IR 05000269/1981002
| ML19345G665 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 02/24/1981 |
| From: | Jape F, Julian C, Myers D, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML19345G661 | List: |
| References | |
| 50-269-81-02, 50-269-81-2, 50-270-81-02, 50-270-81-2, 50-287-81-02, 50-287-81-2, NUDOCS 8104090116 | |
| Download: ML19345G665 (13) | |
Text
{{#Wiki_filter:. . g Ocoq'o, UNITED STATES d kq ! ^^ '.) NUCLEAR REGULATORY COMMISSION n $ E REG lON 11 g[ 101 MARIETTA ST., N.W., SUITE 3100 e, ATLANTA, G EORGI A 30303 ..... Report Nos. 50-269/81-2; 50-270/81-2 and 50-287/81-2 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Facility Name: Oconee Docket Nos. 269, 270 and 287 Li. cense Nos. DPR-38, 47, 55 Inspected by: /N 4 /([ 2/r /7<' im F. Jape Date Signed n f)s Y c ('-{:,, l.-. -) :_ /i ~/ ., W. Orders / j' Date Signed /Y
.L / d /77 D. Myers / -Date Signed Approved by: _ NN/ Caudie Juliarh> Acting Section Chief, RONS Branch Date Signed SUMMARY Inspection Date: January 2 through January 31, 1981 Areas Inspected: This routine inspection involved 336 resident inspector-hours on site in the areas of plant operations, survei l *, ancE testing. maintenance observations, refueling operations, and nuclear station modifications.
Results: Of the 5 areas inspected, no violations or deviations were identified in 3 areas; 3 vic1ations were found in 2 areas; two Violations - failure to follow proce-dures, See paragraph 7 and 11; Violation - polar crane operation, see paragraph 13.
81040'90/6
. . . DETAILS 1.
Persons Contacted Licensee Employees
- J. E. Smith, Station Manager
- J. M. Davis, Superintendent of Maintenance
- J. N. Pope, Superintendent of Operations
- T. B. Owen, Superintendent of Technical Services
- R. T. Bond, Licensing and Projects Engineer Other licensee employees contacted included 20 operations personnel, five technicians, 20 operators, four mechanics, four security force members, and three office personnel.
- Attended Exit Interview 2.
Exit Interview The inspection scope and findings were summarized on January 16 and January 29 with those persons indicated in Paragraph I above. The viola-tions described in Paragraphs 7,11 and 13, were discussed with licensee management who acknowledged understanding of them.
The Open Iterc s as detailed in Paragraphs 6, 9 and 10 were also discussed.
3.
Licensee Action on Previous Inspection Findings Not inspected.
4.
Unresolved Items Unresolved items were not identified during this inspection.
5.
Plc.nt Operations The inspector reviewed plant operations throughout the report period, January 2 through January 31, to verify conformance with regulatory require-ments, technical ' specifications and admialstrative controls. Control room logs, shift supervisors logs, shift turnover records and equipment removal and restoration records for the three units were continually perused.
Interviews were conducted with plant operatior,s, maintenance, chemistry, health physics, and performance personnel on day and night shifts.
Activities within the control rooms were monitored during all shifts and at shift changes.. Actions and/or activities observed were conducted as prescribed in Section 3.08 of the Station Directives. The complement of licensed personnel on each shift met or exceecled the minimum required by IEB-79-05C.
Operators were responsive to plant _ annunciator alarms and _ appeared to be cognizant of plant condition. . .
Plant tours were taken throughout the reporting period on a continual basis.
The areas toured include but are not limited to the following: Turbine Building Auxiliary Building , Units 1, 2, and 3 Electrical Equipment Rooms Units 1, 2, and 3 Ceble Spreading Rooms Station Yard Zone within the protected area During the plant ?.ours, ongoing activities, housekeeping, security, equip-ment status and raciation control practic s were observed.
Oconee Unit One continued operation at 85-90% power throughou+ the majority of this reporting period. A tube leak on "A" steam generatt e held rela-tively stable at approximately 0.08 to 0.1 gpm.
