ML20141G044
| ML20141G044 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 06/20/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20141G032 | List: |
| References | |
| 50-327-97-04, 50-327-97-4, 50-328-97-04, 50-328-97-4, NUDOCS 9707030283 | |
| Download: ML20141G044 (21) | |
See also: IR 05000327/1997004
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U.S. NUCLEAR REGULATORY COMISSION
REGION II
Docket Nos:
50 327, 50 328
License Nos:
Report Nos:
50 327/97 04, 50-328/97-04
Licensee:
Tennessee Valley Authority (TVA)
Facility:
Sequoyah Nuclear Plant, Units 1 & 2
Location:
Sequoyah Access RotJ
Hamilton County, T.e 37379
Dates:
April 13 through May 24, 1997
Inspectors:
M. Shannon, Senior Resident Inspector
R. Starkey, Resident Inspector
D. Seymour, Resident Inspector
J. Blake, Senior Project Manager, RII, (Sections M1.2 and
M1.3)
Approved by:
M. Lesser, Chief, Projects Branch 6
Division of Reactor Projects
Enclosure 2
9707030283 970620
ADOCK 05000327
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EXECUTIVE SUMMARY
Sequoyah Nuclear Plant, Units 1 & 2
NRC Inspection Report 50 327/97 04, 50-328/97 04
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This integrated inspection included aspects of licensee operations,
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maintenance, engineering, plant support, and effectiveness of licensee
controls in identifying, resolving, and preventing problems. The report
covers a six-week period of resident inspection.
Operations
The conduct of operations during the inspection period was
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considered to be satisfactory.
However, weaknesses in plant
operation were identified during plant heatup and startup
evolutions (Section 01.1).
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A non cited violation was identified for failure to maintain the
reactor coolant system (RCS) tem3erature and pressere within the
procedural operating limits of t1e plant startup procedure
(Section 01.2).
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A violation was identified for failure to meet the surveillance
requirements of Technical Specification (TS) 4.10.3.2 and the
licensee's definition of " Start of Physics Testing" contained in
the Low Power Physics Testing procedure was considered to be
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inappropriate (Section 01.3).
A failure to follow procedures with multiple examples was
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identified related to exceeding the reactor fuel preconditioning
limitations.
Examples included failure to adequately control the
reactor power ramp rate to less than 3t; failure to properly log
plant status such as alarms, reactivity changes and surveillance
activities; and failure to properly notify the shift manager of
changes in plant status (Section 01.4).
The inspectors concluded that the licensee is meeting the intent
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of NUREG 0737 regarding shift turnover and relief procedures
(Section 01.5).
Steam generator level deviations on Unit 2 were continuing but had
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not caused significant operational difficulties.
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Maintenance
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The inspctors noted that work activities and the performance of
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surveillance activities were adequately performed with the
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exception of the steam dump valve maintenance (Section M1.1).
The licensee's pressure boundary and containment inservice
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inspection activities were well organized, implemented correctly,
and properly documented.
(Section M1.2).
ASME Section XI, repair and replacement activities, as
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demoristrated by the SG feedwater piping replacement, were well
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controlled and documented.
(Section M1.2).
The Design Change Notice for the feedwater pi aing replacement,
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completed in 1996, did not acknowledge that tie Code of Record for
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repair and replacement activities changed in December 1996.
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(Section M1.2).
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A weakness was identified in the area of the Unit 1 surveillance
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procedure for the leak testing of ASME Class 1 bolted connections,
in that the issued procedure was essentially the same as that used
for the last unit 2 outage, without considering lessons learned
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from implementation problems during that outage.
(Section M1.2).
The licensee's program for inspection of steam generators appears
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to be well managed and conducted in a conservative manner. The
analysis guidelines were found to be well written and easy to
interpret.
(Section M1.3).
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Mechanical maintenance did not verify that all work had been
completed prior to closing out the work packages on the Unit 1
steam dump valves. Procedure revisions to address the missed
steam dump bolt torquing requirements in 1996 on Unit 2. were not
sufficient to identify and correct all of the associated work
procedures, resulting in not torquing the bolts on Unit 1 (Section
M2.1).
Enaineerina
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The licensee was successful in implementing various modifications
to improve the operation of the Unit 1 steam dump system (Section
E2.1).
Plant Support
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An inspector follow up item was identified to review the
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licensee's completed corrective actions following an inadvertent
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spill of several thousand gallons of contaminated water
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(Section R1.1).
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Report Details
Summary of Plant Status
Unit 1 began the inspection period in Mode 6, Cycle 8 refueling activities.
Reactor startup and Mode 2 entry was made at 2:40 a.m., on May 11, 1997, and
Mode 1 entry was made at 6:32 a.m. on May 12, 1997. The unit operated at power
for the remainder of the inspection period.
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Unit 2 began the inspection period in power operation. The unit operated at
power for the duration of the inspection period.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments
While performing inspections discussed in this report, the inspectors reviewed
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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.
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I. Doerations
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Conduct of Operations
01.1 General Comments (71707)
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Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. The inspectors observed mid loop
oaerations, operation in Mode 4, entry into Mode 3. rod drop testing,
t1e reactor startup, portions of physics testing, and portions of the
power increase to 100%.
In general, the conduct of operations was
acceptable, however, weaknesses in plant operation were identified and
are detailed in following sections of the report.
During the Unit i reactor startup on May 11, 1997, the inspector noted
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that the designated Unit 2 senior reactor operator (SR0) was detailed to
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Unit 1 to assist in the unit startup. This condition left Unit 2.
without active SR0 oversight for over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Although allowed by the
TSs, the inspector questioned the process of removing unit SR0 oversight
for non emergency plant evolutions / conditions. The inspector requested
the licensee to review their process / program for staffing during non-
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emergency plant evolutions / conditions.
01.2 Reactor Coolant System Heatuo To 330 340 F
a.
Insoection Scope (71707 and 40500)
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The inspector observed activities associated with plant heatup following
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the Unit 1 refueling outage. This included licensee preparations for
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entering Mode 3.
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b.
Observations and Findinas
On May 6, 1997, the inspector was observing routine control room
activities related to required surveillance testing prior to entering
Mode 3.
