IR 05000327/1997008
| ML20211E283 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 09/22/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20211E201 | List: |
| References | |
| 50-327-97-08, 50-327-97-8, 50-328-97-08, 50-328-97-8, NUDOCS 9709300084 | |
| Download: ML20211E283 (31) | |
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l U.S. NUCLEAR REGULATORY COM L J10N REGION 11 Docket Nos:
50-327. 50-328 License Nos:
50 327/97-08. 50 328/97-08 Licensee:
Tennessee Valley Authority (TVA)
Facility:
Sequoyah Nuclear Plant. Units 1 & 2 Location:
Sequoyah Access Road Hamilton County. TN 37379 Dates:
July 6 through August 23, 1997 Inspectors:
M. Shannon. Senior Resident inspector R. Starkey. Resident Inspector D. Seymour. Resident Inspector W. Miller. Reactor Inspector Region 11. (Section F8.1)
R. Hernan. Project Manager. NRR. (Section E8.1)
C. Smith. Reactor Inspector. Region 11. (Section E2.1.
E8.2)
Approved by:
M. Lesser. Chief Reactor Projects Branch 6 Division of Reactor Projects
Enclosure 2 9709300004 970922 POR ADOCK 05000327
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EXECUTIVE SUMMARY Sequoyah Nuclear Plant Units 1 & 2 NRC Inspection Report 50-327/97 08, 50-328/97-08-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 an announced inspection by the Project Manager and a Region !! reactor inspector.
Querations The conduct of operations during the inspection period was considered te i
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be acceptable.
This conclusion was based on various control room observations and findings associated with the vital battery issue discussed in inspection report (IR) 97-13. (Section 01.1)
An Unresolved item was identified related to a potential inoperable AFD
.o monitor alarm.
In addition, it was noted that the AFD and OPTR alarms were not functioning as expected and the deficiencies were not promptly addressed. (Section 02,1)
The control room operators were effective in controlling a downpower e
evolution. (Section 02.2)
One violation was identified for failure to meet code requirements e
during Section XI valve testing.
In addition, it was noted that the operations staff involved with the Section XI valve testing, lacked full understanding of the Section XI test program and of AMSE/ ANSI OHa _1988 code requirements.
Several problems have recently been identified with-valve testing. Some examples are documented in LER 50 327/96-12 and Inspection Report 97-06.
(Section 04.1)
Maintenance e
Numerous maintenance and surveillance activities were observed and reviewed. lne activities were adequately performed.
(Section M1.1)
Unit 2 was taken off-line due to a "C" phase main transformer fault as a e
result of not properly grounding the transformer core.-(Section 02.2)
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The loss of control air event and reactor trip was caused by poor o
material condition in the control air system which resulted in specific isolation, drdin and vent valves not performi g their intended functions. (Section M1.2)
Engineerina The licensee has taken the initiative to improve the corporate safety e
assessment procedure for 10 CFR 50.59 evaluations and make it applicable at all three TVA Nuclear plant sites. (Section E8.1)
Although minor omissions were noted in some UFSAR change packages, the e
more significant changes were generally complete and very well written.
(Section E8.1)
in some cases. safety assessments and safety evaluations documented e
statements such as "the change involves no increase in the probability of an accident." but provided no technical discussion or justification of why the statement was true. (Section E8.1)
Qualitative improvements in determining the root causes of equipment e
f611ures have been demonstrated by the licensee. (Section E2.1)
Problem Evaluation Reports written for equipment reliability problems e
were dispositioned in accordance with the requirements of the corrective action program. (Section E2.1)
Plant Sucoort e
The fire watch violation identified during an investigation by the NRC Office of Investigation was withdrawn as a Severity Level IV Violation, and identified as a non-cited violation.
(Section F8.1)
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Reggrt Details i
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Summary of Plant Status
Unit 1 began the inspection period in power operation.
The unit was manually
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.ie secondary plant.
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i Repairs were made to the control air system and Unit I was restarted on
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August 2, 1997.
Full power was reached on Augus,, 4,1997, and the unit t
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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 was
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temporarily reduced to 55% power on July 3, 1997, due to indications of 3-i.
gassing in a main transformer and a relay actuation.
The unit was taken off
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line (remained in Mode 2) on July 20 due to a re-actuation of the same main
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transformer relay, at which time the "C" phase main transformer was removed from service and the spare transformer placed in service. The unit was
synchronized to the grid on July 21 and operated at power for the remainder
of the inspection period.
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Review of Uodated Final Safety Analysis Renort (UFSAR) Conunitments I
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that were related to the areas inspected, i
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.
In general, the conduct of operations was acceptable.
Problems were noted with misaligning the vital battery and AVO round taking.
This event is discussed in detail in IR 97-13. Other specific events and noteworthy observations are
detailed in the sections below,
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02 Operational Status of Facilities and Equipment 02.1 Deficient Technical Soecification (TS) Recuired Alarm Functions a.
Insoection Scone (71707)
The inspectors reviewed selected control room logs and computer history printouts associated with the various problems encountered with the TS required alarm functions for Quadrant Power Tilt Ratio (0PTR) and Axial Flux Difference (AFD).
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Observations and Findinas During the inspection period, the inspector reviewed the plant condit uns associated with control room log entries on July 4-5. June 8-9 and May 15. 1997.
On each of the subject days, plant transients resulted in various problems being encountered with main control board
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alarm conditior.s.
AFD in Alarm on July 4-5: At 7:26 a.m.
on July 4. the main control board alarm " Computer Alarm. Rod Deviation and Power Range Tilts" annunciated due to the indicated axial flux difference (AFD) being outside the administrative target band. At 8:04. AFD was back inside the target band: however, the control board and computer alarms did not clear. The alarms are designed to stay in the alarm state if more than 30 minutes of penalty points (minutes the AFD alarm is in alarm) are accumulated in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. At 2:30 a.m.
on July 5. operators questioned the operability of the AFD monitor alarm due to the " Computer Alarm, Rod Deviation and Power Range Tilts" being in continuous alarm, without reflash capability, as a result of AFD being outside the target band for greater than 30 minutes on July 4.
Due to the operator's concern with the operability of the AFD monitor alarm, at 2:30 a.m., the operators started takino hourly AFD readings per procedure 9-SI-NUC-000-044.0 Axial Flux Difference, to comply with TS surveillanca requirement 4.2.1.1.b.
The operators also noted that the alarm response procedure for the " Computer Alarm. Rod Deviation and Power Range Tilts" did not clearly explain the reflash functdons on this alarm window. At 8:30 a.m., on July 5. the operators completed the performance of procedure 0-SI-NUC-000-044.0 and noted in the logs that operators had continuously monitored AFD by using control board indicators and the ICS computer AFD target display while the alarm was in.