On 5 Jan, IC 31, the unit tripped as a result of loss of ger.trator excitation but retur ned to power later the same day. A detailed account of the trip is in Paragraph 6.
On January 18, the unit was brought to hot standby in order to repair quench tank drain valve CS-5.
The plant returr ed to power on the following day with no major difficulties. As the repor.f.ig period ends, the unit is at 85% power with a calculated steam generator tube leak of 0.08 gpm.
Oconee Unit Two operated throughout the reporting period at virtually 100% full power with no significant problems.
Unit Three continued a refueling outage throughout the reporting period with no major difficulties. An incident involving a fuel assembly that became-ungrappled due to an unknown cause is currently under investigation and is detailed in Paragraph 15.
6.
Reactor Trip - Unit One On January 5,1981, at approximately 0605, Oconee Unit One tripped from 90%. The initiating event was a turbine trip caused by loss of excitation on the generator field. At the time of the trip, Oconee operations personnel were attempting to increase the VAR's (Reactive Load) on Unit: One and Tso. The operators were to manually increase the VAR's on. both units together to prevent one unit from. losing VAR's while the other gainec. The eactive load (VAR's) was, in fact,. increased too' rapidly on Unit Two fc.ing a drastic and automatic decrease on Unit One, a severe decrease in field magnitude and the resulting reactor trip. The unit response was normal for this type of reacter trip, requiring no manual or unusual actions to recover.
. Licensee requirements and administrative obligations will be peruse 1 further to ascertain complete compliance. (OPEN ITEM 269/81-02-01).
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7.
Control of Secondary Contamination Oconee Unit One has been operating since December 25 with an it;dication of a steam generator tube leak, calculated to 'a 0.08 to 0.1 gpm.
Operating procedure OP/0/A/1106/31, Control of Second:ry Contamination, is being employed by the licensee to effectively minimize radioactive dis-charges from the secondary systems to turbine building sumps and subsequent discharge to the environment. The procedure requires in part that the turbine building sump pump breaker be opened, which places the pump in local
manual control. The procedure further requires that the turbine building sump be released to the environment on a " batch" basis after having sampled the contents of the sump for radionuclide content.
On Sunday, 25 January, 1981, at approximately 0614, the turbine building . sump pump uas started, beginning a batch release. The procedure requires that the t)tal volume of any one release not exceed 6000 gallons or 10 minutes of pump run time with one sump pump. The operator who started the pump left the area to perform another task and forgot to terminate the release. At 0853, after a shift change, the incoming operator found the pump breaker closed (energized) and the sump virtually dry. He immediately openea the breaker and reported the situation to the shift supervisor.
In retrospect, it appears from computer log printout and sump sample results that the pump ran for a total of 19 minutes between 0614 and 0853, equiva-lent to 12,000 gallons discharge. Two sump samples, taken at 0555 and 0820 revealed 'a required dilution flow rate of zero, meaning no Part 20 limits were exceeded during the release.
, Licensee failure to comply with the requirements stipulated in procedure OP/0/A/1106/31 violates Oconee Technical Specification 6.4.1 which requires procedure compliance. (269/81-02-02).
8.
Surveillance Testing The surveillance tests -detailed below were analyzed and witnessed by the inspector to ascertain procedural and performance adequacy.
The completed test procadures examined were analyzed for embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria and sufficiency of technical content.
The selected tests witnessed were examined to ascertain that curi ent written approved procedures were available and in use, that test equipment in use was calibrated, that test prerequisites were met, system restoration completed and test results were adequate.
