IR 05000327/1981016
| ML19350E701 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 04/24/1981 |
| From: | Butler S, Ford E, Quick D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19350E549 | List: |
| References | |
| 50-327-81-16, 50-328-81-16, NUDOCS 8106230454 | |
| Download: ML19350E701 (10) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA ST., N.W.. SulTE 3100 o,
ATLANTA, G EORGIA 30303
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Report Nos. 50-327/81-16 and 50-328/81-16 Licensee: Tennessee Valley Authority 500A Chestnut Street Chattanooga, TN 37401 Facility Name: Sequoyah Nuclear Plant Docket Nos. 50-327 and 50-328 License Nos. DPR-77 and CPPR-73 Inspection at Sequo Nuclear Plant near Soddy Daisy, Tennessee Inspectors:
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Approved by:
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D. Quick, Sect %n~ Chief., RRPI Section Date Signed SUMMARY Inspection on March 6, - April 5,1981 Areas Inspected This routine, unannounced inspection involved 240 inspector-hours on site in the areas of Operational Safety Verification, Inspection and Enforcement Bulletin Review, Unit 2 Preoperational Testing and Completion Status, Plant Incidents and Independent Inspection effort.
Results
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Of the five areas inspected, no violations or deviations were identified in four areas ; two violations were found in one area (Viola:. ion - Failure to use properly calibrated test equipment (327/81-16-01-section 5) Violation - Failure to maintain two trains of auxiliary building gas treatment system operable (327/81-16-02-section5).
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DETAILS
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1.
Persons Contacted
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Licensee Employees J. M. Ballentine, Plant Superintendent C. E. Cantrell Assistant Plant Superintendent W. T. Cottle, A;sistant Plant Superintendent
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J. M. McGriff, Assistant Plant Superintendent J. W. Doty, Maintenance Supervisor (M)
B. M. Patterson, Maintenance Supervisor (I)
W. A. Watson, Maintenance Supervisor (E)
D. J. Record, Operations Supervisor W. H. Kinsey, Results Supervisor R. J. Kitts, Health Physics Supervisor C. R. Brimer, Outage Director R. S. Kaplan, Supervisor, Public Safety Services W. M. Halley, Preoperational Test Supervisor D. O. McCloud, Quality Assurance Supervisor l
Other licensee employees contacted included construction craftsmen,
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technicians, operators, shift engineers, security force members, engineers, maintenance personnel, contractor personnel, and corporate office personnel.
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Other Organizations Five inspectors, Office of Inspection and Enforcement, Region II, three licensee examiners, Operator Licensing Board, Office of Nuclear Reactor Regulat. inn.
2.
Exit Interview The inspection scope and findings were summarized with the Plar.t Super-intendent and members of his staff on March 27, 1981. The licensee acknow-ledged the findings.
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3.
Licensee Action on Previous Inspection Findings 7,
Not inspected.
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4.
Unresolved Items Unresolved items are matters about which information is required to determine whether they are acceptable or may involve nonccmpliance or
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deviations.
New unresolved items identified during this inspection are
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discussed in paragraph 9.
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5.
Operational Safaty Verification The inspector toured various areas of Unit 1 on a routine basis throughout the reporting period. The following activities were reviewed / verified:
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Adherer.:e to limiting conditions for operation which were directly observable from the control room panels.
b.
Control board instrumentation and recorder traces.
c.
Proper control room and shift manning.
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The use of approved operating procedures.
e.
Unit operator and shift engir eer logs.
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General shift operating practices.
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Housekeeping practices.
h.
Fire protection measures for hot work.
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Possi.1g of hold tags, caution tags and temporary alteration tags.
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Meesures to exclude foreign materials from entry into clean systems.
k; Personnel, package, and vehicle access control for the Unit 1 protected area.
1.
General shift security practices on post manning, vital area access control and security force response to alarms.
m.
Surveillance testing and startup testing in progress.
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Maintenance activities in progress.
In regard to a previous problem of electrical noise interferer.ce with the main turbine electrc-hydraulic control (EHC) system (ref, IE report 327/81-12, section 5), the licensee has been monitoring the EHC system since Unit I restart on March 12, 1981, for recurrence of the problem.
The licensee has reported that there has been no indication 'of erratic operation of the EHC system caused by electrical noise interference up to the present time and they believe that various modifications made to the system have t
adequately protected it from extraneous electrical noise interference.
On March 12, 1981, the inspector reviewed surveillance data collected on
. March 4,1)81, by Work Plan WP-9023, to determine if the requirements of 4.6.4.3 of Technical Specifications were satisfied for the hydrogen ignitor system. The data indicated that the ignitor system satisfied operability
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requirements, however. the optical pyrometer (TVA No. 495342) used to measure ignitor temperature was not calibrated.