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During a subsequent review of the control room logs, the inspector noted the potential deficient condition and discussed the item with licensee management. When the AFD monitor alarm is inoperable, the surveillance requirement for TS 4.2.1.1.b. requires the operators to perform monitoring and logging of the indicated AFD for each operable excore channel at least once per hour for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The inspector noted that the operators may have been monitoring the AFD but had not logged the values hourly. The inspector reviewed the AFD monitor alarm circuit and the lack of reflash capability and considered the AFD monitor clarm circuit to be potentially inoperable when the alarm is locked in during the 24-hour period. The licensee stated that they considered the AFD monitor alarm circuit to be operable based on the operators monitoring the ICS AFD target display on the ICS computer.
The licensee's position was based on the fact that if a new alarm condition occurred while monitoring the AFD target display, the ICS display would change colors and cause the letter "M" in the upper right
- hand corner to flash on and off.
Tiie licensee stated that this met the intent for having an operable AFD monitor alarm.
However, the inspectors noted there would not be an audible alarm on the ICS computer or the main control board and the operators would have to have the AFD target display called up on the computer in order to observe any potential alarm condition.
During subsequent review of the alarm circuitry, the inspector noted that the 24-hour penalty point alarm _ was no longer needed to meet TS requirements and should have been removed during the recent computer upgrades.
This would have provided reflash capability for the AFD alarm and this potential problem could have been avoided. The inspectors also noted that several operators did not fully understand what needed to be done with the flashing "M" on the ICS screen and the alarm response procedure did not require continuous monitoring of the AFD ICS computer o
screen.
The inspector concluded that the AFD monitor alarm would probably be inoperable when locked in for the 24-hour period, and subsequent monitoring and logging of AFD would then be required to meet the TS action statement.
Further review and evaluation will be needed to resolve this issue.
Having a potentially inoperable AFD monitor alarm and not meeting the related TS surveillance requirements. is identified an Unresolved Item (URI 50-328/97-08-01).
OPTR in alarm on June 8-9: At 11:45 p.m., on June 8. 1997, the control room operators logged that they had received the " Computer Alarm. Rod Deviation and Power Range Tilts" alarm and that the alarm was being brought in by the upper nuclear instrument detector OPTR.
The alarm j
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actuated several times over a 4-hour period and finally cleared at 3:30 a.m., on June 9.
When the alarm initially actuated the operators reviewed the ICS computer display for upper nuclear detector OPTR and I
noted that an alarm condition did not exist and the alarm should not have actuated.
Subsequent resident inspector review of the ICS computer history for the four hour period. noted that neither the upper nor lower detectors were in an expected alarm condition (0PTR >1.02).
The inspector noted in early July that the licensee had not initiated a work request or a PER to determne if the OPTR ' alarm was actually inoperable or to determine why ti'e alarm had actuated witheat an expected alarm condition.
After discussions with operations, a Problem / Change Request (PCR) PCR SON-1448 was generated to resolve the ICS computer generated alarm deficiency.
Subsequently the licensee determined that the alarm was the result of an actual QPTR being 2% low on one channel. Although this was an alarm input for OPTR the alarm response procedure did not identify this condition as an alarm input.
The alarm response proceUe was revised to include / identify this alarm input.
AFD monitor alarm not properly alarming on May 15:
At 8:01 p.m., on May
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15, 1997, the Unit 1 " Computer Alarm. Rod Deviation and Power Range Tilts" went into alarm due to AFD being outside the administrative target band high limit of +4.3.
Operations manipulated rods as necessary and the control board alarm cleared eight minutes later (this issue is related to the reactor power transient discussed in inspection report 97-04).
During a subsequent NRC and licensee review, it was noted that the computer points for the core average delta flux and the individual detector's delta flux were above the alarm setpoint from 8:01 p.m. until 9:01 p.m. on May 15. however, the main control board and computer alarms did not indicate an alarm condition.
During the initial review conducted in May, the inspectors noted to the licensee that it was unclear why the AFD monitor alarm was not in alarm with all four individual detector readings slightly above the +4.3 ICS computer alarm setpoint.
Following the July 4-5 AFD monitor alarm actuation, the inspectors noted that the licensee had not determined why the alarm had not functioned as intended and had not initiated a work request to verify the AFD alarm setpoint. The inspector also noted that a computer failure, following the May 15 condition had resulted in a loss of the computer historical data for a several day period, including the AFD problem on May 15.
The inspector concluded that further evaluation of the operation of the AFD alarm should be pursued by the license _'
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Conclusions
~ An Unresolved item was identified for having -a potentially inoperable AFD monitor alarm.
-It was_noted that the AFD and OPTR alarms were not functioning as
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02.2 Unit 2 C Phase Main Transformer a.
Insoection Scone (71707 and 40500)
The inspectors reviewed the sequence of events which resulted in two-power reductions on Unit 2.
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Observations and Findinas
~On July 3, 1997, a " Transformer Gas Abnormal" alarm was received in the-control room (CR).
The licensee's investigation identified that the-Unit _2 "C" phase main transformer was generating gas, which actuated the Buchholz relay (monitors gas generation in the transformer) at the top of_.the transformer.
The gas was analyzed and found to contain higher than normal levels of combustible gases, an indication of arcing'or hot spots in the transformer.
Plant management decided to reduce power on Unit 2 in order to remove the transformer from service.
The licensee initially reduced power to 55%: however, the downpower was stopped due to additional' transformer samples indicating a reduction in gas concentrations.
The inspector observed the downpower evolution and noted that the secondary plant responded very well with no noted deficiencies.
There is a history of various problems being encountered during previous downpower evolutions. The inspector noted that the control room operators did a very good job in controlling the downpower.
Equipment changes were closely controlled and monitored, resulting in fewer secondary transient conditions.
After further= evaluation, TVA management decided to continue operating
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the unit without removing the transformer from service.
The decision was made to return the unit to full power and to closely monitor the gas levels in the transformer, which were high but not at the levels requiring an immediate shutdown. Oil samples were taken twice daily.
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analyzed and trended.
The results indicated a slow increase in combustible gases, which appeared to be leveling off.
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On July 20. 1997, the " Transformer Gas Alarm" was received in the CR a
'second time, and the Buchholtz relay was observed to have a larger gas
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bubble than on July 3rd.
Plant management decided to reduce power to approximately 20% and remve the transformer from service and replace it with the spare transformer.
Subsequent oil sample results indicated a sharp increase in combustible gases. The unit was reduced in power on July 20. the transformer was spared out, and the unit synchronized to the grid on July 21. and returned to 100% power on July 23, 1997.
The licensee formed a team to investigate the transformer anomaly.
After the transformer was removed from service it was inspected.
The licensee determined that the transformer core-to-ground strap, which should provide a ground for the main transformer core, was disconnected.
With the core ungrounded, the core would discharge to ground inside the tank, resulting in the formation of combustible gases. At the end of the inspection period, the investigative team had not determined why the core-to ground strap had been left disconnected.
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Conclusions Unit 2 was taken off-line due to a "C" phase main transformer fault as a result of not properly grounding the transformer core.