The selected procedures perused attested conformance with applicable Tech- 'nical Specifications, they appeared to have received the required adminis-trative review and they apparently 'were performed within the surveillance frequency prescribe. . .
l Procedure Title IP/1/A/305/3C NI & RPS Channel C, Unit 1 IP/0/A/301/3S SR & IR Channel Test IP/1/A/305/30 NI & RPS Channel 0, Unit 1 IP/1/A/305/3A NI & RPS Channel A, Unit 1 IP/1/A/305/3B NI & RPS Channel B, Unit 1 IP/0/B/340/02 Control Rod Power Supply PT/0/A/230/1 Radiation Monitor Check IP/2/A/305/3A NI & RPS Channel A, Unit 2 IP/2/A/305/38 NI & RPS Channel B, Unit 2 IP/2/A/305/3C NI & RPS Channel C, Unit 2 IP/2/A/305/3D NI & RPS Channel 0, Unit 2 IP/3/A/305/3A NI & RPS Channel A, Unit 3 IP/3/A/305/3B NI & RPS Channel B, Unit 3 IP/3/A/305/3C NI & RPS Channel C, Unit 3 IP/3/A/305/3D NI & RPS Channel D, Unit 3 The inspect < r employed one or more of the following acceptance criteria for evaluating the above items: 10 CFR ANSI N 18.7 Oconee Technical Specifications Oconee Station Directive Duke Administrative Policy Manual Within the areas inspected, no violations or deviations were identified.
9.
CRD Breaker Failures .On December 2,1980, during a monthly Reactor Protection System Calibration .and Functional Test, a control rod drive breaker (CRD breaker # 11) failed to trip as required; the breaker opened, but there was a 4 to 5 second time delay involved. The apparent cause of the time delay was mechanical binding of the-trip shaft bearing.
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Research into the history of CRD breaker malfunctions at Oconee reveals that since December of 1978 there have been at least five instances when the breakers did not open as required. Detailed below is a brief tabulation of what the research revealed: Date Unit Type Breaker I.D.
Voltage Cause 17 Dec 78
GE CRD 11 575 AC Mechanical AK-2A-25-1 Binding 18 Jan 79
GE CRD 10 575 AC Mechanical AK-2-25-1 Binding 22 Jan 79
GE CRD CB-1 120 DC Mechanical AK-2-15-2 Binding 2 Feb 79
GE CRD CB-1 120 DC Mechanical AK-2-15-2 Binding 26 Nov 80
GE CRD 11 575 AC Mechanical AK-2A-25-1 Binding IE Bulletin 79-09, issued 17 April, 1979, detailed twelve failures at various facilities of General Electric (GE) type AK-2 (i.e., AX-2A-15, 25, 50, 75, or 100) Circuit Breakers installed in safety-related systems.
The causes for failure were attributed to either binding within the linkage mechanism of the undervoltage (UV) trip device and trip shaft assembly or out-of-adjustment conditions in the same linkage mechanism.
The action to be taken by the licensee pursuant to the Bulletin entailed, in part, developing a preventive maintenance program to assure design perform-ance with the GE type AK-2 circuit breaker.
Duke initiated a preventive l maintenance program meeting the requirements of IEB 79-09 in May of 1979.
Of importance to note is the fact that the AC and DC breakers are'in series in the CRD power train and both have a failure history.
In conversations with the licensee, the inspector determined that: The licensee is aware of the ongoing breaker problem.
- The licensee is actively researching possible breaker replacements.
- The licensee has been in contact with G.E. concerning a solution.
- . The inspector will continue to monitor the licensee's progress toward the solution to_ this problem. (0 pen Item 269/81-02-03).
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10.
Reactor Building Spray Pump Impeller Nut On December 17, 1980, during the Unit 3 refueling outage, Licensee Main-tenance Technicians were disassembling the Reactor Building Spray (BS) pump 3A to replace the mechanical seal and found the impeller fastener loose.
Loose impeller fasteners was the topic of IE circular 79-19. As a result of information supplied in the circular, Duke initiated a change to MP/0/A/ 1300/1, maintenance procedure for the BS pump, to include a program to ensure that impeller lock screws are properly toraued. The 3A BS pump had been checked per the procedure during a previous escage.
This implies that the torque applied to the impellar locking screw per MP/0/A/1300/24 may be an insufficient means of locking the impeller.
The licensee has been consulting with the pump vendor (Ingersoll-Rand) representative for additional input in developing a positive locking arrangement. Surveillance testing of the subject pumps failed to diagnose the degraded condition of the component. The licensee is evaluating supple-mental actions such as selective periodic inspections of impeller locking devices until such time as a positive lock is installed to ensure opera-bility of all station BS pumps. Open Item (287/80-02-01).
