IR 05000382/1990005
| ML20042G127 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 04/30/1990 |
| From: | Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20042G125 | List: |
| References | |
| 50-382-90-05, 50-382-90-5, NUDOCS 9005110120 | |
| Download: ML20042G127 (14) | |
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I APPENDIX
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i U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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NRC Inspection Report:
50-382/90-05 Operating License: NPF-38 Docket:
50-382 Licensee:
Louisiana Power & Light Company. (LP&L)
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317 Baronne Street New Orleans, Louisiana 70160 Facility Name: Waterford Steam Electric Station, Unit 3 (Waterford 3)
Inspection At: Taft, Louisiana Inspection Conducted:
March 1-31, 1990
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I Inspectors:
W. F. Smith, Senior Resident Inspector Project Section A, Division of Reactor Projects a
S. D. Butler, Resident Inspector Project Section A, Division of Reactor Projects a
Approved:
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T. F. Westerman, Chief, Project Section A Date
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Inspection Summary l
Inspection Conducted March 1-31, 1990 (Report 50-382/90-05)
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Areas Inspected:
Routine, unannounced inspection of plant status, onsite followup of events, monthly maintenance observation, monthly surveillance
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observation, operational safety verification, followup of previously identified items, licensee event report-followup, and engineered safety feature (ESF)
system walkdown.
Results:
The inspector observed during ESFAS surveillance testing, that the auxiliary component cooling water pumps failed to start as a result of not actuating the sequences test switch at the proper time. While the failure of the component cooling water pump to start was self-disclosing and the surveillance test was rerun satisfactorily, this event focuses on the need for licensee management to continually unphasize the importance of deliberate, e
step-by-step performance of surveillance procedures such that errors are
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eliminated. The concern was that failure to comply with each step in a l
surveillance procedure could just as easily mask a problem such that inoperable safety functions might not be identified.
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In paragraph 3.c, the inspector summarized the circumstances surrounding the reactor trip of March 29, 1990, which occurred due to a major power fault at a nearby substation. The inspector was in the control room at the time of'the event and observed the alert performance of the operators in the safe tecovery from this complex electrical event. The control room supervisor and shif t
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supervisor exercised good control over the recovery while maintaining proper perspective on the integrity of plant safety functions. The emergency operating procedures were followed and teamwork was evident.
Licensee management and other licensed operatorr. quickly appeared in the control room and assisted in an appropriate manner.
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persons Contacted Principal Licensee Employees R. P. Barkhurst, Vice President, Nuclear Operations
'J. R. McGaha, Plant Manager, Nuclear P. V..Prasankumar, Assistant Plant Manager, Technical Support
- D. F. Packer, Assistant Plant Manager, Operations and Maintenance
- A. S. Lockhart, Quality Assurance Manager
- D. E. Baker, Manager of Nuclear Operations Support and Assessments R. G. Azzarello, Manager of Nuclear Operations Engineering W. T. Labonte, Radiation Protection Superintendent
- G. M. Davis, Manager of Events Analysis Reporting & Responses L. W. Laughlin, Onsite Licensing Coordinator T. R. Leonard, Maintenance Superintendent R. F. Burski, Manager of Nuclear Safety and Regulatory Affairs
- R. S. Starkey, Operations $1perintendent
- T. H. Smith, Plant Engineering Superintendent
- T. J. Gaudet, Senior Engineer, Site Licensing Support
- Present at exit interview.
In addition to the above personnel, the inspectors held discussions with various operations, engineering, technical support, maintenance, and administrative members of the licensee's staff.
2.
Plant Status (71707)
As of the beginning of this inspection period, the plant was operating at 100 percent power.
Except for a brief reduction in power to 90 percent on March 16, 1990, to perform control element assembly (CEA) and turbine valve tests, power remained at 100 percent until March 22, 1990, when the reactor tripped in response to two dropped CEAs.
During the outage, a few minor maintenance items requiring hot standby (Mode 3) conditions were accomplished.
Upon repairing the cause of the CEA drop and some damaged steam generator blowdown piping (discussed in paragraph 3 below), the plant was restored to full power on March 25, 1990, where it remained until March 29, 1990, when the reactor automatically tripped due to a major fault at a nearby substation.
The fault was isolated from the power grid, and the plant was restored to full power by March 30, 1990, where it remained through the end of the inspection period.
3.