A positive observation was noted in that the control room operators did a good job in controlling the downpower evolution.
Operator Knowledge and Performance 04.1 Multiole Strokina of a Containment Isolation Valve a.
Insoection Scoce (71707 and 40500)
The inspectors reviewed the circumstances which resulted in a containment isolation valve being stroked multiple times as part of an ASME Section XI code stroke tes '
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Observation and Findinas Containment isolation valve 1 FCV-31C-229 is located in the Unit 1 annulus and is an isolation valve for chilled water to the incore instrument room chiller. On July 14, 1997, this valve was stroked during the performance of an ASME Section XI test in accordance with 0-SI-SXV-31C-266.0, ASME Section XI Valve Testing, Revision 1 (hereafter referred to as SI-266). and 1-SI-SXV-000-201.0, Full Stroking of Category "A" and "B" Valves During Operation. Revision 0 (hereafter referred _to as SI-201). The valve was stroked three times.
For the three strokes -the valve remote position indicator did not indicate full closed and both the red and green indicator lights remained illuminated.
The valve was declared inoperable.
The valve was restroked a fourth time, and the remote position indicator lights indicated appropriately (the fourth valve stroke was not timed).
The valve was stroked an additional three times: these stroke times met the acceptance criteria, and the valve was declared operable.
The licensee wrote a PER which described-the sequence of events for the valve stroking and asked for the system engineer to review the past data and provide recommendations.
A Unit I log entry for 04:45 a.m., on July 14, 1997, stated " Entered LCO 3.6.3a due to 1-FCV-31C-229 has failed its stroke time test three times per 1-SI-SXV-000-201.0." A Unit 1 log entry at 04:55 a.m., on July 14, 1997.-stated, "Restroked 1-FCV-31C-229 three consecutive times and valve successfully passed each time.
Exited LC0 3.6.3a."
It should be noted that the Section XI code states, " valves which fail to exhibit-the required change of obturator position... be immediately declared inoperable" and " valves declared inoperable may be repaired, replaced, or the data may-be analyzed to determine the cause of the deviation and the. valve shown to be operating acceptably." The Section XI code does not allow multiple stroking of valves which do not exhibit the required change of obturator position and subsequently declaring the valve operable.
The-inspectors considered the failure to= maintain the status of the valve as " inoperable" to be a violation of 10 CFR 50.55a. which requires testing in accordance with ASME/ ANSI OMa-1988, Part 10.
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Inservice Testing of Valves in Light-Water Reactor Power Plants-(VIO 50-327/97-08-02).
SI-266, Section 3.0. Instructions. Step 7. requires the operat e to measure and record the stroke time, and includes a table with space for data for three valve strokes. Step 8 states, "IF First stroke time
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recorded in Step [7] DOES NOT meet the Acceptable Range Criteria, THEN
[a] REPEAT steps [6] and-[7] twice. [b] RECORD Date and Time testing completed." Section 5.0, Acceptance Criteria, of SI-266. questions if an acceptable stroke time was recorded on first stroke.
If the answer is "no," the user is directed to the Section 6.0 of the surveillance being performed (SI-201). Section 6.0 of SI-201 states, "IF valve stroke time exceeds Required Action Time, exhibits abnormal / erratic action, and/or valve indication system including Accident Monitoring Instrumentation _does not accurately reflect valve operation, THEN [a]
NOTIFY SR0 that valve is Inoperable for determination of system impact.
[b] INITIATE Test Deficiency Log entry.
[c] RETEST valve (s) following corrective action."
The inspectors considered the coordination between the two sis to be poor. The inspectors believe SI-266 could lead an operator to-stroke a valve three times before referencing the acceptance criteria in Section 6.0 of SI-201~
Also. Section 3.0 of SI-266 did not direct an operator
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to declare a valve inoperable if it failed to stroke on its first stroke.
The inspectors also considered that a flow chart included with the SI-201 procedure Figure 6.1, Valve Stroke Test Flow Chart, could-misdirect the operator. According to the flow chart, if the first valve stroke fell into the " Alert" range, the operator was directed to restroke the valve.
If the second valve stroke was also in the." Alert" range,:the operator was directed to restroke the valve a third time.
If the valve was in " Alert" on the second or third stroke, the operator was to notify Technical Support to assist in evaluation of valve status within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> and document as " Alert" and as a " Test Deficiency."
If the second or third valve stroke was acceptable, the valve was considered acceptable, and the operator was to document the first alert as a test deficiency. These actions meet the requirements of the Section XI code: however, the inspectors considered three points:
the-Section XI. code no longer includes an " Alert" range, the licensee's
" Alert" range acceptance criteria met the criteria for the code's
" Required Action" range (for this valve the acceptance criteria is the reference valve 50%). and the code does not address stroking a valve three times.
The inspectors also noted that SI-201 states, " Valve considered Operable in Alert Range."
The-inspectors noted that at 8:30 a.m.. on July 14, an oncoming SR0 reviewed the PER and questioned whether any additional actions were needed since the valve had already been declared operable. The SRO
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telephoned the: system engineer and discussed the multiple valve strokes with the system engineer, who identified that the valve should be declared inoperable. The SR0 then executed the LC0 Action Statements for the valve within minutes of the expiration of the LC0 Action Time (four hours).
Based on this review, and considering the valve was stroked seven times before being declared operable, the inspectors concluded that the operations staff involved with the testing lacked full understanding of the Section XI test program and of AMSE/ ANSI OMa-1988 code requirements.
Additionally, several recent problems have been identified with valve testing. Some examples have been documented in LER 50-327/96-12 and Inspection Report 97-06.
The inspectors also reviewed the licensee's planned corrective actions for this event.
These included revision of procedure to give more detailed guidance.for valves with stroke times outside the acceptable
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range and to include more detailed guidance for checking the proper operation of the status lights during stroke time tests (not complete).
c. -Conclusions One violation was identified for failure to meet code _ requirements during.Section XI valve testing.
Operations staff involved with-the Section XI valve testing for this-valve lacked full understanding of the Section XI test program and of AMSE/ ANSI OMa-1988 code requirements.