During the observations, the inspector noted that RCS
temperature was approaching 350 F and that exceeding 350 F would
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result in an unanticipated Mode change.
It was noted that the RCS
temperatures from the Integrated Computer System (ICS) were indicating
slightly higher than the control board indicators, and that the ICS
indicated that RCS temperature was above 349 *F.
The ICS temperature indications were discussed with the control room
operators. The control room operators stated that the control board
indicators were the official instruments and the ICS indications were
not used to determine Mode change. However, the inspector noted that
the ICS computer provided the only detailed history, down to tenths of
degrees, and was more accurate than the control board recorders,
therefore the ICS data should be evaluated / considered for use for
specific functions such as Mode changes.
During a subsequent review of the computer history of RCS temperature,
the inspector noted that RCS average temperatura had reached 349.95 F
during a transient while placing the steam dumps in service. The
inspector also noted that the operators had maintained RCS temperature
at about 345 F for several hours while awaitinc permission to enter
Mode 3.
A review of the oaerating procedure. 0 GO 1, Unit Startup From
Cold Shutdown To Hot Standay, noted that Section 5.6.22 required that
"If the unit is to be maintained at this plateau, THEN CONTROL RCS
temperature at 330 to 340 F and pressure between 330 and 350 psig."
Contrary to the arocedure requirement, the operators did not maintain
RCS temperature aetween 330 and 340
F, and as a result came very close
to an unanticipated Mode change.
In addition, the inspector noted that RCS pressure was approximately 372
psig, and a later review noted this was also above the procedural limits
in 0 G0 1.
However, prior to discussions with the licensee, the
inspector noted that the licensee's quality assurance (QA) operations
observer had noted the RCS pressure control deficiency and had initiated
PER No. SQ971353PER to document the failure to follow procedure. The QA
observer noted that RCS pressure had been increased to 500 psig,
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although the procedure in effect required RCS pressure be maintained
between 330 and 350 psig. The inspector verified that the plant was
maintained within the TS pressure and temperature requirements, even
though the procedural requirements were not met.
The inspector noted that the procedural limitations were administrative
in nature and that in this specific case did not compromise plaat
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safety.
In addition, the inspector noted that although the operators
approached Mode 3, the 350 F average RCS temperature Mode change
limitation was not exceeded.
In this case the operators failed to
follow the procedural limitations in plant startup procedure 0-G0-1,
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however, this event was considered to have low safety significance and
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the licensee subsequently implemented prompt corrective actions. These
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included refresher training on steam dumps, margin to operating limits,
improved guidance for mode changes and clearer o>erating parameter
guidance. This licensee corrected violation is
aeing treated as a non-
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cited violation (NCV), consistent with Section VII.B.1 of the NRC
enforcement Policy. (NCV 50-327/97 04-01).
c.
Conclusions
A non-cited violation was identified for failure to maintain the RCS
temperature and pressure within the procedural operating limits of the
plant startup procedure.
The licensee's OA organization identified that the operators failed to
maintain RCS pressure within the procedural operating limits of the
plant startup procedure. This is considered an example of positive QA
organization oversight.
01.3 Failure To Meet TS Recuirements For Physics Testina
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a.
Insoection Scope (71707)
The inspector observed activities associated with the entry into Mode 2,
the start of Physics Testing and the Unit I reactor startup following
refueling activities.
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b.
Observations and Findinas
The ins)ector observed the crew briefing for the Unit 1 Cycle 8 low
power p1ysics testing and observed the reactor startup. At 2:40 a.m.,
on May 5,1997, the operators began pulling control rods (Mode 2) and at
3:39 a.m., on May 5, 1997, the reactor was critical. The crew briefing
was detailed with appropriate cautions highlighted and the reactor
startup proceeded as expected with appropriate supervisory oversight.
During a subsequent review, the inspector noted a potential deficiency
with the interpretation of the " start of physics testing." TS
3/4.10.3.2 requires that the four power range nuclear instrument
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channels and the two intermediate range nuclear instruments shall be
subject to a channel functional test within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> prior to the start
of physics testing. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> surveillance was due to expire on
nuclear instrument NI 42 at 2:18 a.m.
This issue was discussed in the
control room between reactor engineering personnel and operation's
management.
Engineering noted that further surveillance testing would
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not be required if permission to start )hysics testing was granted by
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the shift manager. At 2:13 a.m., the slift manager authorized the plant
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startup, entry into Mode 2 and the start of physics testing. However,
due to feedwater pump and associated procedural problems, which hindered
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Mode 2 entry, reactor startup could not be initiated at this time.
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Subsequently the inspector performed a detailed review of TS 4.10.3.2
and the applicable operating procedures. The following was noted;
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0 RT NUC 000 003.0, Low Power Physics Testing, Section 6.1 6
requires the operator to record the time for Mode 2 entry and
initiation of )hysics testing and to INITIATE control bank
withdrawal. T1e time recorded in this block was 2:13 a.m.,
however, control bank withdrawal did not start until 2:40 a.m.
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The Unit Startup From Hot Standby To Critical
3rocedure. 0-G0 2,
Section 5.3 Note 1 "The unit enters Mode 2 w1en the contro'
banks are first withdrawn." Section 5.3 15.b. stated " START
WITHDRAWAL of control banks and DECLARE MODE 2.
Log in operators
journal." However, the operators logged Mode 2 entry at
2:13 a.m., and initial pulling of the control banks was not
initiated until 2:40 a.m.
In addition, the inspector noted that
actual Mode 2 entry is not made until core K effective is greater
than 0.99, which occurs during withdrawal of the control banks,
not when the first control banks are withdrawn.
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The Low Power Physics Testing procedure. 0 RT NUC 000 003.0,
Precautions and Limitations, Section 3.0 J defined "the start of
ohysics testina as the time that permission from the SR0 senior
reactor operator has been obtained to begin the first withdrawal
of control bank A.
This time would stop the clock on NIS channel
testing for startup." However, this definition was considered to
be inappropriate in that physics testing cannot be performed
unless the reactor is critical and it was also in conflict with
the procedural steps which require entry into Mode 2 and
withdrawal of control rods.