Onsite Followup of Events (93702)
a, pressurizer Spray Valve RC-301A Seating problem On March 16, 1990, RC-301A (pressurizer spray valve) failed to seat tightly as indicated by an abnormally high demand for pressurizer l
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heaters. The valve had opened slightly as a function of pressurizer pressure control when power was reduced to 90 percent in support of surveillance testing. When pressure was restored to the normal band, the valve did not fully seat.
RC-301A has had a history of seating problems. A similar problem occurred on January 27, 1989, resulting in a plant shutdown. At the time, the cause appeared to be actuator-to-stem coupling slippage.
The licensee temporarily modified the coupling arrangement so it would not slip until the plant was cooled down at a later date when the valve could be opened to confirm the cause. The inspectors reported the problem in NRC Inspection Report 50-382/89-03, dated February 17, 1989.
During the Fall 1989 refueling outage, the licensee disassembled the valve and found the seat not fully threaded into the body. The threads were stripped, allowing the valve seat to be pushed farther into the valve body so that the stem could not reach.
This was corrected by implementing a design change that locked the valve seat in place on both RC-301A and -B (the redundant valve).
On March 16, 1990, the licensee was able to seat RC-301A by selecting RC-301B on the control room panel instead of "both " On March 20, 1990, a containment entry was made to check the valve actuator and positioner. When the valve received a signal to close, the positioner left residual air pressure under the actuator diaphragm when it should not, as was suspected. The technicians realigned the positioner, thus correcting the problem.
Based on previous history of this valve, the licensee decided to select RC-301B for normal operation and to not use RC-301A unless the redundant valve failed.
The inspectors reviewed the applicable sections of the FSAR and the
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licensee's evaluation of operating in this manner and feand no safety concerns.
The licensee is considering some design changes to provide a more reliable positioner and a more effective booster. The licensee also plans to disassemble the valve during the next refueling outage to confirm that the cause of this recent seating problem was positioner drift as opposed to internal valve seat problems.
The inspectors will follow up and report on the results of these actions. This shall be tracked as Inspector Followup Item (IFI) 382/9005-01.
b.
Automatic Reactor Trip Due to Two CEAs Dropping At 9:33 p.m. on March 22, 1990, while the reactor was at 100 percent power, an automatic reactor trip occurred on high local power density (LPD) and low departure from nucleate boiling ratio (DNBR).
The core protection calculator inserted penalties as CEAs 36 and 40 i
were dropped, which resulted in a reactor trip. The two CEAs were dropped during troubleshooting activities on Subgroup 9 of Shutdown Group B, which included CEAs 36, 38, 40, and 42. Abnormal voltage alarms had been experienced, principally on CEA 38, and the technicians were taking voltage and current measurements after replacing the Subgroup 9 CEA power switch assembly. While on the hold bus, voltage appeared normal. When they transferred the
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subgroup back to the normal power supply, abnormal voltage occurred
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and the CEAs woulc not stay on the upper grippers. When the operator attempted to transfer the subgroup back to the hold bus for further
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troubleshooting, the reactor trip occurred.
Review of the posttrip data revealed that CEA 36 dropped, CEA 38 did not drop, and, as
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CEA 40 fell into the core, the trip occurred, as designed.
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Within approximately 4 minutes, as the inspector determined from the reactor operator's log, the licensee completed the immediate actions i
required by the emergency operating procedures entry procedure,
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completed a diagnostic, and entered the optimal recovery procedure for an uncomplicated reactor trip. All systems responded as
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designed, and operator actions were appropriate. An emergency feedwater actuation signal (EFAS) occurred, as expected, because Steam Generator Nos. I and 2 water levels dropped to 14 and
12 percent, respectively, which was below the 27 percent setpoint.
All three emergency feedwater pumps responded properly.
Since one main feedwater pump remained in service (the operator manually tripped the other), steam generator water level was restored shortly
thereafter, and the EFAS was reset. Since the plant had been operating at reduced reactor coolant system (RCS) pressure (2175 psia in lieu of 2250 psia), RCS pressure dropped to 1785 psia, which is
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slightly less than the 1800 psia minimum normally expected under these circumstances.
- Upon restoring steam generator blowdown, which was automatically isolated by the EFAS, a small leak appeared in the 2-inch flow control valve bypass line for Steam Generator No. 2, near Valve BD-112B, Further investigation revealed that there may have been waterhammer associated with restoring blowdown flow, because there was also damage to three hangers on the 95-foot long,
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nonnuclear safety piping run between the containment isolation valve and the flow control valve.
The 2-inch bypass line failed due to erosion-related wall thinning.
