IR 05000327/1996017
ML20134P041 | |
Person / Time | |
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Site: | Sequoyah ![]() |
Issue date: | 02/14/1997 |
From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML20134P005 | List: |
References | |
50-327-96-17, 50-328-96-17, NUDOCS 9702250078 | |
Download: ML20134P041 (22) | |
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U.S. NUCLEAR REGULATORY COMISSION
REGION II
Docket Nos:
50-327, 50-328 License Nos:
50 327/96-17, 50-328/96-17 Licensee:
Tennessee Valley Authority (TVA)
Facility:
Sequoyah Nuclear Plant, Units 1 & 2 Location:
Sequoyah Access Road Hamilton County, TN 37379 Dates:
December 8, 1996 through January 18, 1997 Inspectors:
M. Shannon, Senior Resident Inspector-R. Starkey, Resident Inspector D. Seymour, Resident Inspector
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J. Coley, Jr., Reactor Inspector (Section M8.1)
G. Walton, Reactor Inspector (Section E8.2)
Approved by:
M. Lesser Chief Projects Branch 6 Division of Reactor Projects
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Enclosure 9702250078 970214 PDR ADOCK 05000327 G
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EXECUTIVE SUMARY Sequoyah Nuclear Plant, Units 1 & 2
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NRC Inspection Report (IR) 50 327/96 17, 50-328/96 17 This integrated inspection included aspects of licensee operations, 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.
In addition, it includes the results of announced inspections by regional reactor inspectors.
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Operations The conduct of operations during the inspection period was considered to e
be good (Section 01.1).
A weakness was noted in that neither operations nor engineering e
identified that the main steam lines and main steam drain lines were vibrating excessively and the main steam drain line supports were broken (Section M2.1).
A non cited violation was identified for failure to perform Section XI e
testing on two valves (four missed surveillance intervals). Operations improperly used the " test deficiency process" which resulted in not testing the valves (Section M4.1).
e A non cited violation was identified for failure to perform Section XI testing on 18 valves on February 26, 1996. Several reviews, with designated signature blocks, by planning, operations, and engineering of the completed surveillance package were performed, however, the reviews failed to identify the 18 missed valve stroke surveillances (Section
M4.1).
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Maintenance Work activities and the majority of surveillances were adequately e
performed (Section M1.1).
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Significant corrective actions were taken, or were in the process of being completed by the licensee, in the area of maintenance, for the
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deficiencies identified by the licensee in their March 5,1996, Reliability Study (Section M8.1).
A positive observation was noted in that the maintenance technicians
exercised good questioning attitudes regarding the improperly revised setpoint data in the Transmission Power Supply (TPS) Field Test Manual
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(FTM) (Section E2.1).
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A weakness was identified for failure to expedite resolution of heat e
l trace deficiencies in the emergency raw cooling water (ERCW) building
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j and subsequently having to rely on compensatory measures (Section E2.2).
A weakness was identified with the compensatory measures taken in the e
ERCW building due to the apparent freezing of the ERCW screen wash pressure sensing lines (Section E2.2).
Enaineerina A weakness was identified in the licensee's program for trending and e
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l tracking Section XI valve testing in that the program did not identify the missing surveillances (Section M4.1),
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A weakness was identified in that the TPS Field Test Manual was
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inaccurately revised and afte questioning by on site maintenance technicians, engineering inappropriately directed the use of the inaccurate calibration data. This resulted in the tripping of the switchyard intertie transformer (Section E2.1).
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e A weakness was identified in that engineering had not responded to an overdue freeze protection program corrective action item and had not requested an extension for the overdue item (Section E2.2).
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A positive observation was identified for the licensee's initiative to perform an independent review of the steam dump system and to develop corrective actions (Section E7.1).
l Plant Sucoort l
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A non cited violation was identified for an inadequate procedure for l
performing a chemical addition to the reactor coolant system, which
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resulted in a personnel contamination event (Section R1.1).
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l A non cited violation was identified for inapproariately blocking of e
l containment isolation sample valve control switcles which would have l
prevented automatic closure following a solid-state protection system (SSPS) containment isolation actuation signal (Section R1.2).
The licensee's initiative to decontaminate the charging pump skids was e
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considered to be a positive observation (Section R1.3).
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i Report Details
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Summary of Plant Status Unit 1 began the inspection period at 100% and remained at 100% power through December 18. Power was reduced to 90% on the 18th in order to troubleshoot the 1A mainfeed pump electrohydraulic control circuitry.
Power was returned
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to 100% later on the 18th and the unit operated at 100% through the end of the
inspection period, except for a minor down power on Jan 10 due to a feedwater heater problem, i
Unit 2 was tied to the grid on December 8. following the December 6 reactor trip, and continued to operate at 100% power through the end of the inspection period.
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I. Operations
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707 the inspectors conducted frequent
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reviews of ongoing plant operations. The inspectors observed control-room activities during the Unit 2 startup and the subsequent steady
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state conditions experienced during this inspection period.
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addition, the inspector observed control room activities associated with i
the Unit 1 3% downpower associated with a closed instrument air isolation valve to the #7 heater drain tank normal level control valve.
In general, the conduct of operations during the inspection period was considered to be good.
Shift turnover briefings were considered to be a)propriate.
Pre activity and post activity briefings associated with
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t1e reactor trip breaker surveillance testing on January 18, 1997, were ansidered to be good. Other operations related observations are stailed v.) the various sections of this report.
Operational Status of Facilities and Equipment 02.1 Unit 1 Downoower to 97%
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Insoection Scope (71707)
The inspector observed control room activities in response to a Unit 1 reduction in power to approximately 97%, in response to a closed instrument air isolation valve to the #7 heater drain tank normal level control valve. The inspector also reviewed the problem evaluation report for this activity, and discussed this activity with operation *
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b.
