ML20138Q402
| ML20138Q402 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 12/13/1985 |
| From: | Dance H, William Orders, Pierson R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20138Q380 | List: |
| References | |
| 50-369-85-40, 50-370-85-41, NUDOCS 8512270184 | |
| Download: ML20138Q402 (10) | |
See also: IR 05000369/1985040
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET.N.W.
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Report Nos: 50-369/85-40 and 50-370/85-41
Licensee: Duke Power Company
422 South Church Street
Charlotte, NC 28242
Facility Nan; : McGuire Nuclear Station
Docket Nos: 50-369 and 50-370
License Nos:
Inspection at McGuire Nuclear Station near Huntersville, North Carolina.
Inspectors:
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W.' Orders,~ Senior Resident Inspector
Dat6 Sicfned
W
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R. Pi
son, Resident Inspector
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0ath Sigfied
Approved by:
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Hugh C// Dance, Sectibn Chief
Dath Si@ned
Division of Reactor Projects
SUMMARY
Inspection on October 29, 1985 through November 20, 1985.
Scope:
This routine unannounced inspection involved 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> onsite
n the
areas of operations, surveillance testing and mainten e ce activities.
Results: Of the areas inspected, one violation was identified in the area of
surveillance testing.
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- T. McConnell, Plant Manager
- B. Travis, Superintendent of Operations
- D._ Rains, Superintendent of Maintenance
- B. Hamilton, Superintendent of Technical Services
- L.-Weaver, Superintendent of Administration
- M.' Sample, Superintendent of Integrated Scheduling
- E. McCraw, License and Compliance Engineer
D. Mendezoff, License and Compliance Engineer
D. Marquis, Performance Engineer
R. White, IAE Engineer
R. Branch, Site QA Supervisor
Other licensee employees contacted included construction craftsmen,
technicians, operators, mechanics, security force members, and office
personnel.
- Attended exit interview.
2.
Exit Interview
The inspection scope and findings were summarized on November 26, 1985, with
those persons indicated in paragraph 1 above. The violation discussed in
paragraph 12 was acknowledged.
The licensee did not identify as pro-
prietary any of the materials provided to or reviewed by the inspectors
during this inspection.
3.
Licensee Action on Previous Enforcement Matters
No previous enforcement items were closed.
4.
Unresolved Items *
Two unresolved items were identified during this report period and are
discussed in paragraphs 11 and 13.
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5.
Plant Operations
The inspection staff reviewed plant operations during the report period, to
verify conformance with applicable regulatory requirements.
Control
operator logs, shift supervisors logs, shift turnover records and equipment
removal and restoration records were routinely perused.
Interviews were
- An Unresolved Item is a matter about which more information is required to
. determine whether it is acceptable or may involve a violation or deviation.
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conducted with plant operations, maintenance, chemistry, health physics, and
performance personnel. Activities within the control room were monitored
during shifts and at shift changes. Actions and/or activities observed were
conducted as prescribed in applicable station administrative directives.
.
The complement of licensed personnel on each shift met or exceeded the
minimum required by technical specifications (TS).
Plant tours taken during the reporting period included but were not limited
to the turbine buildings, auxiliary building, Units 1 and 2 electricci
equipment rooms, Units I and 2 cable spreading rooms, and the station yard
zone inside the protected area. During the plant tours, ongoing activities,
housekeeping, security, equipment status and radiation control practices
were observed.
Unit 1 Operations Summary
Unit I began the reporting period in Mode 1 operating at 100% power and
remained at that power level until November 2,1985. At 6:40 a.m. that
morning, with both units operating at 100% power, the flexible discharge
line of Instrument Air Compressor B failed resulting in the loss of
instrument air en both McGuire units.
The loss of instrument air resulted
among other things in the pneumatic main feedwater regulator valves
drifting closed on both units, ultimately resulting in reactor trips on both
units due to lo-lo steam generator level. A safety injection occurred on
Unit I but did not occur on Unit 2 as system pressure did not decrease to
the. initiating setpoint.
The safety injection on Unit I required the declaration of an Unusual Event.
The declaration was made at 7:25 a.m.,
that morning and was terminated at
9:04 a.m.
The unit was restarted later that day and remained in Mode 2
pending repair of a severed instrume'nt fitting on the secondary side of the
"A"
Efforts to repair the instrument fitting in Mode 2
were futile. It was decided to place the unit in a status more conducive to
the repair, thus the unit was placed in Mode 3 at 12:55 p.m., on November 3
and was subsequently cooled down to 360 degrees F and 1600 psig.