The failed section had thinned to about 20 percent of normal wall thickness, and at the leak site appeared to be nearly paper thin. The blowdown system underwent extensive piping replacement during the Fall 1989 refueling outage, as part of the licensee's erosion / corrosion inspection program. The licensee explained that the bypass piping normally saw little flow, thus, it may not have been inspected.
However, the licensee found
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that the failed pipe was subjected to more than the normally expected flow due to problems with the flow control valve during the previous fuel cycle. This apparently caused the unexpected erosion and consequent failure.
The inspection performed subsequent to the waterhammer event also revealed a missing vertical strut hanger on the nonsafety-related portion of the blowdown piping immediately downstream of outside blowdown containment isolation Valve BD-103A.
This was the blowdown line from Steam Generator No. 1.
Since this was a relatively short run of piping, there was no visible evidence of waterhammer damage.
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The licensee is investigating, but it appeared that the hanger was i
removed without autho*izing paperwork while replacing corroded piping during the Fall 1989 outage.
Prior to startup, engineering evaluations were performed to determine the operability of the piping and possible impact on nuclear safety.
The evaluations showed that there was no nuclear safety impact, because the nonnuclear safety piping directly downstream of the
safety-related containment isolation valves in the blowdown system
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were adequately supported. However, the integrity of the downstream blowdown piping could not be assured until the thinned bypass pipe i
was replaced, the missing strut hanger reinstalled, and at least one
of the three damaged hangers repaired. The inspectors observed this work being done, and it was completed prior to restoring blowdown and the subsequent startup.
The licenbee evaluated the missing hanger event for reportability under 10 CFR 50.73 and determined that it was
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not reportable,
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The cause of the CEA voltage problem was determined to be a burned connector for the Subgroup 9 power switch assembly. One of the
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prongs appeared to develop a high resistance connection, overheated, and then eventually melted. The connector was replaced and restored
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to operation after postmaintenance testing was satisfactorily completed.
Inspection of the other connectors associated with Subgroup 9 power switch did not exhibit any similar problems.
After the CEA power switch and blowdown system repairs were completed, the plant was restarted and restored to full power operation by 2 p.m.,
on March 25, 1990, c.
Automatic Reactor Trip Due to Fault at Nearby Substation At 7:30 a.n:,, on March 29, 1990, the reactor tripped again from full power operation due-to low DNBR. The inspector was in the control room at the time, so particular attention was focused on the licensee's approach to the event, attention to safety, and the implementation of the appropriate emergency operating procedures (EOPs).
Prior to the reactor trip, workers at the Occidental Chemical Corporation substation in Taft, which was adjacent to Waterford 3, were cycling a breaker when a flash occurred. This reportedly severed a shield wire which eventually created a dead short which lasted approximately 1/2 second on the entire Entergy System Grid.
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This momentarily reduced voltage and frequency on the Waterford 3 offsite power sources to the extent that reactor coolant pumps (RCPs)
slowed to below 96.5 percent of normal speed, and the B vital bus tripped off on undervoltage. The vital bus stripped nonessential loads, and the B emergency diesel started as designed and assumed vital loads through the automatic sequencer. The momentary reduction in RCP speed was sensed by the core protection calculators (CPCs)
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which in turn generated a penalty factor of 0.15.
This was applied to the existing DNBR of 1.5, resulting in a low DNBR trip signal on
all channels, thus tripping the reactor.
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Among the nonessential loads lost when the B vital bus was tripped was the turbine bypass control system.
Since the main turbine
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tripped and the turbine. bypasses did not open, residual primary plant
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heat was dissipated through two steam generator code safety valves on each side, and the twe' atmospheric dump valves, in accordance' with plant design.
Steam generator pressure did not exceed 1100 psia, and l
reactor. hot leg temperature did not exceed 611*F, as expected. All
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safety systems functioned as designed, including actuation of the
The operators performed in an exemplary manner throughout this complex electrical event.
The control room supervisor maintained good control over the operators and nonlicensed operators as they implemented an orderly recovery in accordance with the appropriate E0Ps. At the same time, he maintained proper perspective over the critical safety functions.
This permitted the shift supervisor to maintain cognizance over the " big picture" and obtain needed support.
Teamwork and cooperation was evident throughout the event recovery.
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The posttrip reviews indicated no plant problems and the fault on the grid was identified and isolated, the plant was restarted and returned to full power by 12:49 p.m. on March 30, 1990.
The inspector requested that the licensee provide other data as it becomes available to aid in determining what actually happened on the grid.
Four other nonnuclear units were tripped as a result of the fault, for a total i
generating loss of about 2300 megawatts of power.