Prior to actual control bank withdrawal and Mode 2 entry at 2:40 a.m.,
the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> surveillance requirements for power range nuclear instrument
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NI-42, expired at 2:18 a.m. and intermediate range nuclear instrument
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NI 36 expired at 2:32 a.m.
Plant startup and the actual start of
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physics testing commenced at 02:40 a.m.
Technical Specification
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4.10.3.2 requires each intermediate and power range instrument to be
subjected to a Channel Functional Test within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of initiating
Physics Tests. The licensee's failure to meet the surveillance
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requirements of TS 4.10.3.2 is considered to be a violation (VIO 50-
327/97-04-02).
c.
Conclusions
The licensee's definition of " Start of Physics Testing" contained in the
Low Power Physics Testing procedure was considered to be inappropriate.
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A violation was identified for failure to meet the surveillance
requirements of TS 4.10.3.2
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01.4 Unit 1 Exceeds 3t Per Hour Ramo Rate Durina Fuel Preconditionina
a.
Insoection Scooe (71707)
The inspectors reviewed the circumstances during which Unit 1 increased
reactor power by approximately 6.4% during a time when power ramp rate
was limited to 3% for new fuel preconditioning.
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b.
Observations and Findinas
On May 15, 1997, with Unit 1 at 64% power, operators were performing
Surveillance Instruction (SI) 0 SI 0PS 068-137.0, Reactor Coolant System
Water Inventory, Revision 1, and were periodically withdrawing control
rods in order to maintain RCS average temperature (T avg) within one
degree of the initial starting temperature (563 F) as required by the
SI. During the performance of SI-137 T-avg varied from 2 F to 5 F
less than T-ref which was approximately 566
F.
Control rod Bank D was
withdrawn from 196 steps to 201 steps as operatort attempted to maintain
a stable RCS temperature for the leak rate calculation. During the data
gathering for SI-137.0, Delta I exceeded the target band upper limit of
+4.
When operators determined that they were unable to maintain a
stable RCS T avg temperature or to maintain Delta-I within the target
band, due to increasing xenon concentrations, they aborted the leak rate
procedure. Operators then began diluting the RCS in order to allow
repositioning the control rods to control Delta I.
According to
personnel statements and ICS data, six dilutions of 200 gallons each, a
total of 1218 gallons, were performed in approximately 32 minutes. As a
result of the dilutions, reactor power increased approximately 6.4% in a
52 minute period. Based on statements from operations personnel,
control rods were in " manual" during this dilution evolution.
Subsequently, the ins)ector reviewed the Unit 1 power history from the
ICS coaputer, using t1e power history from the nuclear instrumentation
channels.
In addition to the above power increase, the inspector noted
that during the power increase from 49% power to 65% power on May 15,
1997, that during t,pecific periods the power increase exceeded the 3%
per hour limitation specified in TI 40. The ICS computer history
indicated that from 10:03 a.m. to 11:03 a.m., on May 15, reactor power
was increased by an average of 3.551. The observed power increase did
not meet the procedural requirements for fuel conditioning specified in
TI-40.
Procedure 0-G0 5, Normal Power Operation, Revision 6 Section 5.1,
requires that ramp load rate increases shall be within the limits stated
in TI 40, Determination of Preconditioned Reactor Power, Revision 8.
TI-40 requires for the initial power increase following refueling, that
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the reactor power escalation rate should be limited to 3% power in an
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hour between 20% and 100% of full power. The TI further states that
small deviations are allowed from the 3% per hour ramp rate during power
increases, but the power increase must not exceed 3.5% in any one hour.
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Following discussions with the fuel vendors, the licensee concluded that
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no damage to the new fuel would be expected based on the actual power
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increases which had exceeded the 3% limitations for reactor power
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increase. The licensee's failure to follow the reactor fuel
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preconditioning power limitations / requirements specified in TI 40, is a
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failure to follow procedure and is considered to be a violation (VIO 50
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327/97 04 03).
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The inspectors became aware of the event while attending the operations
shift turnover on Monday morning, May 19, 1997. When the inspectors
reviewed the control room logs for information related to the evolution,
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only two entries could be found. At 8:09 p.m. on May 15, operators
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logged that SI 137.0 had been aborted because there had been an increase
in RCS temperature of greater than 1 degree from the initial conditions.
There were no subsequent entries regarding the six 200 gallon dilutions
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or that reactor power was increased by over 6%. The next logbook entry
was not until 1:00 p.m. on May 16, noted that during a review of ICS
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data, the licensee discovered the excessive power increase.
It was at
that time that operations initiated a PER and the fuel vendors were
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notified.
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The inspectors noted that operators had not logged various plant
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conditions or evolutions that would have assisted in reconstructing the
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time line for this event. The operators did not log the start of the
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RCS leak rate surveillance.
In addition, the operators did not log the
actuation of the AFD (delt6 flux) alarm conditions, the time the
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conditions cleared, or the total number of minutes in alarm, which is
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information used by reactor engineering. Also, operators did not log
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the six reactivity additions (200 gallon dilutions) in a 32 minute
period. The failure to make log book entries related to reactivity
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changes, the AFD alarm conditions, and the start of surveillance
activities, as required by SSP 12.1, Conduct of Operations. Section 3.8,
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Revision 17, is a failure to follow procedure and is considered to be a
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second example of VIO 50 327/97 04 03.
During review of the event, the licensee noted that the shift manager
(SM) had not been aware of the difficulties being experienced by the
Unit 1 operators. Statements indicated that the SM was not aware of the
AFD alarm conditions or that the operators had diluted the RCS with 1200
gallons of water.
Failure of the unit su>ervisor to coordinate with the
SM changing plant conditions as required )y SSP 12.1, Conduct of
0)erations, is a failure to follow procedure and is considered to be a
t11rd example of VIO 50-327/97 04 03.
c.
Conclusions
A violation was identified for the failure of operators to follow a
procedure which limited reactor power ramp rate to 3% per hour, for the
failure of operators to make log book entries regarding significant load
and reactivity changes, alarm conditions, and surveillance activities,
and for the failure to promptly notify the SM of reactivity changes to
the unit and plant alarm conditions.
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01.5 Review of Shift Turnover Checklist Commitment
a.
