heat treatment of CF field welds was
controlled by the code of record. ASME Code Section 111 1971 Edition.
This requirement was implemented by Process Specification L 900 and
associated Postweld Data Sheets which provided the necessary details for
carrying out this operation,
b. Observation and Findinas
At the time of this inspection, all completed main feedwater welds had
been PWHTed using Data Sheet L-908. Rev. 1. As such, the inspector
reviewed associated strip charts to verify that minimum PWHT temperature
!,
levels had been attrined and maintained for the prescribed times, that
heating and cooling rates were consistent with code requirements and
that an adequate number of thermostats were used to assure that the
minimum PWHT temperature had been reached over the required material
width. The inspectors noted that these PWHT strip charts had been
reviewed and approved by the authorized code inspector.
Within these areas, the inspectors noted that heating and cooling rates
were uniform, holding temperatures and times were consistent and well
within minimum requirements. Strip charts traveled at the proper rates
and information on these charts was easily discernable. Welds selected
for this review included three from Loops "A" and ~B" and six from Loop
'C." Temperature recorders and thermocouples used were in calibration
at the time of the activity,
a c. Conclusions:
The CF welds were properly PWHTed following code and procedural
requirements. Equipment was in calibration and personnel overseeing the
activity were adequately trained to performed their tasks.
Enclosure 2
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M1.6 Maintenance Weldino
a. Inspection Scope (62700/55050)
The inspector observed the completed weld repair to the leaking weld
connecting the Unit 2, 3-inch common nuclear service water (RN) return
line to the 20-inch main header reviewed the associated weld process
control form MWP-1. and detailed process control form MWP 3 for
com)leteness and accuracy. The licensee's write up and analysis of this
pro)lem was documented in Problem Investigation Process (PIP) report
number 2 M97-41448.
b. Observation and Findinos
During the Unit 2 SGRP outage (2E0C-11), the licensee observed that the
three-inch branch connection pipe weld, attaching the common return line
from both component cooling pump motor coolers. to the 20 inch main
header was leaking. The piping was rated as ASME Code Section 111 Class
3, Duke Class C. The failed weld was identified as RN2F 88. The
associated piping was three inch schedule 40 (0.375 inch). An
ultrasonic (UT) examination determined that the crack was through wall
at two locations, between 5:30 to 7:00 and 8:00 to 9:00 o' clock.
Average thickness of the three inch pipe, measured by UT was about 0.204
inches. Also the weld was cracked from 12:30 to 5:30 o' clock to a depth
of 0.100 inches. A review of the licensee's analyses disclosed that the
extent of the crack would not prevent the subject pipe from performing
its design function. However, because of the difficulty of predicting
crack growth, the licensee began surveillance of the local area until
train B was removed from service to accommodate the weld repair. The
licensee concluded that the apparent cause for this weld failure was
fatigue f rom flow induced vibration on the associated RN return header
pipe. The licensee indicated that this flow induced vibration had been
one of a chronic nature that dates back to the initial design. The
licensee indicated that modifications and plant configuration changes to
reduce or eliminate this vibration had met with only limited success.
Also, the licensee stated that crack growth was extremely slow since it
had taken approximately 20 years of operation for the crack to propagate
through the weld thickness. By record review and observation. the
inspector determined that the licensee had cut-out the cracked weld,
ground-and prepped the penetration and installed / welded a weld-o-let to
provide additional strength to this joint, The three-inch pipe was then
welded on the weld-o-let. The completed weld appeared to meet minimum
applicable code acceptance criteria,
c. Conclusions:
The licensee's extens1ve investigation to determine the apparent cause
of the RN system RN2F-88 weld-failure was indicative of a cuestioning
attitude and a desire to resolve problems in a well-plannec and
conservative manner.
Enclosure 2
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19
M2 Status of Maintenance facilities and Equipment
M2.1 Outaae Containment Area Insoection
a. Insnection Stone (62707 and 50001)
The inspectors evaluated the licensee efforts in ensuring containment
areas were free of loose materials that could potentially affect
emergency core cooling system operability during the recirculation
phase. Lower and upper ice condenser areas were included. The tours
were completed prior to entry into Mode 4.
b. Observations and Findinas
The inspectors conducted outage closecut reviews of the Unit 2 reactor
building prior to entry into Mode 4 The inspectors focused on
materials in the reactor building areas that could potentially be
dislodged and migrate to the containment recirculation sump screens.
The inspectors also focused on steam generator replacement project
(SGRP) modifications to confirm proper installation of equipment and
supports. The inspectors noted that steam generator and pressurizer
insulation installed during the re)lacement oroject was adequately
installed and properly secured. T1e inspectors noted that most hand
tools and shielding materials had been removed from the reactor
buildin'j. No loose debris was identified that could potentially block
recirculation sump screens and prevent proper containment cooling system
operation during recirculation.
The inspector verified that hangers and supports were properly
installed. The refueling cavity was drained and free of debris. Ice
condenser areas were free of debris and no lower inlet door obstructions
were identified. No visible indications of active primary system
leakage were identified.
Minor items identified by the inspectors are listed below. The
inspectors made subsequent reactor building tours to assure that the
licensee was taking appropriate actions to correct the deficiencies.
