IR 05000327/1986031
| ML20205H320 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 08/10/1986 |
| From: | Debs B, Harmon P, Jenison K, David Loveless, Mcniel S, Linda Watson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20205H303 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.F.1, TASK-TM 50-327-86-31, 50-328-86-31, IEIN-85-094, IEIN-85-94, NUDOCS 8608200051 | |
| Preceding documents: |
|
| Download: ML20205H320 (21) | |
Text
p trig UNITED STATES
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'o NUCLEAR REGULATORY COMMISSION
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p REGION 18 y
j 101 MARIETTA STREET,N.W.
ATLANTA, GEORGI A 30323
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Report Nos.:
50-327/86-31, 50-328/86-31
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Licensee:
Tennessee Valley Authority
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500A Chestnut Street Chattanooga, TN 37401 Docket Nos.:
50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name:
Sequoyah Units 1 and 2 Inspection Conducted: May 6, 1986 thru June 5, 1986 Inspectors: N Im#d/I. M,
/M8d K.~ M. ~JeniscT-Tenior denynspector (Tate Signed fZGJJA L 7/M/84 L. ~J. WatWesidsnt I;pft ectg '
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Approved by:
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B. T. Debs, Chief, Section 1A Da'te Signed Division of Reactor Projects Summary Scope:
This routine, announced inspection involved inspection onsite by the Resident Inspectors in the areas of: operational safety verification (including operations performance, system lineups, radiation. protection, safeguar-is and housekeeping inspections);
maintenance observations; review of previous inspection findings; followup of events; review ~ of licensee identified -items; review of IE Information Notices; and review of inspector followup items.
Results: Three violations were identified:
1.
Violation 86-31-01, Failure to post.a high radiation area (paragraph 5).
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2.
Violation 86-31-02, Failure to take prompt corrective action to resolve preoperational test deficiencies (paragraph 5).
3.
Violation 86-31-03, Failure to establish an adequate work plan (paragraph 7).
8605200051 860812 PDR ADOCK 05000327 PDR G
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REPORT DETAILS 1.
Licensee Employees Contacted H. L. Abercrombie, Site Director
- P. R. Wallace, Plant Manager
- L. M. Nobles, Operations and Engineering Superintendent B. M. Patterson, Maintenance Superintendent J. M. Anthony, Operations Group Supervisor
- R. W. Olson, Modifications Branch Manager M. R. Sedlacik, Electrical Section Manager, Modifications Branch
- H. D. Elkins, Instrument Maintena'nce Group Manager
C. W. LaFever, Instrument Engineering Supervisor M. A. Scarzinski, Electrical Maintenance Supervisor
- M. R. Harding, Engineering Group Manager
- D. C. Craven, Quality Assurance Staff Superviso"
- D. E. Crawley, Health Physics Supervisor
- G. B. Kirk, Compliance Supervisor H. R. Rogers, Compliance Engineer
- R. C. Burchell, Compliance Engineer
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l J. H. Sullivan, Regulatory Engineering Supervisor
- W: E. Andrews, Site Quality Manager i
- W. S. Wilburn, Assistant to the Maintenance Superintendent
- J. Robinson, Assistant to the Modifications Manager
- R. M. Mooney, Supervisor, Systems Engineering Section
- B. B. Wilson, Mechanical Engineering, Systems Engineering Section
- M. J. Blankenship, Manager information Services
- L. D. Alexander, Mechanical Modifications Section Supervisor
- R. W. Fortenberry, Technical Support Supervisor R. K. Gladney, Instrument Maintenance Engineering Supervisor K. W. Fenn, Instrument Engineer J. M. Stitt, Corrective Action. Coordinator, QA J. M. Hereford, Instrument Engineer Other licensee employees contacted included technicians, operators, shif t engineers, security force members, engineers and maintenance personnel.
- Attended exit interview
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2.
Exit Interview The inspection scope and findings were summarized with the Plant Manager and members of his staff on June 10, 1986.
Three violations described in paragraphs five and seven were discussed.
No deviations were discussed.
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The licensee acknowledged the inspection findings.
The licensee did not
identify as proprietary any of the material reviewed by the inspectors during this inspection. During the reporting period, frequent discussions were held with the Site Director, Plant Manager and 'other managers concerning inspection findings.
At no time during the inspection was i
written material provided to the licensee by the inspector.
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4 3.
Licensee Action on Previous Inspection Findings (92702)
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(0 pen) Unresolved Item 327,328/86-28-15:
This item involved containment sump level transmitters being found out of tolerance during performances of SI-202. This issue is further addressed in Paragraph 12.b of this report.
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(Closed) Unresolved Item 327,328/85-10-02:
This item involved an inadvertent Auxiliary Building Isolation caused by an inadequate surveillance. The inspectors observed the immediate short term corrective actions by the licensee. The generic aspects of this issue were covered by the licensee event report.
(Closed) Violation 327/83-29-01: The licensee's actions for this item were reviewed and closed for Unit 1 and 2 in NRC Inspection Report 327,328/85-26.
This entry corrects the inadvertent omission of the Unit 1 docket number from the closeout entry in 327,328/85-26.
4.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable or may involve violations or
deviations. No unresolved items were identified during this inspection.
5.
Operational Safety Verification (71707)
a.
Plant Tours The inspectors observed control room operations, reviewed applicable logs, conducted discussions with control room operators, observed shift turnovers, and confirmed operability of instrumentation.
The inspectors verified the operability of selected emergency systems, and verified compliance with Technical Specification (TS) Limiting Conditions for Operation ( LCO).
The inspectors verified that maintenance work orders had been submitted as required and that i
followup activities and prioritization of work was accomplished by the licensee.
Tours of the diesel generator, auxilia ry, control, and turbine buildings, the essential raw cooling water (ERCW) pump house and containment were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and plant housekeeping / cleanliness conditions.