Observations and Findinas On January 10, the Unit 1 operators received an alarm for low net positive suction pressure to the main feed pumps. Condensate flow was noted to be high and the #7 heater drain tank flow was decreasing. The operators entered Abnormal Operating Procedure S.01, Loss of Normal Feedwater, and began to decrease load. The alarm cleared and reannunciated. At this point, the o (bypass level control valve for the #perators observed that 1 LCV 2-190B 7 heater drain tank) had opened, and the 1 LCV-6-190A (normal level control valve for the #7 heater drain
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tank) had closed. A system walkdown noted that the instrument air I
su) ply valve for the level control valve was found closed.
It was su)sequently reo)ened. The licensee determined the most likely cause of the closure of t1e 1 LCV 6-190A was inadvertent closure of the instrument air isolation valve when a welding lead was dragged across it. Plant load was subsequently increased to return the unit to 100%
power.
In addition to this condition, earlier on January 10, plant personnel had identified a broken air supply line for the Unit 1 heater drain tank high level dump valve. The line was temporarily repaired. Due to the two abnormal conditions, the licensee initiated a " stand down" of work activities and briefed workers on expectations concerning work in the area.
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Conclusions The inadvertent closing of the air supply line to a feedwater level control valve during maintenance activities which resulted in a subsequent plant pertabation is considered to be a negative observation.
Response by control room operators was appropriate.
Miscellaneous Operations Issues a.
Insoection Scope (71707)
The inspector reviewed the most recent Institute of Nuclear Plant
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Operations (INP0) evaluation as required by inspection procedure 71707.
b.
Findinas and Observations The inspector completed a review of the most recent INP0 evaluation, l
dated December 19, 1996. At this time, additional regional follow-up is not planned and is not considered to be necessary. The review noted that the INP0 re> ort findings were consistent with the last SALP report, in addition to t1e inspection findings in the last several resident inspector integrated reports. A summary of the INP0 report, including findings with examples, was discussed with Region II management on January 10, 1997.
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II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Inspection Scope (61726 & 62707)
l The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:
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e 0 SI-SXP 067-201.K Essential Raw Cooling Water Pump K A Performance
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Test, Revision 0
e 0 SI-SXP 067 201.0 Essential Raw Cooling Water Pump Q A Performance Test, Revision 0 e 0-SI-SXP 067 201.R Essential Raw Cooling Water Pump R A Performance
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l Test, Revision 0 e 0-S0-67-3 ERCW Strainers and Traveling Screens. Revision 3 e 2-SI-SXP-072-201.B Containment Spray Pump 2B B Performance Test, Revision 1 e 2 SI-SXV 072-215.B Closure Test of Containment Spray Check Valve 2-l 72 507 Revision 0 l'
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Observations and Findinas The inspectors noted that the work activities and the majority of
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surveillance activities were adequately performed.
Identified
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l surveillance deficiencies are documented in Section M4.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Broken Main Steam Line Drain Sucoort Struts a.
Inspection Scope (627071
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l The inspectors performed routine walkdowns of secondary plant systems in order to identify proper operation of equipment important to safety and to identify any safety concerns.
b.
Observations and Findinas During a walkdown of the main steam lines in the turbine building, the
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inspectors noted more than usual movement of the main steam lines.
In addition, the inspectors noted significant movement of the main steam t
line drains. The vibration of the drain lines was areviously noted in Inspection Report (IR) 96-12 and has been observed )y the inspectors
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since July 1996.
Movement of the drain lines appeared to have 1-
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increased; therefore, the inspectors performed a detailed walkdown of the system.
During the walkdown, the inspectors noted that three support struts (rodded pi)ing supports) were broken. This finding was
immediately reported to t1e control room and a work request and problem evaluation report were initiated. The struts were replaced within a few hours and civil engineering personnel were directed by plant management to review the adequacy of the system supports.
l The inspectors noted that operations personnel had not identified the i
excessive vibration of the main steam line drain system or the broken i
struts.
In addition, the system engineer had not identified the
excessive vibration. The inspectors noted that with the struts missing, the main steam line drains were only supported by the piping connected i
l to the main steam lines and two downstream system struts. Also, the i
vibrations a]peared to be significant enough to eventually cause fatigue failure of t1e drain piping.- Further analysis of the affected drain line to main steam line piping appeared to be warranted.
Discussions with engineering indicated that the main steam line vibration was well within the ;esign of the system. However, due to the
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l broken struts on the main stream line drain piping, engineerir.g was l
evaluating a design change to re rout the drain line piping and adding
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supports for the main stream line automatic drain valves.
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Conclusions The main steam line drains were vibrating excessively and neither operations nor engineering had identified the deficient condition.
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addition, the licensee failed to identify the broken struts. These issues are being identified as a weakness.
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M4 Maintenance Staff Knowledge and Performance M4.1 Missed Section XI Surveillances a.
Insoection Scope (61726)
The inspectors reviewed two events, documented in Licensee Event Report (LER) 50 327/96012, in which valve testing surveillance requirements were not performed as required by technical specifications.
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Observations and Findinas l
On December 3,1996, the licensee discovered two Unit 1 cold leg
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l accumulator sample isolation valves (1-FSV 43 34 and 1 FSV 43-35) which were inoperable due to a missed surveillance. These normally open valves had been tagged out since March 21, 1996, with power removed and
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in the closed position, to support a plant modification.
During surveillances in May, August, and November 1996, the valves were not
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tested because operators had " incorrectly" documented the valves as test deficiencies in that they were tagged under a hold order.
Following i
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l the licensee's discovery of the missed surveillances, a stroke time test was successfully completed on both valves.
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The licensee concluded the missed surveillances occurred due to the improper use of the test deficiency process (SSP 8.1, Conduct of l
Testing, Revision 7). The deficiency process should not have been used for components which were not tested, rather the Limiting Condition of Operation Action Statement should have been entered for the two affected valves when the surveillance test could not be completed. The Limiting Condition of Operation Action Statement was not entered and subsequently the valves were opened on nine occasions over an eight month period.
