ML20203J554
| ML20203J554 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 02/19/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203J504 | List: |
| References | |
| 50-327-97-18, 50-328-97-18, NUDOCS 9803040189 | |
| Download: ML20203J554 (29) | |
See also: IR 05000327/1997018
Text
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-U.S. NUCLEAR REGULATORY COMMISSION
REGION II'
Docket Nos: 50-327, 50-328
License Nos: DPR 77 -DPR-79-
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Report No: 50-327/97-18. 60-328/97-18.
Licensee: Tennessee Valley Authority (TVA)
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Facility: Sequoyah Nuclear Plant.-Units'l & 2
l Location: Sequoyah Access Road
L Hamilton County, TN 37379
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Dates: December 21, 1997 through January _31,~ 1998
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Inspectors: M. Shannon Senior Resident Inspector
R; Starkey, Resident Inspector
R.-Telson. Resident Inspector
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E. Girard, Region II Reactor Inspector-
(Sections E1.5- E8.3)
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_-Approved by: M. Lesser Chief
-Reactor Projects Branch 6
Division of Reactor Projects.
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Enclosure 2
9903040189 990219
PDR ADOCK 05000327
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EXECUTIVE SUMMARY
Sequoyah Nuclear Plant. Units 1 & 2
NRC Inspection Report 50-327/97-18, 50-328/97-18
This integrated inspection included aspects of licensee operations.
. maintenance, engineering plant support, and effectiveness of licensee
controls in identifying, resolving, and preventing problems: in addition it
includes the results of a Generic Letter 89-10 Motor Operated Valve closecut
inspection.
Ooerations
- tly identify
A weakness
that wasremote
a TS recuired identified because
shutdown operators
instrument wasfailed to prorTe and did not
inoperab
enter the 7-cay LC0 for approximately 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> (Section 01.2).
- Unidentified reactor coolant system leakage slowly increased over a
seven month period and was approximately .30 gpm at the end of the
inspection period (Section 02.1).
. A Non-Cited Violation was identified for the failure to take hourly log
readings of AFD with the AFD monitor alarm inoperable (Section 08.1).
- A weakness was identified in operations based on an assistant unit
oper6 tor (AUO) leaving an area while draining a tank which resulted in a
glycol spill, operations inspecting the wrong sump / pit and signing off a
PER as complete. and not removing caution tags after the documented
completion of sump cleaning. These issues contributed to a 700 gallon
contaminated water spill on January 9. 1998 (Section R1.2).
Maintenance
. The licensee's past corrective actions to correct problems with the site
storm drain system were effective (Section M2.1)
. A Non-Cited Violation was identified for a missed TS surveillance
recuirement (SR 4.4.3.2.1.b) for not stroking the pressurizer PORVs in
Moce 4 (Section M8.1).
Enaineerina
. Engineering support for the ieactor coolant Jump stator high temperature
problem was considered to be good based on t1e guidance provided to
oberations
( ection 02.1).which resulted in a well controlled and successful evolutio
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e : Engineering's investigation of the safety injection system relief valve
drifting setpoint issue was considered to be good, it identified that
the relief valve setpoint drifting problem was primarily due to an
ineffective preventive maintenance program (Section E1.1).
. The licensee's investigation into the safety injection relief valve
setpoint drift problem identified that the relief valve guide ring was
subject to severe corrosion when placed in a borated water environment
(Section E1.1).
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Engineering support in dealing with the ongoing turbine impulse pressure
switch setpoint drift problem was considered to be good (Section El.2),
e
A weakness was identifled based on engineering *s missed opportunity to
verify proper positioning of the pressurizer spray valve following
adjustment of the positioner resulting in abnormal pressurizer backup
heater operation (Section E1.3).
- Concerns were raised by the inspectors regarding the licensee's
disposition of a pressurizer level instrument v.hich failed its
calibration surveillance. The inspectors continued to review the
licensee's evaluation. (Section El.4)
,
e Based on NRC inspections and commitments in the licensee's letter dated
l February 12. 1998, the NRC is closing _the review of the GL 89-10 program
l at Sequoyah (Section E1.5)
Plant Sucoort
A violation with two examples was identified for not frisking out of a
posted radiologically controlled area (Section RI.1).
A weakness was identified in that appropriate levels of management were
not informed that posted frisking requirements had not been met and
later that day additional personnel failed to meet the same posted
frisking requirements (Section R1.1).
A weakness was identified based on plant support laborers cleaning the
abandoned upper head injection pit instead of the AEB sump and the
assigned radiation control technician controlling the radiation work
Sermit activ', ties in the abandoned pit versus the AEB sump (Section
11.2).
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Reoort Details J
Summary of Plant Status
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Unit 1 operated at full power for the entire inspection period.
Unit 2 operated at full power for the entire inspection period.
. Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments -
While performing inspectioris 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/or parameters.
I. Ooerations
01 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707. the inspectors conducted fr- sent
reviews of ongoing plant operations. In general, the conduct of
operations was considered to be good with the exception of the missed
LC0 entry noted in Section 01.2 and operational errors noted in Section
R1.2.
01.2 Ooerators Fail to Enter Action Statement for Failed Remote Shutdown _
Instrument
a. Insoection Scoce (71707)
The inspectors reviewed the circumstances related to the failure of
operators to recognize the entry into the TS action statement for an
inoperable remote shutdown wide range pressurizer pressure instrument.
b. Observations and Findinas
On December 21.1997. at 9:00 p.m. . a unit reactor operator. ::hile in
the auxiliary control room, observed that wide range pressurizer
pressure indicator 1-PI-68-342C had failed low and questioned the
operability of the instrument. Subsequently, at 12:04 a.m.. on
December 22. operations personnel determined that 1-PI-68-342C was a TS
required instrument and entered the action statement for TS 3.3.3.5.
Remote Shutdown Instrumentation. During their investigation, the
operators determined that the auxiliary control room indicator had been
inoperable since 5:52 a.m.. on December 18. 1997.(approximately 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br />
from the LCO entry time). This determination was based on the time that
the main control room wide range indicator. 1-PI-68-342A. located in the
same instrument loop had failed low. Repairs to 1-PI-68-342C were
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subsequently completed and the action statement was exited at 11:25
a.m.. on December 22. approximately four days and six hours into the
seven day allowed LC0 outage time.
Several opportunities existed prior to December 22. to identify the
inoperable auxiliary contrcl room indicator. On December 18, when 1-PI-
68 342A (the main control room instrument) failed, operators did not
rerearch control drawings to determine whether other instruments were
affected by the failure and, therefore, did not recognize that the two
instruments (1-PI-68-342A and 1PI-68-342C) were in the same instrument
loop. On December 19. maintenance personnel discovered that 1-PI-68-
342C had failed low, but did not ensure that the information was
communicated to the control room. On December 20. o
first became aware that 1-PI-68-342C had failed low perations personnel
but did not
recognize that a TS LC0 entry was required because of a work request
sticker on the indicator which led them to believe that the instrument
had been previously evaluated for a deficiency. Additionally, the unit
reactor operators performed general walkdowns of the auxiliary control
room once a day (on the midnight shift) and failed to notice or question
the failed instrument on at least two occasions (December 18 and
December 19).
PER No. SO972718PER was initiated to document the failure of operators
to identify that entry into a TS action statement was required for the
failed remote shutdown instrument. The PER concluded that the primary
root cause for not entering the action statement was the failure of
o)erators to review control diagrams to identify all affected components
w1en the main control room instrument failed. On January 23. 1998, the
inspector attended the Management Review Committee (MRC) meeting which
discussed the root causes and corrective actions for the PER. The
inspector concluded that the discussion of the event was thorough and
that the proposed corrective actions were reasonable and complete.
t
c, Conclusions
The inspectors concluded that operators failed to promptly identify that
a TS required remote shutdown instrument was inoperable. This is
identified as a weakness in the thoroughness by which operators evaluate
instrument failures.
92 Operational Status of Facilities and Equipment
02.1 Increase in Unit 1 Unidentified RCS Leakace
a. Insoection Scooe (71707)
The inspectors monitored the licensee's response to the gradual increase
in unidentified leakage over the last several months.
