IR 05000219/1980025
| ML19351D364 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 08/19/1980 |
| From: | Briggs L, Keimig R, John Thomas NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19351D361 | List: |
| References | |
| 50-219-80-25, NUDOCS 8010100030 | |
| Download: ML19351D364 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 50-219/80-25 Docket No. _50-219
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License No. DPR-16 Priority Category C
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Licensee:
Jersey Central Pcwer and Light Company Madison Avenue at Punch Bowl Road
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Morristown, New Jersey 07960 Facility Name: Oyster Creek Nuclear Generatin9 Station Inspection at: Forked River, New Jersey Inspection conducted: July 9 - August 1,198 Inspectors:
M~fd Briggs, nlor H Keactor Inspector date signed LO
, Resident Reactor Inspector ehs/so V
Thomas
'dat'e signed J
date signed
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Approved by:
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R.i(eimig[ Chief,RpftorProjects date signed Section M.1, RO&NMranch Inspection Summary:
Inspection on July 9 - August 1,1980 (Report No. 50-219/80-25)
Areas Inspected:
Routine inspection by the resident inspectors (139 hours0.00161 days <br />0.0386 hours <br />2.29828e-4 weeks <br />5.28895e-5 months <br />) of:
followup of operational events that occurred during the inspection; review of plant operations (startup); tours of the facility; log and record reviews; and followup of IE Bulletins and Circulars.
Results:
No items of noncompliance were identified.
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Region I Form 12 (Rev. April 77)
8010100 0 3 o
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t DETAILS 1.
Persons Contacted
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J. Carroll, Station Manager K. Fickeissen Support Superintendent
W. Garvey, Director, Station Administration E. Growney, Engineering Supervisor, Acting
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T. Johnson, Supervisor, Station I&E Maintenance
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J. Maloney, Operations Supervisor
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J. Sullivan, Plant Superintendent
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The inspectors also interviewed other licensee personnel during the
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course of the inspection including management, clerical, maintenance, and operations personnel.
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Operational Events
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On July 17,1980 at 8:35 p.m. during power ascension following plant startup, operators attempted to control reactor pressure by operation of the steam bypass valves (BPV's).
The operators reduced the pressure setpoints on both the mechanical pressure regulator (MPR)
and the electrical pressure regulator (EPR) but the BPV's failed to
open.
Control rod insertion was begun, but before the heatup and
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pressure increase could be tenninated, one electromatic relief valve (ERV)
opened at a reactor pressure of 1050 psig.
In about 20 seconds
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t pressure decreased to 1000 psig. and the ERV reseated. When the ERV shut, a spurious automatic isolation of the reactor building closed
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cooling water (RBCCW) system occurred. The RBCCW isolation was immediately reset and flow restored. As reactor system pressure again increased, it was determined that the low condenser vacuun trip
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number 2 miSht not be properly reset even though the trip reset light was energized. The trip reset was actuated by the operator. This
' action caused all nine BPV's to open fully. As reactor pressure
. decreased rapidly due to opening of the BPV's the operator tripped shut the BPV's. The resultant pressure transient caused a momentary
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triple low water level indication (Technical Specification value of 4 feet 8 inches or greater above the top of the active fuel) on the event recorder followed 24 seconds later by a reactor water low level scram (Technical Specification value of greater than 11 feet 5 inches above the top of the active fuel).
Following the incident a thorough review was conducted by the inspector and licensee representatives of the' instrument reorder charts, the event recorder chart, and the
. process computer print-out.
In addition, interviews were conducted i
with the on-shift reactor operators and supervisors. The investigation led to the following conclusions:
i The recirculation loop isolation valves remained open on all
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five loops allowing sufficient water flow between the core and
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annulus regions to provide accurate water level indication on both the Yarway and GEMAC instruments.
Indicated water level on these instruments, which have both reference and variable taps in the annulus region, did not go lower than 6 inches below the low level scram setpoint.
No alarm actuations, automatic containment isolations, or
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emergency core cooling system actuations that would have indicated a double low water level condition (7 feet 2 inches above the top of the active fuel) occurred.
No isolation of the RBCCW system occurred at the time of the
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event recorder indication of triple low water level.