.II Maintenance
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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 0-S0-250-9 Technical Support Center Power System
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e 1-SI-Ors-082-007.S Electrical Power System Diesel Generator
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0-SI-0PS-092-078.0 Power Range Neutron Flux Channel Calibration By Heat Balance Comparison e-l-SI-SXP-074-201.B Residual Heat Removal 18-B Performance Test-e 0-SI-ICC-052-075-0 Calibration of Kinemetrics SMP-1 Playback-
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Unit Triaxial Accelerometer SMA-3 and Strong Motion Accelerometer SMA-2 e
0-SI-0PS-068-137.0-Reactor Coolant System Water' Inventory e
WO No. 97-004550-001-Install Hypochlorite Injection Piping Inside ERCW Pump Station e-WO No. 97-004550-005 Replace ERCW Strainer Shaft With Ceramic Coated Shaft e
WR# C3456861 0-VLV-067-07438 -ERCW Pump Discharge e
0-SI-SXP-067-202.B ERCW Traveling Screen Wash Pump B-B Performance Test-e 0-SI-SXP-067-202.C ERCW Traveling Screen Wash Pump C-8 Performance Test
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e 1-SI-SXP-003-201.S-Turbine Driven Auxiliary Feed Water Pump 1A-S Performance Test
1-PI-0PS-062-040.0 Charging Pump Suction. Piping Vent e
1-SI-0PS-067-033.B ERCW Valves Servicing Train B Safety Related Equipment e
SOA210 (C.1) System Operability Checklist
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e-0-SI-0PS-082-007 W AC Electrical Power Source Operability Verification-
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e 2-SI-0PS-082-007.A Electrical Power System Diesel Generator 2A-A e
2-SI-SXP-003-201.A Motor Driven Auxiliary Feed Water Pump 2A-A Performance Test e
1-H0-97-1742 TSC Inverter
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o 0 H0-97-2440 Auxiliary Air Compressor o
TS-32-91 Auxiliary Air Compressor B-B High Air Temperature o
MI-13.1.22 Setpoint Verification and Calibration of Auxiliary Control Air Compressor A-A and B-B Air Dryer Cycle Timers e
RCI-5 Calibration of the Eberline Personnel Contamination Monitor (PCM-18)
e 1-PI-ICC-062-238.0 Calibration of Boric Acid Tank A Level loop 1-L-62-238 (L-102)
e 0-50 82-2 Diesel Generator 1B-B e
SI-102 Diesel Generator Monthly Mechanical Inspections e
MI-4.2.3 Monthly Preventive Maintenance of Diesel Engines e
1-SI-0PS-082-007.B Electrical Power System Diesel Generator 1B-B b.
Observations and Findinas The inspectors noted that the work activities and the performance of surveillance activities were adequately performed.
The inspectors observed the conduct of MI-4.2.3. Monthly Preventive Maintenance of Diesel Engines, where a problem was identified with the failure of 1-MTRD-082-0059/2. Train B Diesel 1B2125 V DC Fuel Oil Priming Motor.
This fuel oil motor and pump serves as a backup to the engine driven fuel oil pump and is not required for EDG operability.
The licensee
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initiated WR No. C360449 to troubleshoot the control circuit to determine why the DC fuel oil priming motor would not start.
The inspectors observed that troubleshooting activities were well
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controlled, and resulted in the identification of a blown fuse.
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licensee replaced the fuse, and completed the maintenance instruction.
After completion of maintenance activities, the inspectors observed the conduct of 1-SI-0PS-082-007.B. Electrical Power System Diesel Generator 1B-B, Revision 11, which was completed without any problems.
M2 Maintenance and Material Condition of Facilities and Equipment M1,2 Unit 1 Trio Due to Loss of Control Air a,
Insoection Scooe (62707 and 40500)
The inspectors reviewed an event, initiated by a loss of control air, which resulted in a Unit 1 trip and a Unit 2 turbine runback.
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Observations and Findinas On August 1. 1997, at 7:38 p.m., Unit 1 operators initiated a manual reactor trip from approximately 62% power and Unit 2 experienced a turbine runback to 80% turbine load when station control air pressure was significantly reduced (decreased from a normal value of approximately 100 psig to 50 psig).
Prior to the manual trip, Unit 1 also experienced a runback to 62% turbine loao due to low control air pressure. The licensee is investigating why the runback continued beyond the runback setpoint of 80% turbine load. With the exception of the Unit I runback, both units responded to the event as expected.
The event was initiated by a control air leak which developed when maintenance workers cut into a 6" diameter control air header pipe in order to install an additional valve on the discharge of the C air compressor. The installation of the new valve was part of a modification to replace the C & D air compressors with more reliable compressors. A clearance boundary had been established which isolated the C & D compressors from the remainder of the control air system so that the new valve could be installed.
Unknown to the maintenance workers, the header being cut was pressurized due to a leaking clearance boundary valve.
Prior to the trip / runback, operators received a control air header low pressure alarm which was followed by an automatic isolation of the
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service air and auxiliary (essential) control air systems from the control air system.
The loss of control air caused numerous secondary plant valves to stroke to their fail safe positions which resulted in the perturbation of feedwater system flow, decreased steam generator levels and initiation of a turbine runback due to high level in the number 3 heater drain tank. Safety related systems were unaffected by the loss of station-control air. Operators were dispatched to the-control' air compressors and manually closed another valve, downstream of the valve which was leaking through, and thus isolated the control air leakage.
Following the event. -the _ licensee discovered a significant accumulation of rust in the seat of the leaking header isolation valve which had prevented.the valve from being fully closed.
This valve had_been previously identified as needing repair / replacement, but the work request had been deferred until 1998.
A drain. valve on the C compressor aftercooler, which had been-used to vent the isolated header prior to cutting the pipe.-was also found to be partially obstructed with an accumulation of rust. A moisture trap on the aftercooler would have been used for this venting, but the trap was known to be inoperable and the bypass around the moisture trap was known to be obstructed (a work request had been written on the bypass valve three weeks earlier).
Operators attempted to vent the header prior to cutting the pipe.-but only a small quantity of air and water was vented.
Operators questioned the adequacy of the venting, but concluded that the header was depressurized.-
The-licensee initiated PER No. SQ971825PER which subsequently concluded that poor material condition in the control air and service air system was a cause of this event. The PER further stated that significant contributing factors were that plant. personnel had accepted poor material conditions and that plant programs had weaknesses that failed to address long-standing material conditions in the control and service air systems.
It should be noted that in October, 1992, a similar event, documented in IR 501327, 328/92-34, occurred due to water intrusion in the-control. air system.
Repairs were made to the control = air system and Unit I was restarted and achieved criticality on August 2. 1997. Mode I was entered on August 3
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and 100% power was reached on August 4.
Unit 2 returned to 100% power on August 2 following stabilization of the control air system.
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Conclusions A negative observation was noted in that the loss of control air event i
and reactor trip was caused by poor material condition in the control l
air system which resulted in specific isolation, drain and vent valves
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not performing their intended functions.
III. Enaineering E2 Engineering Support of Facilities and Equipment E2.1 Corrective Action Proaram (40500)
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Insoection Scooe The inspector reviewed corrective actions developed and implemented for selected Problem Evaluation Reports (PERs) in order to evaluate the adequacy of the licensee's root cause analysis for equipment failures.
The following attributes of the developed corrective action plans were evaluated:
Determination of immediate cause of equipment failure
Determination of the repetitiveness of the equipment failure
Evaluation of licensee's identified root causes
Assessment of tne corrective actions for effectiveness, timeliness, and comprehensiveness b.
Observations and Findinas PER No SO970891PER Steam Dumo Valves Recetitive Packina Leaks This PER documented repetitive packing leaks on the steam dump valves.
The valves were packed using an Electric Power Research Institute (Eh<I)
configuration which used composite and graphoil packing rings.