The inspectors walked down accessible portions of the following safety-related systems on Unit 1 and Unit 2 to verify operability and proper valve alignment:
Chemical & Volume Control System (Unit 2)
Main Steam System (Unit 1)
Main and Auxiliary Feedwater System.(Unit 1)
Reactor Coolant System (Unit 2)
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During a plant tour, the inspectors observed work in progress on Reactor Coolant Pump No.
3, Unit 2.
The work involved removal and replacement of broken oil supply lines to the pump's thrust bearing shoes.
The condition was discovered during the licensee's investigation into the cause of their inability to rotate the idle pump by hand. Lack of oil supplied to the thrust bearing causes the entire pump weight to resist hand rotation. A laboratory failure analysis is in progress to determine the failure mechanism.
No violations or deviations were identified.
b.
Safeguards Inspection In the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities including protected and vital area access controls; searching of personnel and packages; escorting of visitors; badge issuance and retrieval; and patrols and compensatory posts.
In addition, the inspectors observed protected area lighting, protected and vital areas barrier integrity. The inspectors visited the central alarm station and interviewed security personnel regarding their respective duties.
No violations or deviations were identified.
c.
Radiation Protection The inspectors observed Health Physics (HP) practices and verified implementation of radiation protection control. On a regular basis, radiation work permits (RWPs) were reviewed and specific work activities were monitored to assure the activities were being conducted in accordance with applicable RWPs.
Selected radiation protection instruments were verified operable and calibration frequencies were reviewed.
On April 30, 1986, during a routine inspection of the Unit I contain-ment, the inspectors noted that the sign used to post a high radiation area around the incore instrumentation seal table was dangling from the stair rail, was not conspicuous, and did not block access into the seal table area.
The inspectors also noted that the entrance to the area inside the polar crane wall in lower containment was not barricaded and there was no conspicuous posting of the area. A high radiation sign had been placed on the door to the lower containment; however, the door had been opened to the point where the sign was not visible until after entry into the area.
The resident inspector reviewed survey maps for the area around the seal table. The area was not a high radiation area at the time of the Unit 1 containment inspection and the licensee subsequently removed the high radiation sign which was hanging from the stair rail.
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The resident inspector verified by review of the survey maps that the area inside the polar crane wall was a high radiation area as defined by TS 6.12.
The corrective action initiated by the licensee was to barricade and post the entrance to this area.
TS 6.12 states that in lieu of the control device or alarm signal required by paragraph 20.203(c)(2) of 10 CFR 20, each high radiation area in which the intensity of radiation is greater than 100 mrem /hr but less than 1000 mrem /hr shall be barricaded and conspicuously posted as a high radiation area and entrance thereto shall be controlled by requiring issuance of a Special (Radiation) Work Permit (SWP). Failure to barricade and conspicuously post a high radiation area is a Violation of the requirements of TS 6.12 (327,328/86-31-01).
During a subsequent tour the inspectors noted that the entrance to the lower crane wall had been barricaded by mechanical " Swing Gates" which included appropriate posting. Several other areas were barricaded in a like manner, and the licensee indicated that they were going to expand the usage of these " swing gates".
It should be noted that the licensee has replaced the use of SWPs with Radiation Work Permits.
This administrative difference between the documents described in the TS and the actual documents in use appears to be minor in nature and does not represent a violation of the TS.
d.
Preoperational Test Deficiency Review The inspector performed a review of the licensee's test results, deficiencies and associated corrective actions for the preoperational test procedure W-11.7, Revision 0, Calibration of Steam and Feedwater Flow Instruments at Power, which was conducted on both Units 1 and 2.
On Unit 2 it was noted that the licensee had identified two deficiencies (DN-1 and DN-2) and one exception (EX-1) during the performance of W-11.7.
Deficiency DN-1 consisted of the licensee's inability to obtain adequate zero power feedwater flow indications due to the failure to backfill the special test feedwater flow detectors.
The second deficiency (DN-2) was due to the licensee's failure to meet
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the required test acceptance criteria for calibrating the feedwater and steam flow process instrumentation at 75% and 100% thermal power.
In addition, the licensee took exception to performing the calibration adjustments necessary to bring the flow instrumentation within specifications and tc performing the calibration repeatability check specified in the W-11.7 test acceptance criteria.
On Unit 1 the licensee identified one deficiency (DN-1) during the performance of W-11.7.
This deficiency was similar to DN-2 on Unit 2 in that the flow instrumentation did not meet the test acceptance criteria at 75% and 100% thermal power. The TVA Office of Engineering (OE) - now referred to as the Division of Nuclear Engineering (DNE)
granted interim approval on July 23, 1982, for first cycle operation of Unit 1.
This approval was contingent upon the performance of selected portions of W-11.7 on Unit 1 following the first refueling outage. The
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outstanding deficiency was noted to be unacceptable by the licensee at this time. No approval (final or interim) was granted for first cycle Unit 2 operation.
On January 26, 1986, DNE gave full approval for the resolution'of M e test deficiencies and exception associated with these tests.
The licensee's corrective action consisted of the statement that "the Instrument Maintenance Section (IMS) had maintained cognizance of the main steam and feedwater instrumentation since initial startup of the units and that these instruments had been maintained within TS limits
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with few exceptions". Additionally, it was stated that IMS believed that no benefit would be derived for the IMS surveillance program from performing the test portions specified in the Unit 1 interim approval.
It was also stated that the failure to perform these portions of W-11.7
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would not result in any adverse consequences or compromises to nuclear safety.
The licensee stated that the rationale for closing the
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deficiencies and test exception on Unit 2 was the same as that used for closing the Unit I deficiency. In addition, the licensee's corrective action-for DN-1 Unit 1 and DN-1 Unit 2 were similar. However, these two deficiencies were dissimilar and required separate corrective actions.
Section XVI, " Corrective Action" of 10 CFR 50, Appendix B requires that significant conditions adverse to quality, such as deficiencies, deviations, defective material and equipment be promptly identified and corrective action taken be documented and reported to appropriate levels of management.
