IR 05000219/1981014
| ML20010E548 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 08/19/1981 |
| From: | Greenman E, John Thomas NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20010E545 | List: |
| References | |
| 50-219-81-14, NUDOCS 8109040244 | |
| Download: ML20010E548 (17) | |
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50219-810714
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bh hhbf U.S. NUCLEAR REGULATORY COMMISSION 50219-810706 0FFICE OF. INSPECTION AND ENFORCEMENT Region I Report No. 50-219/81-14 Docket No.
50-219 License No. DDR-16 Priority
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Category C
Licensee:
Jersey Central Power and Light Company Madison Aver.ue at Punch Bowl Road Morristown, New Jersey Oyster Creek Nuclear Generating Station Facility Name:
Inspection at:
Forked River, New Jerse,,
Inspection conducted:
July 1 - August 3,1981 10 k m f 1181 Inspectors: M ga a1@ signed
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A. Thomas, Resident Reactor Inspector date signed f
date signed
' Approved by-h[
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/7 h5."G.Greenman, Chief, Reactor
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V Projects Section 2A Inspection Summary: Inspection on July 1 - August 3,1981'(Report No. 50-219/81 14)
Areas Inspected: Routine inspection by the resident inspector (94 hours0.00109 days <br />0.0261 hours <br />1.554233e-4 weeks <br />3.5767e-5 months <br />) of:
licensee action on previous inspection findings, tours of the facility, log and record reviews, followup of events that occurred during the inspection, in-office LER review, on-site LER followup, followup of TMI Task Action Plan items, review of periodic and special reports.
Results: Noncompliances - None in seven areas, three in one area (Failure to maintain secondary con'tainment integrity - detail 5.a.(1); Failure to perform the surveillance required by Technical Specification 4.13 - detail 5.a.(2); violation of Technical Specification 3.4.E. - detail 5.a.(4)).
8109040244 810822 PDR ADOCK 05000219 RegionItormfc (Rev. April 77)
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Persons Contacted J. Carroll, Director, Oyster Creek Operations K. Fickeissen, Manager, Plant Engineering E. Growney, Safety Review Manaaer M. Laggart, Supervisor, Licensing J. Maloney, Manager, Plant Maintenance A. Rone, Engineering hnager W. Stewart, Plant Operations Manager i
J. Sullivan, Manager, Operations D. Turner, Radiological Controls Manager The inspecter also interviewed other licensee personnel during the course of the inspection including management, clerical, maintenance and operations personnel
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2.
Licensee Action on Previous Inspection Findinos (Closed) Unresolved Item (219/81-01-01)
Implement program for control of information tags.
Frocedure 108, revision 26, June 1,1981, " Equipment
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Control", section 5.9, provides a program for control of information tags
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which are used for posting of operational infomation of a temporary nature.
The inspector verified through periodic reviews of the information tag log and by inspection of active tage that the administrative controls of Procedure 108, section 5.9, have been adequately implemented.
(Closed) Item of Noncompliance (219/81-05-12) Core spray pump test procedure was not revised to reflect that the fill pumps no longer rperate
automatically.
The inspector reviewed procedure 610.4.002, revis tn 6, dated May 13,1981, " Core Spray Pump Operability Test", and verified that the procedure has b?en revised to reflect that the core spray fill pumps do not operate automatically.
In addition, the inspector reviewed Support
Program Training Module III, revision 2, dated July 15,1981, " Quality
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'ssurancc" and verified that the general employee training and employee refresher training courses have been revised to include emphasis on the
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importance of procedural compliance. The training module includes a
discussion of the mechanism for obtaining temporary changes to procedures and stresses that procedural steps must be terminated if at any time the procedure is found to be in error. The corrective actions stated for this item in the licensee's letter to NRC:R1 d6ted June 24, 1981, have been adequately implemented.
(Closed) Unresolved Item (219/81-06-01)
Revise procedures to more adequately control defeat of common alarms.
Procedure 108, revision 26, June 1,1981, " Equipment Control", now provides adequate control of defeated
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common alarms.
In addition to requiring an index listing of defeated alams, the procedure provides an individual information sheet for each defeated alarm. The infomation sheet more clearly documents the reason for defeat of the alarm, the method used for defeating the alarm, and the follow-up corrective action that has been initiated. The information sheet allows for adequate control and documentation for defeat of common alarms.