The items were evaluated and/or corrected prior to unit restart. The
items included:
. minor containment sump screen debris (not an operability concern)
e damaged metal flashing for thermal shock protection of primary
containment in pipe chase
. gaps in A and D steam generator enclosures seals between lower and
upper containment
. inconsistent locking of refueling water drain valves between upper
and lower containment
e loose pressurizer safety valve seismic r4 traint bolt
Enclosure 2
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20
c. Conclusions
The inspectors concluded that the overall sump area cleanliness was
adequate. Materials potentially susceptible to high energy releases
during a design basis event were adequately secured and debris dams and
screens were installed to prevent complete blockage of containment sump
screens. The licensee's material accountability and foreign material
controls were considered good. The inspectors concluded that overall
building condition was good prior to restart from the Unit 2 E0C 11
outage. ins
into Mode 4.pector identified deficiencies were addressed prior to entry
M2.2 2A Emeroency Diesel Generator Rebuild
a. Insnection Scone (62707) ,
The inspectors observed and evaluated 2A emergency diesel generator
preventive maintenance activities,
b. Observations and Findinos ,
The inspectors conducted routine observations and held discussions with
licensee personnel to evaluate diesel generator maintenance activities.
The licensee disassembled the diesel engine and evaluated the condition
of critical components. Visual and magnetic particle inspection of
critical engine components was performed to identify potential
degradation. Although comaonent wear was evident, no significant damage
was identified that could lave significantly af fected diesel engine
operation.
The 2A EDG was the last of the four station emergency diesel generators
to be overhauled during the McGuire EOC 11 outages. Following the
overhaul, the diesel was tested to satisfy manufacturer requirements.
No evidence of maintenance deficiencies were identified.
The licensee selected a replacement synthetic engine lubricant.
incorporated during this rebuild. The lubricant was evaluated and
confirmed to meet the necessary properties for adequate lubrication and
oxidation resistance. The licensee confirmed component conditions (hot
bearing deflection) were within acceptance limits. Technical
Specification 4.1.1.2 required opera)ility testing was performed and the
unit was returned to service.
c. Conclusion
The licensee's efforts to overhaui the McGuire Nuclear Station emergency
diesel generators and improve onsite emergency power reliability were
excellent.
Enclosure 2
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M2.3 Unit 1 Containment Puroe_Jalve Inocerable i
4
a. Insoection Sepoe (62707)
.The inspectors reviewed the circumstances related to a containment !
'
-isolation valve repair in the containment air purge system. On November
7, 1997, the licensee determined that containment )enetration M456 i
failed a leak rate test due to excessive leakage tirough containment !
ourge valve IVP8B. The inspectors reviewed the corrective actions, a 10 t
CFR 50.59 evaluation, temporary modification package. Technical !
Specifications (TS), and the UFSAR. i
b, Observations and Findinos
Containment penetration M456 consists of purge valves IVP8B and IVP9A
that are the outboard (located in the annulus) and inboard isolation
valves, respectively. Each valve is an air operated 24-inch butterfly
valve that is normally closed, and the penetration is leak rate tested .
quarterly. Both valves were worked during the previous refueling outage.
A quarterly surveillance performed on October 30,1997 indicated that
containment leakage had increased, but penetration and overall
containment leakage criteria were still satisfied: however, the
penetration leak rate had increased since the arevious surveillance.
The licenste retested the penetration on Novem)er 6 and measurements !
indicated a substantial increase in leakage. On November 7, maintenance ,
~
personnel attempted to adjust the valve and performed a retest. During
the retest, the leakage had increased to the point where maintenance
personnel were unable to pressurize the penetration for testing.
,
On November 7, 1997, the licensee entered a four-hour TS action '
.
-statement for inoperable containment isolation valves (TS 3.6.3) and a
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement for an inoperable containment purge valve (TS 3.6.1.9). After verifying operability of 1VP9A the licensee remained in
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> action statement for TS 3.6.1.9 for repair of IVP8B.
In order to repair the valve, duct work in the annulus was removed and a
blank flange was installed upstream of the purge mpply fan (outside the
containment and the annulus) under temporary moi .. cation MGTM-0031.
This temporary modification sealed the penetration and became part of 4
the annulus pressure boundary. A satisfactory. test of the annulus ;
ventilation system was completed after the modification to demonstrate- ;
that the system could achieve and maintain the required vacuum pressure
in the annulus. _
.!
,
- U)on inspection of the valve, the licensee identified flange sealant as
t1e potential failure mechanism. Excess sealant had dripped onto the i
bottom of the valve seat area. The sealant was removed with cleaning
solution and the containment penetration was' retested. Post-maintenance i
'
testing acceptance criteria were satisfied and the affected TS action.
Enclosure 2 [
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statement was exited within the allotted 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Valve
maintenance procedures did not provide instruction for the use of the
sealant and no engineering guidance had been issued.
The inspectors reviewed previous issues associated with containment
penetration problems. McGuire PIP 1M97-1956 noted that during the
previous Unit I refueling outage, penetration M456 had failed post-
,
maintenance testing due to leakage through IVP9A. The failure was
attributed to excess flange sealant that dripped onto the valve seat
which prevented closure of the valve. Valve IVP9A was cleaned and the
penetration wa:; successfully retested. Similar valve failures had also
occurred following containment penetra'. ion post-maintenance testing in
the previous outage for the same cause noted above.