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Contrary to the above, the licensee failed to take appropriate corrective action for the Unit 1 W-11.7 test deficiency (DN-1) in that the test portions required to be repeated by the OE interim approval were never performed.
Unit 1 deficiencies were subsequently not adequately addressed by the licensee in the followup deficiency resolution. Additionally, the test deficiencies and exception noted in the performance of W-11.7 on Unit 2 were inadequately addressed in their resolution. This is a Violation 327,328/86-31-02.
In addition, a review of NRC inspection report 327,328/86-12 and the Corporate Nuclear Performance Plan in conjunction with interviews of licensee engineers and managers identified a difference in scope with respect to the review of preoperational test data. Inspection Report 327,328/86-12 stated that there would be a review and approval of all preoperational tests prior to the startup of either unit.
The Inspection Report identified this item as Inspector Followup Item 327,328/86-12-02. At this time, the licensee intends only to review those tests with outstanding test deficiencies.
Resolution of this issue will be accomplished under the original NRC Inspection Report item.
e.
A review was conducted of the Design Baseline and Verification Program system walkdowns. There were approximately thirty seven systems that were addressed during the Design Verification Program. Of those, the licensee determined that twelve systems did not require physical
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walkdowns during the initial process in order to facilitate an initial design verification. The Design Baseline Verification Program consists of five general phases which are:
System Calculational' Process Walkdown Package Initiation Walkdown Performance Analysis of Supporting Data - Tnis is to be accomplished by a licensee. contractor working fn Knoxville.
i Resolution Process - This incit. des supplementary information l
gathering or modifications if needed.
The current status (June 10, 1986) of the above program is that the first three steps are essentially complete. The last two steps are in f
process. Of the five general phases, the fourth phase is the most technically involved, and presently has no procedural guidelines. In addition the quality of the initial resolution packages is under review.
The Design Baseline and Verification program is to be
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evaluated by an NRC inspection team the week of June 10, 1986.
No violations or deviations were identified 6.
Monthly Surveillance Observations (61726)
The inspectors reviewed TS required surveillance testing and verified that testing was performed in accordance with adequate procedures; that test instrumentation was calibrated; that LCOs were met; that test results met acceptance criteria and were reviewed by personnel other than the individual directing the test; that deficiencies were identified, as appropriate; that any deficiencies ident1fied during the testing were properly reviewed and resolved by management personnel; and that system restoration was adequate.
For complete tests, the inspector verified that testing frequencies were met
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I dnd tests were performed by qualified individuals.
Questions about procedural adherence, acceptance criteria.and management review of deficiencies were raised during this inspection period. These questions are discussed in paragraph 13 of this report and will be ~ addressed under Unresolved Item 327,328/86-28-15.
The inspector reviewed portions of the following surveillance test activities:
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SI-202 Calibration of Safety Injection System Instruments (Refueling Outage)
SI-2 Shift Log
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SI-98.4 Channel Calibration for Engineered Safety. Feature
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Instrumentation Containment Sump (Refueling Outage)
No violations or deviations were identified.
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7.
Monthly Maintenance Observations (62703)
a.
Station maintenance activities of safety-related systems and components '
were reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with TSs.
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i The following items were considered during this review: LCOs met while components or systems were removed from service; redundant components operable; approvals obtained prior to initiating the work; activities accomplished using approved procedures and inspected as applicable; procedures adequate to control-the activity; troubleshooting activities controlled and the repair record accurately reflected what actually took place; functional testing and/or calibrations performed prior to returning components or systems to service; quality control records
maintained; activities accomplished by qualified personnel; parts and materials used were properly certified; radiological controls
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implemented; QC hold points established where required and observed; fire prevention controls implemented; and housekeeping actively pursued.
b.
The following material was reviewed in connection with an Appendix R (fire protection) modification which resulted in an Auxiliary Building Isolation on May 5, 1986:
Engineering Change Notice 6438 Work Plan 11871 Drawing 45N779-1, Revision 14
Temporary Change 86-757 The modification was performed on shutdown board 1Al-A.
Portions of the modification involved adding a fuse to each side of trip contacts 19/20 on finger interlock 52e for alternate breaker 58.
In addition, trip contacts 19/20 were changed from normally closed to normally open contacts. These two changes were intended to prevent the contacts from
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being fused by a trip-to-close circuit and to separate the breaker
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indicator lights in the main control room and the auxiliary shutdown facility. Three actions were:needed to accomplish this modification.
A contact shaft common to four. sets of contacts had to be removed. The contacts affected by the work plan needed to be rotated. All four sets of contacts needed to be replaced on the common shaft in the proper position. Work Plan 11871 step 2.1.10.6 addressed the reassembly of
the 52e finger interlock by stating that contact points 19/20 and points 23/24 should be checked against drawing 45N779-1. The workplan
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was inadequately written in that it failed to address the position of contact points 17/18 and 21/22. As a result of inadequate configura-tion control, contact points 17/18 were incorrectly rotated to the normally closed position.
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At the completion of the modification, breaker 58 was racked into its normal position.
Because contacts 17/18 were incorrectly rotated to the normally closed position, breaker 1B was tripped when breaker SB was racked in. The trip of the normal breaker resulted in a loss of power to radiation monitor RM-90-101 and an Auxiliary cBullding Isolation (ABI).
10 CFR 50, Appendix B, Section V, requires that activities affecting quality be prescribed and that the applicable instructions, procedures, or drawings include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.
Contrary to the above, the configuration of contacts 17/18 and 21/22 was not addressed in the acceptance criteria of step 2.4.5 of Work Plan 11871 and as a result, was not adequately controlled. Mispositioned contacts 17/18 resulted in an interlocked trip of the normal breaker 1B and an Auxiliary Building Isolation.
This is a
Violation 327,328/86-31-03.
c.
The inspector observed a portion of the work to strengthen a masonry block wall located in the Unit 2 hot sample room. The modifications were being performed to complete actions required to close IEB 80-11, Masonry Wall Design. The inspector reviewed Work Plan 11952 which was being utilized to perform the work.