(Closed) IJnresolved Item (219/81-11-02) Review Procedure 108, resolve use of numbered electrical jumpers for approved maintenance and modification procedures without the use of Check-off Sheets.
Procedure 108, revision 26, June 1,1981, " Equipment Control", now states in paragraph 5.2.1,
"This procedure does not apply to electrical jumpers controlled by PORC
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approved surveillance procedures which incorporate the proper controls to insure that the installation and removal is accomplished in a safe manner.
All other electrical jumpers required by procedures will be logged in accordance with this section". This revision to procedure 108 provides for adequate control of electrical jumpers by the operations department.
The inspector noted that the same level of control over mechanical jumpers and lifted electrical leads has been incorporated in this procedure.
3.
Plant Tours Periodic inspection tours of selected plant areas were conducted to a.
verify compliance with Technical Specifications (TS) and the licensee's administrative procedures in the areas of housekeeping and cleanliness, fire protection, radiation control, physical security, and operational control.
Acceptance criteria for the above areas include the following:
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Technical Specifications
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Procedure 106, Conduct of Operations
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Procedure 108, Equipment Control
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Procedure 115, Standing Order Control
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Procedure 119, Housekeeping Procedure 120, Fire Hazards
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Procedure 122, Security Guidelines for Plant Personnel
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Procedure 903.2, Personnel Monitoring
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Procedure 903.6, Personnel Regulations
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Procedure 915.1, Restriction of Access into Radiation Control
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Areas Procedure 915.4, Contamination Control
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Procedure 915.6, Radiation Work Permit
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Oyster Creek Physical Security Plan 10 CFR 50.54(k)
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Inspector Judgment
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b.
During the course of the inspection, the inspector made observations and conducted. multiple tours of plant areas, including:
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Control Room
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Turbine Building
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Augmented Off-Gas Building
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New Rad-Waste Building
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Cooling Water Intake and Dilution Plant Structure
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Monitoring Change Areas 4160 Volt Switchgear, 460 Volt Switchgear, and Cable Spreading Rooms
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Battery Rooms Maintenance Work Areas
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Yard Areas
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The following observations were made:
r-(1)
Through observation of Control Room monitoring instrumentation and annunciators, log review, and direct observation of selected equipment, the inspector verified tha: instrumentation and systems required to support operations were in conformance with Operation (LCO)pecification (TS) Limiting Conditions for the Technical S
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Verification of conformance to the following
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LCO's was conducted daily:
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TS 3.1.B APRM System TS 3.1.C LPRM System
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TS 3.2.C Standby Liquid Control System TS 3.3.A Pressure Temperature Relations
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TS 3.3.D Reactor Coolant System Leakage
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TS 3.3.F Recirculation Loop Operability
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TS 3.4.A Core Spray System TS 3.4.B Automatic Depressurization System
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TS 3.4.C Containment Spray and Emergency Service Water System
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TS 3.4.D Control Rod Drive Hydraulic System TS 3.5.A Primary Containment
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TS 3.5.B Secondary Containment TS 3.7.A Auxiliary Electric Power
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TS 3.7.C Standby Diesel Generators
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TS 3.8.A Isolation Condensers
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TS 3.13. A Relief and Safety Valve Position Indicators i sc visual checks of selected local plant instrumentation Pc i were conducted to verify that required instruments were in service and that proper correlation between channels existed.
Valves ar ' components in safety related systems were observed to verify proper system alignment. - Accessible major flow path valves in the Core Spray, Containment Spray, Emergency Service Water, and Isolation Condenser Systems were verified to be'
properly aligned by direct observation or observation of local and remote position indicators. All breakers in the 4160 volt electrical system and selected breakers in the 460 volt and 124 Vdc electrical systems were periodically examined for proper alignment.