TVA was informed by the valve vendor. Copes Vulcan. that composite rings were unacceptable for this application because of the stem's side loading on the valve.
This issue had already been identified by the EPRI Packing program and efforts had been underway to correct this problem.
Corrective actions developed and implemented for all Unit 1 and select l
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Unit 2 valves used braided packing in lieu of the composite rings. The inspector reviewed Work Order No. 96-041600-000 and determined that the
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valves _ had been repacked with the braided EPRI configuration per procedure 0 MI-MVV-000-029.0. Attachment J.3.
The remaining Unit 2 steam dump valves will have work requests written to have them repacked using braided packing during Unit 2 cycle 8 refueling outage.
The inspector concluded that the licensee's corrective actions for leaking steam dump valves were in accordance with accepted industry practice.
PER No. S0971584PER. MacCanna Valves Diaohraam Failures This PER documented the results of an evaluation of generic trend-information which indicated that problems existed with Hills /MacCanna valves.
These valves used primarily in the condensate demineralize system had experienced 13 failures in the past twenty four months. The licensee performed a root cause analysis of the valve failures. and determined that the common cause for the majority of failures was failure-of the diaphragm.
The licensee's experience with these valves demonstrated that repeated flexing of the diaphragm _as the valve is stroked causes the diaphragm to crack.
The preventive maintenance program does not provide for periodic replacement of the diaphragms. Additionally the vendor's manual for these valves does not establish any requirements for. periodic-replacement of the diaphragms. TVA requested recommendations from the vendor concerning this-issue.
The vendor's advice was that the diaphragms should be replaced on a frequency depending on the operating time of the valve and the process fluid environment to which the valve is exposed.
Based on discussions with the. vendor and-the primary _
failure mode of the valves the licensee has developed the following proposed corrective actions:
The System Engineer to identify those valves in the Condensate-e Demineralize system that are critical to maintaining water quality to the steam generator and submit revisions to the PM program for periodic replacement of these valves diaphragms.
Maintenance Planning to develop new PM packages based on input
from the System Engineer.
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The inspector discussed the corrective actions described above with the system engineer and reviewed the following documents in order to datermine the basis for selection of the valves listed in Table 2.
l Conderisate Demineralize Key Valve Determination. Preliminary Evaluation:
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FSAR Section 10.4.6 Condensate Polishing Demineralize System
Mechanical Flow Diagrams drawing series CCD 1.2-47W838-1 through 7
Based on the above discussions the inspector concluded that the licensee had identified the root cause and contributing cause for the valves failure. An extent of condition review had been performed with the specific objective of identifying those valves whose performance was critical to maintaining specified water chemistry requirements to the steam generators. The list of valves on Table 2 documented the results of this review.
Preliminary information concerning the frequency for replacing the valves diaphragms was also listed on Table 2.
Additional investigations will be performed by the system engineer in order to establish a quantitative basis for replacing the diaphragms based on the number of valve operation within a specified time.
The PM program will be revised accordingly as more accurate information becomes available from this investigation.
PER No. S0970251 PER. Heat Trace System Placed in (a)(1) Status Freezing of the Essential Raw Cooling Water (ERCW) screen wash pumps sensing lines and ERCW pump discharge sensing lines occurred in January of 1997.
Based on this event the licenses determined that the Maintenance Rule performance value had been exceeded and a repetitive preventable functional failure was encountered as a result of the failures of several heat trace circuits. Additionally, two functional
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failures were found that were not initially counted on the Cause Determination Evaluation Form (CDEF).
PER No. SO970251PER was written to place the heat trace system in (a)(1) status because of these freezing events.
An extent of condition review was performed to specifically identify those systems that were within the scope of the Maintenance Rule for which freeze protection was required.
The licensee also performed a root cause analysis for the failures at the ERCW pumps using Failure Mode And Effects Analysis.
Various failure modes and the refuting / supporting evidence for each failure mode was identified by the
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licensee. Contributing failure modes and the root causes for the failures included the following:
i Inadequate design
Inadequate maintenance procedure
Inadequate training of personnel working on heat trace to ensure
insulation is properly installed.
The licensee also determined that the root cause for incorrectly e
identifying all of the initial heat trace functional failures was because all the Maintenance Rule heat trace circuits had not been clearly identified and correctly grouped in a plant procedure.
An evaluation of the root and apparent causes for previous failures of the ERCW system heat trace circuits was performed.
Based on the results of this evaluation the licensee concluded that the root cause of the repeat failures that caused the system to go to a (a)(1) status was ineffective
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development and corrective action for previous PERs.
The corrective actions for PER No. S0970251PER provided seventeen action items to address all the root causes and ensure adequate recurrence control. The inspector reviewed the developed corrective actions and concluded that the corrective actions were consistent with the identified root causes and was sufficiently broad in scope to provide recurrence control for the identified deficiencies.
PER No. SO970203PER. Fire Protection Ecuioment Recetitive Failures This PER documented repetitive failures of components in Fire Protection Console 0-CPU-013-0300 over a 24-month period. The licensee determined the reason for the failures of several major components of the Pyrotronics System to be caused by the equipment having become obsolete with no replacement parts being available.
Hardware problems associated with the Pyrotronics multi-alarm VI console were dispositioned " Accept-as-Is" with a justification provided in accordance with the requirements of procedure SSP-3.4. Corrective Action. Revision 22.
The inspector reviewed the justification for the " Accept-as-Is" disposition of the fire protection deficiencies along with proposed long term corrective actions.
Based on this review the inspector determined that Project PCN0932. Fire Detection System Upgrade, had been funded for fiscal year 1999 and 2000 to replace the existing system with the latest l
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fire detection system technology.
Compensatory measures implemtated until the system has been upgraded to correct diskette failures were considered adequate. Additionally, the results of an analysis performed by the licensee to determine if a loss of fire detection capability had ever occurred, because of hardware deficiencies demonstrated that equipment design redundancy provided reasonable assurance for detection of fires.
The inspector concluded that corrective actions completed for PER No. SO970203PER were technically adequate and complied with the requirements of the corrective action program.
PER No. 9/1321PER Auxiliary Feedwater (AFW) Level Control Valves On May 4. 1997, three current to pneumatic (1/P) converters used in connection with the AFW level control valves were found to be out of tolerance after having been calibrated one week earlier.
The PER documented numerous problems with I/P converters used with Masonelian and Fisher valves and recommended that the I/P converters be replaced.
The licensee performed a root cause analysis using Event and Causal Factor Analysis methodology and determined that the root cause of the repeatability problem of the I/P converters was equipment misapplication.
Contributing factors to this problem were identified as (1) AFW level control valves (LCVs) application had approached the limits of the valve design with respect to valve leakage and valve stroking: (2) the AFW pump discharge pressure being greater than the valve design rating exacerbates leakage problems: (3) rep'.dcement electro-pneumatic transducers were not reliable and (4) ABB AirCEt diagnostic test equipmer las not used in the valve setup and calibration.