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b. Observations and Findinas
Since June 1997. to the present. the Unit 1 unidentified leakage rate
has increased from approximately .05 gpm to aapraximately .30 gpm. At
the same time the Unit 1 RCP #2 seal leakoff lad slowly increased, and
subsequently stabilized at approximately 4.8 gpm (normal leakoff is
approximately 2.5 gpm). An increase in RCP #2 stator winding
temperature from approximately 250 'F to 292 'F was also observed.
On January 9 1998, the licensee entered Unit 1 containment to visually
inspectRCPI2forsealleakageandtoinspectthepumpmotorcoolerfor
accumulation of boron which was believed to be collecting on the motor
coo b' causing the increase in stator winding temperature. The visual
inspection noted only a small amount of ooron accumulated in the pump
bowl but observed that a more significant amount of boron had
accumulated on the pump motor cooler. The location of the RCS le6k
causing boron accumulation in the motor cooler could not be determined.
On January 13, 1998, the licensee finalized a plan, based on previous
experience with RCP motor cooler boron accumulation, to isolate ERCW to
the motor cooler. This would allow the boron to heat up powderize, and
blow out of the cooler. System Operating Instruction 1 50 68-2. Reactor
Coolant Pumps Revision 17, was used during the performance of this
evolution. The licensee knew from previous experience that when ERCW
was isolated that the stator winding temperature would increase,
stabili * t a slightly higher temperature, then decrease as the boron
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dried out and was blown out of the cooler. When this evolution started.
the A phase winding temperature was ap After the
ERCW was isolated to the motor cooler,the proximately 292 temperature
stator winding 'F
slowly increased to approximately 304 'F. where it stabilized and then
began a slow decrease as the boron was apparently being blown out of the
cooler Subsequeni.ly. ERCW was again supplied to the cooler 6nd the
winding temperature decreased to less than 250 'F. By the end of the
inspection period the RCP stator winding tem)erature had started to
increase and had reached approximately 260 *:.
c, Conclusions
Engineering support was considered to be good based on the guidance
provided to operations which r '.ulted in a well controlled and
successful evolution.
Unidentified reactor coolant system leakage slowly increased over a
three month period and was approximately .30 gpm at the end of the
inspection period. The source of the reactor coolant system leakage has
not been determined.
08 Miscellaneous Operations Issues (92901)
08.1 (Closed) URI 50 328/97-08-01. Potentia 11v Inocerable Axial Flux
Difference (AFD) Monitor Alarm. The p' ant operaters had questioned the
operability of the AFD Monitor alarm due to the " Computer Alarm. Rod
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Deviation and Power Rerge Tilts" alarm window being in continuous alarm
and not having reflash capability. The inspectors reviewed the
o>eration of the alarm and noted that the function of the alarm had
manged over the past several years due to changes in the method of
monitoring / controlling axial offset. At one time the alarm functioned
to warn the operator that the axial flux difference was outside a TS 5%
target band.- The TSs were revised which eliminated the TS target band
and allowed the licensee to treat the St talget band as an
-administrative limit and the TS limit became the doghouse noted in TS 3.2.1.. However, when the TS was revised, the operation of the alarm was-
not changed to match the TS requirement. The licensee subsequently-
implemented a modification to the alarm circuitry to provide reflash
capability to the alarm circuit if the actual AFD ever exceeds the TS 3.2.1 limits. -The inspector concluded that the alarm was not operable
during the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> piiriod that it was locked in and hourly logging of
AFD was required. Based on discussions, the inspector concluded that
AFD was being actively monitored by the control room operators, although
not logged as required by TS 4.2.1.1.b. Based on these observations.
the inspector concluded that this issue was a violation for the failure
to take hourly log readings of AFD with the AFD monitor alarm
inoperable, as required by TS 4.2.1.1.b. This failure constitutes 6
violation of minor significance and is being treated as a Non-Cited
Violation consistent with Section IV of the NRC Enforcement Policy (NCV
50 327, 328/97-18 01).
08.2 (Withdrawn) VIO 50 327/97-04 02: Fai'ure to Meet the Surveillance
Reautremen's of TS 4.10.3.2. For Performina Functional Testina of the
tclgarInstruments. This violation is being withdrawn based on NRC
letter EA 08 030 dated January 28, 1998. -The letter noted that the
licensee's procedure steps for declaring the initiation of physics -
testing, Mode 2 entry, and the initiation of control bank withdrawal
were in conflict, which resulted in a failure to implement them as
written. The letter noted that due to the low safety significance the
NRC.was exercising discretion in accordance with Section Vll.B.6 of the
Enforcement Policy. NUREG 1600, and was not citing this violation. The
. inspectors.noted that corrective actions were reasonable and complete.
II, Maintquance
M1- Conduct of Mainter.ance
-M1.1 General Comments.
a .- Irsoection Scoce (61726 & 62707)
Using inspection procedures 61726 and 62707, the inspectors conducted
frequent reviews of ongoing maintenance and surveillance 6ctivities.
~~- The inspectors observed and/or reviewed all or oortions of the following
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work activities and/or surveillances:
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. WO 95 007297-027 System Transition to Operability of New
High Pressure Fire Protection System
- 2-SI-SXP-003.201.S TDAFW Pump 2A S Performance Test
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. 0-PI NUC-092.036.0 Incore-txcore Detector Calibration
. 1 50 68-2 Reactor Coolant Pumps-Isolation of ERCW to
Motor Cooler
. 2-SI-lCC 068 320.3 Channel Calibi 1 Of Pressurizer Level
Channel 111. Rau 9. Loop L 68-320 (L 461)
b. Conclusions
In general the conduct ot maintenance and surveillance activities was
cons 1dered to be good.
H2 Maintenance and Haterial Condition of Facilities and Equipment
M2.1 Effectiveness of Site Storm Drainaae System
a. Inspection ScoDe (62707)
Because of the recent heavy rains, the inspectors reviewed the
licensee's past corrective actions related to the site storm drainage
system,
b. Observations and Findinas
On July 11, 1994, several storm drains, especially those near the
turbine building, overflowed due to heavy rains and caused minor
flooding in the turbine building and other non-ssfety related locations
on site. This event was documented in Inspection Report 50 327,
328/94 18. Inspection report 94 18 documented that the licensee's
response to the event was good but the inspectors questioned the ability
of the storm drain system to handle the amount of rain received. The
licensee initiated an incident investigation (PER No. S094050711) which
concluded that catch basins and drain pipes were significantly
(typically 50%) blocked and that preventive maintenance instructions
prepared for the annual inspections of yard catch basins hui not
accomplished their intended purpose which was to eisure that the yard
drainage system was functioning as designed. Following that event, the
licensee initiated several corrective actions which included an
extensive plan to clean the storm drains. All the corrective actions
were completed by August 1995.
Recently, the inspector discussed the plant yard drainage system with
the site lead civil / mechanical engineer and reviewed plant drawings to
verify that the yard drainage pond (storm runoff retention pond) was at
a lower eleval. ion than those areas of the plant which drain into the
pond and that it was not feasible for the pond to back up into the
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plant. The inspector then toured that portion of the )lant owner
controlled area where the drainage pond is located. T1e pond 1s-
. designed with an overflow pipe, which is below the elevation of the i
areas that drain into the pond, and the overflow of the pond is directed
into the Tennessee River.
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c. Conclusions
Based on recent inspector observations of water run off during heavy
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rain conditions, the inspectors concluded that the-licensee's past
corrective actions related to the site storm drainage system were
effective.
H8 Hiscellaneous Maintenance Issues (92902)
l
M8.4 (Closed) URI 50 328/97-14 04. Missed TS Surveillance Reatirement SR 4.4.3.2.1.b for Strokina the Pressurizer PORVs-Durina Moce 4. This
event was discussed in Licensee Event Report (LER) 50-327/97014 (see
Section M8.2 of this report). The inspectors noted, from the sequence
of events listed in the LER. that since 1994, the licensee had been
performing the Unit 2 surveillance requirement of SR 4.4.3.2.1.b in Mode
< 5. rather than in Mode 4 as required. As described in the next
paragraph it appeared to the inspectors that the tests performed in
Mode 5 were performed under the same plant conditions as the tests
performed in Mode 4. The inspectors verified that the corrective
actions, for the failure to perform the surveillance in the correct
mode, were reasonable and complete. This non-repetitive, licensee-
identified and correctea v10lation is being treated as a Non Cited
Violation, consistent with Section VII.B.1 of the Nf' inforcement Policy
(NCV 50 328/97-18 02).