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On July 9,1981, the inspector noted an entry on the control room operator shift turnover sheet indicating that the ball valve for the number 2 TIP machine had not closed automatically upon retracting the TIP. This was caused by a malfunction of the
"in-shield" limit switch. After jogging the TIP, the limit switch closed allowing the ball valve to shut. The inspector discussed this item with the Group Shift Supervisor and determined that he was unaware of the Technical Specification requirements on the operability of the TIP ball valves as primary containment isolation valves, and that licensee management had not been informed of the malf"nction. Technical Specification 3.5.A.3.(a)
requires that when a TIP system isolation valve becomes inoperable, the penetration must be secured within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> by use cf a deactivated automatic valve secured in the isolation position or by use of a closed manual valve or blind flange.
After discussing this item with licensee management, the number 2 TIP ball valve was deactivated in the closed position within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of the time of the malfunction. The in-shield limit switch was repaired and tested satisfactorily on July 10,19R1.
This item is addressed further in paragraph 5.b. of this ' report.
(2)
Radiation controls, ir.cluding posting of radiation a eas, the conditions of step-off pads, disposal of protective clothing, completion of radiation work permits, compliance with radiation work permits, use of personnel monitoring devices, area monitor operability, and personnel frisking procedures were observed on a sampling basis.
Independent radiation surveys of various posted areas were conducted to verify that radiation levels were in accordance with postings.
On July 22, 1981, the inspector was approached by an individual who expressed concern about the licensee's compliance with regulatory requirements on radiation controls during decontamina-tion of the control rod drive system hydraulic control units.
The individual stated that contamination levels of up to 15,000 2 existed on areas released as radioactively clean, dpm per 100 cm and that radiation levels as high as 450 mrem per hour existed on components in areas not posted as high radiation areas. The inspector conducted an independent survey of the hydraulic control units on July 23, 1981. Contact radiation levels of up to 450 mrem per hour were found on the P-4 instrument plugs on the accumulator valve blocks.
In all cases, the radiation levels at a distance of three inches in any direction from the P-4 plugs war, less than 80 mrem per hour. These " hot spots" do not present a potential for exposures to a major portion of the body in excess of 100 mrem in any one hour and thus need not be
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posted as "High Radiation Areas" pursuant to 10 CFR 20.203(c).
The inspector reviewed the licensee's post decontamination survey records for 15 hydraulic control units and found that about 35 smears had been taken for each unit prior to its release as unconta.minated.
In all cases where contamination levels were found in excess of 1000 dpm beta-gamma and further decontamination of the affected component was impractical, the component was contained in plastic and tape and clearly labeled as contaminated.
The licensee acknowledged that contamination levels in excess of 1000 dpm could probably be found in generally inaccessible areas of the hydraulic control units, such as in bolt sockets, valve stems, and piping in the piping nests above the units.
The inspector determined that any maintenance performed on the hydraulic control units requires a radiation work permit and health physics coverage. Thus inadvertant personnel contamination is unlikely.
In addition, the general employee training program provides adequate cautions to personnel about the potential contamination that exists on overhead piping, cable trays, and ventilation ducts, and that protective clothing must be worn when working in these areas. The inspector discussed the radiation levels at the P-4 instrument plugs with licensee management and verified that by July 28, 1981, signs had been posted on the hydraulic control units warning that radiation levels above background existed at the P-4 instrument plugs.
Through frequent observations of the hydraulic control unit decontamination job, the inspector determined that acceptable radiation controls exist and that the job is being performed in a safe manner.
No unacceptable conditions were identified.
(3)
Plant housekeeping conditions including general cleanliness, control of material to prevent fire hazards, maintenance of fire barriers, and storage and preservation of equipment were examined. The inspector examined the placement of temporary hoses and extension cords, and the locations of scaffolding erected for maintenance or modification jobs to verify that safety related equipment operability was not impaired. Systems and components were examined for evidence of abnormal vibration and fluid leaks. Selected pipe hangers and seismic restraints were visually examined for indications of mechanical interference or fluid leaks.
(4)
Daily tours of the control room were conducted when the inspector was on site. Control room manning was verified to meet or exceed
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the requirements of Technical Specifications and licensee administrative procedures. Access to the control room was verified to be controlled in accordance with licensee procedures.
Lit control room annunciators were reviewed with operators and shift supervisors to verify that reasons for the alarmed conditions were understood and the corrective action was being taken, if required. Systems or components removed from service for maintenance or testing were reviewed to verify that Technical Specification LC0's were met and that proper surveillances were performed on redundant systems. The inspector observed shift turnovers to verify that continuity of system status was maintained and that turnovers were conducted in an orderly manner.