The inspector discussed the issue with site management. In response to
the failure of IVP8B. the licensee instructed maintenance personnel not
to use the sealant for purge valve work or any other product not
specifically called for by the procedure. Suspect Unit 2 purge valves
were checked during the refueling outage and no sealant was discovered.
The licensee plans to examine other suspected Unit 1 purge valves during
the next scheduled refueling outage.
c. Conclusion
The inspectors concluded that the repair of containment purge valve
IVP8B and the temporary modification were adequate. However, the use of
this sealant appears to involve a failure to evaluate the suitability of
application of this material to prevent adverse effects on containment
isolation valves. Application of sealant resulted in failure of valve
IVP8B. The inspectors concluded that adequate corrective action may not
have been taken when the same containment penetration failed post-
maintenance testing during the previous refueling outage. Pending
further inspector review, this is identified as Unresolved item
50-369.370/97-18-02. Potentially inadequate Corrective Action for Use of
Sealant on Containment Pur v e Isolation Valves.
M3 Maintenance Procedures and Documentation
M3.1 Unit 2 Hydroaen Mitination System (HMS) laniter Testina (61726)
a. Inspection Sc022
The inspectors observed portions of hydrogen igniter glow plug testing.
The inspectors reviewed the test procedure, the UFSAR. and work order 97034012-01.
b. Observations and Findinas
The HMS comprises two trains of glow plugs with 35 igniters per train.
To prevent detonable concentrations of hydrogen gas in containment, the
Enclosure 2
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HMS ensures controlled burning as the hydrogen is released after a
degraded core a':cident. Technical Specification 3/4.6.4.3(b) requires,
at least once per 18 months, verification that each igniter has a
minimum temperature of 1700 'F when energized. To satisfy this
requirement for Unit 2 the licensee performed Periodic Test
2/A/4350/024. Revision No. 6. Hydrogen Mitigatinn Igniter Glow Plug
Test.
Igniters were energized L the control room for at least 30 minutes
)rior to temperature measu.ements, as called for in the procedure.
Juring the test, maintenance technicians used an approved and calibrt.!ed
optical pyrometer to measure each igniter's temperature. Procedural
steps, caution statements, and notes were clear and appropriately
structured to complete the tasks. Instrument uncertainty at the
temperature range of the igniters was properly factored into the test
acceptr.,ce criterion. Double verification was appropriately
incorporated into the procedure and adequately implemented.
Maintenance technicians were knowledgeable of system design and
historical performance. Repeat backs were frequently used. All 70
igniters exceeded the minimum temperature requirements with the majority
nbc 2000 *F< Test results were sent to the system engineer for
ana ysis and performance treeding.
c. Conclusion
The inspectors concluded that testing of the hydrogen igniters was
jerformed well and that maintenance parsonnel possessed good system
cnowledge. The surveillance procedure, execution, and everall test
coordination were excellent with proper Instrument and Electrical Group
(IAE) supervisory guidance prior to the test. All Unit 2 ignite s
exceeded the minimum temperature requirements of Technical Specification
3/4.6.4.3(b).
III. Enaineerina
E2 Status of Engineering Facilities and Equipment
E2.1 Refaling Water Storage Tank (RWST) Design Issues
a. Insnection Stone (37550)
The inspector reviewed recently identified RWST design issues and
related calculations to determine if the issues were adequately resolved
and the calculations accurately defined the basis. Design issues
included missile shield wall height with respect to tornado accident
analysis and RWST depletion in conjunction with operator response times
for the design base accident. Additionally, the inspector reviewed the
implementation of the Unit 2 RWST wide range level instrumentation
modi fication.
Enclosure 2
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- -. . .- ,
- . - - - - - - . . _ . - . - . - - - - . . - . .
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24 -
'I
b. OsServationsand'Findinas
^
McGuire engireering evaluated the RWST missile wall design basis ~ -
-following identification of a concern in this area early in,1997. at i
Catawba. ' The evaluation reviewed the tuinado accident scenario which
-
I
included:a steam break outside of containment in conjunction with-
missile penetration of the RWST at the height of the missile wall
(fourteen feet). The analysis determined the amount of RWST inventory '
required for make up to the reactor coolant system due to shrinkage from
the steam break cool down and the inve'. ory 1:st due to bypass flow to
containment via gravity drain through a residual heat removal: system-
during this time. The inventory below the fourteen foot level was
-adequate for this design requirement. This was documented in' -
.
alculation MCC-1552.08-00 0269. RWST Missile Wall Design Basis ,
Evaluation. revision 1. ,
During a design review in January,1997, the licensee identified that
the operator response times listed in the UFSAR for transfer to cold leg _
recirculation were not consistent with simulator performance, ;
Corrective actions were comprehensive and included revision e' the
applicable emergency operating procedure, opei'ator training, a .d
evaluation of RWST depletion during a design basis accident, A new RWST
depletion calculation was developed to include the. revised operator
response times and the RWST setpoints were verified. New setpoints were
developed for the wide range level instrumentation modification
installed during this outage on Unit 2.
The inspector reviewed approximately ten calculations associated with
the RWST design issues. In general. the calculations were adequate.
Areas where calculations could be improved included documentation of
assumptions, cross-reference capability, and quality of independent
verification, With the exception of the emergency core cooling system
(ECCS) flow calculations, the calculations were developed in 1997.