On Monday, November 4,
1985, the instrument fitting was repaired but a
through wall leak on the
"D" Steam Generator feedwater check valve was
detected. The unit was cooled down and placed in Mode 5 at 8:08 a.m.,
on
November 6,1985, to facilitate the necessary valve repairs. Following the
completion of the repairs, the unit was returned to the grid at 10:34 a.m.,
on November 9.
That afternoon power ascention was terminated due to high
containment temperature which resulted when 1 of 3 operable Containment
Cooling units was lost.
Power was reduced to 10% to facilitate repairs to
the cooling unit and was subsequently increased to 100%.
.cx unit remained at full power until November 20, when a unit runback
occ;rred due to a main feedwater pump trip. The remaining main feedwater
pump was i nable to maintain the required flow, began to oscillate, and
ultimately : ripped on high discharge pressure.
The trip of the remaining
feed pump caused a turbine trip and reactor trip. All systems responded
normally following the trip. The unit completed the reporting period in
preparation for unit startup.
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Unit 2 Operations Summary
Unit 2 began the reporting period in Mode 1 operating at 100*4 power arid
remained at that power level until November 2 when the reactor tripped as
discussed in the Unit 1 Operations section.
A unit fast recovery was
initiated with the unit reaching 100% power at 4:05 p.m., on November 3.
The
unit remained at 130% power for the duration of the reporting period.
6.
Surveillance Testing
-The surveillance tests below were analyzed and/or witnessed by the inspector
to ascertain procedural and performance adequacy and conformance with
-applicable Technical Specifications.
The selected tests witnessed were
examined to ascertain that current written approved procedures were
available and in use, that test equipment in use was calf brated, that test
prerequisites were met, system restoration completed and test results were
adequate.
PT/1/A/4204/01A
Residual Heat Removal Pump 1A Perforr Ence Test
TT/1/A/9100/102
Service Water Train IA Flowrate Comparision
PT/1/A/4209/03P
NV Valve Stroke Timing shutdown
PT/2/A/4600/03E
Refueling Canal Drain Operability Checklist
PT/2/A/4252/01
Auxiliary Feedwater Performance Pump Test #2
.PT/2/A/4252/01A
Motor Driven Auxiliary Ft.eowate! Performance
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Test 2A
PT/2/A/4252/01B
Motor Driven Auxiliary Feedwater Performance
Test 2B
7.
Maintenance Observations
The maintenance activities below were analyzed and/or witnessed by the
resident inspection staff to ascertain procedural and performance adequacy
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and conformance with applicable Technical Specifications.
The selected
activities witnessed were examined to ascertain that where applicable,
current written approved procedures were available and in use, that
prerequisites were met, equipment restoration completed and maintenance- -
results were adequate.
042811
PM/PT Channel Source Checks on all EMF's
56944
Boroscope Containment Heat Exchanger Tubes
126002
SSF Diesel
048176
- 2 Auxiliary Feedwater Motor Driven Pump
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8.
Vital Battery Technical Specification
On October 3, 1985, Operations personnel determined that the method in which
they performed OP/0/A/6350/01A (125 VDC/120 VAC Instrument and Control
Power) did not meet the intent of TS 3.8.3.1 as follows.
To remove a
battery from service for the purpose of an equalizing charge, Operations
personnel performed OP/0/A/6350/01A, Enclosure 4.11.
The procedure requires
placing the.120 VAC power on regulated power supply, removing the associated
static inverter from service, closing the tie breakers between the DC
distribution centers and then opening the breaker between the battery and
the DC distribution center.
The battery is then logged in the Technical
.
Specification Action Item Logbook as a 72-hour action item.
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The 120 VAC Vital Instrumentation and Control Power System receives its
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normal power from separate independent inverters. A regulated power supply
is provided as an alternate non-essential source for one AC vital load for a
maximum of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per TS 3.8.2.1.
Consequently, unless the provisions of Action b. of TS 3.8.2.1 are met, in
that the associated bus is energized with an operable battery bank via an
operable tie breaker within two hours, the TS allow the use of a regulated
'
. power supply as an alternate non-essential source for only 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> versus
the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as implemented by proceaure OP/0/A/6350/01A.
Since
OP/0/A/6350/01A allowed up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without specifying the provisions of
Action b. o f TS 3.8.2.1, this does not meet the intent of TS 3.8.3.1.