(5)
Equipment control procedures were examined for proper implementa-tion by verifying that tags were properly filled out, posted, and removed as required, and by reviewing logs and records for completeness.
i The following active tagging requests were audited by the inspector:
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Outage 81-918, dated July 13, 1981: Remove 1-1 dilution system seal water pucp from service for mtintenance.
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Outage 81-734, dated June 4,1981:
Remove number 1 dilution pump from service for motor maintenance.
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Outages81-808, 816, and 832, dated June 21, 22, and 24, 1981, respectively:" Electrically and mechanically isolate the 1-7 drain sump pumps and motors for maintenance.
The following completed tagging requests were examined to verify proper system realignment following maintenance:
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Outage 81-945, cleared on July 21, 1981: Repair a leak l
on the new rad-waste service wate' system.
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Outage 81-960, cleared on July 28, 1981: Secure all TIP machines for maintenance.
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Outage 81-990, cleared on July 31, 1981:
Isolate the 'A'
CRD filter for cleaning.
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The following electrical jumpers were verified to be properly j
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Checkoff Sheet 80-306, dated October 10, 1980: Jumper number 28 installed in panel 8R to bypass a failed RTD for the
'C' recirculation pump motor winding temperature monitor.
Checkoff Sheet 81-324, dated January 23, 1981: Jumper
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number 1 installed to bypass a failed flow switch in the number 3 dilution pump seal and lubricating water system.
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Checkoff Sheet 81-341, dated April 15, 1981: Jumper nuri.er 2 installed to bypass a failed flow switch in the rumoer 2 dilution pump seal and lubricating water system.
During the course of plant tours, other tags were observed to
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verify that the component status was as stated on the tag and that
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tags were placed in such a manner that they did not obscure panel indicators.
(6)
Areas toured were observed to verify that security access controls to vital areas were maintained, protected area barriers were not degraded, isolation zones were clear, personnel and packages were checked prior to allowing access to the protected area, and security posts were properly manned.
4.
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:
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Procedure 106, Conduct of Operations; Procedure 108, Equipment Control; and,
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Procedure 115, Standing Order Control.
The inspector had no questions in this area.
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Shift logs and operating records were reviewed to verify that:
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Control Room logs were filled 'at and signed:
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Equipment logs were filled out and signed:
Log entries involving abnormal conditions provided
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sufficient detail to communicate equipment status; I
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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; and,
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Logs and records were maintained in accordance with the procedures in a. above, c.
The review included the following plant shilt lons and operating records as indicated, and discussions with licensee eersonnel.
Reviews were condected on an intermittent selective basis:
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Control Room Log. all entries;
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Group Shift Supervisors Log, all entries;
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Technical Specification Log;
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Reactor Auxiliary Log;
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Reactor Log;
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Control Room Turnover Check List; j
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Reactor Building Tour Sheets;
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Turbine Building Tour Sheets;
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Equipnent Tagging Log;
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Lifted Lead and Jumper Log;
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Defeated Alarm Log;
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Standing Orders, all active; and,
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Operational Memos and Directives, all active.
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No unacceptable conditions were identified.
5.
F,ollow-up of On-Site Events a.
The following events occurred during the inspection and were reviewed with licensee management.
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(1)
On July 14, 1981, at about 7:00 P.M., the Standby Gas Treatment System (SGTS) I failed to meet the acceptance criteria of surveillance procedure 651.4.001 when the system failed to start automatically.
In addition, the reactor building main exhaust valve V-28-22 failed to close. The redundant reactor building.uain exhaust valve, i
V-28-21 in series with V-28-22, functioned normally. The system was declared inoperable due to the failure to start and the required surveillance was initiated on SGTS II. At about 7: 30 P.M.,
the surveillance was completed on SGTS II and the system was declared operable even though V-28-22 did not close. Following repairs to SGTS I flow sensors, the system was retested at 11:15 P.M.
on July 14, 1981 and was demonstrated to be operable, however, V-28-22 again failed to close. A ten hour test run of the SGTS II was comme.ced and at about 8:30 A.M. on July 15, 1981, when the reactor bt ilding ventilation was isolated as per the surveillance procedure, valve V-28-22 again failed to close. Prior to this time, neither the operators nor the shift supervisor recognized the malfunction of V-28-22 as a loss ",f secondary containment integrity as defined by Technical Specification 1.14. At 8:30 A.M., the loss of secondary containment integrity was recognized and determined to be a violation of Technical Specification 3.5.B.1 and a reactor shutdown wr.s commenced. Failure to maintain secondary containment integrity.onstitutes noncompliance with Technical Specification 3.5.B.1, (219/81-14-01).