Insoection Scope (71707)
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In a letter to the NRC dated March 20, 1997 TVA notified the NRC of a
change in its commitments to satisfy NUREG 0737, Clarification of THI
Action Plan Requirements,Section I.C.2. Shift and Relief Turnover
Procedures. The inspectors reviewed the NRC's NUREG 0737 position
regarding shift turnover (as delineated in NUREG 0578, THI-2 Lessons
Learned Task Force Status Report and Short Term Recommendations, Section
2.2.1.c): the licensee's initial response to Section I.C.2 of NUREG-
0737: and the licensee's revised response to their shift turnover
commitment, in order to determine if the recent changes meet the intent
of NUREG 0737.
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b.
Observations and Findinos
The NRC position on Shift and Relief Turnover Procedures stated, in
part, that:
1.
A checklist shall be provided for oncoming and off going control
room operators and the oncoming shift supervisor to complete and
sign. The following items, as a minimum, shall be included in the
checklist:
a.
Assurance that critical plant parameters are within
allowable limits.
b.
Assurance of the availability and proper alignment of all
systems essential to the prevention and mitigation of
operational transients and accidents by a check of the
control console.
c.
Identification of systems and components that are in a
degraded mode of operation permitted by TS.
The initial position of TVA regarding shift turnover, committed to the
NRC in the early 1980's, was that a checklist or similar hard copy would
be completed by off going and oncoming shifts at each shift turnover.
The checklist would include critical plant parameters and allowable
limits, availability and proper alignments of safety systems, and a
listing of safety system components in a degraded mode along with length
of time in that mode. That checklist would be signed by the off going
Unit Operator and the oncoming Unit Supervisor and Unit Operator.
In May 1994, the licensee performed a safety assessment in support of
changes to various shift relief and turnover checklists.
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were revised in order to eliminate unnecessary data taking and several
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shift relief and turnover checklists were canceled.
In lieu of a
turnover checklist, 03erators were expected to perform a control board
walkdown, review " pin ( tags" which are placed on control board switches
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which were in an off-normal position, review the status board for off-
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normal equipment conditions, review work request stickers.and their
affect on plant ecuipment, and review the operator's logs. The safety
assessment concluced that the revised shift turnover procedures met the
intent of NUREG 0737. Item 2.2.1.c.
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It should be noted that in approximately 1995, the unit status boards
were eliminated and in 1996, work request stickers, with some
exceptions, were no longer attached to main control board instruments,
but were maintained in a separate " Control Room Deficiencies" binder in
the main control room.
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In its March 20, 1997, letter, TVA stated, "TVA has revised and
implemented the shift and relief turnover program and procedures. The
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current procedures arovide guidance to assure that the oncoming shift
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possesses adequate (nowledge of critical plant status information and
system availability. The current procedures require a shift turnover
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meeting and is conducted by the Shift Manager, SRO. The procedure
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indicated that the briefing should include a review of the plant status,
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problems with plant equipment, evolutions in process or planned for the
shift. Subjects pertinent to shift operations such as standing orders,
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procedures changes, etc. as deemed appropriate are discussed. A listing
of safety system components in a degraded mode along with the time of
entry, are included in the operator's log which are reviewed during
shift turnover. A periodic instruction is utilized following the
turnover process for designated Operations' shift positions."
SSP 12.1, Conduct of Operations, Revision 17, requires that a shift
turnover meeting be conducted by the Shift Manager (SM). The inspectors
routinely attend the shift turnover meeting and have made positive
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comments in recent inspection reports (IR 9611. IR 95 21, and IR 9518)
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concerning those meetings.
Prior to the turnover meeting, the oncoming
operators begin their turnover process in the control. room. This
turnover includes a board walkdown, a review of operator logs, and
discussions of plant status. The logs include information on degraded
equipment and any significant evolutions which have occurred on the
unit. The inspectors routinely review operator logs. The inspectors
have documented weaknesses or violations in operator log keeping in
seven inspection reports since'1995.
It appears that the TVA program is meeting the intent of the NRC
position on NUREG 0737 regarding shift and relief turnover procedures.
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Specifically, critical plant parameters are entered in the operator
computerized logs and are available for review by the oncoming
o>erators. Critical plant parameters are also readily available from
t1e control room ICS. As noted in the licensee's letter of March 20,
1997, a shift turnover meeting is conducted by the SM. That meeting
discusses current plant status, equipment problems, and evolutions
planned or in progress.
In addition to a control board walkdown
conducted jointly by the oncoming and off-goi'ig operators, the oncoming
operator at the controls (0ATC) and the control room operator (CRO) each
perform a Periodic Instruction (PI) which is a status check of vital
systems. All TS Limiting Condition for Operation (LC0) action
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statements which have been entered are listed on a computerized LC0
Tracking System and are reviewed by all oncoming operators.
Additionally, each oncoming operator reviews the control room log book.
Implementation of log keeping remains a 3roblem and when corrected, the
shift turnover process should be acceptaale.
c.
Conclusions
The inspectors concluded that the licensee's program meets the intent of
NUREG 0737 regarding shift turnover and relief procedures, however
improved implementation is necessary.
02
Operational Status of Facilities and Equipment
02.1 Steam Generator Level Deviations
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a.
Inspection Scoce (71707)
The inspectors reviewed the licensee's corrective actions related to
continued steam generator level deviations.
b.
Observations and Findinas
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IR 97 03 described a aroblem with Unit 2 steam generator level
deviations. This pro)lem first occurred in December 1996, and has
occurred numerous times on loops 1, 2 and 3 since December.
Programmed
steam generator level is 44%. The level deviations were typically 2 to
5% increases in level. There have been some instances were operators
took manual control of steam generator level to return it to program;
although, typically, steam generator level returned to the programmed
level after several minutes, without operators taking manual control.
The licensee has taken several actions to correct this problem. Some of
the licensee's actions included:
lubricating flow control valve stems,
recording and analyzing the signals from the level control system,
replacing relays in the controllers, and field tuning the flow
controllers. The licensee instituted a team to address the continuing
level control problems. The licensee is still investigating potential
causes for the level deviations.
c.