Work on the modifications was still ongoing at the end of the inspection period. No violations or deviations were identified.
8.
Licensee Event Report (LER) Followup (92700)
The following LERs were reviewed and closed. The inspector verified that:
reporting requirements had been met; causes had been identified; corrective actions appeared appropriate'; generic applicability had been considered; the LER forms were complete; the licensee had reviewed the event; no unreviewed
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safety questions were involved; and no violations of regulations or TS conditions had been identified.
LERs Unit 1 327/82-126, Rev. 1 Failure of Main Steam Check Valve 327/84-025 Inoperable Pressurizer Level Transmitter 327/84-030 Incore Detector Thimble Tube Ejection 327/84-061 RCS PRT Pressure Indicator Wrong Range 327/85-007 Inoperable Emergency Gas Treatment System 327/85-011 Containment Vent Isolation 327/85-032 Inoperable Emergency Gas Treatment System 327/85-039 Containment Ventilation Isolation 327/85-041 Inadvertent Diesel Generator Start 327/85-046, Rev. 1 Inoperable Fire Hose Stations 327/85-047 Administrative Control of High Radiation Areas 327/86-012 Failure to Properly Stroke Time Valves - (The licensee identified, as part of their overall
surveillance review program, that surveillance
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3 requirements for TS 3.6.3 were inadequate.
The generic aspects of the adequacy of surveillances performed by the licensee will be resiewed in a future NRC surveillance team inspection.)
327/86-019 Auxiliary Building Ventilation Isolation
LERs Unit 2 328/84-021 Reactor Trip on Low-Low Steam Generator Level 328/85-010 Reactor Trip Due to Personnel Error 328/Special Report Inoperable Fire Door 86-07
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Event Followup (93702, 62703)
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On May 2,1986, an inadvertent control room isolation occurred during the performance of SI-240, Functional Test of Control Room Air Intake Chlorine Detection. System.
SI-240 was being performed on the A trair and the isolation occurred as a result of the B train. The involved individuals were interviewed to determine if the cause of the B train isolation could be i
established.
The inspector determined that there was insufficient i
information to establish the cause of the train B control room isolation.
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On May 13, 1986, an inadvertent containment ventilation isolation occurred during performance of SI-166.29, " Control Air Check Valve Test During Cold Shutdown".
During the test, control air was momentarily isolated to j
radiation monitor 2-RM-90-106.
The monitor's low flow alarm energized, creating a high radiation " spike" on the monitor. The high radiation signal
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generated a containment ventilation isolation signal. All applicable valves
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and dampers closed as designed. The control room operator verified proper actuation and then determined that the isolation signal was spJrious and i
invalid. He then reset the signal and returned the ventilation signal to
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normal. This event is presently under review by the licensee and will be tracked as Inspector Followup Item 327,328/86-31-04.
10.
IE Information Notices (92701)
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The following IE Information Notices (IENs) were reviewed and closed. The inspector verified that:
corrective actions appeared appropriate; generic.
applicability had been considered; the licensee had reviewed the event and that appropriate plant personnel were knowledgeable; no unreviewed safety questions were involved; and that violations of regulations or TS conditions
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did not appear to occur.
IEN 85-73 Emergency Diesel Generator Control Circuit Logic Design Error IEN 85-90 Sealing Compounds IEN 85-91 Load Sequencers for Emergency Diesel Generators d
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IEN 85-94 Potential for Loss of Minimum Flow Paths -Leading to ECCS Pump Damage During a LOCA - (All issues in IEN 85-94 were closed in Inspection Report 327,328/86-28 with the exception of the issue addressed in IFI 327,328/86-28-14. This IFI is closed out in Paragraph 12 of this report.
Therefore, this item is closed).
IEN 86-27 Access Control at Nuclear Facilities IEN 86-33 Information for Licensee Regarding the Chernobyl Plant IEN 86-35 Fire in Compressible Material
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IEN 86-39 Failures of RHR Motors and Pump Internals l
11.
Inspector Followup Items (92701)
Inspector Followup Items (IFIs) are matters of concern to the inspector which are documented and tracked in inspection reports to allow further review and evaluation by the inspector.
The following IFIs have been reviewed and evaluated by the inspector. The inspector has either resolved the concern identified, determined that the licensee has performed adequately in the area, and/or determined that actions taken by the licensee have resolved the concern.
IFIs (Closed) IFI 327,328/86-19-07:
Diesel generator cooling water throttle valves were discovered in the wrong position.
In plant training to preclude recurrence has been implemented.
(Closed) IFI 327,328/86-28-02:
Drawing control in the areas of unit applicability, drawing clarity, temporary changes and administrative procedures may not be adequately controlled.
Drawing control problems are being addressed by short term symptomatic fixes and long term programmatic changes.
(Closed) IFI 327,328/86-28-14: This item discussed the potential for common mode failure of the Safety Injection (SI) pumps should valve FCV-63-3 (common SI pump minimum recirculation isolation) be inadvertently shut.
This issue, addressed in IEN 85-94, was reviewed in detail by the inspectors.
The licensee currently has a monitor light (FCV-63-3 SIP MINI Closed) which
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indicates if this valve is in the. fully closed position. The associated monitor panel (XX-55-60 Monitor Lights Group B) containing lights for 17 safety related valves, has an associated annunciator (Group 2 Monitor Lights Component Off Normal) which alarms if any of the valves are out of position.
The facility drawings indicate that this circuit comes from a limit' switch actuating on actual valve position.
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The inspector reviewed the potential for damage of the pumps caused by FCV-63-3 being in a throttled position. This would have the valve out of alignment without annunciation of the fact. The licensee indicated that if the motor operator actuated, it would travel the full stroke closed and could not end up in a throttled position.
The licensee. $tated. that inadvertent misalignment would be unlikely, in that, the valve is in a high radiation contamination zone and is located in the overhead. In addition, a throttled valve would indicate throttled by the presence of a red and a green light on the coritrol room hand switch (HS-63-3A).