The reactor shutdown was terminated at about 10:15 A.M., July 15,1981, when V-28-22 was manually closed and locked. The failure of V-28-22 was determined to be due to a failed solenoid valve which controls air to the main valve operator. The selenoid was repaired and V-28-22 was tested satisfactorily at 3:30 P.M.
on July 15, 1981.
This event is addressed further in paragraph 5.b. of this report.
(2)
On July 13, 1981, the inspector was informed by licensee management that the monthly channel checks of the relief and safety valve
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i position indicators, required by Technical Specification 4.13,
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had not been performed since the incorporation of this surveillance requirement by amendment 54, effective on May 8,1981, to Provisional Operating License DPR-16. This constitutes noncompliance with Technical Specification 4.13,(219/81-14-02).
The failure to perform this surveillance was the result of inadequate review of the Technical Specification amendment by the licensee to insure that all new or revised requirements were implemented.
In addition, the amendment was not properly distributed to all holders of controlled copies of the Technical Specifications to insure implementation of the requirements.
The inspector verified that the channel checks were performed l
immediately upon recognition of the deficiency and that action was initiated to prepare a permanent procedure for documentation of the checks.
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On July 22, 1951, at about 4:00 A.M.
3 reactor shutdown was (3)
-comenced when the shif t supervisor erroneously believed that
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a Technical Specification Safety Limit had been exceeded.
Technical Specification Limiting Safety System Settings (LSSS)
require that the APRM flow biased scram setpoints be reduced by a factor Pfo/PF when the core peaking factors (PF) exceed 7 specified value of PFo. A review of core data following a power manuever showed that for about 30 minutes during the maneuvrr, the maximum peaking f actor was about 122 percent of Pfo.
During this time, the APRM scram set points had been set for a maximum peaking factor of 110 percent of PFo. Thus the safety system setting was higher than specified. The shift supervisor interpreted this as a violation of a safety limit and commenced a reactor shutdown. At the time of the review, the control rod manipulations had been completed and the maximum peaking factor was 107 percent of PFo and no further corrective action was required. The reactor shutdown was terminated at about 4:45 A.M. when licensee management reviewed the event and informed the shift supervisor of his error. The inspector noted that at no time during the event did reactor power exceed the level at which a scram would have occurred had the scram set points been properly reduced. This event was discussed with licensee management who stated that a Licensee Event Report would be submitted concerning the nonconservative LSSS.
This event is addressed further in paragraph 5.b. of this report.
(4)
On July 31, 1981 at about 5:30 P.M., an equipment operator found the south-east containment spray pump room watertight door open in violation of Tecfinical Specification 3.4.E.
The door was immediately shut and dogged by the operator. A subsequent investigation by the licensee determined that the door had been left open by contractor personnel.
This event is a repetitive occurrence for which corrective actions have been ineffective as evidenced by the following examples of previous similar events:
Licensee Event Report 79-36/3L was submitted when the north-
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east containment spray watertight door was found open on October 11, 1979. The corrective action was to place a sign at each door indicating the closure requirements.
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Licensee Event Report 80-32/lT w% submitted when the north-east and south-east containment spray watertight doors were found open on Aug tst 6,1980. The corrective action was to initiate an engineering evaluation to determine an effective means of controlling access through the watertight doors.
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Licensee Event Report 81-07/3L was submitted when the north-east containment spray watertight door was found open on February 2, 1981. The report stated that a positive means of ensuring the doors are closed after passage would be installed.
In addition, positive administrative controls were implemented.
Failure to maintain the containment spray compartment watertight doors closed except during passage constitutes noncompliance with Technical Specification 3.4.E, (219/81-14-03).