The triple low water level indicated by the event recorder was
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apparently caused by a hydraulic disturbance in the annulus area of the reactor vessel resulting from :apid closure of the BPV's. The triple low level sensor is a differential pressure switch with a high pressure tap on the core spray system sparger in the core area and a low pressure tap in the annulus area.
When the BPV's closed, the rapid pressure increase in the steam headers and the annulus region in conjunction with the time lag associated with equalization of pressure across the steam dryers, caused the pressure in the annulus to be momentarily higher than the pressure in the core region.
This caused a momentary erroneous indication of triple low water level that activated the event recorder. The indication was of short enough duration that the electrical relays in the RBCCW isolation circuit were not activated.
Subsequent surveillance testing was performed on the RBCCW isolation system to determine the cause of the momentary RBCCW isolation upon closure of the electromatic relief valve.
All isolation actuation signals (triple low water level by itself or double low water level with high drywell pressure) were tested and no malfunctions were found. The cause of the RBCCW isolation was determined to be a spurious momentary actuation of the isolation circuitry.
Investigation of the malfunction of the low condenser vacuum trip revealed that misadjustment of a limit switch on the trip mechanism caused the indicating lights in the control room to indicate the trip as reset when in fact it was not.
The limit switch was adjusted and the low condenser vacuum trip was tested satisfactorily.
The licensee has agreed to change Procedure 201.2, " Plant Heatup to Hot Standby", to require verification of bypass valve operability prior to reaching full operating pressure j
to preclude recurrence of pressure control problems on startup.
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This item is unresolved pending licensee revision of Procedure 201.2 andsubsequentNRCreview(219/80-25-01).
The inspector had no further questions on this matter.
3.
Review of Plant Operations (Startup)
a.
A review of licensee procedures relative to plant startup was
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conducted on July 9,1980, to verify that systems disturbed during the refueling outage were returned to the required lineup prior to the July 10, 1980 plant restart.
Procedure 201.1,
" Approach to Critical", Revision 19, Figure 201.1-2, " Precritical Checkoff", which lists every plant system required to be operable prior to plant startup was used as a master reference by the inspector. The following sampling of procedures was reviewed:
Procedure 630.4.003, Mechanical Vacuum Pump Isolation Test,
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Revision 0, June 8,1978, completed July 9,1980; Procedure 602.4.002, MSIV Closure Test, Revision 3,
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June 27,1979, ccmpleted July 9, 1980; Procedure 301, Nuclear Steam Supply System, Revisbn 14,
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May 29, 1980, completed June 27, 1980; Procedure 302.1, Control Rod Drive Hydraulic System,
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Revision 6, May 19,1980, completed July 3,1980; Procedure 302.2, Control Rod Drive Manual Centrol System,
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Revision 5, November 14, 1977, completed July 9,1980; Procedure 303, Reactor Cleanup Demineralizer System,
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Revision 6, May 29, 1980, completed July 8, 1980; Procedure 304, Standby Liquid Control System, Revision 7,
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January 14, 1980, completed June 98, 1980; Procedure 305, Shutdown Cooling Systen, Revision 8,
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May 29,1980, completed July 53 1980; Procedure 306, Reactor Vessel Head Cooling System,
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Revision 6, May 19,1980, completed June 11, 1980; Procedure 307, Isolation Condenser System, Revision 10,
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May 12, 1980, completed June 20, 1980; Procedure 308, Emergency Core Cooling System, Revision 12,
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June 18,.1980, completed June 23, 1980;
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Procedure 309.1, Turbine Building Closed Cooling Water System,
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Revision 1. March 18,1980, completed May 5, 1980; i
Procedure 309.2, Reactor Building Closed Cooling Water System,
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Revision 2, May 2,1980, completed July 6,1980; Procedure 310, Containment Spray System, Revision 10,
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June 18,1980, completed June 27,1980; and, Procedure 311, Fuel Pool Cooling System, Revision 6,
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April 3,1978, completed June 24, 1980.
All Procedures were found to be properly completed with independent verification of valve, breaker and switch alignments being conducted by the licensee.
No items of noncomplianc were identified.
b.
The plant startup of July 10, 1980 was observed to verify that appropriate procedures and predetermined rod withdrawal sequences were used and adhered to by the licensee.
The following procedures were used during the reactor startup and heatup.
