IR 05000269/1982027
| ML20062H893 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry, Oconee  |
| Issue date: | 07/26/1982 |
| From: | Bryant J, Falcol D, Falconer D, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20062H869 | List: |
| References | |
| 50-269-82-27, 50-270-82-27, 50-287-82-27, NUDOCS 8208160202 | |
| Download: ML20062H893 (11) | |
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A REcog
. UNITED STATES jo,,
NUCLEAR REGULATORY COMMisslON
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REGION 11 o
.g 101 M ARIETTA STR EET, N.W.
- f ATLANTA, GEORGI A 30303
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Report Nos. 50-269/82-27, 50-270/82-27, and 50-287/82-27 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Facility Name: Oconee Nuclear Station Docket Nos. 50-269, 50-270, and 50-287 License Nos. DPR-38, DPR-47, and DPR-55 Inspection at Sconee site near Charlotte, North Carolina Inspectors':
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Date Signed Approved by:
Jrm h f/h/f/rL J. Agaht, Seejf tn Chief, Division of Project-Date Signed find Resident Programs SUMMARY Inspection on June 10 - July 15, 1982 r
Areas Inspected
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This routine, unannt unced inspection involved 286 resident inspector-hours on
. site in the areas of operations safety verification, surveillance testing, station maintenance activities and plant trips.
Results Of the four areas inspected, no items of noncompliance or deviations were identified.
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8203160202 820726 PDR ADOCK 05000269 Q
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REPORT DETAILS 1.
Persons Contacted Licensee Employees
- J. E. Smith, Station Manager
- J. N. Pope, Superintendent of Operations
- T. B. Owen, Superintendent of Technical Services
- T. Matthews, Licensing and Projects Engineer Other licensee employees contacted included technicians, operators, security force members, and staff engineers.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized on July 16, 1982, with those persons indicated in paragraph 1 above. The licensee voiced cognizance and concern over the findings contained herein.
3.
Licensee Action on Previous Inspection Findings (Closed) Violation (50-287/82-12-01) Movement of spent fuel with the spent fuel pool ventilation system inoperable. The licensee has revised approp-riate procedures to tag out of service all fuel handling devices if the spent fuel pool ventilation system is rendered inoperable. This item is closed.
4.
Unresolved Items Unresolved items were not identified during this inspection.
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5.
Plant Operations The inspector reviewed plant operations throughout the report period, June 10-July 15, 1982 to verify conformance with regulatory requirements,
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technical specifications and administrative controls. Control room logs, shift supervisors logs, shif t turnover records and equipment removal and restoration records for the three units were routinely perused.
Interviews were conducted with plant operations, 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 pre-scribed in Section 3.08 of the Station Directives. The complement of
licensed personnel on each shift met or exceeded the minimum required by
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technical specifications. Operators were responsive to plant annunciator
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alarms and appeared to be cognizant of plant conditions.
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Plant tours were taken throughout the reporting period on a routine basis.
l The areas toured include but are not limited to the following:
Turbine Building
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Auxiliary Building Units 1, 2, and 3 Electrical
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Equipment Rooms i
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Units 1, 2, and 3 Cable
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Spreading Rooms Station Yard Zone l
Within the Protected Area
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During the plant tours, ongoing activities, housekeeping, security, equip-ment status and radiation control practices were observed.
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Unit 1 began the report period in a forced outage to repair a failed CRD l
stator as detailed in report 269/82-23. The unit was placed on line on June 14, 1982 and attained 100 percent on June 16, 1982.
Power operation continued at 100 percent until June 24, 1982 when power was reduced to 96 percent as a result of loose parts indications in the "A" steam generator. Detailed evaluation revealed that the indications
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originated in the quench tank recirculation line and were of no signi-a
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ficance.
Power operation at 100 percent was resumed.
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l On July 6,1982, power was reduced to approximately 15% and the unit turbine
taken off-line to repair degraded "C" extraction piping identified during
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the investigation stemming from the Unit 2 "C" extraction pipe failure on i
June 28, 1982 as detailed in report 50-269/82-26.