The following corrective actions were developed for resolution of the 1/P converters reliability problem:
Evaluate the availability of spare I/P converters and valve
positioners prior to outage calibration, Re-evaluate the design of the AFW LCVs based on (1) Watts Bar o
performance: (2) manufacturer's upgrade to valve positioners and/or I/P converters: (3) industry experience and (4) required function of the equipment to meet operating and accident functions.
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Re-evaluate the use of the ABB AirCEt diagnostic tool for setup e
l and calibration of AFW LCVs as a requirement every outage.
l The inspector reviewed the "Sequoyah UIC7 Air Operated Valve Diagnostic
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Test Results-ABB AirCEt" report dated November 17, 1995, and conducted interviews with licensee's personnel concerning the use of this test equipment.
The inspector concluded that use of this diagnostic tool will improve the reliability and performance of the AFW LCVs, Additionally, the inspector concluded that the licensee had performed an adequate root cause analysis and extent of condition review for this PER, Corrective actions proposed for resolution of the I/P converters reliability problems were considered sufficiently broad in scope to provide adequate recurrence control for the identified deficiencies.
PER No. SO962603PER Revision of Essential Circuit Interaction Calculations This PER was written to document a concern that essential circuit interaction calculation had not been adequately maintained.
Additionally, training on how to prepare and maintain these calculations in accordance with the requirements of procedure CE-E-TI-31, Generic Category C Failure Analysis, Revision 0, had not been maintained.
The following essential circuit interaction calculations were identified as having lost configuration control because of this deficiency:
SON-CLS-014 e
SON-E3-001 The proposed corrective action for resolution of the above was to revise the two calculations to document that they will not be maintained under configuration control.
Tha following documents the results of the inspector's review in order to verify that the licensee's actions were in compliance with the approved design control program.
NUREG-0588, Interim staff Position on Environmental Qualification of Safety Related Electric Equipment, Appendix E. Section 2 requires the licensee to categorize all Class 1E equipment into one of four categories, ie., category a, b, c, or d.
Regulatory Guide 1,89.
Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants. Appendix E, also reiterates this requirement in order to ensure that the Environmental Qualification l
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program conforms to General Design Criteria 1.2.4.and 23 of Appendix A:
Sections 111. XI, and XVil of Appendix B: and 10 CFR 50.49.
Category C equipment is defined as equipment that will experience environmental conditions of design basis accidents through which it will not need to function to mitigate said accidents. Additionally, failure of Category C equipment in any mode is not detrimental to plant safety or accident mitigation and need not be qualified for any accident environment, but will be qualified for its non-accident service environment.
Pursuant to establishing categories for all Class 1E equipment the licensee performed an analysis of the interactions of NUREG-0588 Category A. B. or D devices with category C devices for determining the effects of Category C devices failure on the integrity of the 10 CFR 50.49 Class 1E electric circuits to provide power for completing required safety functions. Every failure mode for each Category C device was evaluated against the required safety functions and determined if it was acceptable.
If the result of the evaluation was determined to be unacceptable the device would either be upgraded to Category B or be electrically isolated.
Design changes that affect, add. or delete equipment which is addressed in a 10 CFR 50.49 category and operating time calculation are required to.e evaluated for 10 CFR 50.49 requirements and the changes implemente through the ANSI N45.2.11-1974 design control program.
The inspector verified that plant procedure SSP-9.3. Plant Modification and Design Change Control. Appendix K.10 CFR 50.49 Environmental Qualification, requires design changes to be reviewed for its effects on 10 CFR 50.49 category and operating time calculations.
The baseline circuit interaction analysis initially performed for categorizing the Class 1E electrical equipment does not require revision per the ANSI N45.2.11-1974 design control program.
Corrective actions involving training requirements for procedure CE-E-TI-31 will be added to the training list for personnel in the Electrical Engineering section at SONP. This corrective action is scheduled for completion on August 25, 1997. The inspector concluded that the licensee's corrective actions for PER No. SO962603PER was technically adequate and complied with the requirements of the corrective action program.
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Qualitative improvements in root cause analyses performed by the licensee-were observed.
Root cause analyses were performed using methodologies involving Events and Causal Factors and Failure Mode and Effects Analysis. Corrective action plans developed from these methodologies were sufficiently broad in scope to provide reasonable assurance for recurrence control of the primary root causes and contributing root causes.
Problem Evaluation Reports were being dispositioned in accordance with the requirements of the corrective action program and 10 CFR 50 Appendix B. Criterion 16.
E8 Miscellaneous Engineering Issues (92902)
E8.1 Revision 12 to the Uodated Final Safety Analysis Reoort a.
Insoection Scoce (37001)
Revision 12 to the Sequoyah UFSAR was issued on December 6, 1996.
The scope of this inspection was to review the licensee's procedures and-controls to implement 10 CFR 50.59, " Changes. Tests, and Experiments,"
and-to review the 10 CFR 50.59 evaluations performed by the licensee for the UFSAR changes and deletions contained in Revision 12.
b.
Observations and Findinas Former Procedure SSP-4.2,=" Management =of the Final Safety Analysis Report," was superseded on May 27, 1997, by TVAN Standard Department Procedure NAPD-7, Revision 0. "FSAR r.anagement," This new procedure standardized the process for all three-TVA Nuclear sites and made improvements in the readability of the UFSAR management process.
It also expanded the definitions section to include administrative changes, living UFSAR, and nonsignificant UFSAR changes.
The new procedure also added a flow chart for the UFSAR process and revised the UFSAR Change Request Form.
Former Procedure SSP-12.13. "10 CFR 50.59 Evaluations of Changes. Tests and Experiments," and TVAN STD-12.13 (same title) were superseded on June 30, 1997. by TVAN Procedure SPP-9.4, Revision 0 (same title). This
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new procedure standardized the process for all three TVAN sites and made improvements in the 10 CFR 50.59 process. The procedure provides for safety assessments, screening reviews, and safety evaluations and has a very complete definitions section. The procedure has incorporated much
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of the guidance contained in NSAC-125. " Guidelines for 10 CFR 50.59 Safety Evaluation."
The inspector reviewed UFSAR Change Request 12-90.
This change removed l
Table 3.5.2.1 Sheets 2 and 3, which listed missile characteristics for various types of small valves, reactor coolant system temperature detector elements (RTDs) and wells, and pressurizer heater elements.
Changes were also made to Sections 3.5.2.2. 3.5.2.3, and 3.5.2.4.
An engineering evaluation (stress calculations). Calculation SOEP-C2-120.
Revision 1. dated October 13. 1996. determined that these components were not credible missiles and therefore the information pertaining to them could be removed from the UFSAR.
The engineering calculation was reviewed and found to be thorough and included excerpts from three Westinghouse pressurizer stress reports.
In all cases, the actual stresses were shown to be well below allowable stresses.
On the basis of the conclusions in SOEP-C2-120, portions of Table 3.5.2.1 pertaining to small valves. RTDs and wells, and pressurizer heater elements valves were removed from the UFSAR.
NUREG-0011. the NRC staff safety evaluation that supported the operating license for Sequoyah. Section 3.5.1. " Missile Selection and Description." states the following:
"The applicant has confirmed that potential missile sources inside containment and potential missile paths are considered in the design.... These include retaining bolts.
control rod drive assemblies, valve bonnets, and valve stems."
Removing the above items from the UFSAR list of credible missiles could be construed to be a change to the plant's design basis, which was reviewed at the time of licensing: and it was not clear whether this-change could be appropriately made under 10 CFR 50.59.
For example, a missile shield in place at the time of licensing could now be removed because the shields are no longer required by the design basis.
Because the staff has not finalized guidelines for removal of information from the UFSAR. this change is identified as inspector followup item (IFI 50-327, 328/97-08-03). Removal of UFSAR Information.
The inspector reviewed UFSAR Change Request 12-68.
This change removed the lithium vs. boron curve (Figure 5.2.3-1) from the UFSAR.
The
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justification for removal was that two different/ boron schemes are now used; one for normal operation and one for rapid planned shutdowns.
These schemes are more properly contained in site operating procedures.
The safety assessment was complete and correct except Item E (effects on information in the UFSAR) on the safety assessment format was initially
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checked "NO" and later changed to "YES."
However, the justification was not changed and still supported a "N0" answer.
The inspector reviewed UFSAR Change Request 12-58.
This change removed the maximum allowable reactor coolant pump vibration limits from the UFSAR on the basis that "the vibration limits specified in Section 5.5.1.2 provide more details than necessary.....do not agree with vendor recommended values specified in Tech Bulletin NSD-TB-75-3." The maximum values specified in the referenced Westinghouse bulletin are 0.020 inches (compared to 0.013 inches in the UFSAR) for the pump shaft and 0.005 inches (compared to 0.003 inches in the UFSAR) for the pump frame.
The safety assessment for UFSAR Change Request 12-58 states "the allowable maximum limits included in this description constitute a level of detail that is not necessary.
The FSAR is being revised to delete these allowable maximum limits" and "therefore, it is prudent, to avoid additional FSAR changes, that this information be deleted from the FSAR."
It is not clear why the maximum allowable vibration limits recommended by the vendor were not placed in the UFSAR. in place of the previous limits, rather than removing the limits from the UFSAR completely. The safety evaluation makes the statement "using the manufacturer's recommended vibration will not increase the probability of a malfunction of the Reactor Coolant Pump." but there is no technical discussion to substantiate that conclusion.
Because the staff has not finalized guidelines for removal of information from the UFSAR. this change is included as another example of inspector followup item (IFI 50-327, 328/97-08-03).
The inspector reviewed UFSAR Change Request 12-40. This change removed Tabla 6.2.4-1. " Containment Penetrations." from the UFSAR. This table consisted of 157 pages containing design information and associated piping system diagrams for all containment penetrations.
The justification for removal of this information is that the information is contained in design output system description N2-88-400 and that removing the table from the UFSAR would avoid conflicts between the two documents. Although not apparently required in the UFSAR at the time of licensing Sequoyah. Section 6.2.4 of the current Standard Review Plan i
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(NUREG-0800) requires this type of information to be in the UFSAR.
Although Sequoyah is not committed to Regulatory Guide 1.70. " Standard Content and Format of Safety Analysis Reports for Nuclear Power Plants."
a table such as Table 6.2.41 is specified in that regulatory guide, The safety assessment states that this table was placed in the UFSAR in Amendment 7 (April 1990) and did not exist there at the time of licensing.
It was not clear why it was placed in the UFSAR at that time. However, there was a commitment in a TVA letter dated January 12, 1987, to incorporate certain containment penetration design information into Table 6.2.4-1 in the next UFSAR update. The SA/SE makes no other justification, other than that stated above, as to why it is acceptable to remove the table from the UFSAR.
Because the staff has not finalized guidelines for removal of information from the UFSAR, this change is included as another example of inspector followup item (IFI 50-327, 328/97-08-03).
The inspector reviewed UFSAR Change Request 12-48. This change revised the parameters associated with the containment accident pressure analysis to reflect a containment transient pressure reanalysis by Westinghouse assuming 11% of the containment spray heat exchanger tubes were plugged.
Peak pressure was calculated to be 11.04 psig compared to the previous 10.9 psig.
This change was found to be acceptable.
The inspector reviewed UFSAR Change Request 12-125. This change revised the minimum pressure at which the accumulators are maintained, apparently because of a design change in the check valve type used.
The change also corrected some typographical errors and made some clarifications. The " Request for SAR Change" Form (Appendix A) said "See attached" on the " Explain" line, but all that was attached were the marked up UFSAR pages.
The information provided to the inspector contained no explanation or justification for the change.
The inspector also reviewed UFSAR Change Requests12-128, 12-3. 12-79.
and 12-74.
These changes dealt with various plant modifications, including reduction of boron concentration in portions of the Chemical and Volume Control System and removal of the pump and valve inservice testing program in accordance with Generic Letter 89-04.
These change request _ packages were complete and the safety evaluations were very well written.
The inspector noted that the quality of Change Request 12-128 was excellent.
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Conclusions A positive observation was noted that the licensee has taken the initiative to improve the corporate safety assessment procedure for 10 CFR 50.59 evaluations and make it applicable at all three TVA Nuclear plant sites.
An inspector-followup item was identified related to the acceptability of removing information from the UFSAR for reasons other than actual changes to the facility or procedures. The NRC staff is presently developing guidance in this area.
A positive oM ervation was noted that although minor omissions were noted in some UFSAR change packages, the more significant changes were generally complete and very well written.
A negative observation was noted that in some cases. safety assessments and safety evaluations documented statements such as "the change
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involves no increase in the probability of an accident,." but provided no technical discussion or justification of why the statement was true.
E8.2--(Closed) Violation 50-327.328/96-16-06, Inadequate Design Control for Rod Control System Plant Modification
.The licensee's letter dated February 12, 1997, stated that Unit 2_ design package was revised to clarify information regarding the importance of
- periodic testing:on eliminating potential failure modes. TVA described additional-commitments in their letter dated June 10, 1996, where they.
comitted to' revise the procedure used _for performing coil current tests.. This revision would incorporate the requirements for also perfo_rming slave cycle current order tests. The inspector reviewed
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plant procedures 2-PI-SFT-085-001.0, Revision 1 -and 1-PI-SFT-085-001.0, Revision 2, Functional Test of Control Rod Drive Mechanism and Slave Cycle Decoder, and verified that licensee's commitments NC0960038001 and NC0930229004 had been completed.
Additional corrective actions delineated in the licensee's letter dated February _12, 1997, concerning lessons learned training for Nuclear Engineering and communications with Westinghouse were verified to have been completed by review of the following documents:
e Training Session Reference: Lessons Learned from NRC Communication Letter on GL 93-04 l
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e TVA memorandum dated February 3.1997 from H. Burzynski to-M. Lorek and C. Butcher. Re: Recent NRC Violation on Rod Control System Plant Modification.
TVA letter dated February 4.1997. from M. Burzynski. Engineering e
and Materials Manager to Mr. John W. Irons. Manager TVA Projects.
Westinghouse Electric Corporation, TVA memorandum dated February 5. 1997. from M, Burzynski to e
R. Shell. Re: Recent NRC Violation on Rod Control System Modification (S0960677PER).
Training and Development Attendance Records: Title of Course e-Activity-NRC Violation on Rod Control System Modification dated February 2. 1997.
The inspector concluded that the licensee had determined the full extent of the violation, taken action to correct current conditions, and developed corrective actions needed to preclude recurrence of similar problems, Corrective actions stated in the licensee's response have been implemented.
.(Closed) URI 50-327.328/97-02-01. Installation of Non 0A Material for QA-Material The licensee's augmented Quality Assurance Program defines seismic category 1L i_tems as non-quality related structures, systems and components whose failure during or following a design basis earthquake could jeopardize-the ability of seismic category 1 items to perform-their safety function. UFSAR. Section 3.2.2.6. Non-nuclear Safety Class (NNS). states that components whose failure would not result in a release of radioactive products and are not required to function during an accident or malfunction within the reactor coolant pressure boundary have been assigned classifications that range from Class E through Class V.
These components complement safety related components and are within close proximity to them.
They are therefore designed to code requirenents that assure the integrity of the systems such that the minimum capability of safety components will not be compromised. These components are designated as either seismic category 1(L)A-pressure boundary retention or-seismic category 1(L)B-position retention.
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The inspector verified that the condenser cooling water piping system is classified as TVA class H piping. seismic category 1(L)B position retention only. The inspector also reviewed procedure SSP-3.2.
Augmented QA Program, Appendix 1. Section 4.A.d. Procurement Document Control, and verified that items and/or equipment requiring position only retention mby be procured as non-0A (0A level 0).
The inspector concluded that materials installed under work requests C211641 and C325693 were assigned the correct GA classification and were procured in accordance with the requirements of the Augmented QA Program.
This item is closed based on objective evidence reviewed.
(Closed) IFI 50-327,328/96-16-05, FSAR Inconsistent Description of Reactor Power Level Offsite radiation doses contained in the SER Supplement No.1 Table 15-1. Radiological Consequences of Design Basis Accidents, were calculated by the NRC based on a reactor power level of 3582 MWt.
TVA in calculating the 10 CFR Part 100 offsite doses used a value of reactor thermal power of 3411 MWt.
Various other values for the reactor thermal power were contained in UFSAR Tables 15.1.2-1, 15.1.7-1. and all the tables in UFSAR section 15.5.
In response to the inspector's request for information regarding the different reactor power levels TVA provided a letter received from Westinghouse dated July 24, 1997 (TVA-97-078) which addressed this subject.
This letter provided a general explanation of the basis for the various reactor power levels in Chapter 15 of the FSAR.
Based on the explanation provided by Westinghouse this item is closed.
IV. Plant Suocort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Comments (71750)
The inspectors performed tours of the control building, auxiliary building, turbine building ERCW pump house and diesel generator buildings and did not identify any noteworthy deficiencies in housekeeping or radiological controls.
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F8 Hiscellaneous Fire Protection issues F8,1 _(Closed) 50 327,328/EA 97-092 01014.
Failure to Perform Hourly Fire Watch Patrols for Degraded Fire Protection Components.
This violation was identified during an investigation by the NRC Office of Investigation and was issued to the licensee by NRC's letter dated March 14. 1997.
TVA responded to this violation by letter dated June 9, 1997. This response provided additional information on the fire watch
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violation at Sequoyah and requested that the characterization of this violation be changed to a non-cited violation.-since the licensee identified the violation, took 1 mediate corrective action and reported the violation to the NRC, TVA's response also provided a description of the management oversight of the Sequoyah fire watch program, including:
the disciplinary action taken against the personnel who failed to perform required fire watch duties; an explanation of the reasons the bar code reader initially used to document the fire watch rounds was discontinued, a description of the scanner device currently being used to verify that the fire watch patrols were being properly performed: and the training provided for the fire watch personnel, Eased on NRC's evaluation of the licensee's response and information cbtained during an inspection performed in March 1997, that was documented by NRC Inspection Report 50-327, 328/97-03, this Severity level IV violation has been withdrawn and is now identified as non-cited violation NCV 50-327, 328/97-08-04, V, Manaaement Meetinas X1 Exit Heeting Summary The inspectors presented the inspection results _to members of licensee management at the conclusion of the inspection on September 4, 1997 (August'25, Section E8,2),
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.
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1 PARTIAL LIST OF PERSONS CONTACTED f
Licensee
- Bajestani, M., Site Vice President
- Burton, C,. Engineering and Support Systems Manager
- Butterworth, H., Operations Manager
- Fecht M.
Nuclear Assurance Manager
- Flippo, T., Site Support Manager
- Freeman, E. Maintenance and Modifications Manager
- Herron, J.,
Plant Manager
- Kent, C,, Radcon/ Chemistry Manager
- Koehl, D. Assistant Plant Manager
- Salas, P., Manager of Licensing and Industry Affairs
- Valente, J.,
Engineering & Materials Manager
- Attended exit interview INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 40500:
Effectiveness of Licensee Controls In Identifying, Resolving, &
Preventing Problems IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707:
Plant Operations IP 92902:
Followup - Engineering IP 92903:
Followup - Engineering ITEMS OPENED. CLOSED. AND DISCUSSED Opened Iype Item Number Status Descriotion and Reference URI 50-328/97-08-01 CPEN Potentially Inoperable AFD Monitor Alarm. (Section 02.1)
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V10 50 327/97-08 02 OPEN Failure To Meet ASME Section XI Code Testing Requirements. (Section 04.1)
IFl 50 327, 328/97-08 03 OPEN Removal Of Information From The UFSAR. (Section E8.1)
Closed lype item Number Status Descriotion and Reference l
NCV 50 327.328/97 08 04 OPEN/
Failure To Perform Hourly Fire Watch CLOSLO Patrols For Degraded Fire Protection Components. (Section F8.1)
VIO 50 327.328/EA WITHDRAWN Failure To Perform Hourly Fire Watch 97 092 01014 Patrols For Degraded Fire Protection Components. (Section F8.1)
V10 50 327.328/96-16 06 CLOSED Inadequate Design Control For Rod Control System Plant Modification.
(Section E8.2)
URI 50 327.328/97 02-01 CLOSED Installation Of Non 0A Material For 0A Material. (Section E8.1)
IFl 50-327.328/96-16 05 CLOSED FSAR Inconsistent Description Of Reactor Power Levei. (Section E8.1)