The hold order was temporarily lifted each of the nine times to permit
opening of the valves in order to take required samples.
l Following the identification of the missed surveillances, management expectations were communicated to the approariate personnel regarding the test deficiency process and regarding t1e review of test packages for completeness. Problem Evaluation Report No. SQ963096PER was l
initiated to document this event. The problem evaluation report also established a corrective action plan to prevent recurrence.
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l The inspector concluded the licensee failed to test valves 1-FSV-43-34
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and 1 FSV-43 35 as required by Technical Specification Surveillance Requirement 4.6.3.3 and procedure 1-SI-SXV 000-201.0, Full Stroking of Category "A" and "B" Valves During Operation, Appendix K, Revision 0.
This licensee-identified and corrected violation is being treated as a non-cited violation (NCV). consistent with Section VII.B1 of the NRC Enforcement Policy (NCV 50 327/96-17 01).
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On December 3, 1996, during the investigation of the event described l
above, a second event was discovered where the surveillance requirements i
were not fulfilled for 18 (normally oyen) valves on Unit 1 (two of which were the isolation valves discussed a>ove). A data sheet, listing the 18 valves, was missing from a test Jackage from the February 26, 1996,
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l performance of 1 SI SXV 000 201.0, ull Stroking of Category "A" and "B" l
Valves During Operation, Appendix K Revision 0.
A review of the
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completed test package by licensed operators and the Section XI engineer did not detect the data page was missing. Therefore, they did not
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recognize that the 18 valves had not been tested. Subsequently 16 of the valves were tested in May, August, and November 1996, and met their acceptance criteria.
The licensee determined the root cause of the event was the failure of operations personnel to identify that the surveillance package was not complete. A contributing factor was the failure of the Section XI
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engineer and the operations surveillance instruction (SI) coordinator to
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identify that the surveillance was not complete.
Problem Evaluation Report No. SQ963105PER was initiated to document this event. The i
problem evaluation report also established a corrective action plan to prevent recurrence.
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The inspector determined that on February 26, 1996, the licensee failed l
to test 18 valves as required by Technical Specification Surveillance l
Requirement 4.6.3.3 and procedure 1-SI SXV 000 201.0. Full Stroking of I
Category "A" and "B" Valves During Operation. Appendix K. Revision 0.
This licensee identified and corrected violation is being treated as a non cited violation, consistent with Section VII.B1 of the NRC
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Enforcement Policy. (NCV 50-327/96 17-02)
l The inspectors discussed this second event with the Section XI engineer l
who trends the performance of these quarterly tested valves. The inspectors were informed that the computer program used for trending valve performance does not " flag" a condition where data is missing, such as occurred for the 18 valves discussed above. The licensee
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initiated Problem Evaluation Report No. SQ970011PER to document the weaknesses which exist in the Section XI valve stroke time data files
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l and initiated a corrective action plan to improve the data files.
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Conclusions
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A non cited violation was identified for the failure to perform l
Section XI stroke testing for two valves during May, August and November
1996.
The test deficiency process was implemented improperly resulting in a failure to appropriately test the valves.
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A non cited violation was identified for the failure to perform Section XI stroke testing for 18 valves on February 26, 1996. Several reviews were performed that indicated the surveillance package was complete, however, the surveillance package was not complete.
This indicated a
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I lack of thoroughness in the review process.
A weakness was identified in the licensee's program for trending and
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tracking Section XI valve testing.
I M8 Miscellaneous Maintenance Issues (92902)
M8.1 Corrective Action Proaram Effectiveness Review a.
Inspection Scope (40500)
This inspection was conducted to determine the effectiveness and the state of completion for specific corrective actions identified by the licensee to correct findings reported in a March 5,1996. Reliability j
Study. This self assessment was very critical of management.
l operations, maintenance, and support engineering. Many items identified l
in the reliability study were similar to items identified by NRC during the same time period. One major finding identified by the licensee was l
that station managers and supervisors failed to ensure consistently that equipment and personnel problems affecting unit reliability were pro >erly corrected in a timely manner.
Especially troublesome was the lac ( of follow through on identified corrective actions. Therefore, the inspector reviewed select corrective actions taken by the licensee particularly in the area of maintenance (specific items examined are l
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i identified in the findings paragra)h below). To conduct this assessment the inspector held discussions wit 1 managers in operations, training.
maintenance and modifications, and licensing: reviewed objective i
evidence of their assigned improvements and the results obtained to
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date; and conducted walkdown inspections to observe equipment cleanliness, the completeness of work, and to determine the i
effectiveness of corrective actions taken on specific hardware i
discrepancies identified in the reliability study where applicable.
In addition, the inspector attended the operations shift-turnover meeting,
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the plan of the day meeting, the curriculum review committee (CRC)
meeting, and the maintenance / modifications morning meeting to determine the adequacy of the neetings' content as they related to specific
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weaknesses identified by the licensee such as STAR (Stop, Think, Act and I
Review) program im31ementation, questioning attitudes, motivation of I
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personnel, teamwor(, and inter department communication.
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b.
Observations and Findinas
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l Actions taken by the licensee on the following corrective actions were
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verified by the inspector:
e Item # 3a: The maintenance manager and maintenance line supervisor will ensure that craft personnel with demonstrated i
knowledge and experience will wrform or supervise the performance
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of any activity described in t1e Sensitive Activities Manual.
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maintenance manager will further ensure that maintenance training, and performance monitoring programs gain, maintain, and measure knowledge and experience to reduce the knowledge and rule based error percentage by 30%.
Actions taken:
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(1)
Maintenance now assigns a general foreman to work identified
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in the Sensitive Activities Manual.