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l The Unit was returned on line on July 7,1982 and attained 100 percent power l
l on July 8, 1982 where it remained until the close of the report period.
l Unit 2 began the report period operating at 60 percent power limited by the
"A" high pressure injection (HPI) pump being inoperable.
Power operation
I continued at 60 percent until the unit tripped on June 26, 1982.
l The reactor trip was initiated by a main turbine / generator trip due to
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i electro-hydraulic control (EHC) oil pressure problems encountered during the performance of the secondary system protection test.
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During the trip, the main steam safety valves lifted as expected, however, t
l one valve failed to rescat within tolerence. RC pressure remained below the
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setpoint of the PORV and pressurizer code safety valves, primary and i
secondary levels remained on scale, no ES setpoints were reached nor was
emergency feedwater initiated.
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The unit was returned to critical conditions and power escalation commenced until the reactor was manually tripped from 95 percent power or June 28, 1982 due to a large rupture in the "C" extraction line as detailed in report (50-270/82-26).
The failed extraction piping was repaired and the unit achieved criticality on July 11, 1982. The Unit attained 100 percent power on July 13, 1982.
Unit 3 began the report period in a refueling and 10 year inservice inspection outage. Auxiliary feedwater header repair continued throughout the report period as detailed elsewhere in this report.
On July 13, 1982 a temporary plug installed on the 3A, cold leg became dislodged and fell into the defueled reactor vessel. The plug was retrieved on July 14, 1982.
Preliminary investigation revealed that one incore instrument nozzle was damaged by the plug. Details of licensee corrective actions will be included in the next report.
6.
Maintenance Activities Maintenance activities were observed and/or reviewed throughout the report period to ascertain that the work was being performed by qualified personnel, that activities were accomplished employing approved procedures or the activity was within the skill of the trade.
Limiting conditions for operation were examined to ensure that technical specification requirements were satisfied. Activities, procedures, and work requests were examined to ensure adequate fire protection, cleanliness control and radiation protec-tion measures were observed and that equipment was properly returned to service.
Acceptance criteria employed for this review included but were not limited to:
STATION DIRECTIVES ADMINISTRATIVE POLICY MANUAL TECHNICAL SPECIFICATIONS TITLE 10 CFR.
Detailed below are 11 maintenance activities which were observed and/or reviewed during the report period:
Work Request Number Component 26067 C Bleed Extraction Steam Line 26620 2A LPI Pump 26619 2LP-32
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26015 C LPSW Pump 25894 2 HP-410 25787 B LPSW Pump 25876 2 LP-41 t
25729-2 C RBCU 25415 2 HP-299
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25378 Instrument Air Compressor 25058 2 HP-115
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Two large maintenance activities of particular interest are detailed below.
Emergency Feedwater Header Replacement
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Because of the discovery of damage to the OTSG Internal Auxiliary Feedwater (AFW) Headers at Davis Besse (Toledo Edison) and Rancho Seco (Sacramento Municipal Utility District) the decision was made to shut down Unit 3 on the
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evening of April 23, 1982 and begin a refueling outage earlier than planned.
(Units 1 and 2 utilize an external AFW header and were not subject to this
damage.) After Unit 3 was cooled and drained, a visual inspection was begun on the evening of April 29, 1982, and it was reported early the next day that damage had been discovered somewhat similar to that reported by Davis Besse and Rancho Seco.
The header is mounted on top of the upper shroud between the 15th Tube Support Plate (TSP) and the Upper Tube Sheet (UTS). The internal AFW ring i
header is constructed of 3/8 inch plate metal with a 13 inch x 5 inch rectangular cross-section. There is a single AFW nozzle injecting into the header to fill the header with water. The water flows into the steam i
generator tube bundle through sixty li inch diameter holes located near the top of the header and equally spaced around it. The header rests on the top of the shroud and is attached to it by eight pairs of brackets which are equally spaced around the header.
Each bracket measures 11 inches wide x 2 3/8 inches long x 3/8 inch thick and is welded to the header. A 2 11/16 inches long x 3/4 inch diameter dowel pin is welded to the inner bracket and
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slip-fit through the shroud and the outer bracket to hold the header in place while allowing for differential thermal movement between the header and the shroud.