This item was discussed.with operations personnel, maintenance test engineers, and appropriate licensee management, and all agreed that the l
controls over valve FCV-63-3 are sufficient to maintain this valve in its desired position.
The licensee's corrective actions appeared to be adequate; therefore, this item is closed.
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The licensee's Corporate Commitment Tracking System was reviewed to determine it viability, extent and implementation.
The following documents were reviewed:
a.
TVA Nuclear Performance Plan submittal, dated March 10, 1986, Revised Corporate Plan
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TVA Nuclear Performance Plan submittal, dated July 17, 1986, Revised Sequoyah Plan c.
TVA memorandum L44 850919 805, Policy Regarding Control Over Making Commitments To The Nuclear Regulatory Commission, Tracking Commitments Through Implementation, and Maintaining Commitments Throughout Plant Life, dated September 26, 1985
d.
TVA memorandum L44 850927 801, Policy Regarding Control Over Making Commitments To The Nuclear Refulatory Commission, Tracking Commitments Through Implementation, and Maintaining Commitments Throughout Plant Life, dated October 2, 1985 e.
Standard Practice (SQA) 135, Commitment Tracking f.
NRC Inspection Reports 327,328/83-31-01, 327,328/85-23, 327,328/85-46, and 327,328/86-06
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NRC memorandum (Hays /Denton) dated March 24, 1986 The TVA Corporate Nuclear Performance Plan,Section IV.C.3 - Improvements in
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Commitment Tracking states that a Corporate Commitment Tracking System (CCTS)
has been implemented and is the responsibility of the Director of Nuclear Safety and Licensing.
The corporate Nuclear Licensing Staff was assigned the responsibility of making initial entries into the CCTS and ensuring that they
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have appropriate management review and approval.
Subsequent data submittal was processed in accordance with Standard Practice SQA 135.
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The inspector verified that the CCTS was implemented and that data entered
subsequent to initial entry activity was processed in accordance with SQA 135.
The data entered into the CCTS is independently verified for each NRC commitment by the site Compliance and Licensing Section through the use of SQA 135 prescribed commitment verification and completion input. form. In addition, the site Compli-
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ance and Licensing Section verifies the data content of CCTS line items with the
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commitment verification and completion input form data which was forwarded to
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corporate Nuclear Safety and Licensing staff.
Data entry into the CCTS appears
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i The inspector verified that multiple commitments resulting from a single NRC issue (e.g., training, modification completion, and procedure revision) receive
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separate CCTS identifications, are assigned to the appropriate managers for resolution, and are closed individually.
In instances where single commit: rents
have several facets requiring action from more than one TVA manager, TVA l
employs internal controls (TROI, MATS, and CATS) programs) to ensure ccmpletion
of all facets prior to commitment closure. CCTS tracking and resolution of multiple commitments appears to be adequate.
The Division of Quality Assurance participation in accordance with the Nuclear Quality Assurance Manual, Part III, Section 7.2 was reviewed. Quality Assurance
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verification of corrective actions taken by the licensee is implemented by SQA 135. QA verification is required for Licensee Event Report and Part 21 Report commitments.
QA conducts reviews, on a requested basis, of some corrective l
actions identified in the CCTS. QA involvement could be strengthened to include
routine audits of the CCTS.
QA involvement appears to meet the minimum require-i ments and appears to be adequate.
The definition of a commitment per TVA memorandum L44 850927 801 is a written j
and docketed statement of TVA actions taken or to be taken by some future date.
The initial version of the CCTS did not address issues which were resolved 3~
through TVA corrective action prior to the issuance of the NRC inspection report which identified the violation or deviation.
If the item was corrected prior to the NRC inspection report issuance, corrective actions are not loaded into the CCTS. The present CCTS has the capacity to load "open, closed, and hold" issues.
The initial version of the CCTS did not maintain status on commitments that had l
no outstanding issues. The present CCTS maintains the status of both open and
closed commitments. The CCTS has the capability to print an open only status list or an open and closed status list. The information retrieval capability of the
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l CCTS appears to be adequate.
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The licensee committed in the Sequoyah Nuclear Performance Plan (unrevised)
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to review past violation responses, IE Bulletin responses, Licensee Event
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i Reports, and NUREG-0737 items back to January 1, 1981.
This action was
intended to establish a data base for the CCTS, and is in process, however, it
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l is not complete. The review appears to be progressing at an acceptable rate i
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and has been identified as an item which must be completed prior to unit i
startup by the licensee.
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12. Review of Facility Operating License (FOL) Conditions, and NUREG-0737 (TMI-2
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Action Plan Commitments) (25565)
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a.
NUREG-0737, Item II.F.1.2.,
Postaccident High-Range Noble Gas and
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Gaseous Effluent Monitoring for Radioactive Iodines and Particulates The inspectors reviewed the licensee's installed equipment to verify
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their compliance with the requirements of a December 10, 1980 letter to.
the NRC. Further review of correspondence between TVA and NRC on this
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item had been identified previously as IFI 327,328/85-43-07.
This review indicated that the licensee's response was ambiguous in that the licensee committed to redundant systems in one.part of_the response and
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in another part stated that the system would only meet the NUREG-0737
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requirements which do not require redundant systems.
The monitors
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installed at Sequoyah are not redundant but do meet the requirements of NUREG-0737.
Other commitments made in the December 10, 1980 letter have also been verified by the licensee.
IFI 327,328/85-43-07 is closed.
Item II.F.1.2 is closed.
During the inspection, the licensee stated that a request would be submitted in the future to change the basic design of the monitors to i
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provide more reliable post-accident radiation monitoring.
This is identified as IFI 327,328/86-31-05.
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b.
TMI Task Action Plan Item II.F.1.2.e - Containment Water Level The inspector reviewed questions raised in Unresolved Item 327,328/
86-28-15 about the containment sump level transtaitters.