(2)
In addition to the CRC, the maintenance manager now chairs his own training curriculum meetings. This began in August 1995, with the goal of implementing " Scenario Training" and
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placing special emphasis on maintenance supervisor training.
Scenario training is where students (craftsmen) are given actual work orders of ecuipment set up in the training l
laboratory, and are graced on how they implement each step
of the work instruction including job prerequisites.
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addition in FY (fiscal year) 1996 mechanical maintenance
conducted scenario training in the plant using the 5th diesel generator.
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(3)
Supervisors were assigned specific expectations for monitoring training. As a result general foreman monitoring of training activities has increased from 83 total observations in 1995 to 146 observations through October, 1996.
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(4)
The maintenance " Peer Evaluation" or " White Card Program" was initiated in 1996. With this program supervisors monitor craft activities using checklists. Over 1000 checklists were performed by general foremen through November, 1996.
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(5)
Increased emphasis was placed on craft skills training. As a result, 989 new craft task qualifications were performed in 1996, verses 399 in 1995.
(6)
Root cause analysis training was conducted for all
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maintenance general foremen.
(7)
An 80 hour9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> SON Leadership Development Program is still in progress.
In February 1996 thirty maintenance and modification staff attended.
Fifteen additional staff plan to attend in March 1997. The theme of this program is transition to a high performance environment focusing on communication and observation skills. Twenty of twenty-eight maintenance / modification supervisors completed this training.
As a result of management's emphasis on im) roved supervision and improved craft skill, rule, and knowledge )ased training, by April 1996, maintenance had realized an approximate 30% reduction in administrative errors.
Maintenance management was fully aware that improvement was still needed. However, managers interviewed were confident that their continuing efforts to improve the quality of training and supervision along with their increased emphasis on personal accountability will achieve these goals.
e Item # 3b:
Retrain maintenance supervisors and craftsmen in STAR and QV&V (Quality Verification and Validation) by start of the Unit 2 Cycle 7 refueling outage.
Actions taken: Training rosters for the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> training given to maintenance craft, planner and supervisor >ersonnel in STAR and QV&V were reviewed. The inspector noted t1at for planners a written test was given in QV&V. A maintenance morning craft meeting was attended, and documentation of other maintenance stand-down meetings were reviewed where specific portions of the meetings dealt with STAR and QV&V program implementation. While at the training center, the inspector observed the TVA STAR simulator developed by the licensee to test personnel skills in a) plying STAR. The inspector found this simulator to be clallenging. Some maintenance managers have piloted the simulator in use.
Discussions with the supervisor of maintenance training indicated that, in January 1997, a schedule is planned to be developed to train maintenance supervisors and craftsmen on the STAR simulator.
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e Item # 3c:
Increase the amount and quality of field supervision.
Actions taken: As noted in Item 3a.(1), (4), (6) and (7) above significant improvements have been made in both job supervision by r
management and supervisor training.
However, this effort is
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planned to be a dynamic aad on going process towards improvement where mana9ement performance evaluations are used to measure i
supervisor performance in this area.
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Item # 9a: Reissue incomplete corrective actions identified in l
arevious reliability efforts (May 17, 1993. SWEC Balance of Plant Jesign Study; June 4, 1993. SON Secondary Plant Reliability Study; and 1995 Reliability Team Report).
l Action taken: The completion of all incomplete corrective actions l
identified in the above assessments have been funded, assigned l
ownership for completion, and given a completion due date. A
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review of the Sequoyah Nuclear Plant FY 96 Fcurth Quarterly Business Plan also revealed that a significant number of the corrective actions have been completed.
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Item # 9b:
Provide the reason for not implementing the action in writing to the plant manager or provide an action plan for implementation.
l Action taken: All corrective actions identified have been assigned ownership and an action plan implemented for their completion.
e Item # 10: Revise and update quarterly the SON Business Plan to
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include specific reliability improvement corrective actions.
Each corrective action will include an owner with due date.
Department
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managers performance appraisals will be adjusted quarterly to reflect performance against these due dates. The actions will:
e address root causes e
be cost effective e
can be implemented in a timely manner Action taken: As of May 1,1996, the SON Quarterly Business Plan
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had been revised and updated to include incomplete corrective
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actions identified in previous reliability efforts and in the 1995 Reliability Study. All items have been funded, assigned ownership, and completion due dates established.
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Item # lla: Revise Site Standard Practice (SSP) 3.4 to include l
personnel qualification requirements, for performing equipment root cause analysis.
Actions taken: Appendix L, Paragraph 2.2 of SSP 3.4 was revised to include qualification guidelines for equipment root cause failure analysis investigators.
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e Item # lib: Train individuals in problem solving techniques.
Action taken:
Initially two pilot courses were provided, one by-
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an industry peer from Commonwealth Edison who instructed courses i
in root cause analysis. The second was provided by an instructor fron the Institute of Nuclear Power Operations (INP0) and was F
based on their Incident Investigation Program.
Sequoyah training personnel attended the initial courses, obtained course notes from i
each instructor, and developed a specific course on problem-
solving techniques which is now given on an on going basis at the
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training center. Training rosters of personnel (137) who have attended the 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> course and training schedules for subsequent
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problem solving training were reviewed by the inspector.
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e Item # 12: Review and revise TVA's customer group (switchyard l
maintenance group) interface agreements to improve equipment
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performance problems and reduce plant capacity factor losses.
i Action taken: TVA implemented a significant organizational change to provide better control of the nuclear plant switchyard. The i
new organization change has an operations and maintenance manager for all TVA nuclear plants. There was a manager assigned to each
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nuclear site, functionally reporting to the site maintenance manager. The new organization change also has a transmission
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support manager that will supply engineering sup) ort from the l
Transmission Power Supply Organization along wit 1 site engineering
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l support.
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Item # 13:
Review and revise TVA's partners in performance i
agreements to improve equipment performance and plant capacity l
factor losses.