The apparent cause of the deformation of the internal auxiliary feedwater
header is inadequate design to withstand the large thermal' and pressure
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forces generated when cold auxiliary feedwater is injected into the header.
During normal operation the header would be filled with super-heated steam
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as the header sits in the upper super heat region of the OTSG. When cold
auxiliary feedwater ( 80 F) is injected into the retangular header, very
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large local pressure differences can occur with large steam-water contact areas which cannot be locally compensated for quickly enough through the 1}
inch diameter flow holes.
Except for the extra strength weld areas the 3/8 inch plate walls are not reinforced and are apparently inadequate for the loads generated under these conditions.
In addition to the possible large pressure drop area the header experiences high thermal differences when the cold AFW enters the header and begins to fill from the bottom up and flows around the header from the single nozzle. While the exact failure process is not totally known, the above forces are believed to be the dominant factors.
The current strategy for the repair is to stabilize the internal header in place and blank flange the existing AFW nozzle. The internal header would serve then mainly as an extension of the shroud and would maintain steam cross flow at the present distance above the 15th TSP.
To stabilize the internal header, six holes are being drilled through the steam generator shell and shroud near each dowel pin and bracket location (except bracket numbers 2 and 3 which can be reached from the manway). The dowel pins will be removed. All loose parts will be recovered. The internal header will be jacked up slightly to remove any internal brackets not securely fastened. The internal header will then be centered on the shroud and welded to the shroud through the six holes and the existing manway.
The six holes drilled in the steam generator shell and shroud for header stabilization work will also be used as points of injection for an external AFW ring header. The design of the external header system is very similar to the design utilized on Oconee 1 and 2.
The design includes an external ring header with six J-pipe risers feeding into the steam generator through thermal sleeves, directly into the tube bundle. The main difference between the external AFW header system to be installed on Oconee 3 and the ones utilized on Oconee 1 and 2 is a new thermal sleeve design which should help eliminate the thermal sleeve cracking problem experienced on the old design.
At the close of this report period, all the holes have been drilled on both steam generators, the "B" internal header has been stabilized and the "A" header is being repaired. The resident inspection staff will continue to monitor the repair efforts.
Thermal Shield Bolt Replacement On January 22, 1982, three thermal shield bolts were observed to have broken heads during a visual inspection of the Oconee Unit 2 core support assembly.
The attachment bolts for shock pad Y-2 were also discovered broken.
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sonic testing revealed crack indications on a total of 24 of the 96 thermal shield bolts. The apparent cause of the bolt failures, as was the case on Oconee Unit 1(Report 50-269/81-18), was intergranular stress corrosion cracking. An evaluation was performed concerning the safety implications of the thermal shield bolt failures on Oconee Unit 1 (R0-269/81-11). The
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i results were reported in previous correspondence, and are considered applic-able to the recent Oconee 2 failures.
The thermal shield bolts were replaced with stud and nut assemblies as they were on Oconee Unit 1.
The shock pad was removed. B&W and Duke Power are
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evaluating the shock pad failure to determine cause and ultimate resolution.
Initial video inspection of the unit 3 core support assembly (CSA) during the ongoing outage did not indicate the same failures as on units 1 & 2.
It was not until the locking clips were removed did it become evident that i
Units 3's CSA had a problem similar to Unit 1 and 2's.
The lower thermal shield bolts were made of ASTM A286 and had been made by
hot heading heavily cold reduced (40-50%) bar stock. The result of this processing was a pronounced microstructural transition which was coin-cidental with the bolt head to shank fillet.
NOTE:
HOT HEADING, HEAVILY COLD REDUCED (40-50%) BAR STOCK -
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HEAVILY COLD REDUCED - A large piece of bar stock is extruded, or rolled, to reduce its size.
For these bolts, a piece of 2" OD bar stock has been reduced to 1" 0D by cold working (extruding or
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rolling).
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HOT HEADING - The bar stock is heated until the metal almost becomes fluid, then the bar stock is forced ~into a mold to form the head.