Inasmuch as this was licensee identified, was a Severity Level IV, was
. reported and corrected promptly and was not a violation that could reason-
ably be expected to have been prevented by the licensee's corrective action
for a previous violation, a notice of violation will not be issued.
9.
Valve Mislabeled
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On August 12, 1985, it was discovered that valve 2RN-886 was listed as
2RN-866 in' procedure PT/2/A/4200/02A (Monthly Containment Integrity
Verification) and PT/2/A/4200/02C (Containment Integrity verification During
The error was discovered during a review of
PT/0/B/4700/23 (Semi-Annual Outside of Containment Locked Valve Verifica-
tion).
Upon discovery, 2RN-886 was verified to be locked closed as
required.
Valve 2RN-886 is located on the Nuclear Service Water (RN)
non-essential header containment penetration (M307).
This valve is also
capped when not in use.
Although this incident is indicative of an
inadequate procedure, the NRC encou ages licensee self-identification and
correction of problems through systematic reviews such as those conducted to
find this error. Pursuant to the stipulations of 10 CFR Part 2 Appendix C
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Section V.A., a notice of violation for an inadequate procedure will not be
issued.
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10.
Lost Work Request
On October 14. 1985, it was determined that the TS required monthly source
check surveillance on all Unit 2 EMF's (Process and Area Radiation
Monitoring Device) performed on May 19, 1985, would have to be classified as
missed surveillance due to the loss of the documentation.
The monthly
surveillance performed prior to and after this event showed that the EMFs
met the functional specifications.
To prevent this type incident from
re-occurring, the licensee plans to implement a Maintenance Management
Procedure 4.3. (Lost Work Request), to address this issue.
In addition,
the planning section will reevaluate the work request routing system,
looking for improvements for control and transfer between groups and will
evaluate the method of keeping work requests and all associated documenta-
tion together.
Although the event qualifies as a missed surveillance,
pursuant to the stipulations of 10 CFR 2, Appendix C, Section V. A., a notice
of violation for failure to meet the surveillance interval specified in
TS 4.3.3.8 and 4.3.3.9 will not be issued.
11.
Evaluation of Delta T Incident
Background
During the course of Cycle 2, McGuire Unit 2 has experienced a gradual
decrease in the indicated value of the full power Delta T across tne core.
In the latter part of June, approximately six weeks after power escalation
commenced for Cycle 2, station personnel performed a precision heat balance
to verify RCS (Reactor Coolant System) flow.
During this six-week time
frame, the indicated Delta T had decreased by approximately 1 degree F.
The
precision heat balance indicated an increase in RCS flow from Cycle 1 and a
corresponding decrease in the measured full power Delta T's for the four
loops.
Because the Delta T channels for the overtemperature Delta T and
overpower Delts T setpoints were scaled to the full power Delta T's obtained
.during the Cycle 1 precision heat balance, the Delta T channels were
underpredicting core power by as much as 5% RTP (Reactor Thermal Power).
Station personnel contacted the Safety Analysis Unit to determine whether
the allowable values fo, the overtemperature Delta T and overpower Delta T
setpoints had been exceeded.
In addition, they requested guidance as to
what corrective actions should be taken related to the apparent non-conser-
vative indication of power in the Delta T channels. It was mutually agreed
upon the+ the Delta T channels should be rescaled to the Delta T values
obtainec from the most recent precision heat balance.
On June 27, 1985, -
station personnel rescaled the Delta T channels to the more conservative,
lower values of Delta T obtained from the June precision heat balance.
However, because of some peculiarities related to the drift of the Delta T
channels, it was difficult to determine whether the overtemperature Delta T
and overpower Delta T setpoints had exceeded their allowable values.
On
July 2, 1985, a letter was sent to Westinghouse requesting their assessment
of the causes and licensing implications of the drift in the Delta T
channels.
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The results of the Westinghouse evaluation identified two potential causes
for the Delta T decrease; a change in the hot leg temperature streaming
pattern and/or a reduction in thermal power.
Based upon an extensive
evaluation of key plant parameters, Westinghouse concluded that the maximum
error due to changes in hot leg temperature steaming pattern is limited to
0.5 degree
F.
Some secondary plant parameters indicate that up to
0.5 degree F of the Delta T reduction may be due to a decrease in thermal
power,.possibly caused by fouling of the feedwater venturis.