Procedure 201.1, Approach to Critical, Revision 19; and,
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Procedure 201.2, Plant Heatup to Hot Standby, Revision 5.
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No items of noncompliance were identified.
4.
Plant Tour a.
During the course of the inspection, the inspector made observations and conducted multiple tours of:
Control Room;
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Reactor Building;
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Turbine Building;
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Cooling Water Intake Structure;
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Maintenance Shop Areas;
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Monitoring Change Areas; and,
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Yard Areas.
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b.
The following determinations were made:
Monitoring instrumentation. The inspector verified that
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selected instruments were functional and demonstrated parameters within Technical Specification limits.
Radiation controls. The inspector verified by observation
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that control point procedures and posting requirements were being followed.
Fluid leaks. No fluid leaks of significance were noted.
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Plant housekeeping conditions. Observations of plant
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housekeeping relative to fire hazards identified no notable conditions.
Piping vibration.
No excessive piping vibration was noted
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during the plant tours.
Control room annunciators. Selected lit annunciators were
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discussed with control room operators to verify that the reasons for them were understood.
By frequent observations through the inspection, the
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inspector verified that control room manning requirements of 10 CFR 50.54(k) and the Technical Specifications were being met.
In addition, the inspector observed shift turnovers to verify that continuity of system status was maintained.
No items of noncompliance were identified.
c.
The following acceptance criteria were used for the above items:
Technical Specifications;
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Inspector judgement.
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5.
Shift Logs and Operating Records a.
The inspector reviewed the following plant procedures to determine the licensee established requirements in this area in preparation for review of selected logs and records:
Procedure 106, Conduct of Operations, Revision 8, July 3,1980;
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Procedure 108, Equipment Control, Revision 21, July 3,1980; and,
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Procedure 115, Standing Order Control, Revision 7,
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September 15, 1979.
The inspector had no questions in this area.
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b.
Shift logs and operating records were reviewed to verify that:
Control room logs were filled out and signed;
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Equipment logs were filled out and signed;
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Log entries involving abnormal conditions provided sufficient
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detail to communicate equipment status;
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Shift turnover sheets were filled out, signed, and reviewed;
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Operating orders did not conflict with Technical Specification
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requirements; Tagging of equipment did not violate Technical Specification
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Limiting Ccnditions for Operation; and, Logs and records were maintained in accordance with the
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procedures in 5.a above.
c.
The review included the following plant shift logs and operating records as indicated and discussions with licensee personnel.
Reviews were conducted on an intermittent selective basis:
Control Room Log, July 9 through 31;
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Group Shift Supervisor Log, July 9 through 31;
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Turbine Building Tour and Turnover Check List;
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Reactor Building Tour and Turnover Check List;
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Control Room Alarm Sheets;
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Control Rod Status Sheets;
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Technical Specification Log;
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Reactor Auxiliary Log;
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Reactor Log; l
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Group Shift Supervisor Turnover Check List;
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Control Room Turnover Check List;
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Standing Orders, all active;
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Operational Memos and Directives, all active;
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Lifted Lead and Jumper Log, all active; and,
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Equipment Tagging Log, all active entries.
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No items of noncompliance were identified.
6.
IE Bulletins and Circulars a.
Bulletins Licensee actions concerning the following IE Bulletins were reviewed by the inspector to verify that; the Bulletin was forwarded to appropriate onsite management; a review for applicability was performed; information discussed in the licensee's reply was accurate; corrective action taken was as described in the reply; and the reply was within the time period described in the Bulletin.
IEB 80-17, Failure of Control Rods to Insert During a
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(1) Procedure Review A detailed procedure review was conducted on July 16, 1980, prior to the performance of scram testing required by IEB 80-17. The following procedures were reviewed:
Procedure 617.4.006, Scram Discharge Volume
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Vent Piping Blockage Test, Revision 0, July 8, 1980; Procedure 615.5.007, Ultrasonic Testing of Scram
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Discharge Header Piping, Revision 0, July 8,1980; and, Universal Testing Laboratories, Incorporated,
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Procedure UTL-JCPL-UT-138, UT Procedure for Detection of Water in Horizontal or Vertical Piping Runs on all BWR's Scram Discharge Header Piping, Revision 0, July 10,1980.