As was seen on Units 1 and 2, UT examination revealed only the presence of an indication.
Bolts that showed no indication by UT were found to be intact when removed but for those bolts with indication, the percent of through wall was not indicative of the bolts condition. Therefore, UT
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examination was used to identify good and bad bolts and not to determine the i
degree of degradation.
The thermal shield bolts were replaced with a stud and nut arrangement as were units 1 and 2.
The work was performed under NSM 2002. The resident inspection staff monitored the replacement / repair efforts through f
completion.
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Surveillance Testing The surveillance tests detailed below were analyzed and/or witnessed by the i
i inspector to ascertain procedural and performance adequacy.
The completed test procedures examined were analyzed for embodiment of the
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j necessary test prerequisites, preparations, instructions, acceptance criteria and sufficiency of technical content.
The selected tests witnessed were examined to ascertain that current written approved procedures were available and in use, that test equipment in use
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completed and test results were adequate.
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The selected procedures perused attested conformance with applicable Technical Specifications, they appeared to have received the required
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administrative review and they apparently were performed within the surveil-I lance frequency prescribed.
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The inspector employed one or more of the following acceptance criteria for l
evaluating the above items:
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10 CFR
Oconee Technical Specification
.i Oconee Station Directive
Duke Administative Policy Manual J
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Procedure Title l
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l PT-1-A-600-10 RCS Leakage Evaluation
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PT-1-A-600-12 Turbine Driven Emergency Feedwater Pump Test IP-1-A-305-03B RPS Channel B On Line
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IP-0-A-301-03S SR and IR Channel Test
i PT-0-B-610-4A Oconee-Control Supervisory Control Test
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i PT-0-A-202-13 HP and LPI Pump Venting j
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IP-0-B-0340-02 CRD DC Hold Supply
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PT-0-A-290-05 Secondary Systems Protection Test i
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IP-0-A-310-12C RB Spray Logic Test
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IP-0-A-310-13C RB Isolation and Cooling i
PT-0-A-290-3 Turbine Control Valve Movement Test i
f IP-0-A-310-12A HPI and RB Isolation Test
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TP-0-A-310-13B LPI Logic CH-4 On Line f
PT-0-A-170-05 Penetration Room Ventilation System
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8.
Reactor Building Spray On June 23, 1982, with Unit 1 operating at 100 percent power, both trains of reactor building spray (RBS) were rendered inoperable for approximately fourteen minutes as detailed below.
During a stroke test of the RBS Train A discharge valve 1BS-1, the valve failed to indicate open. The valve was subsequently visually verified to be full open and a priority work request was initiated to correct the mal-function.
Prior to initiating maintenance,the licensee decided to test the redundant component, RBS train B discharge valve 1BS-2. To avoid disabling both trains of RBS while testing 1B5-2, the licensee opened the train A suction valve 1BS-3, thus providing a train A RBS path through the verified open discharge valve 1BS-1 if required.
However, opening IBS-3 also provided a gravity flow path from the borated water storage tank (BWST) to the reactor
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building floor through the normally open RBS header drain valve 1BS-15.
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The licensee removed train B from service, in preparation for testing 1BS-2.
Approximately 500 gallons of BWST water drained into the reactor building.
Trending reactor building sump level alerted the operators and 1BS-3 was immediately closed, securing the leak path.
Closing IBS-3 rendered both trains of RBS inoperable. This situation
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persisted for approximately fourteen minutes until train B was returned to service.
Both trains of RBS inoperable violates technical specification 3.3.6.c.1.
The incident was reported to the NRC as required by technical specification 6.6.2.la(2).
Three reactor building cooling units (RBCU) remained operable for reactor building accident pressure suppression. Accident analysis has shown that reactor building design pressure would not be reached during a design basis large break loss of coolant accident with three RBCU's operable.
The licensee realized that closing IBS-3 would remove the second train of RBS from service, however that action was necessary to isolate the estab-lished BWST leak path into the reactor building. Actions necessary to return the B train to service were promptly taken.