' Verify licensee action to install a positive locking device on the 3A RBS pump and upgrade surveillance of the subject pumps.
11. Maintenance Obsersations Maintenance activities were observed, witnessed and reviewed throughout the inspection period to verify that activities were accomplished using approved procedures, and the work was done by qualified personnel. Where appro-priate, limiting conditions for operation were examined to ensure that the equipment removal and restoration procedure was properly followed. Accept-ance criteria for the maintenance activities were as follows: Station Directives 3.3.1, 3.3.2, 3.3.5, and 3.3.15, Administrative Policy Manual, Sections 3.3 and 4.7, Maintenance Activities observed were as follows: a.
Control Rod Motor Tube Flange Leak Repair An inspection of the control od motor tube flanges (located on the reactor vessel head) revealed that 14 had indications of leakage. Work requests for each leak, l. led below, ~were -issued and maintenance procedure.MP/0/A/1140/2B was prepared - to control the - job.
The inspector witnessed removal of 6 of the motor tubes and the cleaning of the gasket grooves for these 6 control rods. The work requests and the' maintenance procedure for all 14 control rods were reviewe. t
Work Reouest Number Control Rod Flance 51266
51268
51274
51275
50918
51273
51272
50945
51270
50947
50946
51271
51269
51267
Following remval of the motor tubes, maintenance personnel removed the old gaskets from 11 flanges.
Upon completion of this activity on January 7,1981, two cf the three maintenance men were found to have nasal contamination. An investigation of this personnel contamination event was conducted by the licensee and the resident inspectors. The event was the subject of PNO-II-81-02 and a news release by DPC, issued on January 7,1981.
The workers were decontwinated and whole body counts were performed on all three men on January 7, 9, and 12.
Results of the whole body counts were as follows: - DATES ' Worker Isotope 1/7/81 1/9/81 1/12/81 -
A Co 3.1 0.65 0.27 60Co 0.2 0.05 0.02
B Co 2.1 0.44 'O.06 60Co~ 0.1 0.04 less than LLD All' lung burdens 'are expressed in micorCuries.
The maximum internal - deposition was 13% of the 10CFR20.103 limit.. SS (Worker A on 1/7/81 of Co.)
The 3 remaining gasiets were removed by workmen using long-handled - tools.
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The job is on going and is scheduled to be completed by the first week of February. Inspector followup is planned.
The inspector found the removal records for each control rod as docu-mented on the work request and the procedure to be satisfactory.
b.
Removal-of 3C-LPI Pump From Service For Seal Repair.
Work Request 12624, voided and re' laced by 97276, was issued to repair p the seals on 3C-LPI Pump. To prepare for this maintenance activity, on January 23,1981, at 0530 hours, the 3C-LPI pump was to be removed from service and drained.
This action is completed using OP/0/A/1102/06, Removal and Restoration of Station Equipment, (R&R). A licensed R0 or SR0 completed the R&R as prescribed by the procedure. Approval for use is granted by the Unit Supervisor or Shift Supervisor to insure the R0 or SR0 has properly completed the R&R. This provides an independent verification prior to removal of the equipment from service.
Appro-priate tags are then issued and the valve alignment is perforn.2d and ' independently verified by utility operators.
At the time this activity was being done, the plant was at cold shut-down with the reactor head removed and reactor coolant pump seals were , being replaced. This required the reactor coolant water level to be maintained at 18 inches on level indicator LT-5. The R0 on duty in the control room was monitoring LT-5 freqcently.
At shift turnover, the level was noted to be at 13 inches on LT-5 indicating a need for . makeup. At 0846 on 1/23/81, the RO received a low flow alarm on the LPI header, observed the LPI motor amp meter was erratic and level was indicating 0 inches on LT-5. Actions to restore level were immediately initiated and at 0910 hours, level was at 34 inches on LT-5.
Review of this event revealed an incorrect valve selection was made when the R&R was prepared. A review of the R&R indicates that when the - supervisor gave his " Approval for Use", the error was not detected.
The utility operators aligned the system as instructed, and completed their independent verification also without detecting the error.