During the licensee's extent of review for the Unit 2 event described
above, it was identified that the Unit 1 PORVs had last been tested in
Mode 5 and that the last test performed in Mode 4 was valid until
January 18, 1998. In a letter to the NRC. dated November 21,1997, the
licensee requested an amendment to the Unit 1 TS to allow a one-time
. change, through o)erating cycle 9. to SR 4.4.3.2.1.b to perform stroke
testing of the PORVs in Mode 5 rather than Mode 4. In a letter dated
January 13. 1998, the NRC granted the one time Unit 1 TS amendment
request. The NRC safety evaluation associated with that TS amendment
stated that historically the surveillance is performed at the low end of
the Mode 4 temperature range which is similar to conditions at which the
test was performed in Mode 5. The TS amendment was granted based on the
fact that the Mode 5 PORV testing was technically equivalent to testing
performed with the unit in Mode 4.
M8.2 fClosed)'lER 50-327/97014. Missed Surveil'anccs as a Result of
- nadeauate Procedures and a Failure to Fo' lo'.: Procedure. The events
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associated with PORV--missed surveillances were discussed-in-Section H8;l
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of this report. The inspectors concluded that the licensee's corrective
action for the testing of the EDG load sequence timers and lockout
-features was reasonable and complete.
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~M8.3 (Closed) IFl 50 327.-328/96 08-04. Review Ca1ibration Instrument . !
Accuracy Reauirements. This IFl was origine ly written to follow up on
the licensee's corrective actions to address an 1ssue with calibration ;
instrumentation. A standard voltmeter had been used to perform a
calibratin of a switchyard instrument: however the voltmeter did not
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have the required accuracy. The licensee initiated a PER to address the i
issue and performed a root cause investigation of the problem. The
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licensee identified that the controlling procedure was inadequate in l
that it was a preventive maintenance procedure as opposed to being a -
. surveillance instruction, The controlling procedures were revised to i
specify the proper measurement and test equipment. An extent of ;
condition review was performed and no other problems with maintenance
and test equipnent were identified, The inspectors concluded that the
licensee's corrective actions for resolving the issue were reasonable !
and complete. !
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III. Enaineerina
El Conduct of Engineering
El.1 Safety In.iection Relief Valve Setooint Drift Investiaation
- a, Insoection Scone (37551)
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The inspectors reviewed the licensee's investigation into the drifting i
safety injection relief valve setpoints,
b, Observations and Findinas
The safety in ection system relief valves have experienced lift set)oint-
drifting prob ems during the resent SALP cycle. Until recently, tie
cause of the relief valve set oint drift had net been identified.
Inspection' Report 96 14 noted that the safety injection system relief ,
valves had failed to lift within the acceptable setpoint range on
November 2, 1996. The relief valve setpoints were not reset prior.to
startup which appeared to conflict with the ANSI B31,7 requirements.
IFI 50 328/96-14-01 was identified, at that time, to follow up the
resolution of the ANSI code issue.
Inspection Report 97-06 identified a violation-(VIO 50-328/97-06 08)
because the licensee had failed to implement prompt corrective actions
to resolve a condition adverse to quality in that following the Safety
Injection System over pressure event on November 2. 1996, the relief
- - valves were not reset as required by le ANSI /ASME OH-1 requirements.
"
The licensee had not identified the cause for the drifting set points at i
this time.
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Inspection Report 97-12 noted that the safety iiijection system relief
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- valves had failed to lift within the acceptable setpoint range during a
system over pressure condition on September 9. 1997. IFI 50-328/97-12- .
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7-94-9F** 2- 97 iy m-4 -g--gwr7 -v y- T' y My 7-D-y7 7W*vey'--yy wWv- e w ~f---w-r,ymr-we - - - - - * ' T'evr 1ip vr y g-- w-y g - " - -+--y yge r syi--
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03 was identified to follow the licensee's resolution to the safety
injectionreliefvalvesetpointdriftproblem.
Inspection Report 97-17 identi'ied a weakness with the licensee's
]reventive maintenance progr o :s noted by the licensee. The licensee
)ased this finding on industry reports that noted 70% of all relief
valve failures were caused by oging and that the licensee's preventive
maintenance program had not been revised to incorporate the industry
information.
During the 1997 Unit 1 and Unit 2 refueling outages, the licensee
performed setpoint testing of 10 relief valves from Unit 1 and 20 relief
valves from Unit 2. Three valves were identified with setpoints being
"out of tolerance." Others had drifted but were not out of tolerance as
defined by the ANSI code (>6% from setpoint). The licensee also noted
that since 1992, only five valves (three in 1997) were found with
setpoints "out of tolerance."
Following the 1997 Unit 2 refueling outage, the licensee disassembled
five of the relief valves, three of which had failed the "as found"
tolerance testing. Two relief valves removed from the safety injection
system were found to have severe corrosion on the guide rings. The
licensee noted that the guide rings were fabricated from type 416
stainless steel which wat, subject to rust and corrosion especially in
borated water service.
The inspectors noted that if a relief valve had not lifted or simmered
and if the discharge piping did not allow borated water to enter the
discharge port the relief valve would not exhibit the corrosion of its
guide ring. The safety injection system relief valves had lifted on
multiple occasions and it appeared that the discharge piping could
provide a loop seal and retain water in the discharge port of the relief
valves. These observations would a. count for the excessive corrosion of
the safety injection relief valves and why there was very little
corrosion-to the remainder of the relief valves used on other borated
water systems.
The licensee concluded that the major cause for failure of the relief
valves was aging. The licensee noted that most of the valves had little
or no internal lubrication present and two of the valves were severely
corroded. At the conclusion of the inspection period, the licensee was
evaluating / discussing the guide ring material problem with the
manufacturer (Crosby). The licensee and manufacturer were evaluating
whether the guide rings could be economically manufactured out of the
same material as the relief valve. type 300 stainless steel. The
followup of the licensee's corrective action to resolve the Crosby
relief valve degraded guide ring material issue is being identified as
an inspector follow up item (IFI 50 328/97-18-03).
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c. Conclusion .
The licensee's investigation found that the relief valve setpoint
drifting issue was due to aging and lack of an effective preventive
maintenance program.
The licensee's investigation identified that the relief valve guide ring
was subject to severe corrosion when placed in a borated water-
environment due to a material problem, j
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E1.2 Iurbine Imoulse Pressure Switch Driftina-Problems
a. Insoection scone (37551)
The inspectors reviewed the licensee's continuing investigation into the
drifting turbine impulse pressure switch setpoints.
b. Observations and Findinas
Problems with the non safety related turbine impulse' pressure switches
were first identified during the October 11, 1996, turbine run back.
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'which resulted in an unplanned manual reactor trip (IR 97-13). Water-
intrusion into the switch assembly had caused the switches to stick.
Following the event, all four of the switches were replaced with new
calibrated switches, On February 25.-1997. Unit 2 experienced another
turbine run back; however. the turbine did not run back as designed.
The pressure switches were checked and found.to be out of calibration.
The licensee and manufacturer identified that the electric micro switch -
holding screws had not been adequately torqued at the factory which
accounted for two of the failures. However, this finding did not
account for all of- the setpoint drifting problems Four switches from
each Secuoyah unit (eicht total) and four switches from the Watts Bar
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Junit hac. experienced 8D-100 pound set point shifts after initial
' calibration. The-manufacturer concluded that due to deformation of the
new diaphragm a two month burn in period was required for each new
switch.
outa
' four
Ouring the October 1997.
manufacturer-modified Unit 2swit
pressure refuelin!hes, be. the
ich were licenseetoinstalled
not supposed
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exhibit the previous setpoint drift problems. Within 90 days of
installation. the licensee disenvered that the switches were again
drifting high.
Since'the Unit 2 outage, the licensee continued to perform periodic-
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. calibration checks on the pressure switches on an increased frequency.