The containment sump level transmitters were installed and operating on
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both Units prior to cycle one. Since this time, these Barton model 764 pressure transmitters were found out of. tolerance during the refueling outage calibrations an average of 76% of the time.
The inspector reviewed the following procedures:
i SI-202 Calibration of Safety Injection System Instruments I
(Refueling Outage)
i IMI-63 Safety Injection System SI-2 Shift Log
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SI-98.4 Channel Calibration for Engineered Safety Feature Instrumentation Containment Sump (Refueling Outage)
IMI-135 Maintenance Guidelines for 10CFR50.49 Instrumentation i
IMS-13 Control and Use of Measuring and Test Equipment i
j AI-12 Adverse Conditions and Corrective Actions
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System Description Each channel of the containment sump level system consists of a Barton 764 level transmitter, a filled reference / sense line and a Barton 351
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bellows assembly. A pressure tap is open to 'the'sqal@6t approximately' G six inches above the containment f-loor and penetrates the missile ~ 2
barrier (polar crane wall).
Outside - the mi'ssile barrier is a root valve and then the bellows assembly. The other side of the bellows is contacted by a closed oil-filled sense line, originally filled with water until June 1982. The sense line is then routed up approximately 18 feet to the pressure transmitter. The other side of the transmitter is vented to containment atmosphere and therefore can detect
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containment sump level changes.
These instruments are required by TS and License Conditions [ numbers
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2.C.(23) D.(2) for Unit 1 and 2.C.(16)l.(2)(c) for Unit-2] to be
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operable as Post Accident Monitoring (PAM) instrumentation.
In addition, the TSs require these instruments to be operable for the
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Residual Heat Removal System (RHR) while operating in Low Pressure
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Injection Mode. The containment sump level system bistables provide a
confirmation signal prior to switching over the RHR suction from the Refueling Water Storage Tank (RWST) to the containment _ sump. This TS q-limit is 30 inches + 2.5 inches above the containment floor. During a Design Basis LOCA the switch would occur when the sump level reaches
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13.2 feet, and the recirculation mode would begin as stated in section 6.3.2.2 of the Sequoyah FSAR.
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Modifications
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During the first and second outages on Unit one (November 13, 1980 and February 1, 1982, respectively), surveillance testing showed more
than one-half of the transmitters to be out of tolerance. On Unit 2,
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one of three transmitters calibrated were found out of tolerance during the cycle one outage on February 15, 1981.
l On March 15, 1982, the Instrument Maintenance Section at Sequoyah wrote SQ-DCR-1531 (Sequoyah - Design Change Request) to replace the existing i
containment sump level system with a more reliable system. The ' request stated that six bellows had been replaced since 1980. The plant site wrote another memo to the central office on February 10, 1984, discussing the continual failures and requesting that they continue to process the DCR in an expeditious manner. This issue was not resolved I
until November 26, 1984, as discussed below.
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In June 1982, during review of bellows failures identified at another i
utility, TVA determined that Sequoyah also had a design problem with the water filled sense lines.
The bellows at the low point in the
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system is open to the containment atmosphere.
The normal ambient i
containment pressure is approximately 13.9 psia. Therefore, -the water filled sense line near the transmitter is under a pressure of i
approximately 6 psia due to the negative head from the 18 feet of water pulling down on the transmitter. Because the saturation temperature of'
i-the water at 6 psia is only 170 degrees Fahrenheit (F), flashing of the
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sense line water.was expected during a design basis or Main Steam Line l
Break which anticipates approximately 300 degrees F in contafament.
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Westinghouse was contacted regarding this issue.
The NRC issued a TS i
amendment to allow operations for 30 days, starting on June 18, 1982.
During this period Westinghouse refilled the transmitters with oil.
Subsequently, Westinghouse issued NSID. Data Letter (DL) 82-12 on
September 28, 1982, discussing these issues.
The following year Technical Bulletin NSD-TB-83-07 was published on June 29, 1983, which instructs licensees to fill these systems with Dow Corning 702 silicone
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oil, which has a higher boiling temperature than water.
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Following the refill with silicone oil the licensee stated that they did not continue to experience the bellows failures.
However, air inleakage problems caused by the negative pressure at the top of the sense line continued to be an issue. Sequoyah's short term response to this problem was to " top-off" the line per a Barton approved procedure, and re-calibrate the transmitter.
In the fall of 1983, TVA wrote a Potential Warranty Claim (8027) to Westinghouse because of the continual failures of sump level j
transmitters caused by air ingression into the filled system. TVA was
notified informally through phone conversations with Barton that the modified Barton Double 0-ring transmitters under development should eliminate the air inleakage problems.
In December 1983, Westinghouse issued Technical Bulletin NSD-TB-83-12
reiterating that the modified Double 0-ring transmitter from Barton
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should correct the continual failures. The Bulletin further suggested that in the interim the licensee should monitor the containment sump level indication closely.
TVA determined that their channel check, done once per shift, should detect any major air inleakage.
On February 13 and 15, 1984, and again on May 23, 1984, TVA wrote letters to Westinghouse requesting that they replace the existing
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transmitters with the new double 0-ring type and refill the systems
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under Warranty Claim B027.
On March 15, 1984, Westinghouse
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acknowledged receipt of the first two letters and committed to respond by April 13, 1984.
The licensee stated that no response was received from Westinghouse.
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On November 26, 1984, a TVA letter was sent from Sequoyah Site Design
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Services (SDS) to Sequoyah Project Manager stating that after review of the cost estimates ($1.4 million) the Design Change Request SQ-DCR-15-31 to replace the system with a more reliable system design
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was being cancelled.
The letter went on to state that SDS was
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continuing to pursue the Barton transmitter upgrade.
TVA stated in this letter that, "According to the evaluation made by Westinghouse, the modified transmitters using double 0-rings in the differential
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pressure unit (DPV) could solve the air leakage problem."
In November 1984, two double 0 ring transmitters were procured by plant
maintenance personnel and installed on Unit 2.