T: ve wcre several examples in which an assumption was made but not
douneted. For exam 31e, the RWST pipe diameter for a-nominal 24-inch
pipe was used in the RWST depletion calculations rather than an i
equivalent-diameter for the actual pipe which was_a larger value.
Several references were used to provide different ECCS flow values.
There was some explanation of the basis for the values used within the
- alculations: however, there was no discussion in the designated
'ef.sumptions Section" of the calculation regarding which flow model was
acceptable in the given scenario. The inspector noted that several of
these calculations-included design inputs which were developed in'
portions of other calculations; however, there was no cross-reference .
"
which linked related calculations so that revisions in one calculation
could be addressed in all: related calculations.
The inspector identified computation and design input errors in the RWST
- depletion calculation which demonstrated that the independent review
function was deficient. Calculation MCC-1552.08-00-0118. RWST Level
'
Enclosure 2
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-,-..-.vd
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25
Setpoints, revision 2. dated October 26. 1997, developed level setpoints
for the narrow range instrumentation (Unit 1) and the wide range level
instrumentation (Unit 2). Section 7.5 of the calculation incorrectly
summed ECCS flows contributing to RWST depletion and used an incorrect
design input value for residual heat removal flow. These errors were
not identified ar.d corrected by the independent design review of the
calculation and this is identifieC as Violation 50-369.370/97-18-03.
Inadequate Design Controls for RWD Setpoint Calculation.
The inspector noted an additic u engineering weakness in the RWST level
setpoint calculation related to conflicting design inputs. The initial
calculation (revision 0) deve'oped the level setpoints for the existing
narrow range level instrumentation in February 1997. Appendix B to the
calculation was added by revision 2 on October 26. 1997, and established
the setpoints for the wide range instrumentation installed by a Unit 2
modi fication. The minimum level calculation included a parameter
defined as the critical height to prevent vortex form 6 tion. The
parameter is independent of the range of instrumentat1on used. The
calculation used two different equations to determine this critical
height. The design input in the Appendix B wide range instrumentation
calculation included a statement quoted from the reference source
stating that the equation used in the narrow rar.ge computation was not
applicable to the conditions of the RWST. There were no corrective
actions by the licensee to evaluate the narrow range minimum level
setpoint or to resolve the stated conflict in design inputs. During the
inspection, the licensee revised the calculation for the narrow range
computation using the Appendix B critical height equation which yielded
a non-conservative result. Further analysis was required and the pump
vendor was contacted to verify that the containment spray system pumps
could sustain short-term operation with air entrainmert. The inspector
cuncluded that the licensee's failure to resolve the conflicting design
inputs within the RWST setpoint calculation was an engineering
corrective action performance weakness in the design control area.
The_ inspector reviewed the Unit 2 modification NSM MG-22496. Refueling
Water Storage Tank (RWST) Modification, r3 vision 2, which installed RWST
wide range level instrumentation and provided freeze protection for this
instrumentation. The modification was installed in accordance with the
design documentation and the post modification testing was adequate to
verify the capability of the instrumentation,
c. Conclusion
A strength was identified for the licensee's identification and
resolution of RWST design issues. The quality of calculations was
generally adequate. An exception was a recent calculation for RWST
level setpoints which demonstrated poor performance in that a violation
was identified for inadequate independent design review and a weakness
Enclosure 2
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s :. , n
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,
,
i
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. ' was identified for. deficient corrective action to resolve a conflict in
c design inputs. The Unit 2 RWST wide range level instrumentation _ i
- modification was installed in accordance with the approved design H
z control program. ,
t
~
E3 -- : Engineering Procedures and Do m ntation 1
E3.1 Solid State Protection System (SSPS) Testina Procedure Deficiencin
( a. Insoection Scooe (37551) ;
The inspectors reviewed-the licensee's identification of a potential ;
violation of TS action statements.for-SSPS testing to evaluate the-
potential impact on system operability and nuclear plant safety.
b. Observations and Findinos .
m
On November 11, 1997, the licensee determined that the functional
'
testing required per TS 4.3.1.1 and TS 4.3.2.2 for McGuire Units 1~and 2 .
. SSPS had not been adequately performed to verify operability. .The
e testing performed in accordance with PT/0/A/4601/008A and
,
PT/0/A/4601/0088 had not appropriately tested the Permissive Interlock
P-14 Feedwater Isolation on Steam Generator Hi-Hi level. Feedwater
Isolation on Safety Injection, and the Permissive Interlock P-10 Source
Range Automatic Block functions. The procedures were judged inadecuate
since internal card failures could have potent 411y gone undetectec
during logic testing. Additional reviews indt.ated that the test
,
design developed by-the nuclear steam supply atem (NSSS) vendor, for
, these circuits was inadequate to verify proper operation of the SSPS
logic cards.
Since Unit I was operating in Mode 1. the licensee immediately com
with TS 4.0.3 until the procedures'could be revised and executed. plied
.
Technical Specification 4.0.3 allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to complete the necessary
testing to verify operability. Unit 2 was de-fueled for the Unit 2 E0C
11' outage. The newly revised test procedure was reviewed to ensure that
'
no additional reactor trip risks were introduced. The testing was
completed with satisfactory results and the 'Jnit 1 SS?S trains were
. verified operable. The licensee completed the testing on November 12-
, and exited the action-statement prior to exceeding the 24-hour allowed ,
outage time. The licensee. stated that a detailed cause evaluation would
be performed within 30 days and the results would be presented to
-station management and the NRC via an LER.