Conclusions
The inspectors concluded that the steam generator level deviations had
not caused significant operational difficulties, however, continued
licensee effort in resolving the level control problem is needed.
02.2 Outaae Related Operational Challences
a.
Inspection Scope (71707)
The inspectors reviewed the control room operational logs to determine
the type and frequency of equipment and system status related challenges
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imposed on the operators during the second half of the Unit 1 refueling
outage.
b.
Observations and Findinas
Interviews with the control room operators indicated a higher than
expected level of equipment problems were being observed during the
Unit 1 refueling outage. The inspector aerformed an integrated review
of the control room logs for the period 3etween April 12 and May 13 and
noted multiple potential problems with human performance, procedures,
equipment and plant status control. These problems appeared to have
posed daily challenges to the o)erators.
Further review is necessary to
determine the extent of the pro)lems and to review the licensee's
corrective actions. Therefore, further review of the refueling outage
related operational problems is being identified as an unresolved item
(URI 50 327/97-04 04).
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a.
Insoection Scone (61726 & 62707)
The inspectors observed and/or reviewed all or portions of the following
work activities and/or surveillances:
e 1-S0-2/3-1
Condensate and Feedwater System
e 2 SI-0PS 082 007.B
Electrical Power System Diesel Generator 28 B
e 2-SI SXV-062 230.0
VCT Check Valve Test During Operation
e 2 SI-SXP 074-201.A
Residual Heat Removal Pump 2A A Performance Test
e 1 SI SXP 003 201.S
TDAFW Pump 1A-S Performance Test
e MI 10.54
Diesel Generator Battery Replacement and/or
Battery Bank Bus Rework (System 250)
e 0-PI-SXP 078 201.C
Spent Fuel Pit Cooling Pump C S Performance Test
Diesel Generator 1A Voltage Regulator Repair-PMT
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e 0-SI-SXX 085-043.0
Rod Drop Time Measurements
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e 0-MI-MRR-003 461.0
TDAFW Pump Control Valve FCV-51 Repair
e S SI 0PS 003-118.0
AFW Pump and Valve Automatic Actuation
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e 1 SI 0PS 087 026.B
Loss of Offsite Power with SI-Diesel Generator
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1B B Containment Isolation ~ Test
b.
Observations and Findinas
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The inspectors noted that the work activities and the performance of
surveillance activities were adequately performed with the exception of
the steam dump valve maintenance documented in Section M2.1.
M1.2 Inservice Insoection (ISI)
Unit 1
a.
Inspection Scope (IP 73753)
The inspector reviewed program plans, procedures, and documentation
related to the conduct of inservice inspection (ISI) Inspection during
the Spring 1997, Unit 1 Outage.
b.
Observations and Findinas
Pressure Boundary ISI
Sequoyah Unit 1 began commercial operation on July 1,1981, but because
of extended plant shutdowns, the first 10 year ISI inspection interval
was extended to December 15, 1995.
(Unit 2 which began commercial
operation on June 1,1982, was also deemed to have completed its first
10 year inspection interval on December 15, 1995.) The second ISI
inspection interval began on December 16, 1995, for both units, with a
common ASME Code of record: ASME Section XI, 1989 Edition, with no
addenda. The inspector partially reviewed Surveillance Instruction
0 SI DXI-000-114.2, "ASME SECTION XI ISI/NDE PROGRAM UNIT 1 and UNIT 2."
Revision 1, Effective Date March 20, 1997. As stated in the procedure,
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Surseillance Instruction 0-SI DXI 000 114.2:
... implements the SON Unit 1 Technical Specification
"
(TS) Requirement 4.4.3.2.4 and partially satisfies the
requirements for both Unit 1 and Unit 2 TS
surveillance requirement 4.0.5: and fulfills the
requirements of Site Standard Practice, SSP-6.10,
'ASME SECTION XI ISI/NDE AND AUGMENTED NONDESTRUCTIVE
EXAMINATION PROGRAMS.'"
At the time of the inspection, the ISI examinations planned for this
outage had been essentially completed, thereforS the insaction focussed
on the ISI plan and the documentation of the results. T1e inspector
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reviewed documentation for visual, surface, and volumetric examinations
that were conducted during the Spring 1997 refueling outage. Records of
Ultrasonic Examinations (UT) reviewed in detail included the following:
ComDonent/ Weld
Examination
Comment
SIS 252 - Pipe to Elbow
0 .45 ,60
No Recordable Indications
6" dia. 3/4" wall, SS
SIS-253
Elbow to Pipe
0 .45 .60
360 Indication in Pipe,
6" dia. 3/4" wall, SS
outside area of interest. 45
Indication, not seen with 60
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geometric, possibly counterbore
RCS 040 - Elbow to Pipe
0 .45 ,60
No Recordable Indications
4" dia.1/2" wall, SS
SIF-198 - Elbow to Boss
0 .45 ,60
Augmented IGSCC Exam
6" dia. 3/4" wall, SS
No Recordable Indications
RCS 049
Pipe to Reducer
0 .45 .60
No Recordable Indications
6" dia.
67" wall, SS
RCW-21
Nozzle to
0 .45 .60
63.74% Code Coverage, (Complex
Pressurizer Shell
Calculation) No Indications
3.6" to 3.8" wall, CS
CVCS-148
Pipe to Elbow
0 .45 ,60
No Recordable Indications
4" dia.1/4" wall, SS
SIS 237 - Elbow to Pipe
0 .45 .60
No Recordable Indications
6" dia. 3/4" wall, SS
MSS 11 - Elbow to Pipe
0 .45 ,60
No Recordable Indications
32" dia.1.5" wall, CS
CVCS 112
Pipe to Elbow
0 .45 ,60
2 Indications found with 45 ,
3" dia. 1/2" wall, SS
UT Plus
confirmed with 60 . Re-
additional
evaluation with 70 S, WSY 70 ,
angles
60 RL, 80 High Angle Creeping
Wave, and 0 L.
Determined to
be Geometric.
Containment ISI
Effective September 9,1996,10 CFR 50.55a, was amended to include the
requirements of ASME B&PV Code Section XI, Subsections IWE and IWL 1992
Edition, with 1992 Addenda.