In December 1985,
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Purchase Requisition 371523 was initiated to purchase 9 Barton 764 transmitters with the double 0-ring DPV to replace the existing
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transmitters during Unit one, Cycle four and Unit two, Cycle four refueling outages.
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Licensee Event Reports In 1981, LER 80-91 on Unit I was written to report an instrument'found to be out of tolerance during a channel check.
During 1981 five LERs (1-81-9, 1-81-40, 2-81-116, 2-81-135, and 1-81-151) were written
'j discussing instrument drift and out of calibration conditions found during the TS required channel checks. These~ events were attributed to instrument drift or leaking fill lines.
In early 1982 another LER, number 82-26 was written on leaking fill systems in these level units.
LER 82-70 on Unit I was written on July 1,1982, to address a problem i
discovered during the review of the level transmitters. This design problem with the water filled sense lines is discussed in the modifications section above.
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Four ' times in 1983, LERs were written to the Commission addressing problems with air inleakage leading to channel inoperability. These
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LERs were numbers 2-83-15, 2-83-30, 2-83-97, and 2-83-130.
In LER i
2-83-130 the licensee committed to write a followup report after the j
investigation has been completed.
Issuance of this report is still j
pending.
l LER 2-83-140 discussed the sump level channels being out of tolerance in mode 5.
This was found during performance of SI-202 as described in the calibration section of this report.
The changes in NRC reporting requirements greatly reduced the number of LERs reported on Containment Sump Level.
Two LERs have been written
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since the reporting criteria changed.
LER 1-84-5 was written when it
was determined that the TS surveillance interval for performing this SI (1.25 times 18 months) was exceeded.
Finally, on March 28, 1986, the
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TVA TS review team discovered that the sump level bistables were being
set out of tolerance. During construction the design elevation of the sump floor was changed three inches. This was never reflected in the RHR system RWST to sump swapover setpoint calculation.
This was reported to the Commission in LER 1-86-11.
TVA continued to pursue the modified transmitters as the solution to
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the-Containment Sump Level systems' calibration problems.
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justified that the system continued to be operable as demonstrated by the channel checks. The channel check performed in SI-2 compares all four level indicators every shift.
The inspector noted several times that these transmitters were found to be out of calibration and corrected as a result of the channel check.
Calibration problems Following the refill of these instrument loops with oil, the system i
continued to be found out of tolerance during surveillance calibrations.
These problems appear to be caused by two different sources of error. Air inleakage is being pursued by the licensee as
the major problem. Air inleakage into the sense lines will cause the
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system to indicate a higher sump level than actual and therefore actuate at a lower sump level. (For ease of explanation this will be
j referred to as the " sump high" direction.)
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However, on December 18, 1983, during a normal performance of SI-202, Calibration of Safety Injection System Instruments (Refueling Outage),
one transmitter in Unit one was found to be out of tolerance in the low direction. This can most likely be attributed to instrument drift.
Because the control room indications noisaH9Wead zero percent of scale, this out-of-tolerance situation could not be and was not detected by the channel checks. These channel checks only determine if the control room indication is within + 6% of the other channels.
Including instrument accuracy, the system could be well outside of TS limits before it is detected.
Additionally, on August 27, 1983, and November 11, 1984, during performances of SI-202 in Unit 2, one of four and three of four instruments, respectively, were found out of tolerance in the low direction.
During the August 27 performance, the remaining three transmitters were four.d out-of-tolerance in the sump level high direction.
However, the inspector found no documentation of this situation being detected by the channel check. Additionally, on November 30, 1984, and December 18, 1983, one instrument, required addition of oil to the filled system.
In November 1984, two double 0-rirg transmitters were installed in Unit 2 as discussed above. During the first refueling outage following these new installations, SI-202 was performed on October 9, 1985. All four transmitters (two double 0-ring and two original) were found to be below the lower TS tolerance.
In all cases above, the out of tolerance instruments were simply re-calibrated and returned to service. The documentation was reviewed by the Instrument Engineer and the deficiency logs were olaced in his personal files.
This information, however, was never oscalated in management, formally tracked, or reviewed by operations parsonnel.
In summary the following complete performances have been Jone at Sequoyah:
Unit 1 Unit 2 Date Instruments Date
.nstruments Out of Out of Tolerance Tolerance l
11/13/80 3 of 4 02/15/81 1 of 3 l
02/01/82 2 of 3 08/27/83 4 of 4 i
12/06/83 1 of 3 11/30/84 4 of 4 l
10/09/85 4 of 4 l
l Management Review
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In discussions with Regulatory Compliance personnel the inspector was informed that all instruments out of TS tolerance are to be reported in
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accordance with AI-12. AI-12 describes Test Deficiencies as methods of l
reporting and document 1ng Conditions Adverse to Quality (CAQ). AI-12 l
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states that, "Section Supervisors are responsible for evaluating each reported CAQ and initiating corrective action in a timely manner. CAQs shall be screened by Section Supervisors to determine whether they may
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constitute significant CAQs...".
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i The Deficiency Logs written for the above addressed out of tolerance situations were not reviewed by the-Section Supervisor. This review I
was done by the Instrument Engineer who is two levels of management-
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below the Section Supervisor.
The licensee stated that the review j
required by AI-12 was delegated by the Section Supervisor to the l
Instrument Engineer. Delegation of this responsibility could result in failure to escalate problems to management and inconsistent screening
of CAQs for significance.
The cover page of an SI-202 performance, step 3.6, questions, "Did all SI data meet acceptance criteria Yes No. If criteria was not satisfied, notify the Shift Engineer who completes Regulatory Compliance Section.
The acceptar.ce criteria in Item 4.1 of SI-202 states, " Instruments and instrument loops in IMI-63, Appendix-A have j
been calibrated, left within tolerances and returned to service." The procedure does not require the Shift Engineer be notified if an instrument is found out of TS tolerance.
A new revision to SI-1, Surveillance Program - Units 1 and 2, was written with the intent of
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assuring higher level reviews of instruments found out of tolerance.