Actions taken: A new Sequoyah/ Westinghouse strategic business team charter was written which realigned organizational team members to ensure timely, efficient, and economical support was provided in engineering, maintenance, and outage services. The charter also established licensee / contractor task teams for the turbine generator, nuclear steam supply systems performance.
outage support, and steam generators.
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Conclusion Completion of the above corrective actions demonstrated to the licensee's commitment to improve operational reliability.
Previously identified corrective actions have been funded, ownership assigned, and completion dates established. Knowledge, rule, skills, awareness, root cause analysis, and leadership training have been given and continue to be given. Supervision of craft work and training activities has
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improved significantly, although improvements can be made in this area with improved supervisor training in monitoring work activities. The
inspector observed definite improvements in most maintenance areas trended for performance.
However, additional time will be needed to
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realize sustained improved performance for the efforts expended.
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addition, material and hardware problems could continue to effect i
operational performance adversely until scheduled modifications and replacements are completed.
l M8.2 (Closed) LER 50 327/96012:
Missed Surveillances On Cold Leg Accumulator Valves and Missing Data Sheet In Surveillance Package. The events described in this LER were discussed in Section M1.1 of this report. No new issues were revealed by the LER.
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III. Enaineerina
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E2 Engineering Support of Facilities and Equipment
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E2.1 Triopina of Intertie Transformer Bank a.
Inspection Scope (37551)
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On December 20, 1996, the 500/161 kilovolt intertie transformer bank trip)ed when the over pressure relay actuated on the " spare" phase tapcianger. The inspectors reviewed this event and the licensee's
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investigation of the event.
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Observations and Findinas i
Both units were at 100% power when the intertie transformer bank tripped: however, neither unit was affected by the event. The licensee's investigation determined that the pressure relays for the
" spare" phase (the spare 3hase transformer was inservice) and the other i
two inservice phases had >een set incorrectly due to an error in the l
recently revised TPS FTM. The FTM, revised September 2, 1996, stated l
that the setpoint should be 1.7 psi.
Examination of the vendor manual I
and the previous revision of the FTM indicated that the setpoint should be 7.2 psi.
Initially all three relays were found near 7.1 psi prior to resetting them to 1.7 )si. The technicians involved in changing the set >oints questioned t1eir supervision regarding the new setpoint num>ers. Their question was referred to the licensee's corporate engineering group which concluded that the 1.7 psi value was correct as stated in the revised FTM.
Based on the response from corporate engineering, the technicians reset the pressure relays to the new value i
of 1.7 psi.
Subsequently, the spare intertie transformer bank tripped.
On December 21, 1996, the pressure relays were recalibrated to the correct setpoint of 7.1 psi. and the intertie transformer bank was returned to service.
c.
Conclusions The inspectors concluded that TPS technicians exercised good questioning attitudes regarding the revised setpoint data in the FTM. This is
considered a positive observatio i
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The TPS Field Test Manual contained incorrect setpoint data and TVA l
corporate engineering erroneously advised the maintenance technicians
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area of engineering support.
E2.2 Freeze Protection Issues a.
Inspection Scooe (37551. 71714)
The inspectors reviewed two issues related to the freeze protection i
program and one event related to the apparent freezing of two ERCW t
screen wash pump pressure sensing lines.
b.
Observations and Findinas j
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In April 1996, the licensee initiated several corrective actions under Problem Evaluation Report No. SQ960210PER to improve the Sequoyah freeze protection program. One of the corrective action items (Sequence No.
11) from that problem evaluation report was to " Perform an extent of condition evaluation of the Periodic Instructions (PI) to insure the j
design basis is met." That corrective action had a due date of November 15, 1996. On January 13, 1997, the inspector questioned nuclear engineering as to the status of the open item and was informed that the open item had not been completed nor had a request been made to extend the due date beyond the original due date of November 15, 1996.
All other corrective. actions associated with that problem evaluation report have been completed.
It should be noted that the inspectors, in
IR 96 04, dated June 5,1996, stated that the licensee could not
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demonstrate that an evaluation had ever been performed to define the scope of the freeze protection arogram to ensure that design basis requirements were being met.
Wien the current inspection period ended, that evaluation had not yet been completed.
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In September 1996, during performance of 1-PI-EFT 234-706.0, Freeze
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Protection Heat Trace Functional Test, the licensee identified that a l
majority of the heat trace circuits at the ERCW pumping station failed the acceptance criteria specified in the PI.
Problem Evaluation Report
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No. SQ962375PER was initiated on September 9, 1996, to document this finding.
Subsequently, that problem evaluation report was closed and
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l rolled into a previously written problem evaluation report, No.
l SQ962327PER, dated August 31, 1996, which dealt with ERCW heat trace problems.
The licensee initiated actions to replace the existing 4-watt per foot ERCW heat tracing. During the process, electrical maintenance was informed by purchasing that 4-watt heat tracing was no longer available from the vendor and 5 watt heat tracing was ordered. An SDCN to evaluate the 5 watt versus the 4 watt heat tracing was initiated by nuclear engineering and was scheduled to be completed on November 8, 1996, but was not issued until December 3, 1996. The SDCN concluded that the 5 watt would overload the breakers; therefore, the use of 4-watt was recommended.
Subsequently, the heat trace vendor manufactured
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the required 4 watt heat tracing with an original delivery date of
a) proximately December 12, 1996. The 4 watt heat tracing was shipped to
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t1e site on January 15, 1997.
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i It should be noted that Inspection Reports 96 01 and 96 04 discussed problems related to ERCW heat tracing. A weakness with the freeze protection program was identified in IR 96 04 as IFI 50 327, 328/96 04-13.
IR 96 14, dated December 31, 1996, documented that the licensee appeared to have an acceptable freeze protection program. However, as noted during this inspection period, uncorrected problems continue to i
l exist with ERCW heat tracing.