I c. ~ Conclusions
The-inspectors concluded that-the licensee failed to establish an
~. adequate procedure for SSPS testing to ensure proper operation of the
- system during all potential failure modes. The inspectors recognized
ithat the. licensee response to the discovery was good. The inspectors
e Enclosure 2
.
--
.-.,--g ...,r-.. _ - - _, _ , _m
. _ _ _ . . _ .._ . _ _ _ _ _ . _ _ _ _ _ . _ _ _ . . _ _ . _ _ _ _ . _ . . . _ . _
"-
, ..
,
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27 .
.l
Jalso noted.that no circuits were determined to be inoperable.'following
the additional logic testing. - As a result the inspectors concluded ;
that the licensee s--failure to establish adequate procedures for_ testing
of the SSPS logic circuitry constituted a TS violation. However, this i
non repetitive, licensee-identified and corrected violation is being
treated as a Non Cited Violation (NCV), consistent with Section VII.B.1- '
of the NRC Enforcement Policy; NCV 50-369.370/97-18 04. Inadequate
Procedure for-SSPS Testing.
'
E3.2 Inadeauate Testina of Diesel-Generator Lube Oil System Valves !
a. Insoection Scooe (37551)- i
f
The inspectors reviewed the cause for a failure to adequately conduct _
the quarterly stroke time test valves 1(2)LD108A and 1(2)LD119B as
specified by the McGuire inservice test program. These valves-
automatically open when differential pressure across the Unit 1 and 2
emergency diesel generator lube oil filters reaches the established
setpoint to maintain oil flow to the diesel engines.
.
b. Observations and Findinas
On October 30, 1997 the licensee determined that the procedure for
Diesel Generator Lube 0il System Train B Valve Timing PT/1/4350/006B. ,
was inadequate to accurately test valve performance. The licensee was
performing stroke +1me testing of the valves using a stopwatch while the
normally utilized plant computer was removed from service-for
modifications. The tests measured a. valve stroke of approximately 8
seconds which was beyond the procedure defined acceptance criteria. The :
licensee reviewed previous test data and recognized that during earlier
stroke time testing of the valve, a consistent value of approximately 2
seconds was recorded. Subsequent reviews of plant computer points used -
for stroke time testing of valves revealed that the earlier measurements
were incorrect and did not reflect a full stroke of the valve from the
closed to open position. . Using the computer points identified in the
procedure, the measurement was from the " closed" position to the "not
closed" position instead of the "open" positinn.
Test results using a stopwatch indicated a stroke time of approximately
-5-7 seconds for each of the valves._ The procedure specified an
acceptance criteria of-2 seconds: however.- the system required stroke
time was 60 seconds to su] port continued diesel operation. The-licensee
compared the results of. tie: test to other test data obtained during ,
motor operated valve testing (GL 89-10) and confirmed that.the results
obtained using a stopwatch closely matched the GL 89t10; test data.
Changes were implemented for the stroke time testing procedures for the-
Unit l'and Unit 2 emergency diesel generator M e oil systems. Testing
-was completed using-a stopwatch. An operability evaluation was
-
completed that indicated that the diesel generators as well as the- - -
Enclosure 2. ,
>
v ,s , [ ,. [,,_-- ,,,y
.
1
1
28
affected valves were operable with respect to their required function
since the actual valve stroke times met the IST program stroke time
requirement. The licensee also performed reviews of other IST tested
valves to identify other valves that may not be tested appropriately to
ensure operability. No related issues were identified.
c. Conclusions
The inspectors recognized that the licensee's failure to meet IST
program prescribed test requirements was due to an inadequate procedure
and the failure of the licensee to review the validity of computer
points used for stroke time testing. However, based on the safety
significance of this event, the licensee's efforts to review and
evaluate test results against GL 89-10 data, and review for other
problems, this non-repetitive, licensee-identified and corrected
violation is being treated as a Non-Cited Violation, consistent with
Section Vll.B.1 of the NRC Enforcement Policy. NCV 50-369.370/97-18-05.
Inadequate IST Surveillance Procedure.
E4 Engineering Staff Knowledge and Performance
E4.1 Review of Doerator Aid Computer (OAC) Reolacement
a. Inspection Scone (37551)
The inspectors reviewed the OAC replacement modification to monitor
implementation of the project. adequacy of design controls, adequacy of
'
compensatory measures for control room integrity and compensation for
loss of parameters during the no-mode phase of the project.
b. Observafions and Findinas
The McGuire Unit 1 OAC replacement, was implemented during the 2E0C11
outage under Nuclear Station Modification NSM MG-12412/00. The original
computer was a early 1970's vintage Honeywell 4400 process monitoring
system. This system had become increasingly difficult to maintain due
to s)are parts availability, had limited input / output, processing and
graplics capabilities.
In addition to re) lacing the OAC, additional systems were replaced and
integrated into t1e OAC to provide plant monitoring functions. These
included the Plant Events Recorder, the ESF Bypass Status Indication
System, the Transient Monitoring System. the Unit Interface Controller
and Diesel Generator Diagnostic Engine Monitoring Systems.
The inspectors reviewed various portions of the OAC installation.
