IR 05000334/1989022
| ML20005G727 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 01/11/1990 |
| From: | Collins E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20005G723 | List: |
| References | |
| 50-334-89-22, 50-412-89-21, NUDOCS 9001220259 | |
| Download: ML20005G727 (15) | |
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U. S. NUCLEAR REGULATORY COMMISSION 7.
REGION I
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Report Nos.
50-334/89-22 50-412/89-21 License No.
DPR-66 i
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Licensee:
Duquesne Light Company g-One Oxford Center
301 Grant Street-Pittsburgh, Pennsylvania 15279 Facility Name:~ Beaver Valley Power Station, Units 1 and 2 t-.,
. Location:
Shippinoport, Pennsylvania j
' Dates:
October 14 - November 17, 1989
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Inspectors:
J. E. Beall, Senior Resident Inspector P. R. Wilson, Resident Inspector i b 0.w I /is / M Approved by:
no Elmo E. Collins, Acting Chief Date Reactor Projects Section No. 48 Division of Reactor Projects Inspection Summary:
Combined Inspection Report Nos 50-334/89-22 and 50-412/89-21 for October 14 - November 17, 1989.
L Areas Inspected:
Routine inspections by the resident inspectors of licensee l
actions on previous inspection findings, plant operations, security, radio-'
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logical. controls, plant housekeeping and fire protection, surveillance testing, maintenance,' recirculation spray cooler tube' corrosion, feedwater line repair, in loss of overpressure protection and licensee event reports.
o Results:
Overall, the facility was operated safely. A decline in Unit I housekeeping was observed (Section 4.6) Licensee activities associated with the repair of corroded tubes in the Unit 1 Recirculation Spray Coolers (Section 7). and Unit 1 feedwater lines (Section 8) were well handled. One
. violation was identified regarding the failure to follow procedures (Section
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9). This mistake led to the loss of one required train of cold overpressure protection.
In addition, other weaknesses were identified in the control of licensed activities which contributed to the above event. One previous open NRC item was reviewed, and partially closed.
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TABLE OF CONTENTS i
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1. Persons Contacted..........................
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Summary of Facility Activities...................
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3.
Status of Previous Inspection Findings (IP 71707, 92702, 92701)...
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Operational Safety (IP.71707, 71710, 40500).............
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4.1.ceneral.............................
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4.2 ESF Walkdown.........................
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lL 4.3 Operations..........................
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.4.4 Plant Security /Phy sical Protection..............
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4.5 Radiologic Controls......................
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4.6 Plant Housekeeping & Fire Protection.............
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Surveillance. Testing (61726)....................
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6. Maintenance (62703)..........................
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7.
Unit 1' Recirculation Spray Cooler Tube Corrosion (37700)......
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8.
Unit 1 Feedwater Line Repair (37700).
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8.1 Feedwater Elbow Cracks....................
8.2 Repair of the IA and IC Feedwater Lines...,.......
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Unit 1 Loss of One Train'of Overpressure Protection (71707, 93702),...................
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10.
Inoffice Review of l.icensee Event Reports (90712, 40500)
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11. Unresolved Items..........................
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12.. Meetings (30703)...........,...............
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DETAILS 1.
Persons Contacted During the report period, interviews and discussions were conducted with members of licensee management and staff as necessary to support inspection t
activities.
2.
Summary of Facility Activities At the beginning of the inspection period, Unit I was defueled for the
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seventh refueling outage. On October 17, Mode 6 was entered with the commencement of fuel onload.
Fuel onload was completed on October 20 and Mode 5 was reached on October 23.
Unit I remained in Mode 5 for the remainder of the inspection period.
Unit 2 operated at 100% power throughout the inspection period.
3.
Status of Previous Inspection Findings The NRC Outstanding Items (01) List was reviewed with cognizant licensee i
personnel.
Items selected by the inspector wera subsequently reviewed through discussions with licensee personnel, documentation reviews and field insoection to determine whether licensee actions specified in the Ols had been satisfactorily completed.
The overall status of previously identified inspection findings was reviewed, and planned / completed licensee actions were discussed for the items reported below.
3.1 (0 pen) Unresolved Item (50-334/86-07-01): Improve Emergency Diesel
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Generator (EDG) reliability.
This item consolidated four previously identified NRC concerns into one item.
The inspector reviewed subitem I which described more than 60 discrepancies between the licensee's Preventive Maintenance (PM) program and the vendor's l
recommendations.
The licensee had stated that many of the vendor i
preventive maintenance recommendations were inappropriate due to the i>
assumption of continuous service or high start frequency versus the unit usage (about one hour per month). -This item was reviewed in November 1988 (IR 50-334/89-28; 50-412/89-22) where the inspector found that several discrepancies remained without documented justi-
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fication. The EDG vendor evaluated the PM program and responded that the licensee EDG PM program was adequate for the intended applica-l tion.
Therefore, subitem 1 for the above unresolved item is closed.
Subitems 2 through 4 remain open.
4.
Operational Safety l
4.1 General Inspection tours of the following accessible plant areas were con-I ducted during both day and night shifts with respect to Technical Specification (TS) compliance, housekeeping and cleanliness, fire
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protection, radiation control, physical security / plant protection and
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operation / maintenance admini;treHve control y
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-- Control Room
-- Safeguard Areas
-- Auxiliary Building
-- Service Building
-- Switchgear Area
-- Diesel Generator Buildings
-- Access Control Points
-- Containment Penetration Areas I
-- Protected Area Fence Line -- Yard Area
-- Turbine Building
-- Intake Structure
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-- Reactor Containment
-- Spent Fuel Building 4.2 ESF Walkdown l
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The operability of selected engineered safety feature systems were i
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verified by performing detailed waltdowns of the accessible portions
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of the systems.
The inspectors confirmed that system components were in the required alignments, instrumentation was valved-in with appropriate calibration dates, as-built prints reflected the as-
installed systems and the overall conditions observed were satis-factory.
The systems inspected during this period included the Emergency Diesel Generator, Safety Injection and Recirculation Spray systems.
The inspectors conducted detailed, independent valve and breaker alignment checks of the Unit 2 Emergency Diesel Generators.
No concerns were~ identified.
4.3 Operations During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures,
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facility configuration and plant conditions. Selected plant operating procedures, surveillance test procedures, and temporary procedure changes were reviewed.
During plant tours, logs and records were reviewed to determine if entries were prperly made, and that equip-ment status / deficiencies were identifieA ed communicated.
These records included operating logs, turnc S sheets, tagout and jumper
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logs, process computer printouts, unit d f-normal and draft incident reports. The inspector verified adherence to approved procedures for
ongoing activities observed. Shift turnovers were witnessed and staffing requirements confirmed.
Inspector comments or questions resulting from these reviews were resolved by licensee personnel.
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Onsite Safety Review Committee meetings were attended to evaluate the
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licensee's self-assessment capability.
In addition, inspections were conducted during backshifts and weekends on 10/15, 10/20, 11/04, and 11/05.
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4.3.1 Inadvertent Steam Generator Blowdown Isolation On October 21, 1989, an inadvertent Unit 2 steam generator blowdown isolation occurred (Engineered Safety Feature) due to high activity while performing a surveillance test.
Plant operators were in the i
process of restoring steam generator (SG) blowdown flow (isolated as part of the surveillance) when the isolation occurred. The licensee l
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had determined that while normal blowdown flow activity was less than i
minimum detectable, system manipulations (e.g., valving changes,
C adjustments to flow, or temporary isolations) could result in the i
release of contaminated deposits remaining from a prior SG tube leak, J
Therefore, a Standing Order had been issued to plant operators requiring that the SG blowdown sample line radiation monitor's high activity setpoint be temporarily raised while performing manipulations
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of the blowdown system to prevent inadvertent isolations. The event j
was caused when the radiation technician assigned to raise the high
activity setpoint of the SG blowdown radiation monitor incorrectly raised the setpoint of another radiation monitor. When SG blowdown flow was restored, it subsequently isolated due to high activity.
Licensee proposed corrective actions included incorporating the guidance given in the standing order into the SG Blowdown System operating procedures and counseling personnel involved in the event.
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All required NRC notifications were made.
No unacceptable conditions were identified.
4.3.2 Unit 2 Automatic' Transfer of Service Water Train "A" Seal Water Supply On November 6, 1989, the train A seal water supply for the service
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water pump automatically transferred (Engineered safety Feature) from the filtered water supply to the pump discharge supply. The Unit 1
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filtered water system provides the normal supply of seal water of the
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Unit 2 Service Water Pumps. The automatic transfer occurred when a v
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Unit 1 breaker was opened as part of an approved clearance which
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de-energized valves in the Unit 1 Filtered Water System.
This, in i
turn, resulted in loss of both the normal and backup supply of l-filtered water. When filtered water pressure decreased, the Seal Water System automatically transferred to the Unit 2 service water pump discharge supply via Engineered Safety Feature valving. The
plant operators promptly restored the filtered water supply to the
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service water pumps.
L The cause of the event was an inadequate description of electrical loads in the Unit 1 Operating Manual (0M), Chapter 38, that was used
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i to prepare the clearance. The description of loads did not include o
l the backup filtered water supply valve that shut when it was de-ener-l --
gized. The personnel assigned to preparing clearances extensively rely on the accur*.:v of the load lists in the oms.
The licensee
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informed the insp:etor of corrective actions which included the review of load lists in OM 38, review of other evolutions that have l-the potential of causing a loss of filtered water, and posting signs l
on the motor control center listing the valves that would be de-energized if a particular breaker was opened. All required NRC notifications were made. No unacceptable conditions were identified.
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4.3.3 Automatic Start of Unit 1 Emergency Diesel Generator On November 12, 1909, with Unit 1 in Cold Shutdown (Mode 5), the Emergency Diesel Generator (EDG) No I automatically started during the start of the 1A Reactor Coolant Pump (RCP). The 1A RCP was started as part of the Reactor Coolant System fill and vent proce-dure. Approximately 1.5 seconds after the RCP start, the "A" Normal 4 KV bus tripped on overcurrent for the B phase. This resulted in the loss of preferred power to the "AE" 4 KV emergency bus and the automatic start of EDG No.-1.
The EDG subsequently repowered the
"AE" bus as designed.
The Residual Heat Removal System that was in operation, automatically tripped as designed and was promptly restored by the control room operators. One emergency 480 V motor control (IMCCI-E9) failed to load automatically and was manually loaded.
The cause of the 4 KV bus trip was determined to be a wrong setting in the "B phase overcurrent relay. The relay had been worked during
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the outage and a restoration step had been inadvertently missed which reset the trip setting. The as found setting was 2,400 amps vice the required 7,200 amp setpoint.
The licensee inspected all other similar relays and no other setting errors were identified. At the end of the inspection period, the licensee was still investigating the cause for the failure of the 480 V feedbreaker to automatically load following the start of the EDG. The inspector had no other questions at this stage of the licensee review.
4.3.4 Inadvortent Loss of One Train of Cold Overpressure Protection On November 13,1989, Unit 1 control room operators determined that one train of cold overpressure protection (one of two power operated relief valves) was inoperable. At the time, Unit I was in Cold Shutdown (Mode 5) with the Reactor Coolant System (RCS) being maintained at 275 psig via a nitrogen bubble in the pressurizer.
Unit 1 Technical Specification 3.4.9.3 required that both trains of cold overpressure protection be operable with RCS temperature less than or equal to 275 F.
For more details, see Section 9.
4.4 Plant Security / Physical Protection Implementation of the Physical Security Plan was observed in various plant areas with regard to the following:
Protected Area and Vital Area barriers were well maintained and
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not compromised; Isolation zones were clear;
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Personnel and vehicles entering and packages being delivered to
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the Protected Area were properly searched and access control was in accordance with approved licensee procedures;
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f Persons granted access to the site were badged to indicate
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whether they have unescorted access or escorted authorization; i
Security accers controls to Vital Areas were being maintained
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and that persons'in Vital Areas were properly authorized.
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Security posts were adequately staffed and well equipped,
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security personnel were alert and knowledgeable regarding position requirements, and that written procedures were avail-l
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able; and
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Adequate illumination was maintained.
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'No deficiencies were identified.
4.5 _ Radiological Controls Posting and control of radiation and high radiation areas were inspected. Radiation Work Permit compliance and use of personnel monitoring devices were checked.
Conditions of step-off pads, disposal of protective clothing, radiation control job coverage, area
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monitor operability and calibration (portable and permanent) and personnel frisking were observed on a sampling basis.
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During a tour of the Unit 1 West Penetration Room, a Radiologically Controlled Area (RCA), the inspector identified some discarded candy wrappers.
The inspector found a cigarette butt in the Safeguard Valve Pit, also a RCA.
The identification of the above items indicates there was a potential ingestion of food and smoking in the RCAs, a violation of the licensee's work rules.
Similar concerns were identified in previous inspections (IR50-334/89-03; 50-412/89-03 ar.d IR50-334/89-18; 50-412/89-18).
Further licensee attention is required to prevent further recurrence.
4.6 Plant Housekeeping and Fire Protection Plant housekeeping conditions, including general cleanliness conditions and control and storage of flammable material and other potential safety hazards, were observed in various areas durir.g plant
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tours. Maintenance of fire barriers, fire barrier penetrations, and verification of posted fire watches in these areas were also observed.
The inspector conducted detailed walkdowns of the accessible areas of both Unit 1 and Unit 2.
No significant deficiencies were identified.
l During the inspection period, general housekeeping at Unit I declined l
even though there was a decrease in outage activities. Paper trash, tape, cotton glove liners, rubber gloves, dirt, etc., were found in l
radiologically controlled areas.
In some potentially contaminated work areas, the inspector observed excessive dirt and debris, which could potentially result in personnel contamination outside the posted contaminated areas. General housekeeping in Unit 2 was good,
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5.
Surveillance Testino
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The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, i
test instrumentation was properly calibrated and used Technical Soecifi-cations were satisfied, testing was performed by qualified personnel and test results satisfied acceptance criteria or were properly dispositioned.
The following surveillance testing activities were reviewed:
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OST 2.26.1 Tubrine Throttle, Governor, Reheat
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Stop and Intercept Valve Test, t
OST 1/2.43.17B Control Room Area Radiation
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Monitor Functional test.
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No deficiencies were identified,
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6.
Maintenance
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The inspector reviewed selected maintenance activities to assure that:
the activity did not violate Technical Specification Limiting
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Conditions for Operation and that redundant components were operable; required approvals and releases had been obtained prior to
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commencing work;
procedures used for the task were adequate and work was within the
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skills of the trade; activities were accomplished by qualified personnel;
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where necessary, radiological and fire preventive controls
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were adequate and implemented; QC hold points were established where required, and
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observed;
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equipment was properly tested and returned to service.
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Maintenance activities reviewed included:
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MWR 894565 - Repacking Safety Related Valves MWR 894608 -
"C" Steam Generator Feedwater Line MWR 894639 Inspect and Repair of Recirculation
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Spray Coolers No deficiencies were identifie,
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7.
Unit 1 Recirculation Spray Cooler Tube Corrosion On October 24, 1989, as part of a licensee self initiative to examine the
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integrity of various heat exchangers' tube integrity, a 71% through wall
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l-defect was detected using eddy current testing in the IB Recirculation Spray Cooler.
The Recirculation Spray (RS) system is designed to i
depressurize the containment along with the Quench Spray System to sub-atmospheric pressure and to provide long term containment cooling follow-
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y ing a loss of coolant accident. -In addition, the RS system is designed to
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provide a backup water supply to the high head safety injection pumps should the low head injection pumps fail, i
The Licensee removed the suspect tube and sent it to a vendor for destructive examination. This examination revealed that the tube had been subject to "under deposit crevice erosion" where the surface of the tube showed a small pit of approximately 30 to 50 microns, but a significantly larger pit was found below the surface.
The examination accurately measured the depth of the pit to be 75% through wall. This confirmed the accuracy of the licensee's eddy current test methodology.
The licensee's. Engineering Department determined that the maximt..i acceptable through wall indication was 60%.
It was also determined that only 54 tubes per RS system train (two coolers per train) could be plugged and still meet system design requirements.
Further eddy current testing revealed that the 1A RS spray cooler had no unacceptable indications, the IB RS cooler had an additional 32 unacceptable through wall defects, the IC RS cooler had one and the 10 RS cooler had 134 unacceptable tubes.
The A and C coolers make up RS train 1A and the IB and 10 coolers are in train B.
The shell side of the coolers is normally maintained dry while the tube side is kept in wet layup with treated river water.
The licensee was conducting an investigation to determine why only one train was significantly affected by the above type of corrosion at the end of the inspection period.
The licensee's intentions at the end of the inspection period were to plug the defective tubes in the B and C RS coolers and to replace the majority, if not all the defective tubes in the D RS cooler.
The licensee was able to procure in-kind replacement tubing.
The Engineering Department's support and the coordination of activities associated with this problem from all affected site departments were excellent, greatly reducing the potential impact on the Unit 1 outage schedule.
The licensee informed the inspector of plans to develop a corrective maintenance program to continue to monitor RS cooler tube integrity.
The inspector had no further questions at this stage of the heat exchanger repair.
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l 8.
Repair of Unit 1 Feedwater Lines 8.1 Feedwater Elbow Cracks l
On October 20,.1989, ultrasonic testing (UT) of the feedwater line i
elbow clnsest to the-1A Steam Generator (SG) indicated apparent cracking in the heat affected zone of the weld closest to the SG.
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The elbow was located adjacent to the SG with one end welded to the
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SG feedwater nozzle. The UT indications were observed on the elbow side vice on the feedwater nozzle.
Radiographic examination of the joint did not identify any indications of cracking.
Following engineering evaluation of the UT data, the elbow was replaced.
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The feedline elbow cracking problem had previously been identified as a potentially generic concern with Westinghouse SGs. Additionally, this same problem previously occurred in 1979 and again in 1988, where.all three feedwater elbows had to be replaced.
Subsequent to the initial identification of the cracking in 1979, the licensee implemented a periodic radiographic examination schedule for the affected piping. UT of the affected feedwater piping along with radiographic examination was implemented in 1988 following the sixth refueling outage. The licensee initially attributed the feedwater
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elbow cracking phenomenon to thermal stratification of the 16 inch main feedwater lines caused by the flow of localired and relatively cold auxiliary feedwater, which created a large thermal gradient in the feedwater piping.-
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The inspector questioned whether measures to prevent further feedwater
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elbow cracking had been evaluated and/or implemented.
The licensee stated that a permanent resolution should be in place by the eighth refueling outage. The actual design of the permanent repair would be determined following analysis of the feedwater line behavior during plant operation. Temporary thermocouples and lanyard pots were to be installed on the affected feedwater pipes to provide data on what
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forces or temperature gradients may be causing the cracking phenomenon.
The licensee sent the affected elbow to a vendor laboratory for i
destructive examinations.
Preliminary results from this examination did not confirm the existence of cracks.in the elbow.
The tests indicated the UT indications were the result of machining grooves in the elbow.
The Unit 2 feedwater system utilizes the thermal sleeve design for the affected elbows, therefore, similar problems are not as likely.
The Unit 2 inspection requirements are delineated in the ASME Section XI, Inservice Inspection Program.
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l 8.2 Repair of the 1A and 10 Feedwater Lines
.On October 2, 1989, an engineer monitoring the replacement of the l
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above feedwater elbow, nbserved that the 1A main feedwater line was i
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Subsequent walkdowns of the feedwater lines identi-
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fied that the IC main feedwater line was also grounded in its pipe rupture whip restraint.
In addition, the first hydraulic $nubber upstream of the whip restraint for the 1A feedwater line was found to be bottomed out. The embedment for the snubber _had been slightly pulled out, damaging the crane wall. The licensee also determined that a uniball restraint upstream of the first snubber had seized.
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No deficiencies were identifi J on the IB feedwater line
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The 1A feedwater line was subsequently. cut on both sides of the crane wall. The cut section of the pipe was then rotated to center
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the pipe in the whip restraint. The pipe was then welded in place.
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The IC feedwater line was cut in three locations, repositioned and then welded in place.
Nondestructive examination of the pipes indicated there was no apparent damage to the feedwater lines.
Engineering evaluation determined that neither feedline had been bent. The welds on the affected lines were subsequently satisfactorily radiographed and the piping was pressure tested. The inspector periodically monitored repair activities and no concerns
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were identified.
The snubber with the failed embedment was repositioned and anchured to an adjacent spare embedment.
Examination of the damage to the crane wall was evaluated to be slight and localized to the area around the failed embedment. The seiz M uniball restraint was also replaced.
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s At the end of the inspection period, the licensee was conducting an L4 evaluation to determine the possible cause for the apparent movement
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of the two feedweter lines. Among the possibilities being analyzed were water hammer and thermal ssratification.
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In conjunction with the feedwater elbow concerns described in Section 7.0, temporary instrumentation is to be installed on the feedwater lines to monitor the pipes behavior during plant operation.
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The inspector will follow the licensee evaluations concerning the above problem.
The repair activities for the feedwater lines were well handled.
u The sup.nort provided by the licensee's Engineering Department was thorough and timely. Although the problems with the feedwater lines were found late in the outage, the repair activity had only a minimal
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impact on the outage schedule.
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Inadvertent Loss of One Train of Cold Overpressure
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Protectior.
Unit 2 Technical Specification (TS) 3.4.9.3 require that cold overpressure protection be provided when Reactor Coolant System (RCS) temperature is less than or equal to 275 F. by either two operable Power Operated Relief
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Valves (PORV) or &n RCS vent path of greater than or equal to 3.14 in2, i
The action statement allows for continued operation with one PORV inoperable for seven days at which time the RCS must be depressurized and l
vented by a path of at least 3.14 ina within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. On
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November 13, 1989, with the RCS in Cold shutdown (Mode 5), at 275 psig, control room operators determined that one of the two required PORVs was
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inoperable and had been inoperable for approximately 69 hours7.986111e-4 days <br />0.0192 hours <br />1.140873e-4 weeks <br />2.62545e-5 months <br />.
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On Movember 9,1989, a clearance (No. 562735) was approved and posted in preparation for the containment Type A Leak Test.
As part of the
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clearance, tha 3/4 inch root valve (RC-1) to the RCS sample system was shut. The ciosure of RC-1 was added as a prerequisite to the Type A test in 1986 to prevent an air leakage path out of the containment during the leak test.
This action disabled the wide range pressure indication and the pressure signal to one train of the Cold Overpressure Protection System.
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PORVs for cold overpressure protection were not required during the Type A
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test because the RCS would be vented during tne test. At the time the clearance was hung, the required cold overpressure protection for the RCS
was provided by two PORVs which were blocked open by a mechanical device.
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During the Unit I refueling outage, the licensee formed a group of
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operators dcdicated to the r. reparation and posting of clearances.
The group, supervised by senior reactor operators, was inade up of reactor and plant cgerators. _ The on shift nuclear shift supervisor wat still required to approve all clearances.
The licensee utilized detailed control room status boards to assist control room operators. These status boards included piping diagrams for all major plant systems.
Site Administrative Procedure (SAP) 41
" Clearance Procedure", required that when the plant operators completed the valving sequences and posted the clearance tags, that he return to the control room and update the control room status board prints to reflect actual valve positions.
In addition, the operator was required to sign the clearance form stating that the status board prints had been updated.
For this clearance, the operator failed to update the control room status board prints as required.
In addition, the clearance supervisor failed to recognize that the operator had not signed the clearance form stating that the status board prints had been updated when the clearance was reviewed.
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Later, on' November 9, due to the identification of additional maintenance in the containment,-the Type A test was postponed.
However, the clearance
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In the interim, Operations
- was to perform Operating Manual (0M) procedure 1.6.4 F, " Fill and Venting the Reactor Coolant System". One of the initial conditions required by-procedure, required that the RCS be aligned in accordance with the OM 1.6'.3,. " Reactor Coolant System Valve List".
Control room operators performed.this step by' ensuring that the required valve lineup had been recently performed and then checking the control room status-board prints-to determine if any of the valves had been repositioned,since the valve iineup was performed.
Root valve RC-1 was required to be opened, however the status board prints had not been updated to reflect that it was shut.
The control room operators did not recognize that RC-1 had been shut.
On November 10, the cold overprotection system was placed in service.
.RCS pressure was subsequently raised to approximately 130 0:1g via a nitrogen bubble in the pressurizer. OM 1.6.4 F required that upon _ reaching 100-150ipsig in the.RCS, that Cold Overpressure Protection System be verifitd to^ be in service by performing Operating Surveillance Test (OST)
01.6.8 " Placing-Overpressure Protection System (OPPS) in Service". OST 1.6.8 required that the two overpressure protection PORVs be stroked and timed. 'RCS p.ressure was subsequently raised to approximately 300 psig.
On November 13, the shift technical advisor observed that one of_the two control: room wide range RCS pressu e indicators (0-3000 psig) sas reading substantially lower than actual RCS. pressure as read on the narrow range pressure indicator. (0-600 psig). Operators detersined that RC-1 had been shut as part-of the clearance for the Type-A test and ced. Ared gra trair
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of OPPS inoperable.- The valve was subsequently opened, returning the train to service.
Inspector review determined that the root cause of the event was the
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failure of the operator to update the control room status board prints as
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required by SAP-41.1 The inspector also questioned why the onshift
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licensed operators failed to detect the deviation in wide range pressure-indications for several shifts during control room panel walkdowns.
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Other factors contributed to the event. OST 1.6.8 was inadequate in that
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it did not have requirements to verify that OPPS was receiving a valid RCS i
pressure signal or that the pressure transmitters associated with OPPS were properly aligned.
Not removing the clearance for the Type A test i'
.after the test was postponed also contributed to the event. Both the
-clearance group and the Unit i nuclear shift supervisor apparently failed to recognize that one train of OPf5 was disabled by the closure of RC-1.
The-inspector had conducted an audit of selected control room status boards and identified no deficiencies.
The inspector had audited selected boards in Aucust 1989 and again in October 1989.
No concerns had been I
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r identified.- Two violations had been~previously identified (50-334/87-06-03
and 50-334/88-28-01) due to the. failure to properly maintain the status e,
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board s '. One of the corrective actions for the above violations was the addition of the requirement for operators to sign the clearance form stating.that the status boards had been updated.
The licensee informed the inspector tnat a Human Performance Evaluation System _(HPES) review would.be conducted. The licensee also discussed r
proposed long-term corrective actions which included the following:
'A.
Th'e addition of caution statements in the. Type A test procedure to
' inform personnel that one train of OPPS would be disabled by closing-RC-1.
B.- -Under review was.the addition of requirements for the supervisor of the_ clearance group to sign.the clearance form stating he reviewed-the form af ter the tags were posted and verified that the operator 4E
~ posting the tags had updated the control room status boards.
C.
Revise'0ST 1.6.8 to include steps to verify-that the OPPS-pressure transmitters were_ properly aligned and that the OPPS pressure transmitters were receiving an accurate pressure signal.
The failure to update the-control room status boards as required by SAP 41-is a violation (50-334/89-22-01). This, along with the inadequate OST
.and the failure of; plant operators to recognize that one train of 0PPS was inoperable, is an example of a weakness in the control of licensed
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-activities.
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~ 10. 'Inoffice-Review of Licensee Event Reports (LERs)
- The' inspector reviewed LERs submitted to the NRC Region I Office to verify that the' details of the event were clearly reported,. including the accuracy-of the description of the cause and the adequacy of the correc-tive' action. The inspector determined whether further information was
- required from the licensee, whether generic. implications were indicated and whether the= event warranted onsite-followup. The following LERs were reviewed:
Unit 1:
LER 89-012-00 - Incore Thumble Tube Wear Unit ?:
LER 88-0G2-01 - Reactor Trip and Control Room Bottled Air Pressurization System Actuation LER 89-024-01 - Leak Collection Ventilation Flowpath Automatic Realignment Acutation
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15-L The above'LERS'were reviewed with respect to the requirements of 3 -
10 CFR 50,73-and the guidance provided in NUREG 1022. Generally, the LERs were found-to be of high quality with good. documentation of event analyses,.
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root cause determinations and corrective actions.
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11. Unresolved-Items
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Unresolved items'are matters about/which more information is required in order to ascertain whether they are acceptable items, violations or deviations.
No new unresolved items were identified in this inspection.
L 12. Meetings
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I Periodic meetings were held with senior facility management during the course of this-inspection'to~ discuss the inspection scope and findings.
A-summary of inspection' findings was further discussed with the licensee at the conclusion of the report period on November 19, 1989.
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