On January 12, 1997, the main control room was notified that both A-train ERCW traveling screens would not rotate when placed in service due to suspected freezing of the screen wash pump discharge pressure sensing
line. Subsequent investigation by electrical maintenance concluded that the installed heat tracing was functioning properly and that the temperature of the sensing line, as measured by a contact thermometer, j
was above freezing (the lowest measured tem >erature was 42 F).
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However, when heat was applied to each of t1e sensing lines the traveling screens began to operate normally. Although electrical maintenance could not conclude that freezing actually occurred, the apparent frozen condition was corrected when heat was applied to the pressure sensing line.
Following this event, the licensee increased the compensatory freeze protection measures at the ERCW pumping station.
It should be noted that on February 5, 1996, a similar event occurred when both B train ERCW traveling screens failed to operate due to frozen and ruptured screen wash pump discharge pressure sensing lines.
c.
Conclusions The lack of engineering response to an overdue freeze protection program corrective action item is considered to be a weakness in engineering support for the freeze protection program.
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The insufficient efforts to expedite resolution of heat trace deficiencies at the ERCW pumping station is considered a weakness in management oversight of ERCW freeze protection.
The apparent freezing of the ERCW screen wash pressure sensing lines is considered to be a weakness in the freeze protection compensatory
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actions.
E7 Quality Assurance in Engineering Activities E7.1 Steam Dumo Drain System Problem Analysis i
a.
Inspection Scope (40500)
Due to previous problems with the steam dump drain systems for both units, the licensee initiated an independent review to determine the I
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most likely cause of the problems. The inspectors reviewed the licensee's independent review and evaluated the corrective actions.
b.
Observations and Findinas The analysis noted that the main steam dum) drain system was designed to preclude water accumulation in the lines w11ch could create water hammer load conditions.
It noted that the system has been a source of problems since plant startup and that a number of modifications have been implemented but have not been fully effective. To address the concerns, l
an independent team of engineering specialists was gathered to perform a problem analysis and to determine the root cause(s) for the system problems.
In addition, the team was tasked with recommending
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appropriate corrective actions to resolve the system problems.
The team concluded that the most likely cause for the observed problems l
was " steam dump drain pressurization" and " condenser steam migration."
This seemed to fit all of the observed system conditions such as hot drain piping, pressurized drain tank, popping noises in the drains and
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dump lines, and inverted temperatures at the drain inlets.
The team recommended modifications to improve system reliability which included the following:
e Increase the size of the drain line to the atmospheric drain sump so that the drain tank will drain faster.
Relocate the vacuum pump drains to the drain tank to preclude e
water intrusion.
Remove insulation from the drain header to help sub cool e
condensation in the drain system.
e Install " ball valves" on each drain line on both units.
e Redesign the drain tank level control systems to eliminate the use of Mercoid level switches which have caused recurrent problems.
e Provide control room indication and alarm of abnormal drain system operation.
Re evaluate the design pressure of the drain tank and modify the e
design, if necessary, to accommodate postulated pressurization from one failed drain valve.
The analysis noted that these modifications should be implemented.as described and could be implemented during the next cutage. This is identified as Inspector Follow up Item 50 327,328/96 17 03:
Steam Dump Drain Improvements, pending licensee resolution of the recommendation.. _ _ _ _ _ _ _
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Conclusions In response to performance problems, the licensee's actions to perform an independent review of the steam dump system and to develop corrective actions is considered to be a positive observation.
E8 Miscellaneous Engineering Issues (92903)
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E8.1 (Closed LER 50-327/95009: Rod Position Indication Out of Step witn Demand Position Indication System.
(Closed LER 50 327/96007: Rod Position Indication System Out of Step with Demand Position Indication System.
(Closed LER 50 327/96011: Rod Position Indication System Out of Step with Demand Position Indication System.
The above three LERs discussed similar events in which the Unit 1 rod position indicators (RPIs) for two control rods were more than the required 12 steps out from their respective demand position indicators (step counters) which required entry into Limiting Condition of Operation 3.0.3.
The actual position of the rods was indicated by the demand position indication system and was not in error. The root cause for these events, discussed in the LERs, was that the response of the RPI is nonlinear, and the resulting difference between the RPI readout and the actual rod po-ition is most pronounced near rod midscale. The licensee is evaluating options for long term corrective actions.
No new issues were revealed by the LERs.
E8.2 10oen) VIO 50 327. 328/EA 95 252: This violation identified that in July through September 1991, the licensee discriminated against an employee engaged in protected activities.
The inspector performed an in office review of this violation and reviewed the following listed documentation.
- In the letter, transmitting the Notice of Violation dated February 20, 1996, the NRC concluded that corrective actions taken and planned to correct the violation and prevent recurrence and the date when full compliance will be achieved had already been adequately described and provided to the NRC in a January 12, 1996 letter.
e TVA letter to the NRC dated January 12, 1996. This letter describes surveys conducted at Sequoyah by the TVA Office of Inspector General (0IG) in 1994 which indicates that 99% of TVA employees and 100% of contractor employees would report their l
concerns to management. Further, another 0IG audit was completed in 1995, that recorded the same percentages as the 1994, survey.
The January 12, 1996, letter indicates similar results were found j
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In addition to the above listed corrective actions, the inspector reviewed documentation recently issued by TVA that emphasized TVA's continuing support of eliminating harassment in the work A
memorandum from the TVA President, dated August 7, 1996, place.
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employee intimidation, harassment, discrimination, or retaliation for j
expressing employee concerns will not be tolerated.
Yhis violation will remain open pending the outcome of the TVA appeal to the United States Court of Appeals for the Sixth Circuit a.c discussed in NRC's letter dated April 4, 1996 cn this subject. The NRC accepted the licensee's corrective actions and actions to prevent recurrence by letter dated February 20, 1996.
Implementation of these actions was not inspected at this time.
The inspector found the licensee had also taken additional corrective dctions relative to notifying TVA employees that intimidation and harassment at the TVA nuclear facilities will not be tolerated.