Subsections IWE and IWL provide ISI
requirements for concrete containments, steel containments, and steel
liners for concrete containments. The amendment to the rule provided a
five year period, until September 9, 2001, before full implementation of
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Subsections IWE and IWL.
In correspondence with the industry,
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(November 6,1996, letter to Alex Marion, Nuclear Energy Institute from
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Gus Lainas, Office of Nuclear Reactor Regulation, concerning
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" Implementation of Containment Inspection Rule") NRC provided a Staff
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position that, in response to deficiencies noted prior to the full
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implementation IWE and IWL, re] air and replacement activities must be
conducted in accordance with tiose subsections.
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The licensee has issued two temporary changes to Procedure No. N VT 1,
" VISUAL EXAMINATION PROCEDURE FOR ASME SECTION XI PRESERVICE AND
INSERVICE," Revision 25, dated December 3, 1996, to include the ASME
1
Code,1992 Addenda, visual _ ins)ection requirements for containments.
The changes were TC 97 03 whic1 included inspection requirements for
pressure retaining bolting materials and seals and gaskets, and TC 97 06
which provided inspection requirements for containment vessel surfaces.
The inspector conducted a walk through inspection of the Unit 1 up,)er
containment looking for indications of coating degradation, etc., which
should be indicative of potential inservice problems with the steel
containment. A part of the inspection was conducted on April 17, 1997,
using the remote video equipment used by health physics personnel for
surveillance of work activities in the upper containment. The rest of
d
the inspection was done using 7X binoculars during a containment entry
on April 18, 1997. The inspector noted that the majority of the u)per
containment walls and dome were only coated with what appeared to
3e
" carbo zinc" type of primer coating. There were a few areas of the wall
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that were coated with a light colored coating over the primer, these
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areas appeared to be in good shape with no evidence of peeling or
flaking.
Reoair and Reolacement
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At the time of the inspection, the licensee was replacing feedwater line
elbows on Steam Generators 3 and 4 due to thermal fatigue cracking in
the area of the weld connecting the elbow to the feedwater nozzle on the
SG.
The replacement elbow included a modification to include a thermal
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The inspector observed welding o)erations on the elbow to pipe weld on
the feedwater line for SG #3. T1e operations observed involved the
set up of the welding machine for the start of a weld aass and, the
,
initiation and partial completion of the weld pass. T1e inspector
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reviewed the documentation package at the job site, and discussed
welding procedure requirements with the welding operators.
The inspector reviewed the documentation package for DCN No. M 11336 A
which was prepared to: " Remove existing steam generator feedwater nozzle
elbows and transition pieces and replace it with a new design with a
thermal liner for the purpose of mitigating cracking due to thermal
fatigue." For the most part, the documentation package for this DCN was
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very comprehensive.
One minor problem was noted on page 22 of 32 of Appendix G, " Safety
Assessment Checklist," Item 52, concerning ASME Section XI. The safety
assessment states that the Code of record for SG repair and replacement
at SON is ASME Section XI, 1980 Edition through Winter 1981 Addenda.
While this statement was true at the time that the safety assessment was
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completed in early 1995, as a part of the design of the modification, it
was no longer the case after December 15, 1996, when it was determined
that both Sequoyah units had completed the first 10-year ASME, ISI. As
of December 16, 1996, the Code of record for repair and replacement of
ASME Code related items at SQN became the 1989 Edition.
For the purpose
of this modification, this was a minor problem because the later edition
of the Section XI allowed the same design and fabrication rules to apply
that were permitted by the earlier edition of Section XI. The problem
was pointed out to the licensee as an example of something that
engineering support and design organizations should be made aware of
whenever a plant transitions from one ISI inspection interval to the
next, with a resulting change in Code of record.
Leak Testina of Bolted Connections
During review of ISI documents, the inspector inquired if ASME Code Case
N-533, " Alternative Requirements for VT 2 Visual Examination of Class 1
Insulated Pressure-Retaining Bolted Connections,Section XI,
Division 1," had been approved for use at Sequoyah by NRR. The
inspector also asked to review the procedure (s) for conducting the
Class 1 pressure tests.
The licensee provided the inspector with a copy of Surveillance
Instruction No.1 SI-SXI 068 201.0, " Leakage Test of the Reactor Coolant
Pressure Boundary," Revision 0, dated March 21, 1997: prepared for the
inspection of Unit 1 during the current refueling outcge. The licensee
also provided a copy of the documentation package for Surveillance 2 SI-
SXI 068-201.0, Revision 0, dated April 26, 1996, which had been used for
the pressure testing of Unit 2 during its last refueling.
During the review of the Unit 2 surveillance procedure documentation
package, in the section of the procedure devoted to the in:oection of
pressure retaining bolted connections, the inspector noted ' hat the
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procedure had been issued without a definitive list of i:elted
connections to be inspected.
Instead, the VT 2 examiner was provided
with a list of reference drawings and an inspection list of 25 blank
lines to be filled out as the inspection was completed. The
documentation package showed two obvious weaknesses with the Unit 2
procedure: 1) Twenty five lines were not enough, as there were numerous
entries written in the margin of the list; and 2) The use of a blank
list and a number of reference drawings did not provide an auditable
record to ensure that "all" of the pressure retaining bolted connections
had been examined. This latter point was shown by the fact that after
the Unit 2 surveillance was signed as complete, the licensee issued a
PER to inspect a number of bolted connections that had been missed.
The inspector also noted that the Unit 1 procedure was essentially a
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duplicate of the procedure issued for Unit 2.
In light of the fact that
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the review of the Unit 2 surveillance procedure had discovered two
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obvious problems during its initial implementation, the ir ,pector
informed the licensee that the failure to incorporate lessons learned in
the next iteration of a new procedure showed a lack of sensitivity to
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the problems and would be considered as a weakness in the area of
surveillance procedure development.
Licensee management agreed with the
inspector's assessment of the procedure, and Revision 1 of Procedure
1 SI SXI 068 201.0, was issued on April 18, 1997, containing a
definitive list of pressure retaining bolted connections, expected to be
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found within the Class 1 piping system boundary,
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c.