In that the above delineated violation meets the criteria set forth in current NRC enforcement policy designed to encourage licensee initiative for self-identification and correction of problems, a notice of violation will not be issued.
9.
Emergency Feedwater Initiation Logic On July 6, 1982 the licensee detected that certain technical specification required surveillance testing of emergency feedwater initiation logic was not performe m p
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Technical Specification 4.1, table 4.1-1, item 53a, requires monthly operabi-lity testing of the control oil pressure switches on the main feedwater pump turbines which initiate auto start of all three emergency feedwater pumps.
Item 53b requires monthly operability testing of the discharge pressure switches on the main feedwater pumps which function, as do the control oil pressure switches, to initiate auto start of emergency feedwater.
For simplicity, the specifies of the event will be discussed on a per unit basis.
Unit 1 - The technical specification amendment incorporating the require-ments of items 53a and 53b was approved on April 8,1982. On May 23, 1982, 45 days from the date of the specification, the surveillance grace period expired resulting in the technical inoperability of the three emergency feedwater pumps on Unit 1.
It was not until July 6,1982, after the success-ful testing of the logic, that the pumps were returned to operable status.
Unit 2 - On April 9,1982 calibration procedure IP-0-A-275-5Y Turbine
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Driven Emergency Feedwater Pump Initiation Functional Test was performed.
Although this is an annual test, it fulfills the requirements of the monthly test. On May 24, 1982 however, the surveillance grace period expired resulting in the technical inoperability of the turbine driven pump until July 8, 1982 when the surveillance test was successfully completed.
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determined that the surveillance interval was not exceeded for the two motor
driven emergency feedwater pumps. Technical specification 3.4.1 requires
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that the reactor not be heated above 250 F unless three emergency feedwater pumps (one steam driven pump capable of being powered from an operable steam
supply system and two motor driven pumps and associated initiation
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circuitry) are operable.
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During the period between May 23, 1982 and July 6, 1982 the Unit 1 emergency T
feedwater pumps were required to be operable from June 12 until July 6, a
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total of 24 days. On Unit 2, the turbine driven pump was required to be
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i operable from May 24 until June 28, a total of 36 days. Oconee Unit 3 was not affected since it was shutdown for virtually the entire period, i
Once the problem was identified on July 6, 1982, the licensee took prompt
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corrective action, testing the unit 1 logic the same day and the unit 2 logic en July 8.
The root cause of the above delineated events appears to be inadequate review of the new technical specification requirements in that the Surveil-lance requirements were neithe. recognized nor implemented.
In subsequent discussions held with appropriate levels of licensee
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management, it was discussed that they recognized the inadequacies revealed
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by the above detailed events and are currently evaluating the current process through which new technical specification requirements are imple-
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~l mented. The licensee intends to modify the process to preclude future instances of the type discussed, i
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In that the above delineated violation meets the criteria set forth in current NRC enforcement policy designed to encourage licensee initiative for self-identification and correction of problems, a notice of violation will not be issued.
The resident inspection staff will review the program changes to ascertain adequate corrective action.
10. HP Surveillance On July 15,1982 and 9:00 p.m., the resident inspector, while performing a routine auxiliary building tour found the South door to room 304, a HIGH RAD area to be unsecured. The inspector summoned an HP technician to the area to witness the occurrence and secured the door.
10 CFR 20.203 requires that each entrance or access point to a high radiation area be: equipped with a control device which shall cause the level of radiation to be reduced below that at which an individual might receive a dose of 100 millirems in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> upon entry into the area; or equipped with a control device which shall energize a conspicuous visible or audible alarm signal in such a manner that the individual entering the high radiation area and the licensee or a supervisor of the activity are made aware of the entry; or maintained locked except during periods when access to the area is required, with positive control over each individual entry.
Room 304 is normally maintained locked except during periods of personnel access. The above delineated finding constitutes a violation of the require-ments of 10 CFR 20.203.
The licensee was cited in violation of the same requirement in report 50-269/82-17. The NRC has not received the licensees response to the violation, nor the context of proposed corrective actions to be implemented, thus this most current violation will be held in abeyance.
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