E8.3 L'odated Final Safety Analysis Reviews A previous discovery of a licensee operating their facility in a manner contrary to the UFSAR section, highlighted the need for a special
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focused review that compares plant practices, procedures and/or parameters to the UFSAR description.
During this inspection period, the inspectors reviewed the applicable j
sections of the Updated Final Safety Analysis Report that related to the areas inspected. One inconsistency was found and described in Section R1.1.
IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 Lithium Hydroxide Addition to the Reactor Coolant System a.
Insoection Scope (71750)
The inspectors reviewed the licensee's methods for making lithium hydroxide additions to the reactor coolant system.
b.
Ob_servations and Findinas On December 9, 1997, during a lithium hydroxide addition to the reactor coolant system, a pump hose disconnected and an individual's shoes and pants were contaminated. The licensee wrote a personnel contamination report, and Problem Evaluation Report Number SQ963157PER for this event.
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The inspectors determined, from reviews of the problem evaluation report, procedures, personnel statements, the personnel contamination
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report, and discussions with the licensee, that lithium hydroxide was l
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added to the reactor coolant system via flow to the volume control tank using connections in a sample sink in the Hot Sample Room. The information indicated that three attempts were made on December 9. to add the lithium hydroxide.
On the first attempt, a tygon tubing pump hose disconnected and reactor coolant spilled onto the floor, contaminating the technician. On the second attempt, a tygon tubing line in the pump head burst (a technician noted that line pressure downstream of a closed valve had increased to 400 aounds per square inch).
On the third attempt, a tygon tubing line aurst off the pump.
No further attempts were made.
The inspectors reviewed TI-19. Chemical Feed Controls, Revision 27, and verified the procedure included steps for an alternate method for making a chemical addition to the reactor coolant system using connections in a sample sink in the Hot Sample Room (the solution is pumped through tygon tubing into a hotleg sample outlet valve using a peristaltic pump as the motive force). The inspectors determined the procedure was revised in 1990 to include this method for adding lithium hydroxide. The inspectors noted that Figure 2 of this procedure had the location of the sample inlet and outlet valves reversed relative to what was observe in the hot sample room sink.
The inspectors reviewed the Instruction Change Forms and safety assessment for these procedure changes. The safety assessment procedure / modification checklist did not consider any potential changes in nuclear safety for: human factors, equipment failure modes, equipment reliability, etc. The checklist also was checked "no" for questions regarding changes to the Safety Analysis Report.
The inspectors determined, through discussions with the licensee, that the alternate method was, in fact, the primary method of adding lithium hydroxide to the reactor coolant system for the last year (approximately).
The inspectors also determined the tygon tubing used for the lithium hydroxide addition was rated for a maximum working pressure of 44 pounds per square inch. The backpressure from the volume control tank is approximately 30 pounds per square inch.
However, the action of the pump can cause work-hardening of the tygon tubing, which can subsequently crack at a much lower pressure than the rated pressure The licensee also determined the failure of the technicians to use hose clamps for some connections contributed to the problem.
The licensee determined the observed 400 pounds per square inch pressure was caused by valve leak-by and did not contribute to this incident.
The inspectors reviewed Final Safety Analysis Report Section 5.2.3.4, l
Chemistry of Reactor Coolant, which states, "The lithium hydroxide is l
introduced into the reactor coolant system via the charging flow. The
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solution is prepared in the laboratory and poured into the chemical mixing tank." An alternate sampling method was not delineated.
l However, the inspectors determined that Revision 12 to the Final Safety
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Analysis Report, submitted to the NRC in December 1996, changed the wording of the aforementioned paragraph to state, "The solution is
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pre)ared in the lat, oratory and routinely poured into the chemical mixing tan (."
The licensee's corrective actions included immediate suspension of this
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addition method and scheduling a procedure revision to remove this method. The licensee is currently exploring other methods to add chemicals to the reactor coolant system, which would be designed and a> proved via the 10 CFR 50.59 process. The licensee is also applying
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t1e 10 CFR 50.59 process to review their chemical addition and sampling procedures. The licensee's root cause for the incident was the selection and use of inappropriate chemical injection equipment (pump and connector).
The inspectors concluded that, contrary to Technical Specification 6.8.1.a. the procedure used to perform the alternate method was
inadequate in that it delineated inapproariate materials and equipment.
it contained insufficient guidance for t1e performer with regard to hose clamps, etc., and that one figure had the location of the samale inlet i
and outlet valves reversed relative to what was observed in t1e hot
sample room sink. This licensee identified and corrected violation is being treated as a non-cited violation, consistent with Section VII.B.1
of the NRC Enforcement Policy. This issue is identified as NCV 50 327, 328/96-17-04, Inadequate Procedure for Performing a Chemical Addition.
f c.
Conclusions A non cited violation was identified for an inadequate procedure for
performing a chemical addition to the reactor coolant system which resulted in a personnel contamination event.
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R1.2 Steam Generator Blowdown Samolina a.
Insoection Scope (71750)
The inspectors reviewed the licensee's methods for sampling steam i
generator blowdown.
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b.
Observations and Findinas The chemistry organization conducted a review of chemistry practices and work arounds. This review resulted in Problem Evaluation Report No.
SQ963164PER for an inadequate sample system design for steam generator blowdown sampling. The licensee's arocedure for obtaining steam generator blowdown samples, while tie units are in modes 2 through 4 requires the use of mechanical blocks to hold open the steam generator
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blow down sample line valves.
If the unit's auxiliary feedwater pumps
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are operating, these valves receive an auto close signal.
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would prevent valve closure by a containment isolation phase A signal.
The licensee determined that holding these valves open rendered them inoperable and required entry into Limiting Condition of Operation Action Statement 3.6.3.a.1, which requires restoration of the inoperable valves to operable status within four hours. The licensee conducted a survey of 23 chemistry personnel and determined the longest time the containment isolation valves were blocked open was approximately three hours, with the average amount of time being two hours.