Conclusions
The licensee's pressure boundary and containment ISI activities were
well organized, implemented correctly, and properly documented.
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ASME Section XI, repair and replacement activities, as demonstrated by
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the SG feedwater piping replacement, were well controlled and
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documented.
A weakness was identified in the area of the Unit 1 surveillance
procedure for the leak testing of ASME Class 1 bolted connections, in
that the issued procedure was essentially the same as that used for the
last Unit 2 outage, without considering lessons learned from
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implementation problems during that outage.
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M1.3 Steam Generator (SG) Inspection
Unit 3
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a.
Insoection Scope (IP 50002)
)
Through discussions with personnel and review of documentation, the
inspector reviewed the Eddy Current (ET) inspection of the Unit 1 SGs.
f
b.
Observations and Findinas
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The Unit 1 SGs are Westinghouse Model 51 which contain low temperature,
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mill annealed, Inconel 600 tubing supported by carbon steel, drilled
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support plates, with WEXTEX tubesheet expansions.
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The inspector reviewed the Steam Generator Analysis Guideline for Eddy
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Current Data, Revision 1997.02 dated February 1997, along with
Evaluation Guideline Change Form #1, dated April 13, 1997. The
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inspector also conducted several discussions with inspection and
supervisory personnel to evaluate the ET activities and determine the
status of the SG inspections. The inspector also reviewed tabulated
results of the ET tests.
On April 17, 1997, the inspector participated in a conference call
between the licensee and NRC concerning the status of the ET testing.
During this call, the licensee presented a description of the ET testing
which had been accomplished; the preliminary results of the tests; and
the status of in situ pressure testing of SG tubes. Due to a
communications problem with transmitting the licensee's data tables to
the appropriate people in NRR, the conference call was continued on
April 18, 1997, after all parties were able to review the appropriate
data tables.
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The inspector also observed the in situ pressure testing of SG 4, tube
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R33C21, which was reported to have a 91% through wall, 4 inch long axial
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PWSCC indication at the first hot-leg support plate. The tube was
pressurized to 1600#, then 2800#, and finally 4750# with a two minute
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hold at each pressure level. There was no leakage from this tube during
the test.
c.
Conclusions
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The licensee's program for inspection of SGs appears to be well managed
and conducted in a conservative manner. The analysis guidelines were
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found to be well written and easy to interpret.
M2
Maintenance and Material Condition of Facilities and Equipment
4
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M2.1 Reoair of Unit 1 Steam Dumo Valves
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a.
Inspection Scooe (62707)
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On May 12, 1997, during a routine turbine building walk down, an NRC
resident inspector identified two Unit 1 steam dum) valves with loose
bolts on the valve operator. The licensee wrote PER No. SQ971375PER to
document this finding.
Subsequently, when the licensee closed the
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valves to continue the plant heatup/startup, the valves indicated in the
mid position (both green and red lights lit).
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b.
Observations and Findinas
1
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Further review noted that the licensee had inspected /reiuebished all
twelve of the Unit 1 steam dump valves during the cycle 8 refueling
outage.
Mechanical maintenance had replaced the valve trim on some of
the valves during the outage and, following reassembly, instrument
maintenance was required to adjust the valve stroke and torque the
locking bolts.
Step 6.7 in 0 MI HVV 000 029.0, the mechanical
maintenance procedure dealing with the setting of the steam dump valve
stroke, was used for this work, however, this section had not been
completed. The licensee's investigation determined that the instrument
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maintenance grou) used a different maintenance procedure to perform this
work, and that t1e specific instrument maintenance procedure did not
include the steps for torquing the locking bolts.
A similar problem occurred on Unit 2 following the Unit 2 cycle 7
refueling outage, when the locking bolt on a steam dump valve was found
broken.
During the Unit 2 cycle 7 outage, the licensee had not
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adequately set the stroke on all of the Unit 2 steam dump valves and the
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locking bolts had not been torqued.
Subsequently when steam dump valve
SD 107 was stroked the locking bolt was broken off. The valve was
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isolated at that time and remains isolated until repairs can be made.
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3
The licensee is investigating why the corrective actions for the first
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occurrence did not adequately correct all of the related maintenance
procedures.
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During the licensee's review of this deficiency, the licensee identified
that communications between the mechanical maintenance group and the
instrument group were poor, mechanical maintenance did not validate the
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work activities and supervisory oversight was weak. These findings were
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based on the fact that, although Section 6.7 of the mechanical
maintenance procedure was found to be blank, personnel did not verify
that all of the work had been completed by the instrument group prior to
closing out the work package.
The system is not safety-related and the problem is not considered to be
a regulatory concern, however this condition was considered to be
important because the failure of the locking bolts could result in a
loss of control of the steam dump valves and with the potential for the
valve to fail full open.
c.
Conclusions
Mechanical maintenance did not verify that all work had been completed
prior to closing out the work packages on the Unit 1 steam dump valves.
Procedure revisions to address the missed bolt torquing requirements in
1996 on Unit 2 were not sufficient to identify and correct all of the
associated work procedures, resulting in not torquing the bolts on
Unit 1.
M2.2 Failure of Voltaae Reculator on Emeraency Diesel Generator (EDG) 1A A
a.
Insoection Scope (62707)
The inspectors reviewed the sequence of events related to the repair of
the voltage regulator on EDG 1A A.
a.
Findii..s and Observations
On May 21, 1997, during performance of 1-SI 0PS 082 007.A. Electrical
Power System Diesel Generator 1A A, Revision 10, on EDG 1A A, operators
emergency stopped the EDG when generator voltage exceeded 9000 volts
(voltage should have been within the range of 6210 volts to 7590 volts).
The EDG was declared inoperable and the appropriate TS action statement
was entered. The licensee determined that no damage was done to the
generator and that the condition of high voltage existed for less than
five minutes.
Maintenance determined that a voltage regulator card had
failed. A replacement card was subsequently installed to replace the
one which had failed.
On May 23, 1997, the inspector observed the performance of a post
maintenance test (PMT) conducted under Work Order (W0) 97 007711. The
PMT tested the responsiveness of the repaired voltage regulator under
load and load reject conditions. The voltage regulator responded as
designed during the PMT, met the acceptance criteria of SI 0PS 082 007.A
and subsequently was declared operable.