When the system was opened to drain, a flow path was inadvertently established allowing the reactor ' coolant level to decrease to the minimum, whi.h corresponds to 0 inches on LT-5.
The system was draining for approximately two hours, and was occurring over shift change. Following correction of the valve alignment error, the system was correctly aligned for the seal repair without incident.
During the event, the reactor coolant temperature increased from 64 F to 99.5 F.
No personnel were exposed and no increase in radiation levels were noted in the reactor buildin ~ . . . .
This is a violation of technical specification 6.4.1.e. with respect to a failure to follow the R&R procedure.
Although a second signature was obtained, a double verification was not accomplished and the valving error was not caught (287/81-02-02).
12.
Unit 3 Refueling The inspector witnessed portions of the refueling activities during the night and day shifts on Unit 3.
The items observed inclcded: adherence to the procedure; verification that containment integrity was maintained per technical specifications (TS); that baron concentration in the transfer canal and spent fuel pool was as required by TS; the communications between control room, refueling bridge and spent fuel pool were maintained; and proper checkout was made of fuel handling equipment prior to actual fuel movement. No problems or concerns were identified by tha inspector.
Problems encountered throughout the refueling operations were resolved using carefully planned actions.
Changes in sequence steps were processed per policy. A log of significant events was maintained throughout the refueling operations. An accurate core map was mcintained in the control room during the refueling period.
Following completion of fuel movements, core verification was checked using underwater video equipment.
No discrepancies were noted. Burnable poison rod retainers were installed and verified correct with underwater video equipment.
The retainers are installed using procedure TT/3/A/150/02, Installation of Burnable Poison Rod Assembly Retainers. This activity was witnessed by the inspector. No problems were identified.
13.
Polar Crane Violation On January 6, 1981, at approximately 1013, during the Unit 3 Refueling Outage, Mechanical Maintenance personnel operated the polar crane over the fuel transfer casal while the reactor vessel head was removed.
Fuel handling was in progress at the time; however, fuel was not being moved at the moment of the incident. The fuel handling crew was endeavoring to free a stuck fuel assembly.
The above-described operation violated Oconee Technical Specification 3.12.3 which prohibits operation of the building polar crane and auxiliary hoist over the fuel trsasfer canal when the reactor vessel head is removed with irradiated fuel in the core. (287/81-02-03).
14.
Reracking Unit 1/2 Spent Fuel Pool NRC letter dated December 24, 1980 transmitted to the licensee Amendments No. 90, 90, and 87 for licenses for Oconee Nuclear Station units Nos. 1, 2 and 3.
These amendments consist of changes to the Stations common Technical , t ~
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Specifications to allow an increase in the spent fuel storage capacity from 750 to a maximum of 1312 fuel assemblies through the use of neutron absorb-ing high density fuei racks.
Inspectors have reviewed the fuel rack receipt inspection procedure, TN/1&2/A/4000/83, and the installation procedure, TN/1&2/A/1482/0/C, to ensure adequate instruction is provided in the following areas: 1.
Control of rigging and handling to prevent damage to new racks, existing structures and spent fuel.
2.
Removal of existing rack structures.
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Proper location.
4.
Dimensional checks for levelness and clearances.
5.
Final clearance checks using a dummy fuel assembly.
Inspector invcivement in the reracking work activities is ongoing. Areas reviewed include receipt inspection of the racks for obvious defects and apparent shipping damage, verification of compliance with procedures during installation and receipt inspection, adherence to Technical Specification requirements involving fuel handling operations in the spent fuel pool area and verification of alignment checks of installed racks. Review of licensee Quality Assurance records to confirm compliance with requirements of 10CFR5G Appendix B in the area of receipt inspection, shop fabrication, material certification, installation records and QA audits, is ongoing.
15.
Nuclear Station Modifications (NSM) Several station modifications, listed below, were reviewed and job sites visited to ensure that these changes were controlled by established, approved procedures.
Section 4.4 of the Administrative Policy Manual defines the accepted program for modifications. This program is used as the acceptance criteria.