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However, licensee personnel agreed that the new revision could permit the existing practices to continue.
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I During an interview, the Instrument Engineer stated that he would not report to his management or operations any instrument found out of TS tolerance if the plant mode did not require the specification be in effect. Therefore, a containment sump level transmitter found out of tolerance would not be escalated as a potential problem because the
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transmitters are always calibrated during refueling outages (Modes
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5&6). The inspector will review the requirements to evaluate all out of TS tolerance conditions for reportability under 10 CFR 50.72.
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The lack of trending and management review of this problem will be i
reviewed to determine to what extent these reporting problems exist i
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throughout the surveillance program.
At this time 'the inspector is
only aware of the problem with the instruments in IMI-63.
This includes the TS process instrumentation in the Safety Injection System.
The licensee stated that a draft revision to SQA-84, Reportable Occurrences, will formalize and clarify to the Instrument Maintenance section the procedure for documenting an instrument found out of tolerance.
This item will be tracked as part of Unresolved Item 327,328/86-28-15.
During an initial interview with the Instrument Maintenance Engineering
Supervisor and the Instrument Engineer, the inspector noted that these
individuals did not appear to be aware that these instruments continued
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to be found out of tolerance in the low direction. They were also l
still working on the air inleakage problem as the root cause of the
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sump level system problems.
They stated that " Ray-Chem" heat i
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shrinkable tubing was being used to seal around the fill valve on the sense line. They also discussed the use of seal welding similar valves shut in the pressurizer level control system. They expressed concerr.
that this would not solve the problem and that it could just increase the difficulty and risk of at power system maintenance.
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Other Instruments Out of Calibration As part of the Containment Sump Level System the inspector reviewed completed performances of SI-202.
During this review the inspector identified that several instruments in the Safety Injection (SI) system were found out of procedural tolerance. Some of these instruments were also out of TS tolerance.
TSs did not address a tolerance for other instruments required to be operable.
The SI instruments out of tolerance conditions will be reviewed as part cf Unresolved Item 327,328/86-28-15.
Equipment Qualifications The inspector reviewed Equipment Qualifications binder XMTR-001 and verified that the required maintenance was prescribed in the procedures listed above.
Measuring and Test Eouipment On March 17, 1986, the licensee determined that Heise model 710B-digital pressure gage No. 522051 was out of calibration. The gage had been used to calibrate the sump level transmitter 1-LT-63-179. Work Request (WR) No. 124769 was written to re-check the calibration of this instrument. The instrument calibration was found to be in calibration on May 5, 1986.
Licensee procedure IMS-13, Control and Use of Measuring & Test Equipment, which controls this procedure was reviewed during this inspection.
No concerns were identified.
Stress Corrosion Cracking Westinghouse Technical Bulletin 83-07 (see above) addressed the need to process the silicone oil to assure that Stress Corrosion Cracking (SCC)
and pitting of the stainless steel beltows does not occur.
The bulletin stated that the reduction of the moisture content to less than 10 parts per million was necessary to assure that the fluorides and chlorides in the silicone oil would not interact with the stainless steel material.
As air inleakage continued to be a problem the licensee developed a procedure (addressed under modifications above) to " top-off" these lines rather than perform a complete drain evacuation and re-fill of the sense lines. This procedure, although sufficient for adding oil to the line, does not appear to address the potential for moisture entrainment from the containment atmosphere leaking into these lines.
The leakage allows a path for moisture to enter the oil in the line and yet this oil is not reprocessed to remove the moisture as it was before the initial filling.
This item will be reviewed by the inspector and will be tracked as Inspector Followup Item IFI 327,328/86-31-06.
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TMI item II.F.1.2.e and unresolved item 327,328/86-28-15 remain open pending review of the above concerns.
13.
Operating Experience Review (90714)
ReviewofaSignificantConditionReport(SCk)IdentifiedatWattsBar a.
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An SCR from Watts Bar Nuclear Plant (SCR WBN-MEB-8620) was reviewed by the inspectors for verification of the review process at Sequoyah. The review and actions taken by the licensee appeared adequate.
The SCR l
described the potential for losing water from the ECCS Recirculation sump through floor drains to the Auxiliary Containment Sump, and from there through openings in the sump's level transmitter standpipe to the containment raceway.
As a result of the review performed by the Sequoyah staff, the licensee
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l discovered a potential problem with level transmitters associated with
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the Auxiliary Reactor Building Sump. The standpipes supporting the
level transmitters are capped with a flange which serves as the j
mounting plates for the transmitters. A modification to the transmitters for Unit 2 involved adding a vent tube to allow air displaced by rising water in the standpipe to be vented to a point above-the minimum ECCS sump level. This modification was required to
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make the transmitters operate correctly. The transmitters associated
with Unit I have not had this modification performed, but the
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transmitters appear to be operating correc tly. Since the Unit 2
transmitters required a special vent, the arrangement of the standpipes on Unit 1 is questionable. The licensee is presently evaluating whether
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the Unit 1 standpipes have a vent path that is not described on their prints or work plans. This will be followed as IFI.327,328/86-31-07.
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b.
Review of Part 21 Reoorts Applicable to Sequoyah Units 1 and 2 l
(Closed) P2185-03:
Defective Bar Graph Latchup on Technology for Energy Corporation (TEC) Valve Flow Monitor Module.
The licensee tested modules utilized at Sequoyah as recommended by TEC and no
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failures were identified.
TEC stated that the latchup defect, if
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present in the module, would be indicated. by the special test and
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subsequent testing was not required. This item is closed for Units 1 and 2.
(0 pen) P2185-04: AK and AKR Type Low Voltage Power Circuit Breakers.
The licensee's document search indicates that this item has not been evaluated at Sequoyah. The vendor's September 13,1985 letter indicates
that the licensee was to be informed in a service letter. The licensee is determining if the problem was reviewed and dispositioned in the Division of Nuclear Engineering. This is applicable to Units 1 and 2
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and is identified as IFI 327,328/86-31-08,
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