The licensee discovered this on March 6, 1981, and generated a Special Maintenance Instruction, SMI 1-150-1,. to verify the accuracy of the optical pyrometer by comparing readings on selected ignitors to readings made with a cal!brated surface reading pyrometer. The optical pyrometer appeared to be accurate enough in the' range it was being used to ensure the ignitors met the tednical speci-fication operability requirements.
The licensee indicated they could not properly calibrate the opti::al pyrometer until a special calibration set was obtained. The set is on order from the manufacturer.
The use of uncali-brated measuring and testing devices in an cctivity affecting quality is a violation of 10 CFR 50, Appendix B, Criterion XII (327/81-16-01).
On March 16, 1981, the inspector observed the replacement of the motor bearings on the IA-A motor driven auxiliary feedwater pump. The bearings were being replaced because the fiberglass bushing on one of the bearing caps was deteriorating and causing excessive noise and affecting the oil seals for the bearing. The inspector observed the craftsmen and cognizant engineer performing the work and questioned them to determine the level of experience and faciliarity with the technical manual. requirements for installing and adjusting the motor bearings. The power stores requisition was examined to cetermine if the replacement parts had been properly procured.
Following reassembly of the motor the inspector observed the initial start, vibration measurements and run-in of the bearings.
The bearing temperature appeared to increase to a normal value and remain constant as expected. Motor vibration was normal.
On March 18, 1981, the inspector observed the calibration check of dif-ferential pressure switch 1-PD15-1-17A. This pressure switch monitors steam flow to the turbine of the turbine driven auxiliary feedwater (AFW) pump and functions to shut the AFW isolation valve when steam flow reaches an excessive value, indicating the line has ruptured. The pressure switch wcs being checked for proper calibration because the isolation valve was shutting prematurely and had to be reopened manually from the control room to operate the pump. fhe instrument mechanics had the. proper calibration data and maintenance request. However, they indicated, that no detailed procedure was available to calibrate this type of differential pressure swi t':h.
One of the instrument mechanics was a journeyman and one was an apprentice.
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The inspector discussed this matter with the instrument supervisor and expressed nis concern over the lack of precedural control for calibration of this type of equipment. He indicated that the instrument mechanics appeared to be having difficul / checking the calibration of the switch in that they had to try several methods before obtaining satisfactory results.
The instrument supervisor indicated that he considered this type of calibration to be within the skill of their instrument mechanics since they received training in this area as part of their overall training and qualification program. He agreed to discuss this matter with the mechanics involved and
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review their p'rogran to determine if the need for further procedural controls are necessary.
The inspector will continue to review the licensee's program for. procedural control of instrument calibration in future inspections.
The differential pressur - switch setpoint was sub-sequently raised to a higher value with the concurrence of the licensee's engineering design group to ensure tnat the valve would close on an actual rupture of the steam line and not because of transients that occurred during pump starting.
During a review of St.rveillance Instruction, SI-166.1, involving stroke time testing of containment isolation valves, the inspector noted that the response time criteria for the radiation monitoring valves (system 90) was 10 seconds instead of the 5 seconds required by technical specifications.
The inspector brought this to the attention of the Results Supervisor who took measures to change the SI to incorp e te the correct response time for
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these valves and review the critaria for o h valves to ensure that there were no similar errors. The inspector reviewed response times recorded for these valves since Unit licensing.
No instance could be found where they
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exceeded the technical specification limit of five seconds.
The licensee could offer no explaination for tne error.
On March 25, 1981, the inspector was informed by the licensee that both trains of Auxiliary Buildir.g Gas Treatment System (ABGTS) had been inoper-able for approximately twelve hours with Unit 1 at 98% power. The 28-B diesel generator which would supply backup power to B train ABGTS was tagged out for surveillance testing early on March 24.
Later in the day, on March 24, the shift engineer allowed A train ABGTS to be disabled to work on a suction damper assuming that B train could still be considered operable in accordance with 'echnical Specification 3.0.5.
This error was discovered at 0030 on March 25. The A train ABGTS was restored to operable status at 0125
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on March 25, in compliance with TNhnical Specification 3.0.3.
Power operation with both trains of ABGTS inoperable is a violation of Technical Specification 3.7.8.1 (327/81-16-02).
The licensee has taken steps to ensure the responsible personnel are familiar with the applicability of Technical Specification 3.0.5, which allows continued operability without backup emergency power availability.
On March 28, 1981, the licensee performed a temporary alteration of pressurizer level channel 1-68-339.
The channel had developed.a constant offset, indicatina 15% lower than the other two channels, due to a vent line that had been installed off the top of the associated condensing pot during a previous outage.