Failure of the fault to
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be automatically isolated in a timely manner gave rise to NRC questions on the reliability of the offsite power source for Waterford 3.
The licensee stated that a detailed report would be published by Entergy Services, Inc.-
in about 2 weeks. The licensee is also considering the possibility of placing the turbine bypass control system on a more reliable
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uninterruptable power supply, so that when nonessential loads are stripped
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from the vital busses, turbine bypass control would be retained. This would reduce challenges to safety equipnent such as the steam generator
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code safety valves.
These actions shall be tracked as IFI 382/9005-02.
No violations or deviations were identified.
4.
Monthly Maintenance Observation (62703)
The station maintenance activities affecting safety-related systems and components listed below were observed and documentation reviewed to ascertain that the activities were conducted in accordance with approved
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work authorizations (WAs), procedures, Technical Specifications, and appropriate industry codes or standards.
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WAs 01052711 and 01054404. On March 8, 1990, the inspector observed work in progress on the nonsafety-related Instrument Air Compressor B.
Corrective maintenance was being performed on the compressor discharge check valve and the filters on the suction and discharge of_the compressor. The cooling water strainer was also being replaced. The inspector verified that the equipment was properly removed from service and tagged, and that the work was authorized by the shift supervisor.
The work instructions were reviewed and found to be adequate for the tasks being performed aird the workers were familiar with the work to be done.
The supervisor was questioned on the cleanliness requirements for the instrument air system.
He stated that Class C cleanliness had to be maintained as called for in the WA and Procedure UNT-007-005, " Cleanliness Control." Inspection of the system cleanliness prior to closure was
performed by an independent verifier and documented.
No problems were identified.
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b.
WA 01055559. On March 20, 1990, the inspector observed preventive maintenance performed on the Low Pressure Safety Injection (LPSI)
Pump B motor. The motor bearing lubricating oil was changed in accordance with the licensee's Procedure UNT-005-007, Revision 3,
" Plant Lubrication Program." The inspector verified that the proper oil was used.
- Since LPSI Pump B was located in a contamination controlled area, and in a radiation area, the inspector noted two practices that were not'
conducive to minimizing personnel radiation exposures as low as
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reasonably achievable (ALARA).
First, the new oil was not staged in the area, even though a transient combustible permit was issued. As a result, the mechanics donned anticontamination protective clothing twice to do one simple job. This created a small amount of unnecessary radiological waste and caused the mechanics to spend more time in the radiation area. The mechanics explained to the inspe. tor that they were not allowed by procedure to stage the new oil until the old oil was removed from the room.
This perception was in error, based on the inspector's subsequent review of the licensee's procedures.
Second, the work instruction did not give the mechanics the option to not clean the oil level sight glass if it was already
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clean.
Efforts to take apart and clean an already clean sight glass resulted in additional, unnecessary exposure. The above ALARA
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considerations were discussed with licensee management. They committed to ensure that the plant staff understands the transient combustible procedure requirements, and that repetitive maintenance instructions provide an option, where appropriate, to avoid unnecessary work in radiation areas for the sake of ALARA. The inspectors will follow up on actions taken.
This item shall be tracked as IFI 382/9005-03.
-c, WAs 01052446 and 01046939.
On March 21, 1990, the inspector observed portions of preventive maintenance activities on Dry Cooling Tower Fan 14B. As a result of vibration data taken per the licensee's
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predictive maintenance program, the motor was removed for overhaul prior to motor failure.
In an effort to restore the fan to service as quickly as possible, the licensee replaced the motor with a spare.
However, the replacement motor was overhauled during an earlier period when rotors were not balanced, and the motor exhibited more vibration than expected when it was energized. The licensee decided to _ leave the fan administrative 1y out of service until the original
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motor was overhauled, balanced, and reinstalled.
Engineering evaluated the fan as operable so that it could be etilized if needed.
This was a more conservative approach thar to take the motor back out of service while waiting for the original motor to be overhauled.
No problems were identified.
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WA 01056036.
On March 21, 1990, the inspector observed the replacement of optical isolators in the power supply switch for CEA Subgroup 9.
Based on voltage traces taken on the CEA drive mechanisms, the technicians considered these isolators to be a likely cause of abnormal voltages that existed on CEA 38.
Subsequent retesting showed the problem still existed and, after more troubleshooting, the entire switch was replaced. Upon retesting the-new switch, CEAs 36 and 40 dropped, causing the automatic rector trip described in pararaph 3.b above.