No procedural inadequacies were identified.
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(2) Witnessing of Scram Testing
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The resident inspectors witnessed one of the required scram tests conducted by the licensee.
A pre-scram test briefing and walk-through was conducted by the licensee at 9:10 p.m. on July 16, 1980, to insure that all personnel were familiar with test requireunts and that all recording equipment functioned properly. One recorder was identified during the walk-through that was not inking properly. The defective recorder.vas replaced and retested at that time.
The actual scram test was conducted at 10 p.m. on July 16, 1980. The inspectors observed that all control rods inserted fully.' Reports from the various data stations, received in the control room, indicated that all recorders had functioned properly and that all data (manual scram) were recorded (test results are detailed in paragraph 6.a.(4)).
(3) Witnessing of Scram Discharge Volume Ultrasonic Tests for Standing Water On July 17,1980, (12:25 a.m. to 6 a.m.) subsequent to scram testing performed on July 16, 1980, the inspector observed ultrasonic testing (UT) of the scram discharge volume (SDV) performed by Universal Testing Laboratories, Incorporated (UTL) personnel to determine the amount of free standing water in the SDV. All points tested indicated that no water was present except point number 6, (exact location identified in licensee procedure 617.5.007)
located in the north side 2 inch horizontal drain header.
Additional UT examinations were made by the Level III UTL examiner but a definite conclusion could not be reached as to how much water, if any, was in the header.
At 10:30 a.m. on July 17,1980, the 2 inch SDV drain header was radiographed from 3 different angles.
Radio-graphic examination showed that no water was present; however, a U-shaped indication in the bottom of the pipe was evident. This section when wetted by the scram on July 16,1980 gave a UT indication that the pipe was approximately half full of water.
Review of the radio-graphic films indicated that the defect was a cold lap fomed when the pipe was fabricated. The thickness of the defect was determined to be 0.005 inches. The pipe wall thickness is a nominal 0.360 to 0.400 inches. The licensee will perfom a safety evaluation to insure pipe dagradation is within acceptable limits.
This item is unresolved pending the licensee's evaluation and NRC review (219/
80-25-02).
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(4) Test Data Review Test data from both scram tests submitted by the licensee on July 24, 1980, were reviewed.
Test data included the following parameters:
Control rod scram times (70 rods);
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Scram solenoid scram bus voltage;
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Scram valve air header pressures;
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Scram instrument volume fill time;
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Vent and drain valve opening and closing times;
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Delay time from scram to full closure of vent and
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drain valves; Chemical analysis (suspended solids) of scram
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discharge volume water; SDV drain time;
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Results of UT examination;
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Reset time of scram reset timer; and,
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SDV pressure variation with time.
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The findings of the above review were as follows:
(a) The large time difference between closing times of the north (7 seconds) and the south (21.85 and 20.27 seconds) SDV header vent valves was questioned by the inspector. The licensee stated that valve characteristics plus the fact that the SDV drain valve also vents into the south control air header and the larger volume of the south air header (approximately twice the north side volume)
would tend to keep air pressure at a relatively high value and increase the SDV vent valve closing time.
The inspector agreed with the licensee's statements concerning this matter.
In addition, the vendor (G.E.), in a Projects Division Memo,
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dated July 10, 1980, stated that vent and drain
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valves may take as long as 30 seconds to close wits no adverse effects.
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The inspector had no further questions concerning this item.
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(b) Another area of concern was the time required for the
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SDV to drain and allow the reactor protection system (RPS.) channel number 1 to reset following the automatic scram (161 seconds) compared to reset time following the manual scram (84 seconds). The licensee could not explain the large drain time difference by the conclusion of this inspection on August 1, 1980.
During a subsequent meeting with NRC representatives in the NRC Region I Office, King of Prussia, Penn-sylvania, on August 5, 1980, the licensee pointed out that during a scram on August 4,1980, a similar problem was experienced in RPS channel number 2.
Licensee investigation on August 4, 1980, determined
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that a snap action SDV level switch on the SDV failed to reset when the SDV was drained. The switch did reset during removal of the switch coverplate for
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internal switch examination. The switches in question were installed for seismic qualification reasons during the recent refueling outage. The failure of the second switch to reset on August 4,1980, could explain the large SDV drain time difference, for RPS channel number 1 reset, experienced during scram testing on July 19, 1980. This item is unresolved pending further data collection and evaluation by the licensee and the resident inspectors (219/80-25-03).