The inspector
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previously interviewed four technicians and independently verified the average amount of time the mechanical blocks were left in place and also thai, the mechanical blocks were not left unattended while in place.
I Site Licensing reviewed Problem Evaluation Report No. SQ963164PER and l
determined this issue was not reportable because the maximum known l
length of time to sample all four steam generators was three hours, less l
than the four hour limiting condition of operation allowed outage time.
l The licensee's procedure required notification of the control room prior
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l to blocking these valves open.
However, the licensee's interviews of
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understand that the containment isolation function of the valves would be defeated by mechanically blocking the valves open. The inspector also independently discussed this concern with various control room operators and agreed with the licensee's finding.
The licensee's corrective actions included immediate suspension of the use of the mechanical blocks, a review of procedures to ensure other sampling practices do not adversely impact containmant isolation valves.
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and a review of steam generator procedure history to evaluate past i
sampling practices.
Other scheduled corrective actions included-
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Revision of chemistry sampling procedures to clearly identify when l
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containment isolation valve manipulations are required:
An evaluation of the steam generator blowdown sampling system to t
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determine the feasibility of a design change / system modification l
to minimize containment isolation system impacts:
e Inclusion of valve cont.rol logic training in the Chemistry Continuing Training program; and l
e Performance of a cross disciplinary review of chemistry sampling procedures and associated safety analyses.
The licensee cetermined the root cause to be inadequate procedure development and review process.
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i The inspectors concluded that, contrary to Technical Specification 6.8.1.a. the procedure used to perform the steam generator blowdown sampling was inadequate in that it inaapropriately required " holding open" containment isolation valves. T1is licensee identified and corrected violation is being treated as a non cited violation, I
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consistent with Section VII.B.1 of the NRC Enforcement Policy. This issue is identified as NCV 50 327, 328/96 17-05. Inappropriate Blocking.
of Containment Isolation Valves.
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Conclusions One non cited violation was identified for inaapropriate blocking of containment isolation valve control switches w11ch would have prevented automatic closure following a containment isolation actuation signal.
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R1.3 Material Condition of Charaina Pumo Skids a.
Inspection f. cope (71750)
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During routi:,e plant tours, the inspectors noted the material condition
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of plant areas and equipment.
b.
Observations and Findinas The inspectors noted, during tours of the auxiliary buildings, that there were few leaks, debris was appropriately bagged, equipment was l
properly stored, and areas were properly posted. While observing work activities on the Unit 1 "B" charging pump, the inspectors noted the advantages of having the charging pump skids decontaminated. The cleanup of the skids was considered to be a positive initiative by the licensee because it provided easy access to the charging pumps for
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operation and maintenance.
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Conclusions l
l The licensee's initiative to decontaminate the charging pump skids was i
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considered to be a positive observation, i
V. Manaoement Meetinas
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X1 Exit Meeting Summary The inspectors ) resented the inspection results to members of licensee i
management at t1e conclusion of the inspection on January 24, 1997. The l
licensee acknowledged the findings presented.
l The inspectors asked the licensee whether any materials would be considered proprietary.
No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
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Licensee
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Adney, R.
Site Vice President
- Beasley, J., Acting Site Quality Manager i
Bryant, L., Outage Manager
- Burzynski, M., Engineering & Materials Manager
- 0riscoll, D., Training Manager
- Fecht, M., Nuclear Assurance & Licensing Manager
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- Flippo. T., Site Support Manager
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Harrington, W., Acting Maintenance Manager
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- Herron, J., Plant Manager
- Kent, C., Radcon/ Chemistry Manager i
- Lagergren, B., Operations Manager
- Rausch, R. Maintenance and Modifications Manager Reynolds, J., Operations Superintendent
- Rupert, J., Engineering and Support Services Manager
- Shell, R., M'1ager of Licensing and Industry Affairs Skarzinski, M., Technical Support Manager
- Smith, J., Licensing Supervisor Summy, J., Assistant Plant Manager
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Symonds, J. Modifications Manager
- Attended exit interview
INSPECTION PROCEDURES (IP) 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 71714: Cold Weather Preparations
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IP 71750:
Plant Support Activities IP 92902:
Followup Maintenance IP 92903:
Followup - Engineering ITEMS OPENED. CLOSED. AND DISCUSSED Opened h Ites Number Status Description and Reference j
NCV 50 327/96-17-01 Open/
Failure to perform Section XI Tests l
Closed on Two Valves.
(Section M4.1)
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NCV 50 327. 328/96-17-02 Open/
Failure to Perform Section XI Tests i
Closed on 18 Valves.
(Section M4.1)
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NCV 50 327, 328/96 17-04 Open/
Inadequate Procedure for Performing Closed a Chemical Addition.
(Section R1.1)
NCV 50 327, 328/96 17-05 Open/
Inappropriate Blocking of Closed Containment Isolation Valves.
(Section R1.2)
IFI 50-327, 328/96 17-03 Open Steam Dum) Drain Improvements.
(Section E7.1)
Closed i
IYDe Ites Number Status Description and Reference LER 50 327/96012 Closed Missed Surveillances On Cold Leg Accumulator Valves and Missing Data Sheet In Surveillance Package.
(Section M8.2)
j LER 50 327/96011 Closed Rod Position Indication Out of Step with Demand Position Indication System.
(Section E8.1)
LER 50 327/95009 Closed Rod Position Indication Out of Step with Demand Position Indication System.
(Section E8.1)
l LER 50-327/96007 Closed Rod Position Indication Out of Step with Demand Position Indication System.
(Section E8.1)
Discussed VIO 50 327, 328/EA 95 252 Open The Licensee Discriminated Against An Employee Engaged In Protected Activities.
(Section E8.2)
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