-The Westinghouse evaluation stated that the approximately 1 degree F drift
associated with the Delta T channels is within the uncertainty allowances
assumed in the safety analyses.
Therefore, the precision heat balance
performed in June may be considered valid.
In addition, since the error
associated with the calculated flow is within the uncertainty allowance
assumed in the safety analyses, there are no flow related technical
specification violations associated with the Delta T drift incident.
However, when ~ the 1 degree F drift is added to the errors associated with
not calibrating the Delta T channels during startup, the total error
associated with the Delta T channels is greater than the uncertainty
allowances assumed in the safety analyses.
Prior to the June 21, 1985,
calibration of the Delta T channels, these errors were as follows:
Loop A
Lopp B
Loog_C
Loop D
B0C 1 Delta T
57.4
57.8
59.8
58.1
6/21/85 Delta T
55.97
54.73
56.53
56.12
Error in Degree F
1.43
3.07
3.27
1.98
Error in % full power
2.5
5.3
5.5
3.4
'These Delta T channel errors can potentially impact the FSAR accidents which
take credit for a reactor trip on the overtemperature Delta T or overpower
Delta T trip functions.
There is s'ufficient margin included in the over-
temperature Delta T setpoint calculation to account for the Delta T channel
errors.
Therefore, the accident analyses which take credit for a reactor
trip en overtemperature Delta T (RCCA Withdrawal at Power, RCCA Misalign-
ment, and Boron Dilution) remain valid. However, for the overpower Delta T
trip function, there is not sufficient margin in the setpoint calculation to
account for the Delta T channel errors.
Several Technical Specification problem areas were encountered, including
unit consistency in the overpower and overtemperature Delta T expressions,
application of maximum setpoint variation from the computed trip setpoint,
and TS implication that rescaling should take place each time a precision
heat balance is performed.
In some instances McGuire appeared to be less
conservative than recommended, and in one appeared to be more conservative.
This issue will be maintained as an Unresolved Item (370/85-41-01) pending
qualified evaluation of Westinghouse's analysis and subsequent evaluation of
this incident as it affects McGuire.
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12.
Failure to Perform Technical Specification Surveillance
On October 22, 1985, at 1:20 P.M. , Operations personnel discovered that
Enclosure 13.2 (Refueling Canal Drain Operability Checklist) of PT/2/A/
4600/03E (Quarterly Surveillance Items) had not been completed for Unit 2 by
its latest due date of October 18. The refueling canal drains are required
to be operable in Modes 1 through 4.
The procedure was subsequently
performed and successfully completed at 1:45 p.m. that afternoon.
During'the licensee investigation of the incident, they discovered that the
Unit 2 PORV (Pressure Operated Relief Valve) block valve operability test
(Enclosure 13.1 of PT/2/A/4600/03E) was performed on October 21, three days
after its latest due date of October 18. The PORV block valves are required
to be operable in Modes 1 through 3.
A review of the incident with respect to the root cause revealed that an
Operations Engineer in charge of scheduling Operations periodic tests
reviewed PT/2/A/4600/03E, which had been completed on June 25.
He
-incorrectly assumed that the PT performed on June 25 met the requirements
for the entire quarter (April 21 through July 21), and the next due date
would be October 21, or three months from July 21. The correct due date for
the PT was September 25 or three months from its last completed date of
Jule 25.
On October 21, control room personnel completed Enclosure 13.1 of PT/2/A/
4600/03E (PORV Block Valve Operability Checklist) but did not complete
Enclosure 13.2 (Refueling Canal
Drain Operability Checkli st) .
On
October 22, Operations shift personnel turned the procedure over to the
Operations PT group, stating that the shift did not have time to perform
the PT. The assistant shift supervisor in charge of the PT group contacted
the Operations Engineer to find out how much grace time there was left on
the surveillance.
It was at this point that the Operations Engineer
detected his mistake.
It was not discovered until later, during the investigation on the refueling
canal drains, that the PORV-block valves had been technically inoperable
from' October 18 to October 21 when Enclosure 13.1 of the PT was completed.
The same Operations shift was on duty on October 21 and 22.
The shift
supervisor initialed the procedure step verifying Enclosure 13.2 (Refueling
Canal Drain Operability Checklist) was completed and signed the procedure as
being completed on October 22. The shift supervisor also made log entries
-into the shift supervisor's logbook concerning the missed surveillance on
the refueling canal drains but no entry was made concerning the PORV block
valves.