Walkdowns of the work areas for the OAC project were performed
periodically. The inspectors reviewed compensatory measures that were
established for cable routing through control room penetrations related
to the OAC replacement modification. The inspector monitored the cable
Enclosure 2
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29
pulling process and found the implementation of the compensatory
-measures well executed with adequate support from 03erations personnel.
The inspector monitored the variation notices that lad been issued for
the OAC replacement inodification. The inspector considered that the
changes were mostly minor and of a type that would normally be
encountered in this size of project.
The inspector considered the OAC replacement project to be effectively
implemented. Engineering support to the OAC project was similar to that
observed on the Unit 10AC replacement and was considered excellent.
The significantly low number of problems encountered during the project
implementation indicated effective planning and engineering during all
phases of the project.
c. Conclusion
Engineering activities associated with the OAC replacement project were
determined to have appropriate design controls with good overall
engineering performance. Compensatory measures established for cable
pulling through control room penetrations were observed to be
conservative and pro)erly implemented. The replacement should improve
the reliability of tie OAC at McGuire and greatly enhance the amount and
clarity of information available to operator about the operational
status of the plant. The safe implementation of the new OAC for both
Unit 1 and 2 was considered a strength. Management attention throughout
the project's implementation was good.
E7 Quality Assurance in Engineering
E7.1 Unit 2 Steam Generator Replacement Proiect (SGRP) Modifications
a. Jm pfenlign_Vcone (50001)
The inspector reviewed the implementation of the Unit 2 SGRP
modifications to determine if they were installed in accordance with
applicable design change documents and the licensee's approved design
control program. The review included resolution of field discreaancies,
processing of field changes, post-installation inspections, and QA
oversight. The following modifications were reviewed:
NSM 29810 Modify SG Instrumentation Tubing
NSM 29915 Auxiliary feedwater System Elbow Replacement Due to SG
Nozzle Replacement
NSM 29610 Nuclear Sampling System Piping Reroute Due to SG
Nozzle Relocation
Enclosure 2
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NSM 29420 Main feedwater System Piping Reroute Due to SG Nozzle
Relocation
NSM 29230 Replacement SG Insulation
b. Observations and Findinas
,
implementing procedures included appropriate detail and quality control
inspection hold points. Identified field discrepancies were adequately
addressed and resolved. Post-installation inspections were adequate to
verify the installation was consistent with the design drawings. Field
changes were processed in accordance with approved design controls.
Quality assurance involvement and oversight were adequate,
c. Conclusion
Unit 2 SGRP modifications were implemented in accordance with the
approved design control program. 0A involvement and oversight was
adequate.
E8 Hiscellaneous Engineering Issues !
E8.1 (Closed) AD)arent VIO (EEI) 50-369.370/96-02-01 and VIO EA 96-80 01013:
Inadequate :reeze Protection Procedures Causing Inoperability of RWST
Level Transmitters.
On May 9. 1996. EEI 50-369.370/96 02-01 was cited as a severity level
III violation (EA 96-80-01013) with a civil penalty of 5 50.000.
Significant reviews of the corrective actions taken for the subject
violation were previously performed in IR 50-369.370/96-10. Numerous
corrective actions were implemented including: increasing the setpoint
of the RWST enclosure thermostats; operability verification of the other
RWST level transmitters: procedure revisions to require checking of the
RWST enclosure thermostats; and installation of low temperature computer
alarms. The licensee also implemented a cold weather task force to
further improve their freeze protection programs at all sites. However,
additional design problems were identified by the NRC concerning the
adequacy of the RWST enclosure heaters late in 1997 which resulted in an
additional violation for oversized heaters being installed in the RWST
enclosures (see Section E8.2). Based on these previous reviews and
reviews perfonned regarding freeze protection readiness conducted during
this inspection period, the inspectors concluded that corrective actions
have been taken to address this violation. In addition to the
corrective actions identified in the licensee *s response to the
violation, significant modifications have been performed on the Unit 2
RWST level transmitters, including improved design capabilities for
implementing freeze protection. These actions were further discussed in
Sections 04.1 and E2.1. Implementation of similar modifications on Unit
1 are planned during the next scheduled refueling outage. Based on the
inspectors' review, this violation is closed.
Enclosure 2
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31
E8.2- (Closed) VIO 50-369.370/97-04-04: Failure to Ensure Installation of :
Correct Heaters-in RWST Enclosure j
This issue involved the NRC's identification of oversized freeze-
' protection heaters installed in the RWST level transmitter enclosures. :
i
- The violation constituted a potential for overheating of the RWST level
transmitter enclosure and the transmitter exceeding its upper-
temperature range. Immediate corrective actions for the violation
included the performance of-a conditional surveillance to ensure that .
the temperature for each safety-related level transmitter remained ,
-within allowable limits until the heaters could be rcplaced. ,
-
The licensee subsequently installed the appropriately sized heaters in-
the subject enclosures and added a high temperature alarm to alert--
control room operators of a- failed thermostat that could result in
excessive RWST enclosure temperatures. Additional licensee actions-
concerning this issue were previously described in section E8.2_, :This .
,
violation is closed. ,
E8.3 (Closed) Insoection Followuo Item (IFI) 50-369.370/97-01-02: RWST
Design Basis
This item addressed RWST design issues identified by the licensee early
in 1997. These included RWST depletion and operator response times in a
design basis accident and the design basis for the RWST missile shield
wall.