(5) System Walk-Down The resident inspectors conducted a walk-down of the SDV to detennine the following:
Drain slope was correct over the entire accessible
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piping run (approximately 45 feet of 2 inch piping in the north header is enclosed in a sleeve encased in concrete);
No loop seals were present;
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No problems such as other system connections were
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evident; and, Drawings reflected accurate detail with regard to
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principle system features.
One item, concerning piping slope, was discussed in detail with the licensee. Licensee measurements were conducted using an inclinometer and indicated a slope of one half to one degree (1/8 to 1/4 inch per foot); the inspectors used a 12 inch long bubble level. Measurements by the inspectors
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did not agree with the licensee's readings concerning the amount of slope.
Inspector readings indicated a slope of 1/16 to 1/8 of an inch per foot. All readings indicated that piping slope was in the proper direction and approximately 1/8 of an inch per foot.
Licensee drawings indicate that slope is 1/8 of an inch per foot.
It was determined by the inspectors that since the slope was in the proper direction and UT results indicated that no water was present that the disagreement between licensee and inspector readings relative to the amount of slope was acceptable.
(6)
Procedure Review A procedure review was conducted to verify that procedural content, concerning licensee action should all rods fail to insert during a scram, met or exceeded the requirement of IEB 80-17.
The following procedures were reviewed:
Procedure 532, Auto and Manual Reactor Scram, Revision 9,
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July 7,1980; and, Procedure 506.5, Scram System Failure, Revision 2,
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July 7,1980.
No items of noncompliance were identified.
(7) SDV Daily Checks, Prompt Notification, and 10 CFR 50.59 Review (a) SDV Daily Checks The inspectors verified, by conducting periodic checks, that procedures 615.5.007 and UTL-JCPL-UT-13B discussed in paragraph 6.a.(1), were being performed daily by UTL and the licensee during plant cperation.
(b) Prompt Notification The licensee has committed to promptly notify (within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) the NRC:RI when any of the following systems are less than fully operable:
Isolation Condenser;
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Containment Spray System;
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Standby Liquid Control System; and,
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Main Steam Bypass System.
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(c)
10 CFR 50.59 Review The licensee conducted a safety review of the Standby Liquid Control System (SBLCS) in an effort to determine if modifications could be made to the system, under 10 CFR 50.59 provisions, to increase system flow by allowing two (2) pump operation.
The results of that review indicated that modifications to increase system flow could not be accomplished under 10 CFR 50.59.
No items of noncompliance were identified.
IEB 78-01, Flamable Contact-Arm Retainers in G.E. CR120A
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Relays.
Licensee actions concerning this Bulletin were previously reviewed and documented during IE inspection 50-219/78-21 and 79-14. Licensee action at that time was partiall A review of job order (J0) 2047-E (QASL No. 3757)y complete.
completed on June 13, 1980, indicated that all contact-arm retainers had been replaced during the 1980 refueling outage.
The inspector had no further questions concerning this item.
IEB 78-14, Deterioration of Buna-N Components in Asco Solenoids.
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This item was previously reviewed and documented during IE inspection 50-219/79-19. Licensee action was incomplete at that time with full replacement of Buna-N components scheduled for the 1980 refueling outage. A review of J0 number 2913-I (backup scram solenoid valves), completed on May 9, 1980, and J0 number 0154-V (scram solenoid valves), completed on April 16, 1980, indicated that all Buna-N components have now been replaced.
The inspector had no further questions concerning this item.
b.
Ci rculars Licensee actions concerning the following IE Circulars were reviewed to verify that the circular was received by licensee management, that a review for applicability was performed, and that action taken or planned is appropriate.
IEC 79-22, Stroke Times for Power Operated Relief Valves.
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This circular does not apply to BWR facilities; however, the inspectors verified that the circular had been received and
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evaluated for applicability by appropriate licensee personnel.
The inspectors had no furhter questions concerning this item.
7.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of noncompliance, or deviations. The unresolved items identified during).
this inspection are discussed in paragraphs 2, 6.a.(3), and 6.a.(4)(b 8.
Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings.