IR 05000269/1982015

IE Insp Repts 50-269/82-15,50-270/82-15 & 50-287/82-15 on 820410-0510.No Noncompliance Noted.Major Areas Inspected: Operations,Surveillance Testing,Maint & NUREG-0737 Mods

ML20054K166
Person / Time
Site:	Oconee
Issue date:	06/11/1982
From:	Bryant J, Falconer D, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20054K161	List: IR 05000269/1982015 ML20054K160
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.1, TASK-2.B.3, TASK-2.F.1, TASK-TM 50-269-82-15, 50-270-82-15, 50-287-82-15, NUDOCS 8207010262
Download: ML20054K166 (11)

Text

- - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ .____ _ _ _ _ _ _ _ _ _ _ _ _

' * *

rare

• g UNITED STATES 8 o NUCLEAR REGULATORY COMMISSION 3 E REGION ll 0 8 101 MARIETTA TT., N.W., SUITE 3100 g ATLANTA, GEORGIA 30303

• **

Report Nos. 50-269/82-15, 50-270/82-15 and 50-287/82-15 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, DPR-55 Inspection at Oconee site near Seneca, South Carolins Inspectors: [2 A cMA /h, W. Orders (/ gf b 6////SZ Date Signed k.' (l r h a s fN,s a

-

bhlIES D. Falco er{ / g' r/ Date' Signed Approved by: 6 4--~4--

J. C. Bryant, Section Chief ( Division of b d /'!IL Da'te Signed Project and Resident Programs SUMMARY Inspection on April 10 - May 10,1982 Areas Inspected This routine, announced inspection involved 289 resident inspector-hours on site in the areas of operations, surveillance testing, maintenance, and NUREG 0737 modification Results Of the four areas inspected, no violations or deviations were identifie B20611 PDR ADOCK 05000 G

-- -- . . - - _ - _ .

.

. .

DETAILS

' Persons Contacted

Licensee Employees

• J. Ed Smith, Station Manager J. N. Pope, Supervisor Operations

, T. Owen, Supervisor Technical Services i J. Vaughn, Supervisor Mechanical Maintenance

• T. Cribbe, Licensing & Project Engineer

• T. Matthews, Licensing Engineer

) Other licensee employees contacted included technicians, operators mechanics, security force members and office personne * Attended exit interview Exit Interview The inspection scope and findings were summarized on April 10, 1982, with those persons indicated in paragraph 1 abov . Licensee Action on Previous Inspection Findings

,

Not inspecte . Unresolved Items Unresolved Items were not identified during this inspectio . Plant Operations The inspector reviewed plant operations throughout the report period, April 10 - May 10, 1982 to verify conformance with regulatory requirements, technical specifications and administrative controls. Control room logs, shift supervisors logs, shift turnover records and equipment removal and restoration records for the three units were routinely peruse Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance personnel on day and night shift 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 exceeded the minimum required by technical specifications. Operators were responsive to plant annunciator j alarms and appeared to be cognizant of plant conditions.

!

l

;

,_ _ - _ _ _ , , _ _ _ _ _ _ . - _ . . _ . - - _. _ _ _ _ . _ . _ _ _ _ , , _ , -

.

. .

Plant tours were taken throughout the reporting period on a continual basi The areas toured included, but were not limited to the following:

Turbine Building Auxiliary Building Units 1, 2 and 3 Electrical Equipment Rooms Unit 1, 2 and 3 Cable Spreading Rooms Station Yard Zone Within The protected area Unit 2 Reactor Building During the plant tours, ongoing activities, housekeeping, security, equipment status and radiation control practices were observe Oconee Unit 1 began the report period operating at a power level of 100 percent. The unit was shut down on April 20, 1982 to add oil to the 1A1 reactor coolant pump lower motor bearing. Reactor power was returned to 100 percent on April 21, 1982. Operation continued at 100 percent until feedwater heater problems necessitated a reduction in power to 81 percent on May 5, 1982. After isolating the feedwater heater leak (heater 1-B-1),

reactor power was returned to 96 percent where it remains at the close of this repor Oconee Unit 2-began the report period in the latter stages of an ISI/ refueling outage. The unit began heatup from cold shutdown conditions on April 26, 1982. On April 29, 1982, the unit was returned to cold shutdown conditons and the RCS was drained to replace degraded vertical tendons in the secondary shield wall and repair valve 2-CF1 as detailed elsewhere in this report. The anticipated on line date is May 20, 198 Oconee Unit 3 began the report period operating at a power level of 100 percent. On April 24, 1982, the unit shut down for an extended

~

ISI/ refueling outage approximately 19 effective full power days early to examine steam generators A and B for auxiliary feedwater header degradatio Results of the examination are delineated elsewhere in this repor . Surveillance Testing The surveillance tests datailed below were analyzed and/or witnessed by the inspector to ascertain procedural and performance adequac The completed test procedures examined were analyzed for embodiment of the necessary test prerequisites, preparations, instructions, acceptance criteria and sufficiency of technical conten The selected tests witnessed were examined to ascertain that current 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 adequat The selected procedures perused attested conformance with applicable Technical Specifications, they appeared to have received the required

-_ _ _ _ - _ _ _ _ _ _ _ - . _ _ _

. .

administrative review and they apparently were performed within the surveillance frequency prescibe Procedure Title IP-0-A-0310-12-A HPI & RB Isolation CH-1 9n-Line IP-0-A-0310-12-B LPI Logic CH-3 On-Line IP-0-A-0310-13-A .HPI & RB Isolation CH-2 On-Line IP-0-A-0310-13-B LPI Logic CH-4 On-Line IP-0-A-0310-14-A ES Analog CH-A On-Line IP-0-A-0310-14-B ES Analog CH-B On-Line PT-1-A-600-10 RC Leakage Evaluation Test PT-1-A-600-1 Periodic Instrument Location PT-0-A-230-01 Radiation Monitor Check PT-0-A-230-15 HPI Motor Coolant Flow Test PT-0-A-150-09 Personnel Hatch Leak Test PT-0-A-600-15 CRD Movement Test IP-1-A-0305-03C RPS CH-C On-Line PT-0-A-160-03 RB Coolers ES & Performance PT-2-A-160-12 TDEFWP Performance Test PT-0-A-160-03 RB Coolers ES & Performance Test PT-0-A-250-05 HPSW Pump & Power Supply IP-0-B-340-02 CRD DC Hold Supply IP-1-A-305-03B RPS CH-B On-Line PT-1-A-600-12 Turbine Driven Emergency Pump PT-1-A-600-13 Motor Driven Emergency Pump PT-1-A-203-06 LP Injection Performance Test The inspector employed one or more of the ;ollowing acceptance criteria for evaluating the above items:

10 CFR ANSI N 1 Oconee Technical Specifications 0conee Station Directive Duke Administrative Policy Manual Within the areas inspected no items of non-compliance or deviations were identifie . 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

.

, - . . - _ __ .. . - . -

. .

!

,

4 i ensure adequate fire protection, cleanliness control and radiation j protection measures were observed and that equipment was properly returned

service t Acceptance criteria employed for this review included but was no limited to

Station Directives Administrative Policy Manual

'

Technical Specifications Title 10 CF Detailed below are 7 of 39 maintenance activities which were observed and/or reviewed during the report period:

i Work Request Component 25255 A Spent Fuel Filter

'

25201 Valve BS-3 24848 1-RIA-54 i 23476 1-LPSW-24 22435 2-BS-10 21452 2-LP-1 21450 2-CF-1 52523B Unit 2 Secondary Shield Wall Tendons

,

Of particular interest was the maintenance performed on valve 2-CF-1 as a j result of the following event.

i On April 26, 1982 valves CF-1 and CF-2 were closed in preparation for the

'

'

performance of the intersystem LOCA leak rate test (PT/2/A/150/150).

Personnel inside the reactor building when the valves were closed called the l control room informing them that CF-1 was damage Subsequent scrutiny revealed that the Limitorque operator had torn itself from the valve after i bending the 21 inch diameter valve stem approximately 10 .

Analysis reveals that the valve operator failed to operate properly due to an accumulation of grease in the Belleville washer housing area which

,

precluded torque switch actuation.

i The valve was disassembled, examined, lapped and the stem was replaced.

!

! The operator was examined and refurbished as necessary, the grease was removed from the spring housing and stroke tested successfully on May 10,

'

198 Current licensee plans entail the examination of valve CF-2 for similar j problems and, at the next convenient opportunity, implementation of j modification which will vent the Belleville washer housing back to the gear

,

box thus preventing recurrance of this event.

t

-_. -. .

, - - _ _ _ . . . - . . _ _ . - _ _ - . . _ _ _ _ _ _ - - - _ . _ _ - - . - _ . - _

. .

The resident inspection staff is currently examining similar failures to determine generic significance. The results of the examination will be documented in the next repor . TMI Action Items The status of selected Unit 2 TMI action item modifications is categorized below. The modifications installed on Unit 2 were verified by the resident inspection staff. The licensee providad justification for the items that were not implemented by letter to the Nuclear Regulatory Commission dated April 16,198 II. Reactor Coolant System Vents Item II.B.1 requires that remotely operated reactor coolant system and reactor vessel head high point vents be installed. The Oconee design of the RCS high point vent system entails two solenoid operated valves mounted in series in each of the two steam generator piping high points and in the reactor vessel head high point. The resident inspectors verified the installation of the modification on Unit II. Postaccident Sampling Item II.B.3 requires that a design and operational review of the reactor coolant and containment atmosphere sampling systems be performed to determine ability to sample under accident conditions. . Should the review reveal that personnel could not promptly and safely obtain samples, additional design features and/or shielding are to be provide At Oconee, sampling points have been selected to allow collection of pressurized and unpressurized reactor coolant samples. Pressurized and unpressurzed reactor coolant will be collected from the cold leg drain line on each unit. A sump sample will be collected from the low pressure injection system coolers. The pressurized and unpressurized reactor coolant and sump sample lines will be routed to a sampling bood designed to reduce radiation exposures during sample collectio In addition to the reactor coolant and sump samples, a containment atmosphere sample line will also be routed to this sampling hood. The containment atmosphere sample will be obtained from the hydrogen analyzer sample lines.

i

The resident inspection staff verified the installation of the in-contain-j ment portions of this item on Unit Delays associated with the Unit 1-

'

modification have impacted the Unit 2 installation schedule. The licensee anticipates the completion of the Unit 2 system by September 30, 1982.

,

l II.F.1(1) Noble Gas Effluent Monitor i

Item II.F.1.(1) requires that noble gas effluent monitors be installed with an extended range designed to function during accident conditons as well as during normal operating conditions.

.

. _ . _ , _ _ _ _ _ - . - - . __ , __ , _ _ _ . - __

. .

At Oconee, unit vent monitors for nobles gases are to be provided for each'

unit with a range adequate to cover-normal and accident conditions. Three mogitorswillberequiredtomeasureactivitiesfrom1x10-7uCI/ccto1x 10 uCi/cc of noble gase Continuous indication of unit vent radiation level and the appropriate alarms will be provided in the Control Roo Erratic indications from the installed system has necessitated the return of the detector portion to the vendor for modification. Satisfactory operation of the balance of the Unit 2 system was verified by the resident inspection staf II.F.1.(3) Containment High Radiation Monitor ItemII.F.1.(3)reggiresthatcontainmentradiation-levelmonitorswitha maximum range of 10 rad /hr be installed; a minimum of two such monitors that are physically separated be provided; and monitors be developed and qualified to function in an accident environmen The liceasee has installed the in-containment portions of this syste Cable connector problems have delayed modification completion. The resident inspection staff verified the completed portions of the Unit 2 syste II.F.1.9(4) Containment Pressure Monitor Item II.F.1(4) requires that continuous indication of containment pressure be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and-5 psig for all containment The licensee committed in a letter to NRC staff dated January 2,1980, to j install two identical safety class pressure transmitters to monitor the i Reactor Buildino (RB) pressure and provide signals to Control Room indicators, (one per transmitter), and a shared chart recorder. Each

channel will be powered by vital instrument busses. Each transmitter will be located outside the RB and will monitor the pressure with a bellows

'

sensor coupled with a filled capillary tub Each transmitter will have its own separate independent containment penetration and will be completely

,

independent from the other channel. This instrumentilion will meet l Regulatory Guide 1.97, dated December 1975.

l l Each transmitter will monitor a range of -5 psig to 175 psig, a range of j three times the RB design pressure.

l The resident inspectors verified the installation of the above equipment on ( Oconee Unit 2.

l II.F.1.(5) Containment Water Level Monitor Item II.F.1.(5) requires that continuous indication of containment water i

level be provided in the control room for all plants. A' narrow range I

i

. .

instrument shall be provided covering the range from the bottom to the top of the containment sump. A wide range instrument shall also be provided which shall cover the range from the bottom of the containment to the elevation equivalent to a 600,000 gallon capacit At Oconee, the Reactor Building (RB) water level will be monitored by wide range and narrow range systems. The narrow range level transmitter will be qualified to Regulatory Guide 1.89 (November 1974) criteria. The trans-mitter shall be powered from the vital instrument busses and will provide Control Room indication and will be monitored by the plant computer. This transmitter shall have a range 0-3' (one foot above the containment floor).

The wide range level monitor shall be qualified to meet Regulatory Guide 1.97 (December 1975) criteria and shall monitor the level from the containment floor to a level of 15' or 600,000 gallon Each transmitter shall provide control room indication with an input to a shared chart recorder. Each transmitter shall be powered from the vital instrument busse The resident inspection staff verified the installation of the above equipment on Oconee Unit II.F.1(6) Containment Hydrogen Monitor Item II.F.1.(6) requires that continuous indication of hydrogen concentra-tion in the containment atmosphere be provided in the control roo Measurement capability shall be provided over the range of 0 to 10% hydrogen concentration under both positive and negative ambient pressure.

! In a letter to NRC staff dated January 2,1980, the licensee comitted to 1 install two separate identical analyzer systems per unit. These analyzers l will operate independently of the recombiner system and will be supplied by c

vital sources of power. Each analyzer will be able to monitor either of two

! identical containment sampling headers or the calibration gases. Each I analyzer shall have, along with control panel indicator and alarm, a separate control room indicator and alarm with a shared chart recorde Each containment sample header will have five inlet samples available for monitoring: Top Operating level Basement Radiation Monitor /Recombiner Inlet header Radiation Monitor /Recombiner Discharge header.

l l

l Sample selection and switching is accomplished manually by the operator from

[

the remote analyzer control panel. Each analyzer shall have its own sample i and return containment penetrations.

i a

. .

Installation of the containment hydrogen monitor systems for all three units will not be completed until the recently identified problems with the Conoflow Pressure Regulators used in the Comsip Hydrogen Analyzer are resolve . Emergency Feedwater Headers During the April 1981 outage at Davis Besse-1 a strong correlation was developed between tube defects in the A-0TSG and the location of the 8 internal auxiliary feedwater header bracket / dowel pin assemblies. Eddy current test results appeared to indicate that tube defects were caused by vibration or impact of the header bracket / dowel pin assemblies on the tube During the March 1982 refueling outage at Davis Besse -1 a follow-up eddy current (EC) inspection was conducted in both the A and B-0TSG's to further evaluate the integrity of the tubes in front of these 8 assemblies as part of the normal 0TSG tube inservice inspection. The results of this initial inspection identified new indications within the dowel pin envelope and at the elevations of the top and bottom of the header. As as result, all periphery tubes _ in both generators were inspected. A total of 29 EC indications were recorded including 3 pluggable indication Visual inspections revealed that the auxiliary feedwater headers were distorted, the brackets were bent / torn and the dowel pins were missing in 6 of the 8 locations inspecte In the B-0TSG the auxiliary feedwater nozzle sleeve was no longer inserted in the heade During the April 1982 outage at Rancho Seco, an inspection perforned of the internal auxiliary feedwater headers revealed the same type of danage as observed at Davis Bess Because of the damage found at Davis Besse and Rancho Seco, Duke Power Company shutdown Unit 3 on April 23, 1982. Only Unit 3 steam generators have internal auxiliary feedwater headers and thus the unit was shutdown prior to its scheduled refueling outage based on the probability that it may also have the above described damage. Visual examination conducted on April 30,1982 confirmed that both steam generator were damage Current available information detailing the postulated failure mechanism is as follows:

--

Pressure calculations performed to date indicate the potential for high local delta 4Ps which could plastically deform the header outer surface, but do not yet explain the inner wall conditio Thermal calculations indicate potential for deformation of outside wall as observed, but do not yet explain the inner wall conditio Either of the above mechanisms or a combination create outer wall and bottom plate distortio .

.--s .

. .

--

Outer support bracket rotates outward and binds dowel pin in shroud hole thereby defeating dowel pin slip mechanis Subsequent AFW actuations create thermal ratchet effect (header cooldwon and re-heatup) that further distorts dowel pin and bracket As header support is degraded, vibration and wear of pins and brackets occur Pin to inner bracket weld fails freeing pin to vibrate or ratchet ou There are a number of options currently being reviewed to retain the steam generators to service. These options include the following:

--

Stabilize existing header and redesign nozzle sleeve. Inject auxiliary feedwater through the existing nozzle directly into the tube bundl Inject auxiliary feedwater through the main feedwater nozzle Remove the existing header and replace it with a redesigned heade Fix auxiliary nozzle and repair existing heade Stabilize the existing headers and design and install an external heade Duke Power Company, in conjunction with Babcock and Wilcox (B&W)'and the B&W owners group are currently evaluating the most viable repair optio Current considerations appear to favor the last of the repair options; the external heade Oconee Units 1 and 2 have an external auxiliary header. The design was modified on Unit 3 to employ the internal heade The resident inspection staff will continue to monitor the repair effor . On April 28, 1982 during heatup of Unit 2, the licensee discovered a detached tendon cap from the secondary shield wall vertical tendo Preliminary examination of the tendon revealed that it had failed. The licensee initiated a cooldown to cold shutdown conditions and a thorough examination of the eight vertical secondary shield wall tendons ensued. The licensee determined that each of the vertical secondary shield wall tendons had experienced the corrosion of strand members in the lower anchor are Evidence indicates that the corrosion of the vertical secondary shield wall tendon strands was the result of moisture entrapment within the vertical tendon spac The licensee tentatively plans to replace six of the eight vertical tendons that did not meet the acceptance criteria when examined. Corrective actions a j

.. . o

also include drilling a hole in the vertical tendon end caps to facilitate drainage of the tendon space and establishing a preventive maintenance progra Preliminary examination of the Unit 3 secondary shield wall vertical tendons indicates that four of the eight vertical tendens have experienced corrosion in the same area. Unit 1 secondary shield wall vertical tendons will be examined during the next outag Inspection of the horizontal shield wall tendons is ongoing; the resident inspection staff will monitor the effort and report the results in a subsequent repor . Pressurized Thermal Shock The inspectors verified that the licensee has incorporated pressurized thermal shock phenomena into the licensed operator training and requalifi-cation training program The licensee is utilizing an in-house lesson plan for pressurized thermal shock training. The lesson plan consists of approximately one-hour of instruction on the mechanics of pressurized thermal shock phenomena, pressurized thermal shock events, and the role of the reactor operator in minimizing pressurized thermal shock. B&W has a formal pressurized thermal shock lesson plan under development. The licensee plans to implement the B&W lesson plan upon its completio The inspectors reviewed emergency procedures EP/0/A/1800/04, " Loss of Reactor Coolant" and EP/0/A/1800/14, " Loss of Steam Generator Feedwater" to verify that they incorporated pressurized thermal shock concerns. Both procedures address pressurized thermal shock by specifying regions of acceptable and unacceptable operation on a reactor coolant system pressur versus reactor coolant system temperature graph.

L