The licensee noted that the pressure switches were continuing to exhibit
up to a-10% setpoint drift and up to a 20% reset setpoint drift between
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calibration checks, based on data taken on January 9. 1998.- The - -
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censee's. records. ft all of the switches. indicated that'the switches
- op drifting after a period of time after being exposed to system
pressure..
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At the end of the inspection period, the licensee informed the
inspectors that the manufacturer had identified the probable cause of
the setpoint drift. The manufacturer concluded that the enclosure
mounting support for the electric micro switches within the pressure
switch was deforming. The manufacturer stated that a new pressure
switch with stronger support would be provided to resolve the drifting
setpoint issue. The affected pressure switches were identified as B761B
1000 PSI Ashcroft pressure switches manufactured by Oresser Industries.
They are used in quality related rather than safety related applications
at the Sequoyah site. The pressure switches provide pressure signals
for the turbine run back circuitry and for the auxiliary feedwater
actuation circuitry. The followup of the licensee's corrective actions
to resolve the Ashcroft pressure switch drifting setpoint issue is being
identifled as an Inspector Followup Item (IFl 50 328/97-18 09).
c. Conclusions
Engineering suppurt in dealing with the ongoing turbine impulse pressure
switch setpoint drift problem was considered to be good.
El.3 Pressurizer Backuo Heater Ooeration Due To Sorav Valve leakaae
a. Insoection Scone (37551 and 71707)
The inspectors reviewed the cause of the )ressurizer s) ray valve
abnormal leakage, which has resulted in tie need for tw continuous
operation of one group of pressurizer backup heaters during the present
Unit 2 operating cycle,
b. Observations and Find 10qq
During a control room walkdown the inspectors noted that a pressurizer
backup heater group was continuously energized to maintain reactor
coolant system pressure. Discussions with the operators indicated that
the pressurizer spray valve was leaking.
The inspectors verified that the required operation of the backup heater
grour did not-impact technical specification (TS) requirements for
pressurizer heater capacity. The TS requirement for 150 kW of heater
capacity is based on operation during natural circulation and the spray
valve leakage would only be a concern during forced circulation
operation,
The inspectors discussed the issue of setting the valve stroke for the
pressurizer spray valve. Engineering noted that during the last
o)erating cycle the pressurizer spray valve was rotating slightly past
tu fully closed position which was causing a valve position indication
problem. During the Unit 2 Cycle 8 refueling outage. the licensee
adjusted the valve operator. This was done while the plant was in
"cde 5 and the adequacy of the adjustment could not be verified at that
time.
. - _ _ _ _.-.,_. _ _ . _ . - . . _ _ . _ _ ___ _ _ _ _
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11 !
,The-s stem engineer informed the inspectors that he had planned to
verif the adjustment when the plant reached Mode 3. However. when the i
unit reached Mode 3. the system engineer was involved with other issues
.
. -and was unable to perform the post maintenance tcsting on the valve.- .
l 0'erations
a energized one of the backup heater grou)s and continued with *
4
'
t1e plant startup. Because of lant conditions, t1e valve )osition :
cannot be ad usted once the uni is in Mode 1 or Mode 2. T1e missed
"
opportunity- o perform the post maintenance position verification is
considered to be a weakness.
. ._
c. Conclusions '
i
A weakness was identified based on system en ineering's missed
e
,
opportunity to verify pro)er positioning of he pressurizer spray valve
following adjustment of tie positioner resulting in abnormal pressurizer -
backup heater operation.
~
EL4 Potentially Dearaded Pressurizer Level Instruments
j
'
a. Insoection Scooe (37551)
The inspectors reviewed the equipment history surveillances and various
problem evaluation reports (PERs) associated with concerns related to
the proper operation of pressurizer level (hot calibration) instrument
b .- Observations and Findinos
During the Unit 2 refueling outage, during October and November, 1997.
!
'
the inspectors noted in the control room. logs that a pressurizer 1
instrument channel had failed its calibration surveillance and that a ,
Technical 0)erability Evaluation (T0E) had been completed. The T0E
indicated tlat the instrument had failed its *as left" calibration (3 of- ,
'9 points out of specification), did-not meet manufacturer's
'
s)ecifications for hysterisis_-(required . 5% vs. actual 1%) and pressure.
s11ft (required .5% per 1000 psi vs actual 1% per-100 psi) and was not
~
in conformance with the scaling documents 'for generation of-the
calibration setpoint data. The T0E concluded that the pressurizer
-
instrument was acceptable as-is and Unit 2 was restarted.
The inspectors reviewed the-issue further and noted in:the surveillance
history that the calibration data was changed in 1988. The change was .
-based-on personnel having ste> ped on the instrument condensing pots and
bent them downwards. The wort history indicated that either the
calibration: data needed to be changed or the condensing pots restored
< prior _to startup The calibration
,
condensing pot _ lines.were deferred. procedure was revised and the bent
.
. .When the condensing-pot lines were eventually repaired, the calibration.
, -procedure was not revised. Following the Unit 1 drain down event in
~ April of 1997, the licensee noted a conflict between the pressurizer
level instrument as-built piping diagrams-and the values used for
_ _ - - _ _ - _
. - . - . _ . - _ - - - . - - . - - . . - - . . - - . _ -
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calibration cf all three of the pressurizer level instruments (hot :
calibration).- During walkdowns of the pressurizer level sensing lines-
and instruments in containment, the licensee vecified that the piping
diagrams-were correct and that the calibration procedures were in slight
error of 1% to 25.
At the end of the inspection period, the inspectors were reviewing the
requirements for resolution of degraded equipment-conditions as ,
documented by Generic Letter 91-18. Revision 1. The irispectors were
. also reviewing concerns with the-accuracy of the TS oressurizer high
level trip setpoint (92%) and repairs to the pressuriter level sensing
piping following the 1988 discovery non conformance. This issue is
identified as an Unresolved item pending further inspector review (URI
50-328/97-18 04).
c. Conclusions
An Unresolved item was identified concerning potentially degraded
pressurizer level instruments.
'
El.5- Imolemertat on of Generic Letter fGL) 8910." Safety Related Motor-
Doeratec Va' ve Testina and Survei lance"
a. JnsoectionScone(TemocraryInstruction 2515/109)
TVA's implementation of GL 89-10 was previously reviewed and determined
insufficient during NRC Inspection 50-327, 328/97-06. Outstanding issues
were identified which involved the long-term capabilities of certain
motor-operated valves (MOVs) and MOV groups.-.In a letter to the NRC
dated July 8.-1997, TVA committed to nine actions to address these
issues. NRC verification of completion of the actions was identified as
inspector followup item 50 327, 328/97-06 07. Actions to Resolve
Remaining GL 89-10' Issues.
The current inspection assessed TVA's resolution of the nine issues and
completion of related commitments. In addition, the-inspection further -
examined TVA's implementation of trending recommended by
GL 89-10. The ins)ection was. conducted through reviews of documentation :
and interviews wit 1 licensee personnel.
,
b. Observations and Findings
1, - Commitnent Comoletion and Issue-Resolution
Commitment 1 (Licensee Trackina No; NC0970056001)
NRC Inspection-50-327, 328/97-06 found that TVA did not- have sufficient
+
test data to justify the 0.40 valve factor that it had assumed in
calculating the design basis thrust requirements for'several gate valve
-
groups. To resolve this issue. TVA committed to revise its calculations
and use a (more easily supported)-group valve factor of 0.60, unless
test data was available to support a different value. TVA further
_
_._ _ _ _ _ _ _ .
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13 I
indicated that. if it did not already have test data to justify the
valve factors used it would evaluate industry data to justify the valve i
factors. l
To assess TVA's completion of this commitment and resolution of the I
related issue, the inspectors reviewed summary data for all of
Sequoyah's GL 89 10 gate valves and the thrust calculatiens and valve
factor bases for the following sample of the gate valves: 1FCV-01-018.
1FCV-03 179A. 2FCV 03 047 2FCV-68 332. and 2FCV-68 333. The inspectors
found that the thrust calculations applied a valve factor of 0.60 or
higher unless a lower value had been justified based on Sequoyah's
in plant testing. Further. TVA made an effort to obtain and evaluate
industry test data to justify the valve fac'.rs applied when it did not
have a)plicable data from it's own tests. However, the inspectors found
that tie data TVA had obtained to justify its valve factors were
inadequate in several instances. Therefore, the commitment was generally
met but did not result in complete resolution of the original issue.