The vent line had filled with water increasing the reference head of the instrument and causing it to read 15% low. The licensee had performed testing to verify that the offset was constant and that the channel accurately indicated changes in pressurizer level.
The temporary change involved disconnecting two other transmitters that supplied indication to the backup control room and routing them to a different pressurizer level tap and rescaling channel 68-3'39 to indicate actual pressurizer level based en the new reference leg and read. justing the high
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pressurizer level reactor trip setpoint.
Following the alteration, a channel functional test was performad. The channel was declared operable on March 29.
The inspector reviewed Work Plan, WP 9117, and the safety evaluation per-formed as required by 10 CFR 50.59. The work was also discussed with the instrument supervisor and a Region II inspector, who also reviewed the temporary modification. On April 2, the inspectors noted that pressurizer level channel 68-339 was reading 7% higher than the other two channels indicating that tne instrument was not continuing to perform reliably. This was brought to the attention of the shift engineer who declared the channel inoperable and took the action required by Technical Specifications. This matter is still under consideration by' the inspectors.
No other violations or deviations were identified.
6.
Inspection and Enforcement Bulletin (IEB) Review IEB 80-24 was issued concerning Prevention of Damage due to Water Leakage inside containment.
The licensee's response was reviewed by Region II and Inspection and Enforcement Headquarters and a concern was expressed over the fact-that the alarm for high water level in the containment pit sump (CPS)
under the reactor vessel was not in the main control room.
The inspector obtained a commitment from the licensee to log the status of the CPS water level alarm each shift and report an alarm condition to the main control room.
This will be done until a final determination is made as to the adequacy of the licensee's response to IEB 80-24.
No violations or deviations were identified.
7.
Unit 2 Preoperational Testing and Completion Status During the reporting period the inspectors continued to review the status of Unit 2 preoperational testing, construction completion, resolution of construction deficiencies and open inspection items. The status of these items will be updated as work is completed and inspections performed.
The inspector reviewed the proposed Unit 2 Technical. Specification for accuracy and adequacy.
The inspector forwarded his comments 3o Region II for transmittal to Nuclear Regulatory Commission Headquafters.
The inspector discussed the adequacy of Sequoyah's Quality Assurance Program for Unit 2 operation with a Region II Quality Assurance specialist.
The inspector was informed that the following areas were satisfactory, based on previous inspections performed at the site:
1.
Preoperational Testing Quality Assurance (35301)
2.
Operational Staffing (36301)
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Preoperational Test Record (39301)
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0perating Staff Training (41301)
The following program areas were inspected and found to be satisfactory.
' Implementation will be examined during future inspections.
1.
QA Program - QA/QC Administration (35740)
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QA Pro 5 cam - Audit (35741)
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QA Program - Document Control (35742)
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QA program - Design Changes and Modification (35744)
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-QA Program - Procurement Control (35746)
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QA Program - Receipt, Storage and Handling of Equipment and Materials
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(35747)
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QA Program - Records (35748)
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QA Program - Test and Experiments (35749)
No violations or deviations were identified.
8.
Plant Incidents On March 9,1981, the inspector was informed by the licensee of a bomb threat note found in a trach can in the auxiliary building. The inspector verified that the proper actions were taken to inform the Nuclear Regulatory Commission per 10 CFR 50.71. The affected areas of the plant were evacuated and a search performed. A Region II safeguards specialist was kept informed of the licensee's response to the suspected threat.
The licensee sub-sequently determined that the note was written as a scenario to be used during a future training - excercise and was improperly discarded by the author.
The licensee indicated that in the future all such training material will be clearly marked as such to prevent a recurrence of this problem.
On March 14,1981, Unit 1 tripped from approximately 40% power. The trip was due to a failure of the air line to #3 steam generator main feed regulating valve. The valve failed shut on the loss of control air. The resulting loss of feedwater caused a reactor trip.
All systems appeared to operate as designed, however, approximately three minutes after the trip the Essential Raw Cooling Water (ERCW) valves that supply backup feed water to the Turbine Driven _ Auxiliary Feedwater pump opened automatically due to a low pressure transient on the pump suction.
ERCW was injected into all four steam generators. The licensee notified the Nuclear Regulatory Commission per 10 CFR 50.72.
In order to correct the out of specification chemistry of the steam generators, continuous blowdown was commenced and continued for approximately thirty-six hours with the unit in hot standby until steam generator chemistry was restored. The cause of the automatic shift to ERCW was determined to be an insufficient time delay in the low pressure circuitry which opens the valves. The time delay was increased to prevent recurrence. The licensee plans additional testing to determine if any
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further measures may be needed to prevent this problem.