The licensee evaluated and resolved these design issuts. 41s is
'
discussed in section E2.1 of this report. Additional:v. ' design basis
review of the refueling water system was initiated to f urther assess the
system design basis. The inspector concluded this item was adequately
addressed.
IV. Plant Support
P4 Staff Knowledge and Performance in Emergency Preparedness-
P4.1 Results of December 11. 1997. Site Auamentation' Drill (71750) 4
On December 11, 1997, the licensee conducted an unannounced McGuire Site
emergency. preparedness augmentation drill. The drill involved the- ,
aarticipation of approximately 180 responders to the Technical Support
- enter. Operations Support Center, and the uptown Charlotte Emergency.
Operations Facility. All drill objectives were determined:to have been
met and all of the facilities were manned within the required times. A
drill critique was performed.and identified several minor areas for
improvement. The insaectors concluded that the ability of the McGuire .
-site to fully staff t1e required ebrgency preparedness areas was being
adequately demonstrated.
r
_
Enclosure 2
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SI- = Conduct'of Security and Safeguards Activities
51.1 Licensee' Reoort of Potential Eauioment Tamoerina Event-
.a. Insoection Scooe (71750)=
The-inspectors reviewed events surrounding a report of potential
equipment tampering on Unit 2.
b. Observations and Findinas
Between December 2. 1997. and December 4, 1997, with Unit 2 in Mode 6
near the end of a refueling outage and Unit 1 operating at 100 percent
power,- the licensee discovered indications of potential tampering with
the Unit-2 upper and lower personnel air locks air seals. The damage
was identified during the performance of testing of the air lock to i
support restart of the unit. It appeared that a sharp instrument-was-
used to puncture or slash approximately 1- to 2-inch long cuts in the
seals on the hinge side of t1e door seals. The licensee informed the
resident inspectors of the indications and regional NRC management was :
i
-
then notified. On December 5. 1997, a Regional NRC inspector arrived
on-site to review the event and monitor the licensee's response. The 4
results of this inspection were documented in Inspection Report 50- l
369.370/97-19.
'
The inspectors responded by ins)ecting both the upper and lower airlock.
It was determined that all of tie seals (total of eight) had indications
y of tampering, with several of the cuts later. determined to be through
'
wall punctures of the seals. Extensive tours were then conducted by the
L inspectors on December 4 inside the Unit 2 containment. No additional
[ indications of tampering were identified. The inspectors also performed
- additional walkdowns in safety-related and important-to-safety areas
affecting in both units through the end of the inspection period. ,
Specific licensee actions taken to address the event included:
. Replacement of all'the Unit 2 personnel airlock door seals
'
.- Heightened awareness of operations, radiological controls, and
. _ security personnel to potential tampering events
,
,
.- Increased plant management tours and posting of security guards at
"
the-subject airlocks .
1
Initiation ofJoutage restart valve lineup on Unit 2 and 100
'
.
percent verification of all instrument root valves within the Unit
2. containment (approximately 480 valves)
.
'
. Development and performance of a ' Unit 2 critical valve checklist
which would re-verify the essential emergency core cooling system .
u
.
Enclosure 2
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33
flowpaths within the containment before restart
- Inspection of the Unit 1 vital areas outside containment
A telephone call was conducted on December 4,1997, between the licensee
and NRC Headquarters and Region 11 to discuss the results of the
licensee's initial investigation and future plans. The licensee
formally reported the tampering event to the NRC on December 4. 1997.
On December 15. 1997, an additional telephone call was held between the
licensee and NRC Headquarters and Regional Management prior to the
restart of Unit 2 from the refueling outage. In the call, the licensee
described the status of their investigation and what actions had been or
will be taken to support safe operation of both units. The licensee
indicated that no additional indications of tampering had been
identified on either unit.
c. Conclusion
The inspectors concluded that the licensee's response to the identified
tampering event was adequate. Subsequent inspections of both Unit 1 and
2 systems identified no additional indications of tampering. Further
reviews of this event were detailed in Inspection Report 50-369.370/97-
19.
V. Manaaement Meetinos
X1 Exit Heeting Summary
The resident inspectors aresented the inspection results to members of
licensee management at t1e conclusion of the inspection on December 17, 1997.
At a visiting inspector exit on December 12. 1997, the licensee expressed
dissenting comments on the inspectors * observations documented in Section E2.1
regarding a RWST design calculation issue. Following the end of the
inspection period, the licensee provided the following written statement to
document their dissenting comments:
The subject Duke calculation contains a statement that a previous
version of vortex calculation was not aapropriate for the height to
diameter ratio of the FWST geometry. T1e statement in the Duke
calculation was meant as a restatement of an assertion contained in an
academic paper published by an author who developed a new correlation.
The statement in the Duke calculation file was not meant to be an
endorsement of that author's conclusion.
The author of the second academic paper brought into question the
applicability of the previous author's correlation for a particular
range of height to diameter ratios. The original academic paper states
that the correlation is appropriate for the height to diameter ration of
the FWST. Resolving the disagreement between these two public domain
Enclosure 2
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34
>ublications is beyond the scope of the Duke calculation for vortex
Jehavior.