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III. Enaineerina
E2
Engineering Support of Facilities and Equipment
E2.1 Unit 1 Steam Dumo System Modifications
a.
Inspection Scope (37551)
,
Due to previous problems with the operation of the steam dump systems on
both units, the inspectors observed the operation of the steam dump
system from the control room and locally during restart activities
following the Unit 1 refueling outage.
b.
Observations and Findinas
Following problems encountered with the Unit 2 steam dump system during
the October 11, 1996, plant shutdown, the licensee developed corrective
actions to address the various problems with the steam dump systems on
both units.
Inspection Report 50 327, 328/96 17 documented the proposed
corrective actions. During the Unit 1 refueling outage the licensee
implemented various system modifications to correct the problems with
the Unit 1 steam dump system.
During plant startup, the inspectors observed the o)eration of the steam
dump system.
Previously the steam dump system had seen observed with
mild water hammering due to water accumulation in the steam dump
discharge lines.
Modifications to the steam dump drain system appeared
to have successfully corrected this condition.
Although the recent modifications to the steam dump system appeared to
be effective. the inspectors noted a few operational / maintenance
problems regarding steam dump system operation during the startup. The
various problems encountered were as follows:
the steam dump system
master controller failed and had to be re) aired; the drain valve for
steam dump valve 50113 failed, causing t1e line to fill with water,
resulting in SD 113 being isolated during plant startup; and maintenance
did not torque the steam dump velve locking bolts (Section M2.1).
c.
Conclusions
The licensee was successful in implementing various modifications to
improve the operation of the Unit 1 steam dump system.
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)
IV. Plant Support
R
Status of RP&C Facilities and Equipment
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R1.1 Radioactive Water Soill
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a.
Inspection Scooe (71750)
The inspectors reviewed the licensee's actions in response to a large
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radioactive water spill on May 19, 1997.
b.
Observations and Findinas
I
1
On May 19. 1997, a fire operations individual observed water flowing
down the stairwell on elevation 669 of the auxiliary building. The
licensee subsequently determined that the water came from a failed
conductivity probe on the inlet to the Modularized Fluidized Transfer
Demineralization System located in the 706 elevation in the railway bay.
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The licensee estimated that approximately 3000 gallons of radioactive
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water were spilled. Approximately 600 gallons of this water migrated to
the outside rad waste yard. Although the spill itself was contained in
the RCA (inside and outside in the rad waste yard), the licensee
measured contamination in the french drain system located underneath the
rad waste yard.
.
Contamination levels in the rad waste yard indicated up to 18,000
disintegrations per minute per 100 square centimeters. There were no
personnel contaminations as a result of the. spill or the clean up. The
licensee's immediate corrective actions included securing and posting
the areas, damming and cleaning up the affected areas, application of a
coating on the asphalt in the rad waste yard to prevent migration of the
i
contamination, and sampling the yard pond and storm drains.
Contamination was not detected in the yard pond or the storm drains.
The licensee also sampled the french drain system which runs underneath
!
the rad waste yard and outside the RCA. Contamination was detected in
the french drain system at the boundary of the RCA.
The licensee started excavating the contaminated portions of the rad
waste yard and sections of the french drain system, including the gravel
underneath the french drain system, for removal and disposal of
contaminated material. TVA corporate hydrologists were involved in the
development of follow up actions.
c.
Conclusions
The inspectors concluded that the licensee's actions to contain and
,
mitigate the radioactive water spill were appropriate. An inspector
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follow up item (IFI) was identified for reviewing the licensee's
completed corrective actions for the spill (IFI 50 327, 328/97 04 05).
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V. Manaoement Meetinas
X1
Exit Meeting Summary
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The inspectors ) resented the inspection results to members of licensee
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management at tie conclusion of tne inspection on June 5,1997. The
licensee acknowledged the findings presented.
The inspectors asked tb 'icensee whether any materials would be
considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
- Adney, R., Site Vice President
- Beasley, J., Acting Site Quality Manager
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Bryant. L., Outage Manager
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Driscoll
D., Training Manager
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- Fecht, M. , Nuclear Assurance & Licensing Manager
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Fink,
F., Business and Work Performance Manager
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- Flippo.
T., Site Support Manager
- Herron, J.. P1 ant Manager
Kent, C., Radeon/ Chemistry Manager
- Lagergren. B., Operations Manager
O' Brian, B., Maintenance Manager
Rausch, R. Maintenance and Modifications Manager
Reynolds,
J., Operations Superintendent
- Rupert,
J., Engineering and Support Services Manager
- Shell, R., Manager of Licensing and Industry Affairs
- Smith,
J., Licensing Supervisor
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Summy, J., Assistant Plant Manager
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- Valente,
J., Engineering & Materials Manager
- Attended exit interview
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INSPECTION PROCEDURES USED
,
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls In Identifying Resolving, &
Preventing Problems
IP 61726: Survaillance Observations
IP 62707: Maintenance Observations
)
IP 71707: Plant Operations
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IP 73753:
Inservice Inspection
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IP 50002: Steam Generators
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ITEMS OPENED. CLOSED. AND DISCUSSED
Opened
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T__ype Item Number
Status
Descriotion and Reference
50-327/97 04-01
Open/ Closed Failure to Maintain RCS Temper _ture
and Pressure Within the Limitations
of Plant Startup Procedure 0 G0 1
(Section 01.2).
50 327/97 04 02
Open
Failure to Meet the Surveillance
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Requirements of TS 4.10.3.2, For
Performing Functional Testing of the
Nuclear Instruments (Section 01.3).
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50 327/97 04-03
Open
Failure to Follow Procedure For
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Exceeding Fual Preconditioning
Limitations, Not Logging Changes In
Plant Conditions, and Not Informing
the Shift Manager of Changes In
Plant Conditions (Section 01.4).
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50 327/97 04 04
Open
Further review of potential
regulatory issues noted in the
Unit 1 operational logs (Section
02.2).
IFI
50 327, 328/97 04 05
Open
Review licensee's corrective actions
following an inadvertent spill of
several thousand gallons of
contaminated water (Section R1.1).
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