The NSM's reviewed were: NSM-0N-0816, Replace Feedwater Check Valves,.FDW-37 and 46.
NSM-0N-0939, Replace FA and CRA Masts with Single Multi-function Mast.
NSM-ON-1317, Repair Anchors and Hangers per IES 75-02 and IES 79-14 Within the areas inspected, no items of noncompliance were identified. A brief description of the ecdifications and the areas inspected are presented below.
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a.
NSM-0N-0816 Numerous leaks 1.'ve been experienced on feedwater check valves, FWD-37 and 46. These valves are located in the penetration rooms and leakage increases the humidity within the room, which in turn threatens the operability of the penetration ventilation filters.
Repairs to date have been temporary in nature.
A furmanite process has been the primary repair technique. The licensee had initiated plans to replace thase valves with an improved design in August of 1976.
Two valves were received in January, 1981 and are currently being installed in Unit 3.
Procedure TN/3/A/816/0 has been prepared and approved for installation. The procedure was found to be satisfactory and in use at the job site. A visit to the job site on three occasions by the inspector revealed the work to be progressing satisfactorily and in agreement with plans and procedures.
b.
NSM-0N-0939 A study was conducted to determine ways of reducing refueling outage duration. -One of the recommendaticqs was to replace the fuel assembly mast and the control rod assembly n.ast with a single multi-function mast. This new device is expected to reduce the overall time required to complete a refueling sequence.
Station modification ON-0939 was prepared to implement the recommenda-tion.
The following documents were reviewed to determine compliance with the modification controls: NSM-0939, Replace FA & CRA Masts with Single Multi-Function Mast.
BWNP 20004 (6-76) Multiple Function Mast Specification 08-1005791-00 Vendor Procedures Nos. 20726-2, 20726-1 and 20726-3.
C-20726-3, Shop Checkout for Multi-Function Mast Procedure Numbers: 5131, Checkout and Operating Procedure for Fuel Handling Machine With Multi-Function Mast 5116, FA Grapple Test Procedure L 5130, Test' Procedure for Orifice Rod and Control Rod 5121, Fuel Grapple Pull Test
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The multi-function mast was installed in Unit 3 and used for the fifth
refueling operations (Cycle 6) for this unit.
Installation and checkout procedures conducted at the Stearns-Roger Manufacturers shop and at Oconee were satis facto ry.
Throughout refueling activities, representatives from Stearns-Roger were available to assist and resolve any problems encountered.
, On January 12, 1981, near the end of refueling steps, one fuel assembly became disengaged from the fuel assembly grapple while attempting to place it in core position A-10.
An investigation is underway to determine the cause of this event and a report is expected from the licensee in. February, 1981. A team was formed to prepare a special procedure to recover the ungrappled fuel assembly.
Procedure T0/3/A/1300/01, Removal of Ungrappled Assembly 0/MC from Core Area, was developed and approved for use.
The procedure required a 3800 pound cable to be looped under the fuel assembly with the cable ends attached to the fuel bridge. Tension was applied to the cable to prevent the fuel assembly from falling; the assembly was then grappled and raised slightly. During the raising, tension was maintained on the cable. The fuel assembly was then hand jacked into the mast. With the fuel assembly back up in the mast, the bridge was moved by hand wheel to an area away from the core. The fuel assembly was then placed in an oversized fuel storage rack for examination.
Refueling' steps were then completed using the auxiliary bridge and the main bridge without further problems. A complete review of the multi-function mast is underway.
The inspector witnessed the entire recovery operations. The operation proceeded smoothly and according to plan. There were no violations-identified with this operation.
c.
NSM-0N-1317 In response to IEB 79-02 and IEB 79-14, the licensee has initiated modification 1317 to cover repair. of anchors and hangers. A general procedure, MP/0A/3019/04, Pipe Support Corrective Maintenance, has been issued for repair or corrective activities.
During the Unit 3 refueling outage, the reactor building spray header hangers were being corrected.
The inspector visited the job. site and ir.terviewed the workmen. ' At the job site, the inspector found the procedure.in use, records being maintained and work progressing as planned. There were no violation within the areas inspected.
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