Contrary to TS 3.6.5.8 and 4.4.4.2,
the surveillance to verify the
operability of the refueling canal drains and the PORV block valves were not
performed within their applicable surveillance intervals as described above.
This is a-violation (370/85-41-02).
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13.
Containment Pressure Control
A review of Licensee Event _ Report (LER) 369/85-29, has indicated that the
peak containment pressure calculation for FSAR Section 6.2.1 resulted in a
value which may exceed the design internal containment pressure of 15 psig.
This analysis was performed using parameters as described in LER 369/85-29,
-specifically the WCAP-8246-Model computer code. With the procedural change
implemented on November 30, 1984, such that the order in which pump suction
transfer changed (containment spray pumps are swapped last on the 10-10
alarm), the containment spray could have been secured for a short period of
time following ice melt, this could have resulted in containment pressure
reaching 15.8 psig.
Duke has proposed that with a newer computer code, WCAP 10329 and other
considerations, containment pressure would not exceed 15 pounds, even with
the procedural changes implemented in November 1984.
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Emergency Procedures were changed on 10/4/85 to specifically require ND
spray initiation at 3000 seconds versus 3600 seconds.
This reduces peak
pressure to within design pressure using the older computer code.
This item will be carried as an Unresolved Iter (369/85-40-01).
14.
Inservice Testing Discrepancy
On October 18, 1985,- Quality Assurance (QA) personnel were performing QA
surveillance MC-85-63 on the Pump and Valve Inservice Testing Program
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(IWP/IWV).
During the surveillance, it was discovered that valves 1NV-223
and 2NV-223, Centrifugal Charging Pump Suction from Refueling Water Storage
Tank Check Valves had never been partially stroked as required by the
IWP/IWV. These check valves are located between the Refueling Water Storage
Tank and the_ Centrifugal Charging Pu'mp Suction line. A search was conducted
for station procedures which included partially stroking these valves. None
were found. A Nonconforming Item (NCI) Report was subsequently issued by QA
to the Nuclear Production Department.
The _ IWV section of IWP/IWV provides rules and requirements for inservice
testing to verify operational readiness of certain valves. These valves are
required to perform a specific function in shutting down a reactor to cold
shutdown conditions or in mitigating the consequences of an accident.
Article 3522 of IWV states that " check valves shall be exercised to the
position required to fulfill their function unless such operation is not
practical during plant operation.
If only limited operation is practical,
during plant operation the check valve shall be part-stroke exercised during
plant operation and full-stroke exercised during cold shutdowns.
Valves
that cannot be exercised during plant operation shall be specifically
identified by the owner and shall be full-stroke exercised during cold
shutdowns."
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The IWV test requirement for valves 1NV-223 and 2NV-223 is to verify proper
valve movement of these valves every three months. However, in accordance
with Article 3522, the licensee has taken exception to full-stroke
exercising these valves during plant operation or cold shutdown. Instead,
.these valves were to be partially stroked during cold shutdown and fully
stroked during refueling.
Licensea personnel believe that the same reasoning for not full-stroke
exercising these valves during plant operation or cold shutdown should also
apply to the partial-stroke test.
Testing of this valve requires opening
INV-221A or INV-222B, Changing Pump Suction from Refueling Wat,er Storage
Tank and Centrifugal
Changing Pump Suction from Refueling Water
respectively.
Failure of one of these valves in the open position aligns
the Refueling Water Storage Tank to the suction of the changing pumps with
no means of isolating the flow path. This could result in an increase in
boron inventory in the reactor coolant system and could result in a plant
s
shutdown.
Full-stroke exercising at cold shutdown could result in a low
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temperature overpressurization. It is their intention to revise the IWP/1WV
submittal to require only full-stroke exercising during refueling.
The
partial-stroke requirement will be deleted.
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. A review of past events determined that failure to perform this type of
surveillance was an isolated incident.
In addition, this discrepancy was
identified by a licensee conducted QA surveillance.
Since this incident
meets the requirements of 10 CFR Part 2 Appendix C Section V.A., a notice of
violation for failure to perform a required surveillance will not be issued.
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-15.
Open Items Review
Ti e following item was reviewed in order to determine the adequacy of
coarective actions, the implications as they pertain to safety of
opt rations, the applicable reporting requirements, and licensee review of
the event.
Based upon the results of this review, the item is herewith
cloted.
Unit _2
LER 85-22
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