This event was critiqued by the licensee with the contractor on August 3,1981, and increased administrative controls were placed on the watertight doors. A contractor supervisor is now required to inspect the dooi twice per shift to verify that they are closed.
In addition, a member of the work force in the area is assigned the responsibility of maintaining a log of all openings and closings of the doors.
h-The inspector discussed the events in paragraphs 3.c.(1),
b.
5.a.(1), and 5.a.(3) of this report with licensee management and expressed concern that all three events involved either a failure of shift supervisors to recognize the technical specifi-cation considerations of the event or a misinterpretation of technical speciTicat%ns by shift supervisors. The failure of the number 2 TIP ball valve to close automatically and the failure of the reactor building main exhaust valve to close automatically were not recognized as degradations of the primary and secondary containment isolation systems, and the event in which high peaking factors were encountered was thought to be a safety limit violation.
Jn twc of these events, the routine reviews by licensee management identified the errors and corrective action was taken within the t me frames specified in Technical
Specifications.
In the other event (failure of the TIP ball valve), the error was discovered by the inspector and promptly identified to licensee manacement who took corrective action as l
required by Technical Specifications. The issue of the shift
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supervisor's wor,. ing knowledge of the Technical Specifications l
will remain unre 91ved pending further review by the NRC and l
the licensee (215/81-14-04).
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6.
In Office Review of Licensee Event Reports (LER's)
The inspector reviewed LER's received in the NRC:R1 and Resident Office to verify that details of the event were clearly reported including the accuracy of the description of cause and adequacy of corrective action.
l The inspector also determined whether further information was required from
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the licensee, whether generic implications were involved, and whether the event warranted on-site followup. The following LER's were reviewed:
LER EVENT 81-21/3L Reactor high pressure sensors RE03B, C, and D trip settings were higher than specified.
81-23/3L Drywell to torus differential pressure was not maintained within specified limits.
81-24/3L Emergency Service Water pump operability checks were not performed as required.
81-26/3L Isolation condenser initiation pressure switch tripped at a value higher than specified.
- 81 28/3L Unmonitored release of reactor and turbine building
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air through a torn temporary seal in the new ductwork for new radwaste ventilation exhaust.
- 81-30/lT Violation of secondary containment when exhaust valve V-28-22 failed to close.
Inspector review of LER 81-24/3L regarding failure to perform the required operability checks of the emeraency service water pumps determined that the report did not adequately address the cause of the event. The licensee caumitted to submit a revised report.
At the exit meeting for this inspection the licensee stated that the revised report hed been written and was being reviewed by the Plant Operations Review Committee. The revised report will be reviewed in a subsequent inspection.
No other unacceptable conditions were identified.
7.
On-Site Licensee Event Follow-up For those LER's selected for on-site followup, the inspector verified that reporting requirements of Technical Specifications and Regulatory Guide 1.16 had been met, that appropriate corrective action had been taken, that the event was reviewed by the licensee as required by facility procedures,.and that continued operation of the facility c
was conducted in accordance with Technical Specification limits.
The LER's selected for on-site followup are denoted by an asterisk (*) in detail 6. above. The following specific observations were made and discussed with licensee management:
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LER 81-30 - Review of this event and inspector findings are discussed in peragraphs 5.a(1) and 5.b. of this report.
LER 81-28 - On July 6,1981, at about 9:30 A.M., the licensee discovered a tear in a plastic sheet used tempcrarily to block a newly installed section of ventilation duct. The duct had been tied-in to the discharge duct of the reactor building exhaust fan, EF 1-6.
The other end of the duct was terminated at the roof of the new radwaste building and was scheduled for future tie-in to the new radwaste building ventilation exhaust. The open end of the duct was temporarily sealed with plastic sheeting over a wooden frame. A triangular shaped tear of about 6 inches X 6 inches in the plastic and a leaking seal surface permitted an unmonitored release of a small portion of the reactor and turbine buildings ventilation exhaust due to the pressure developed by the exhaust fans. An air sample taken at the point of the release showed an Iodine-131 concentration of about 17 percent of the occupational limit.