The unit was'
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restarted when chemistry was restored in the steam generators.
On March 17, 1981, Unit I tripped from approximately 90% power. The trip was
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due to a dropped shutdown control rod. All systems appeared to operate properly. The Nuclear Regulatory Commission was rotified per 10 CFR 50.72.
Investigation by the licensee revealed an open cable to the affected rod
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motor.
Plant cooldown was required for. the repair.
When unit cooldown was completed and the missile shield removed, the licensee found that a snap connector had come loose and allowed the connector to corrode.
Inspection of other cables revealed no similcr problem on the othe'r rod motors.
The corroded connector was cleaned and replaced and the unit
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returned to power on March 21, 1981.
On March 22, 1981, the licensee detected a radioactive gas leak in the auxiliary building. The auxiliary building was evacuated of all unecessary personnel while surveys were being made and the source of the leak located.
Three persons were slightly contaminated. The source of contamination was determined to be an open sample valve in the Unit 2 hot sample room. The
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valve was shut and tagged. The highest activity levels detected were 6.82 MPC, gaseous, and 1.37 MPC, particulate. These levels were quickly dispersed or decayed off.
No release outside the auxiliary building was cetected.
The Nuclear R2gulatory Comnission was notified per 10 CFR 50.72.
No violations or deviations were identified.
9.
Independent Inspection Effort The inspector routinely attended the morning scheduling and staff meetings during the reporting period. These meetings provide a daily status report on the operational and testing activities in progress as well as a dis-cussion of significant problems or incidents associated with the start-up
.and preoperational testing and operations effort.
On March 20, 1981, the Nuclear Regulatory Commission (NRC) was notified by the licensee, persunant to 10 CFR 21, of a deficiency with the motor operators for Electrodyne valves. The deficiency involves the location of the compartment -heater in the operator. The heater is located in close proximity to the limit switch compartment and can cause a degradation of the limit switches which have cases constructed of,hard plastic.
Region II questioned the report in several areas including length of time to evaluate the problem and notify the responsible office in Tennessee Valley Authority (TVA), the licensee's justification for their corrective action and an accurate acc9unt of the number and location of Electrodyne valves at
the plant and the schedule for the completion of the licensee's corrective action.
.The problem was identified at the plant on February 4, 1981. An ints mal report was filed and the licensee evaluated the problem and formulated thsic
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corrective action. On February 19, the plant determined that the problem was reportable per 10 CFR 21 and the TVA corporate office received this determination on February 20.
This initial evaluation period by licensee personnel at the plant is not considered excessive by the inspector in this particular instance because of the work load on the plant staff due to the Unit 1 outage that began on Februa ry 6, and the inadvertant spray down of the Unit I containment which took place on February 11. However, once the corporate office received notification, the " responsible office," as defined by 10 CFR 21, was not properly notified of the defect until March 19. Once the " responsible officer" had been notified, the NRC was notified per 10 CFR 21. The inspector does not believe that the excessive period of time from when the plant staff determined the matter to be reportable until the
" responsible officer" was notified complies with the intent of 10 CFR 21 or can be considered as part of the evaluation period which is allowed for.
This will remain as an unresolved item (327/81-16-03) until further infor-mation is obtained from the licensee regarding the cause of the excessive delay and their corrective action.
The inspector reviewed the actual defect in the Electrodyne valve motor operators and the - licensee's corrective action.
The defect involved a resistance heater which is located directly adjacent to the limit switch compartment which is made of hard plastic and susceptible to failure from
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the heat.
The problem is complicated by the fact that the heater is designed to operate at 120 VAC and was operating at 135 VAC due to elevated voltage on the plants distribution system. The licensee is not certain if this is a contributing factor to the problem. After a safety evaluation was performed, as required by 10 CFR 50.59, the licensee determined that the heaters could be disconnected. This determination was based on the valve's location in the auxiliary building in a controlled environment where con-densation and moisture would not be a severe problem.
The heaters were disconnected using the plant's temporary change procedure and a design change request was submitted to the licensee's engineering design group for permanent corrective action. Discussion with engineering design personnel indicated that it was standard licensee policy to have heaters in the operators of limit switch valves. The design group had not decided if they will concur with leaving the heaters out of the operators permanently or
replacing them with a smaller heater and/or relocating the heater in the operatcr housing. The inspector will review the licensee's final deter-mination before an evaluation is made on the adequacy of their corrective ' action.
There was some confusion involved with'The actual number of valves involved at Sequoyah and' the schedule.. for discon-
necting the heaters and replacing any limit switch assemblies, f f-necessary.
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The inspector discussti this with the plant maintenance staff to clarify this matter and a corrected report was filed by the licensee.
No violations or deviations were identified.
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