The performer of the revised Duke calculation realized that the new
correlation would generate more conservative results than the original
correlation. This was the basis for choosing the new correlation in the
revised calculation. This decision was not meant as an endorsement that
the previously used correlation was in error in the prior Duke
calculation. Standard Duke working practice in a case where an earlier
calculation is found to be in error would involve generation of a PIP
(10 CFR 50 Appendix B Corrective Action Problem Report) and evaluation
of Operability.
Duke, therefore, respectfully disagrees that this was a violation with
regards to appropriate use of the Corrective Action Program of 10 CFR 50
Appendix B Criterion XVI. In addition, the use of new and more
conservative engineering calculation methods without upgrading previous
calculations is considered a strength and not a weakness by Duke. To
continue to use old methods while new methods emerge would not maintain
an appropriate engineering state of the art. To backfit cll previous
calculations with new calculation methods is not cost effective. Only
when previous methods are shown to be in error will the corrective
action program be used to evaluate the consequences of errors.
[At the exit, this issue was initially identified as a potential violation.
However, after additional review it was documented as a weakness.]
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
Barron, B., Vice President. McGuire Nuclear Station
Boyle, J., Civil / Electrical / Nuclear Systems Engineering
Byrum, W., Manager. Radiation Protection
Cash. M., Manager. Regulatory Compliance
Crane, K., Regulatory Compliance
Dolan, B., Manager, Safety Assurance
Geddie. E. , Manager, McGuire Nuclear Station
Herran, P., Manager Engineering
Loucks L., Chemistry Manager
-Thomas. K.. Superintendent. Work Control
Travis, B.,-Manager. Mechanical Systems Engineering
Tuckman, M., Senior Vice President. Duke Energy Corporation
Enclosure 2
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- .. .. - . .. . .. . - -. . ,
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7 .
c
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35=
f
- INSPECTION PROCEDURES USED--
^ ~
- IP 37550.s -
Engineering 1 .. -
IP.37551:- - Onsite Engineering
~
-IP'50001: :
Steam Generator Replacement
IP'61726:' 1 Surveillance Observations
-
IP 62707: - Maintenance Observations
LIP 71707':- Conduct =of Operations
c
.
LIP-71714: Cold Weather Protection Preparations
.IP 71750:t - Plant Sup) ort
IP 92903: - Followup Engineering
IP 929016 ' Followup-Operations-
ITEMS OPENED. CLOSED, OR DISCUSSED
-
" OPENED ~
50-370/97-18-01- URI. Hispositioned Containment Isolation Valve -
- During Unit 2 Refueling Operations (Section
02.2)-50-369.370/97-18-02 URI Potentially Inadequate Corrective = Action
.-for Use of Sealant :on Containment Purge
-
.
Isolation Valves (Section M2.3)-
50-369.370/97-18 03- VIO -Inadequate ' Design Controls for RWST-
Setpoint-Calculation (Section E2.1)
50-369.370/97-18-04- NCV Inadequate Procedure- for SSPS Testing-
(Section E3.1)
'
-(Section:E3.2)
}
CLOSED 4
50-370/97-02-(Rev 0.1) LER- Reactor Trip Due to --Reactor Coolant Pump .
Motor Failure (Section 08.1)
50-369/97-06 LEP. Unit -l' Engineered -Safety Features (ESF)
Actuation Due to Tripping of .tne Main-
~
Feedwater Pumps (Section 08.2)
- 50-369/97-08-01"
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URI: Root Cause of Main' Steam Valve Vault ~ Level
Actuation (Section 08.3) -
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1501369.370/96-02-01: (EEI : Inadequate Freeze Protection Procedures
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'50-369.370/97-04-04L- VIO- Failure.to Ensure! Installation of Correct
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!50-369,370/97-01-02 - IFI RWST_ Design Basis (Section E8.3)
DISr,USSED:
LIST 0F ABBREVIATIONS AND ACRONYMS USED:
AFW= -.- Auxiliary feedwater
'CFR- - Code of Federal Regulations
-EA - Enforcement Action
ECCS ,
.EDG -- Emergency Diesel Generator 1
'EEI -
Apparent Violation
E0C -- End OfLCycle
ESF. - Engineered Safety Feature i
GL -
Generic-Letter-
HMS - Hydrogen Mitigation System
IAE - Instrument and Electrical Group
IFI- -
Inspector: Followup Item
-IR --- Inspection Report-
IST -- Inservice Testing
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LER - Licensee Event: Report
NCV' -
Non-Cited Violation
Nuclear Regulatory Commission
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NRC - -
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NRR - NRC Office of Nuclear Reactor Regulation
NSD -
Nuclear System Directive .
NSM -
Nuclear Station Modification
NSSS - Nuc_ lear Steam Supply-System
OAC -
Operator Aid Computer
PDR --
Public Document Room ,
PIP - Problem Investigation Process
PM -
Planned Maintenance i
Pressurizer Relief Tank
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PRT- -
Periodic Testing
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PT -
OA ' Ouality Assurance
RHR -
Residual-Heat Removal
-RMWST - Reactor. Makeup Water Storage Tank i
- RWST: -
Refueling Water Storage-Tank
.SAIC-'
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- Science: Application International Corporation
.G:S -
LSGRP -- : Steam Generator Replacement Project
SSC :-- Structures, Systems;and: Components
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- SSPS" ' Solid State Protection System
,TS4 -- Technical Specifications
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UFSAR - Updated Final Safety Analysis Report'
Unresolved item
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URI -
- VID -
Violation
VN -- Variation Notice
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