Upon discovery of the release, EF 1-6 was secured and EF 1-7 was started. This reduced the pressurt in the duct and minimized the rate of release. Shortly after this, metal plates were bolted over the openings in the duct and the release was terminated. An investigation of this event determined that a visual inspection of the temporary cover had been conducted on July 2, 1981 and the cover was found to be intact. Assuming that the cover was torn immediately after that inspection, the release is conservatively estimated to have lasted for four days. The licensee calculated an estimated release of about 58,500 cubic feet of air.
Using the observed concentration of Iodine 131 and applying the most restrictive dispersion factor for a ground level release from the new radwaste building, the Iodine 131 concentration at the site boundary was approximately 0.00015 percent of the MPC value of 10 CFR 20 Appendix B Table II Column 1.
Thus, no regulatory limits were exceeded.
The inspector expressed concern over the licensee's control of contractor work which allowed a temporary plastic cover to be used over a potential release point when the more permanent covers used after this event could have been used initially. The licensee stated that all special procedures for installation of modifications by contractors will require a field review by operations supervision.
The procedure for this installation will be reviewed and revised if necessary prior to final tie-in of the new duct.
The inspector had no further questions in this area.
8.
Review of TMI Task Action Plan Items Item I.C.l.1 - Review of Small Break Loss of Coolant Accident l
a.
l (SBLOCA) Procedures.
l The following procedures were reviewed with respect to the i
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guidelines of NED0-24708:
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Procedure 515.3, revision 7, March 5, 1981, "Small Pipe Break Inside Drywell".
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Procedure 515.4, revision 4, March 5,1981, "Small Pipe Break Outside Drywell".
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Procedure 516.1, revision 9, June 2,1980, " Main Steam Line Rupture Outside Drywell".
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Procedure 516.2, revision 9, June 2,1980, " Piping Rupture Inside Drywell, Offsite Power Available".
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Procedure 516.3, revision ll, June 2,1980, " Piping Rupture Inside Drywell With Loss of Offsite Power".
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Procedure 516.4, revision 9, June 2,1980, " Isolation Condenser Line Break Outside Drywell".
Procedure 516.5, revision 9, June 2,1980, " Piping
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Rupture Inside Drywell With Loss of Offsite Power and One Diesel Generator Inoperable".
The above procedures contained the appropriate symptoms, imediate actions, subsequent actions and precautions identified in the GE owners group SBLOCA guidelines.
No unacceptable conditions were identified.
b.
Item I.C.S.-Feedback of Operating Experience.
The licensee has established the Operating Experience Implementa-tion Committee, which by procedure 123 revision 1, dated October 31,1980, " Operating Experience Implementation Required Reading", is required to review and assess Licensee Event Reports; Service Information Letters; and other documents relating to operating reactor events. The committee members determine the appropriate recipients of this information and promulgate it in the form of a required reading list which is incorporated in the ongoing operator training program. This satisfies the requirement s of item I.C.5 of NUREG 0737.
c.
Item I.C.6.-Verification of Correct Performance of Operating Activities.
The Licensee's administrative procedure 108 revision 25, dated December 22,1980, " Equipment Controls", specifies the require-ments for verification of correct performance of operating activities.
Independent verification of system alignment is
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. required during installation and removal of safety tags and electrical or mechanical jumpers, and during lifting and reinstallation of electrical leads.
System checkoffs and prestart up valve lineups are independently verified, ar.d instrumentation valve lineups in safety related systems are independently verified following surveillance tests or maintenance evolutions requiring valve manipulation. This satisfies the requirements of item I.C.6 of NUREG 0737.
9.
Review of Periodic and Special Reports.
Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 were reviewcd by the inspector.
This review included the Collowing considerations: the report includes the information required to be reported to the NRC; planned corrective actions are adequate for resolution of identified problems; and that the reported information is valid. Within the scope of the above, the following periodic reports were reviewed by the inspector.
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June, 1981 Monthly Operating Data Report 10.
Unresolved Items Unresolved items are matters about which more infcrmation is required in order to ascertain whether they are acceptable items, items of noncompliance, or deviations. The unresolved item identified during this inspection is discussed in paragraph 5.b.
11.
Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings. A summary of the inspection findings was also provided to the licensee at the conclusion of report period on August 3,1981.
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