The inspectors identified the following concerns regarding the test data
that TVA used in valve factor justifications:
- Gate Valve Grouo 1. Walworth 4-inch /600# flex wedae aate valves.
This group included 7 steam supply isolation valves to the Turbine
Driven Auxiliary Feedwater Pump (TDAFWP). Three of the valves
(2FCV-001-17, 1FCV-001-018. and 2FCV 001-018) were required to
isolate for a steam line rupture accident and, therefore, would
have to close under blowdown flow. TVA applied a 0.60 valve
factor in the thrust calculations for all Group 1 valves. It did
not have in-plant c.r industry test data for these valves but did ,
have data for larger Walworth valves which supported a 0.50 valve
factor under pumped flow. On the basis of that data, the licensee
considered it conservative to apply a 0.60 valve factor to the
Group 1 valves. The inspectors questionedu 'asing the valve factor
justification on testing of larger valves, especially as blowdown
flow conditions were experienced by some Group 1 valves.
- Gate Valve Groun 2. Anchor /Darlina 4-inch /600# flex-wedae cate
yf yn This group consisted of a single gate valve (1FCV-001-17)
which served as a steam supply isolation valve to the TDAFWP. TVA
used test data obtained from similar valves that were tested at
Arkansas Nuclear One (ANO) to justify the use of a 0.65 valve
factor for 1FCV-001-17. However, the inspectors noted that this
valve would have to close under steam blowdown flow conditions.
Because the ANO valves were not tested under steam blowdown
conditions the inspectors were concerned that the test data would
not be directly applicable to 1FCV-001-17.
Gate Valve Grouc 8. Crane 12-inch /320# solit-wedae cate valves.
lVA assumed a valve factor of 0.60 in calculating thrust
requirements for these safety injection valves. TVA nad no
Sequoyah test data to justify the 0.60 value and indicated it had
not been able to obtain industry test data ap)11 cable to these
valves. The inspectors were concerned with tais lack of
_
,
14
justification as the valves had marginal capabilities in the open
safety function direction, based on calculations applying a 0.60
valve factor.
In a letter to the NRC-dated February 12. 1998, the licensee committed
to actions to resolve the above concerns. The letter stated that the
Electric Power Research Institute (EPRI) Performance Prediction
Methodology (PPM) would be used to determine the thrust requirements for ,
l
valves from Groups 1, 2, and 8 (taking into account any ' lowdown
o
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performance requirements) and.that the PPM results would be incorporated- - i
into the design ant' :etup calculations. The inspectors noted that the
PPM was based on extensive vaive testing and was acceptable to the NRC,
!
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subject to the provisions of a related safety evaluation. The
licensee's letter indicated the actions for the above valves would be
complete by about September 30, 1998.
l In addition to the above concernt regarding justification for the valve
factors assumed in determining thrust requirements for gate valve Groups
1, 2. and 8: the inspectors identified several less significant concerns
regarding the licensee's gate valves, which licensee personnel stated
would be evaluated and addressed in Sequoyah's long term MOV program:
e
Gate Valve Grouc 9. Walworth 3-inch /1500# solid wedae aate valve s
The licensee used the results from tests performed on two similar
valves at its Watts Bar plant to justify applying a 0.60 valve-
factor to gate valve Group 9. The closing valve factors obtained
from the Watts Bar tests were 0.519 and 0.146, exhibiting a . larger
difference than expected for similar valves. The cause for this
large variation was-not explained,
e Gate Valve Grouos 10. 14. and 21- Anchor /Darlina 8.18. and 14-
inch /300# double-disc cate valves. 1he licensee used in plant
test results from gute valve Group-22 (Anchor / Darling 8-inch /300#
double disc gate valves) to justify applying a 0.60 valve factor
to these three groups. The inspectors found some weakness in the
support for this value because of-the variability in the valve
factors (0.23 to 0.59) determined from the Group 22 test data and
because the Group 22 valves were.significantly smaller than the
valves in Groups 14 and 21. The concern regarding these valves
was limited, as they were capable of accomodating much higher
(1.2 or greater) valve factors than 0.60,
e Gate Valve Grouc 23; Cooes Vulcan 14-inch /1500# double disk aate
va' ves. TVA used the results of open stroke tests performed on
four similar-valves at Dhblo Canyon to justify a 0.60 valve
-factor for Group 23. The edequacy of the. testing was questioned
by the inspectors as they found that the tests had been performed
with hydro pumps for the pressure source instead of system pumps,
resulting-in little-flow. Also, TVA did not-have any valve factor
.
-
- -
-- -
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- -
.
,
15
-
- data for the closing direction, which was a safety function direction-
for these valves. The concern regarding these valves was limited, as
- they were capable of accommodating a much higher (0.85) valve factor
-than would typically be expected for gate valves.
l Commitment 2 Ricensee Trackina No. NC0970056002)
! NRC Inspection 50 327, 328/97-06 identified that the licensee-did not
l- have sufficient information to demonstrate the adequacy of the torque
, requirements established for operation of Sequoyah s Pratt butterfly
valves. - The torque requirements had been provided by the manufacturer
(Pratt). To resolve this issue. TVA cTimitted to work with Duke Power
Company or obtain appropriate test data from other sources to validate
the Pratt requirements.
To assess the licensee's actions for this commitment, the inspectors
reviewed the following:
e 1.icensee documentation addressing this commitment collected under
tracking number NC0970056002
. Culculations documenting the design basis review, torque, and
.
capability assessments for valves 2-FCV-67-146. 0 FCV-67-152. 0
FCV-70 194. and 0 FCV-70-198 7
. Essential. Raw Cooling Water System (System 67) Flow Diagrams 1,2-
47W845-1. Revision 21: and 1.2 47W845-2. Revision 53
e Design criteria SON-DC-7.4. Revision 11. Essential Raw Cooling
Water System
...
Final Safety Analysis Report Sections 9.2.1.2 (Component Cooling
System) and 9.2.2 (Essential Raw Cooling Water System)
The inspectors found that the licensee had been obtaining and evaluating
Pratt butterfly valve test data from Duke Power Company, consistent with
its commitment. -However, the original issue was not resolved as this
effort was still. ongoing. The results had not been factored into the
butterfly valve torque calculations and only the smaller Pratt butterfly
valve sizes were being addressed. The results obtained from Duke
indicated a small nonconservatism (less than 10%) in the manufacturer's
predicted torque requirements for the smaller size valves. This
increased torque requirement was well within the capabilities of the
licensee's valves.
In its letter to the NRC dated February 12. 1998, the licensee committed-
to revise-its calculations for the smaller (18-inch and under) Pratt
butterfly valves, based on-the Duke test data. In addition, the
m -
licensee committed to obtain additional torque test data or run-the EPRI
PPM to' validate the torque requirements for.Sequoyah's 20 and 24-inch
-
Pratt butterfly valves. ~ The letter indicated these actions would be
^ complete by about September 30. 1998.
-_____ _ _
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Commitment 3 (Licensee Trackina No. NC0970056003)
NRC Inspection 50-327. 328/97-06 found that the switch setting sheets
used to spec 1fy the switch settings for Sequoyah's safety related MOVs
had not been revised to incorporate all of the most recent setting
limits determined in reconciling the design setting values with test
-results in the thrust calculatinns. To resolve this issue. TVA
comitted to issue a design change notice (DCN) to update the switch
.
setting)
1. 1997 .sheets after the thr
The inspectors ustthat
found calculations
TVA issuedwere
DCNcompleted (byNovember
S 13223A on December
11. 1997, which updated the switch settings for the Generic Letter 8910
MOVs. The inspectors com. oared the settings identified in the DCN with
the results contained in the related thrust calculations and confirmed
agreement. The licensee had completed the commitment and the related
issue was resolved.
Commitment 4 (Licensee Trackina No. NC0970056004)
i
NRC Inspection 50-327, 328/97-06 identified that, while TVA had tested
most of Sequoyah's globe valves under dynamic conditions. it had not
verified that the test data supported the 1.0 closing valve factor which
had been assumed in thrust calculations for Velan globe valves. In
response. TVA committed to review globe valve differential pressure test
data to determine if the 1.0 closing valve factc" was adequate. The
record of completion of this review reported that a valve factor of 1.1
was determined more appropriate. This revised valve factor was included
in the revised thrust calculations. The inspectors reviewed the thrust
calculation for 2FCV 63 003 and verified that a valve factor of 1.10 was
used for the closing direction. The licensee's actions for this
commitment were complete and resolved the related issue.
Comitment 5 (Licensee Trackina No. NC0970056006)
NRC Inspection 50-327. 328/97-06 identified that TVA was relying on
results from pum)ed flow testing to justify the thrust predictions for i
the pressurizer alock valves (1/2FCV-68-332/333). Pumped-floa testing
would not adecuately represent the blowdown flow conditions which would
be experiencec by a block valve in closing off flow from a failed open
pressurizer relief valve. In response to this issue, TVA committed to
perform maintenance improvements to the valves' internals to better
accommodate operationu 'nder blowdown flow and committed to use the EPRI
PPM to establish thrust requirements for the valves.
The inspectors verified that TVA had completed PPM calculations to
establish thrust requirements for the block valves through a review of
the documented results. Also, the inspectors reviewed work requests and
work orders included in the commitment completion documentation (under
tracking number NC0970056002) which confirmed that the maintenance
improvements had-been completed for the Unit 2 block valves. In -
accordance with the 11cer.:ee's commitment the maintenance improvements
for the Unit 1 valves are scheduled for the Fall 1998 outage. The issue
. .
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17
will not be fully resolved until the maintenance improvements are
completed on the Unit 1 valves.
i
Commitment 6 (Licensee Trackina No NC0970056007) I;
NRC Inspection 50-327, 328/97 06 identified that containment spray
valves 1/2FCV-72-002/039 had marginal capability to perform their
design basis function. TVA comitted to verify disc orientation and
perform a PPM calculation to better establish the thrust requirements
!
for these valves. TVA also comitted to determine improvements for
these valves. A re evaluation of the valves' safety functions
determined that they would not be required to close against any
differential pressure. Therefore, valve disc orientation would not be
an issue. The inspectors confirmed that the PPM calculations had been
completed and found that they determined that the open thrust
requirements exceeded the actuators' capabilities. In response, the
licesee developed an operability evaluation which showed that the
available valve factor capability of the Sequoyah valves (based on
measured pump differential pressures and packing loads) exceeded valve
factor recuirements. The valve factor requirements were determined
based on cata obtained in testing similar valves at Diablo Canyon and
EPRI. ~he inspectors verified that TVA had scheduled design changes to
incrocse actuator capability for these valves to be completed during the
next outage for each unit.
'
Commitment 7 (Licensep Trackina No. NC0970056008)
NRC Inspection 50-327, 328/97-06 identified that TVA had not included
any margin for MOV degradation in calculating valve requirements. In
response. TVA committed to add a 5% margin as a minimum requirement to
provide for valve degradation. The inspectors reviewed the thrust
calculations for a sample of valves (1FCV-01-018. IFCV-03-179A. 2FCV-63-
003, 2FCV-03 047, 2FCV-68-332, and 2FCV-68-333) and determined that the
5% margin for valve degradation had been included. TVA had completed
itt comitment and the issue was resolved.
Comitment 8 (Licensee Trackina No. NC0970056009)
NRC Inspection 50-327, 328/97-06 identified that TVA had not considered
the potential loss of thrust caused by load sensitive behavior for those
valves that were controlled by limit switch. In re m * TVA comitted
to revise the thrust calculations to include a minimu,. 10% margin to
address load sensitive behavior under limit switch control, until an
evaluation was completed to determine the appropriate value. The
inspectors reviewed the thrust calculations for a sample of valves
(1FCV 01-018. IFCV 03-179A. 2FCV-63-003. 2FCV-03-047, 2FCV-68-332, and
2FCV-68 333) and determined that a minimum 10% margin had been included.
In addition, a 20% margin had been included for the Reactor Coolant
System Pressurizer Block-Valves (2FCV-68-332 and 2FCV-68-333) based on-
the assumptions applied to the non tested members of gate valve Grcup 7.
These revised requirements were included in the MOV settings changes
that were implemented by Comitment NC0970056003. Based on this sample,
,
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the inspectors found that licensee personnel had revised the thrust !
calculations to include margin for load sensitive behavior, as
~
~ committed. This resolved the iasue. j
"
Comitment 9 (Licensee Trackino No. NC0970056010)
NRC Inspection 50 327, 328/97-06 identified that the reactor coolant
system pressurizer block valves (2FCV-68 332 and 2fCV 68 333) had-
P
marginal capability with respect to their actuators * torque structural .
4 % . limits for the open direction. TVA committed to revise the Sequoyah !
- -calculations to increase in the torque ratings of the actuators and !
. resolve the actuator structural capability issue.
,
4'
In the current inspection..the inspecto.3 confirmed that TVA had applied [
i results-from Limitorque Actuator Fatigue Life Analysis, Version 1.0, to c
justify extending the actuators' ratings from 250 ft-lb to 280 ft-lb (a :
12% increase). The analysis indicated that it would be acceptable to !
open the valves 150 times under the worst case design basis conditions. ;
'
i A safety factor of 5.25 was applied to arrive at the 150 cycle limit.
'
The inspectors considered the licensee's actions to adequate to complete
__
the commitment and resolve the issue. 7
l : Commitment 10 (Licensee Trackina No. NC0970056011)
-
TVA committed to provide a letter to the NRC describing status of the
nine comitments above by December 31,1997. The inspectors verified
-
that TVA had provided the subject status letter, dated December 19,
f 1997.
E
Dearaded Voltaae 1
1
In reviewing TVA's calcuiations for block valves 2FCV 68-332 and 2FCV- +
68-333, the inspectors questioned the degraded voltage values used in i
the capability c61culations. For H0Vs that did not actuate
v automatically in respcnse to a design accident, TVA assumed that the
grid voltage sup)1ied to the'480 V- bus would be at about 100 3ercent
rather than at t1e degradad grid setpoint of 93.5 percent. T11s
assumption was based on Sequoyah's use of automatic tap changers.- ,
Details of the licensee's bases were evaluated by the NRC-Office of ;
Nuclear: Reactor Regulation (NRR). Electrical Engineering Branch. and the *
, assumation was determined acceptable. The evaluation was documented in *
'
--
a doc (eted NRC memorandum from J. Calvo to R. Wessman, dated
._ February 12,.1998.
'
2. Imolementation of MOV Trendina
The inspectors previously reviewed the licensee's implementation of MOV :
. trending during Inspection 50-327. 328/97-06. At that " the :
licensee had just-completed an outage and had not preps report 1
documenting the trending recommended by GL 89-10. Duri ie current
inspection, the inspectors obtained and reviewed the tre eport r
subsequently prepared to determine if it indicated that axamination -i
t
1
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__5-~.r i m E,1mm . . E rw. - =,m -- , , ,,,-mm .
..w., -.m, m, ~ - '
,.__w.,v.-. . . - . m -.-..w.--._,#., -- -,-,ro .
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- of MOV data for trends recommended by GL 89 10 was completed. The !
inspectors found that information included in the report generally '
- indicated that trending was being performed in accordance with the
t
recommendations of GL 89 10. However, the inspectors noted that
enhancements could be made in the following areas:
. Although the report contained a large amount of data, there were
i no charts or graphs to-indicate trends or the lack thereof.
'
'
e There were no ecmments or comparisons on the effectiveness of the
"
MOV program. The status of resolution of previous problems was not
mentioned. For example, there were no comments on the effect of
replacement of.contactors that were previously a problem. >
]
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. c. Conclusi005
i- With tha commitments made in the licensee's letter dated February 12.
1998, t to inspectors determined that the licensee met the intent of GL ,
89-10 in verifyin
MOV, at Sequoyah.g the design basis capability of the safety-relatedThe li
- to be addressed:- '
e.
'
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The valve factors employed in calculating the required thrusts -for
-
gate valve Groups 1. 2. and 8, will be more fully justified, i
l e -TVA was obtaining test data for smaller (18 inch and under) Pratt
- butterfly valves from Duke Power Company. TVA will further- !
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evaluate the data and revise the Sequoyah calculations based _on
the results, in addition. TVA will improve its support for the
~
predicted torque requirements calculated for Sequoyah's larger (20
and 24 inch) Pratt butterfly valves.
I e Maintenance im)rovements will be completed on the Unit 1,
pressurizer PORV block valves.
p
.
! Based on the NRC' inspections and the licensee's commitments in its ,
letter dated February 12, 1998, the NRC is closing the review of the ;
, GL 89-10 program at Sequoyah. Resolution of the outstanding licensee
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commitments is identified as-ins 50-327, 328/97-18-
' .08, Remaining GL 89-10 Concerns.pector followup
The outstanding item are
commitments
, described above under the heado s for Commitments 1, 2. 5..and 6. This
( -item will also track the com" .etIon of the remaining commitments from
inspector followup item 50 327.328/97-06-07. j
,
E8 -Miscellaneous Engineering ~ Issues (92902)
4 .
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E8.1 (Ocen) :FI 50 327/97-18-05; Uodated Final Safetv Analysis Reoort (UFSAR) '
Oodate "o include Plant Modifications To the Main Switchyard During a
,-- -
-~1993 NRC inspection at Sequoyah. concerns were-Identified regarding the
4 adequacy'of the 161 kv offsite power grid voltage. TIA 94 021 was
t initiated by Region 11 and forwarded to NRR for evaluation. After the ,
l TIA was initiated, the licensee implemented switchyard modifications to ,
t-
h
z. , -- u .- .- --- - -,, .-.-- , . - - -. - - - - --,;-. -- -
.
20
provide more reliable and stable grid voltage which eliminated the
original-1993 concerns. The licensee )lans to update the Safety
Analysis Report to include those switc1 yard modifications in
Amendments 13 and 14. This inspector follow up item is being o)ened to
track the completion.of the switchyard modification update to tie Safety
Analysis Report contained in sections 8.2.1 and 8.2.2. of the UFSAR.
.E8.2 (Closed) URI 50 327/97 06 09. RemotePositionjndicatorTest. Based on ;
. plant walkdowns and a review of Section XI test records, the inspectors i
identified a-potential problem with the turbine driven auxiliary
feedwater pump throttle valve position indication. The position
L indication was not pro >erly set and only monitored 50% of valve travel.
L The inspectors noted tlat the nottle valve was functioning properly
over 100% of its stroke but were concerned with the Section XI testing
.
requirements. The licensee provided an evaluation that supported the-
l adequacy of the Section XI testing and the throttle valve position
L
indication was reset to indicate / measure the full stroke of the valve.
l The ins)ectors concluded tb- the as found condition was acceptable.
althougl not correct, and . ficensee's subsequent corrective actions
l
were reasonable and complets, The inspectors were concerned with the
-
.-performance of the ASME Section XI required.-2 year surveillance.-on
remote position indication verification. Followup of this concern will
be performed as an Inspector Followup Item (IFl 50 327/97-18 06).
E8.3 (Closed) Insoector Followuo Item 50-327. 328/97 06-07: Actions.ta
resolve remainina-GL 89-10 issues. TVA's actions to resolve this item
are discussed in El.5.b.2 above. Most of the actions originally
identified to this item had been com)1eted. Those remaining and
significant concerns identified in t1e current inspection will be
tracked under the new inspector followup item identified in E1.5.c.
IV, P1 ant Sunoort-
R1 Radiological Procection and Chemistry (RP&C) Controls (83750)
.R1.1 Personnel Monitorina Discrenancies
a. Insoection ScoDe (71750)
The inspectors evaluated a concern with a potential failure by personnel
-to monitor (frisk) when exiting a radiologically controlled area (RCA)
in'the control building.
b. Observations and Findinos.
On the morning of January 26, 1998, an NRC inspector accom
control building assistant unit operator (AV0) on rounds. panied
Duringthe
the
-= -=
tour.-the inspector and the-AU0 entered-the-Unit 2 mechanical equipment
-
room, which was a posted RCA. Just prior to exiting the area (Door A-
188), they encountered a hexagonal red sign (Stop sign) which stated
" Frisk Hand and feet Prior to Exiting: Then Process Through Whole Body
.
.
21
Frisker." The AVO told the NRC inspector that the sign was not
applicable and both exited the area without frisking hands and feet.
After com)leting the tour, the inspector attempted to exit the RCA:
however,
lis barrt hat was contaminated and radiation control assistance
was requested. While the inspector's hat was being decontaminated, the
inspector discussed the posting of the Unit 2 mechanical equipment room,
witn the radiation control technician, Subsequently, the posting and
frisking issue was discussed with the NRC senior resident inspector.
l
'
After decontaminating the inspector's hat, the radiation control
technician went with the AVO to the mechanical equipment room to observe
l the posting. The licensee stated that the technician had told the AVO
! that he was su i
at that time. pposed to frisk hands and feet prior to exiting the area, i
Later in the day on January 26 the resident inspector discussed the
issue with a Region 11 health physics inspector, who had just arrived on
site. The inspector went with a member of radiation control mana
to tour the mechanical equipment room and discussed the posting.The gement
e
supervisor informed the Region 11 inspector that frisking was not
required and both individuals exited the area without frisking. ,
After further discussions, on the morning of January 27. 1998, the
radiation control supervisor determined that he had incorrectly
interpreted the )osting requirements and that his actions had been
inappropriate. le promptly notified the NRC inspectors of the error and
initiated a PER, it was noted that since the mechanical equipment room ,
was posted as a RCA, frisking prior to leaving the area was required and
that they had both inappropriately exited the room on the previous
afternoon.
The licensee took prompt corrective actions to communicate the frisking
requirements to site personnel, the room was reposted, walkdowns of
similar areas was performed, and a third party review to evaluate
consistency and clarity of RCA postings was performed.
The general requirements for the radiation control program are contained
in the Radiological Control Instruction RCI-1, Radiological Control
Program. Section 4.0 D states " Prior to exiting the RCA, all personnel
shall monitor themselves in a whole body contamination monitor. A hand
and foot frisk may be utilized in lieu of these monitors if authorized
by RADCON.* The Unit 2 mechanical equipment room was posted as a
radiologically controlled area and was posted with requirenients for
frisking of hands and feet. On two occasions on January 26 a total of
four personnel failed to frisk prior to exiting the Unit 2 mechanical '
equipment room. These failures to follow the Radiological Control
Program instructions by not properly frisking out of a posted
radiologically controlled area, are considered to be two examples of a
failure to follow procedure and are identified as violation (VIO 50-
-328/97-18 07),
.
,
!
!
22 :
c. Conclusions
l
A violation with tm examples was identified for not properly frisking
out of a posted radiologically controlled area. ;
'
.
Communications were considered to be weak in that both the radiation
control technician and the AUD were aware on the morning of January 26
that the posted requirements had not been met: however, appropriate
levels of management were not informed of the issue which led to the
- second example of the inappropriate frisking violation. -
1
R1.2 Inadvertent Release from Unit 2 Additional Eauioment EgildinaSus
a. Insoection Scone-(71Z50).
The inspectors reviewed the events associated with an inadvertent
release of several hundred gallons of contaminated water from the Unit 2
, additional equipment building (AEB) sump. The inspectors also reviewed
.
the previous issues related to the release which contributed to the
! adverse condition.
e b, Observations and Findinas
.
On January 10. 1998, at anproximately 12i35 a.m. the Unit 2 Auxiliary
-
.
Building AVO reported water flowing out of the AEB from under the >
"
exterior door. The event resulted in contamination of the AEB lower J
'
floor and the outside yard area from the security door to the storm-
. drain. - It was estimated that approximately 700 800 gallons of low level
'
contaminated water see>ed out under the AEB door and the majority of the ;
contaminated water pro) ably entered the storm drains during the release.
'
'
The inspectors reviewed the historical issues that led to the release.
On September 1, 1997, the ice condenser ice making machines were taken
out of-lay up and placed 111 standby in preparation for the Unit 2
-
>
- outage. This permitted a leaking sight glass on the ice machine to
overfill tf e glycol overflow collection tank. Operations noted the
<
overfilled tank and directed the auxiliary building- AVO to drain the
tank. N AU0 began to drain the overflow collecting tank to a 55
gallon rel: however, he left the area before completing the task.
,
When ht eturned, he-found the barrel had overflowed onto the floor.
-
'
The ALB building sump was tested for glycol and the test noted that the .
sump contained approximately 10% glycol. It was estimated that the-sump
contained about 5)0 gallons of nearly black water which contained ,
glycol. oil and other debris. On September 1 the sump pumps were
caution tagged to prevent glycol contamination of the waste cleanup
'.
system. -The licensee planned to clean tha dump prior'to removing the
caution tags. -
The sump cleaning was delayed until after the Unit 2 outage in' the event .
that-more glycol leaked into the sumo during the ice making evolution.
The Unit 2 outage was completed on November 3, 1997, and documentation i
i
E_'__ ______l.____~.i___.. .____.l____
.
23
noted that the sump cleaned by December 3. 1997. The caution order
on the sump pumps .iot released and the pumps remained deactivated.
Following the event. he licensee discovered that th AEB sump had not
been cleaned as docun ited. The plant support labore s had mistakenly
cleaned the adjacent up)er head injectio pit instead of the AEB sump.
A radiation control tec1nician had been assigned to monitor the
laborers. in lieu of a special radiation work permit. The technician
also mistakenly identified the abandoned upper head injection pit as the
assigned cleanup area. Subsequently, operations mistakenly verified the
AEB sump had been cleaned after inspecting the upper head injection pit
and signed off the PER.
At 9:29 ).m.. on January 9. 1998, the main control room received an AEB
sump hig1 level alarm. The AU0 noted that the AEB sump level was high
but not increasing rapidly. The AVO set up a temporary pump to pump the
sump contents to 55 gallon drums and requested drums be sent to the AEB.
At 12:22 a.m.. on January 10. the drums were delivered to the door
outside the AEB. At 12:28 a.m. the AVO noted water flowing out from
under the AEB door and the control room directed that the sump pumps be
started to pump the AEB sump to the floor drain tank. Outflow of water
from the AEB. stopped at about 12:36 a.m.
The licensee subsequently noted that the AEB sum) pum) discharge
isolation check valves were degraded and had leated t1ough excessively
while operations was pumping the Cask Decontamination Collecting Tank to
the Floor Drain Collecting Tank. This led to overflowing the AEB sump
due to the sump pumps being disabled.
The inspectors noted )oor operating practices in that the AU0 left the
area while draining tie glycol overflow collecting tank to a 55 gallon
drum which subsequercly overflowed, operations signed off the PER that
the sump had been cleaned after inspecting the upper head injection pit,
and the clearance on the sump pumps was not removed in a timely manner
after the documented completion of the AEB somp cleaning.
The inspectors noted poor action in that the radiation control laborers
cleaned the wrong area and signed off the work documents.
c. Conclusion
A weakness was identified in the area of operations based on an AU0
leaving the area while draining a tank which resulted in a glycol spill.
inspecting the wrong sump / pit and signing off the PER as complete, and
not removing the caution tags after the documented completion of the
sump cleaning.
.
- _ , - - - - - , , - - - -
. ._ - -
.
.
_
,
'
i
1
!
24 .
A weakness was identified in the are, of plad support based on the i
plant support laborers cleaning the aandm.ed upper head injection pit ,
instead of the AEB sump and the assigneu radiation control technician !
controlling work in the abandoned pit versus the AEB sump. .
t
V. Manaaement Meetinas
- X1 Exit Meeting Summary
'
The inspectors presented the inspection results to members of licensee -
management at the conclusion of the inspection on February 9.-1998. The
MOV inspection exit was conducted on January 23, 1998. The licensee ,
acknowledged the findings presented.
During.the inspection period, the inspectors asked the licensee whether
any materials would be considered proprietary. No proprietary
information was identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
..*Bajestani. M..-Site Vice President
- Burton C. . Engineering and Support Systems Manager
- Butterworth . H., Operations Manager ;
Fecht. M.' : Nuclear Assurance Manager
Gates. J., Site Support Manager
- Freeman.-E. Maintenance and Modifications Manager
- Herron. J..-P1 ant Manager
Kent. C.. Radcon/ Chemistry Manager
Koehl. D. Assistant Plant Manager
O'Brien. B.. Maintenance Manager..
.
Salas. P., Manager-of Licensing and Industry A' fairs
- Summy. J., Assistant Plant Manager
- Valente. J., Engineering & Materials Manager
- Attended exit interview ,
INSPECTION PROCEDURES USED'
.I
IP 37551: Onsite Engineering
- IP 61726:- Surveillance Observations
. IP 62707: Maintenance Observations
- IP 71707:- Plant Operations-
- 1P 71750
- Plant Support
IP:92901: Followup - Operations
, , -,e.. 4 --
, . ,ir-- v* ,e v- <~ , . - - - - - . v - --< v, n-v----,.,.--- , wre w - ,- --+--*--r- -e.
_, _ _ - - _ _ -
-
25
IP 92902: Followup -' Maintenance
IP 92903t Followup =- Engineering
IP 92904: Followup - Plant Support
- Tl 2515/109
- Inspection Requirements for Generic letter 89 10, Safety-
Related Motor operated Valve Testing and Surveillance
ITEMS OPENED. CLOSED. AND DISCUSSED
Ooened
lygg Item Number Status Descriotion and Reference
-NCV 50 327,328/97 18-01 Closed Failure to Log AFD at least Once Per
>
Hour With AFD Monitor Alarm
Inoperable (Section 08.1)
NCV 50 328/97 18 02 Closed Failure to Stroke Pressurizer PORVs
in Mode 4 (Section M8,1)
IFI 50-328/97-18-03 Open Follow up on Corrective Action to
Resolve Issue With Crosby Relief
Valve Degraded Guide Ring Material
(Section El.1)
L URI 50 328/97-18-04 Open Resolve Issues Related to
Pressurizer Level Instrumentation-
(Section El.4)
IFI 50 327/97-18 05 Open Safety Analysis' Report (SAR) Update-
To Include Plant Modifications To
the Main Switchyard.(Section E8.1)
- IFI-- 50 327/97-18 06- Open Follow up on Concern with Two Year
Surveillance on Remote Position
Indication Verification (Section
E8.2)
VIO 50 3?8/97-18 07 Open Two Examples of Failure to Frisk
-When Exiting the RCA as Required by
_
Procedure RCI-1-(Section R1.1)
- IFI- -50-327, 328/97-18-08 Open Remaining GL 89 10-concerns (Section
E1.5.c)
IFl 50-328/97-18-09 Open Ashcroft Pressure Switch Setpoint
Drift.(Section E1;2)
<
J
. , -. _ _ _ - . . - __- . _ - . . - - -- - - ..-. _ -. -
l
26
Closed
IX2g item Number Status Descriotion and Reference
URI 50-328/97 08 01 Closed Potentially Inoperable Axial Flux
Difference (AFD) Monitor Alarm
(Section 08.1)
URI 50 328/97-14 04 Closed Missed TS Surveillance Requirement
SR 4.4.3.2.1.b for Stroking the
Pressurizer PORVs During Mode 4
(Section M8.1)
LER 50 327/97014 Closed Missed Surveillances as a Result of
Inadequate Procedures and a Failure
to Follow Procedure (Section M8.2)
IFl 50-327, 328/96-08-04 Closed Review Calibration Instrument
Accuracy Requirements (Section M8.3)
URI 50 327/97 06 09 Closed Remote Position Indicator Test
(Section E8.2)
IFl 50-327, 328/97-06-07 Closed Actions to resolve remaining GL 89-
10 issues (Section E8.3).
Discussed
lyng item Number Status Descriotion and Reference
VIO 50-327/97-04-02 Withdrawn Failure to Meet Surveillance
Requirements of TS 4.10.3.2 for
Performing Functional Testing of the
Nuclear Instruments (Section 08.2)
t
-
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> s 'm --- --yy -