Once the reactor was shut down, more thorough troubleshooting was done and a bad connector was
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found. Once replaced, normal voltages were restored and a successful retest was accomplished.
The work instructions were adequate to the circumstances. The technicians followed the instructions and appropriate quality controls were implemented.
No violations or deviations were identified.
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5.
Monthly Surveillance Observation (61726)
T.he inspectors observed the surveillance testing of safety-related systems and components listed below to verify that the activities were being performed in accordance with the Technical Specifications.
The applicable procedures were reviewed for adequacy, test instrumentation was verified to be.in calibration, and test data was reviewed for accuracy and completeness. The inspectors ascertained that any deficiencies identified were properly reviewed and resolved.
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a.
Procedures OP-903-068, Revision 6, " Emergency Diesel Generator Operability Verification," and OP-903-094, Revision 6, "ESFAS Subgroup Relay Test-0perating."
l On March 5, 1990, the inspector observed the performance of the f
monthly operability verification of Emergency Diesel Generator (EDG) A which the licensee coordinated with the 62-day automatic actuation logic test of engineered safety feature actuation system (ESFAS),
Train A, Position 10, Relay K110.
The inspector also witnessed the
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automatic actuation logic test of ESFAS, Train A, Positions 11 and 16
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(Relays K410 and K412, respectively).
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The initial conditions for the ESFAS Relay K110 test were consistent with those required by the EDG A operability test, so the operators were able to complete two surveillances requiring an EDG start with l
only one start, thus reducing the number of starts on the EDG.
j The tests were conducted by licensed operators in the control room.
The operators appeared to be well prepared for the tests and were
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following procedures except as noted below.
The final test results were satisf actory.
Section 7.11 of OP-903-094 was the first test performed.
At the end of the section, Step 7.4 required the operator to align EDG A for
" STANDBY." This was done, but the step required the operator to record verification that this was done, on Attachment 10.1 of the procedure.
The accomplishment and independent verification signatures
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for this step were not entered until after EDG A was started and r
running for the next test, when the condition to be verified no longer existed.. This appeared to defeat the purpose of the verification signoff and demonstrated another example of where plant personnel were not performing verifications as intended. This is considered to be a further example of the same violation contained in the Notice of Violation accompanying NRC Inspection Report 50-382/89-41 for which the licensee had not yet fully implemented corrective actions. The inspector's followup of this item will be included as part of the inspection of the licensee's corrective actions taken in response to the existing violation.
During performance of Section 7.10 of the procedure, Step 5 specifies that the operator initiate the ESFAS actuation test by
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" Simultaneously press and hold the INITIATE ACTUATION pushbutton on CP-33 and momentarily place the EMERGENCY DIESEL GEN A SEQUENCER test
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switch to test." The operator failed to place the EDG A sequencer
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test switch on CP-1 to " test" and, as a result, unsatisfactory test
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results were obtained, i.e., the auxiliary component cooling
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water ( ACCW) pump did not start. When the inspector questioned whether anyone placed the test switch to " test," the operators immediately recognized that the procedure was not followed resulting in failure of the ACCW pump to start.
The error could have been prevented by proper attention to the detailed steps of the surveillance procedure. The reactor operators and senior reactor operators involved were the same individuals who did an excellent job in recovering from the reactor trip of March 29, 1990, described in paragraph 3.c above. The test was repeated in accordance with the procedure with satisfactory results. The inspector discussed the incident with licensee management and expressed concern that while this particular occurrence was self-identifying, such errors could just as easily preclude the identification of nonfunctioning safety features.
The licensee's actions on this issue is considered to be an IFI.
(382/9005-04).
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6.
Operational Safety Verification (71707)
The objecti/es of this inspection were to ensure that this facility was being operated safely and in conformance with regulatory requirements, to ensure that the licensee's management controls were effectively discharging the licensee's responsibilities for continued safe operation, to assure that selected activities of the licensee's radiological protection programs are implemented in conformance with plant policies and
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procedures and in compliance with regulatory requirements, and to inspect i
the licensee's compliance with the approved physical security plan, t
The inspectors conducted control room observations and plant inspection tours and reviewed logs and licensee documentation of equipment problems.
Through in-plant observations and attendance of the licensee's plan-of-the-day meetings, the inspectors maintained cognizance over plant status and Technical Specification action statements in effect.
In the previous inspection report covering the period February 1-28, 1990, the inspectors discussed seat leakage problems with the pressurizer code safety valve, See NRC Inspection Report 50-382/90-04.
The leakage continued to be a minor problem throughout this inspection period.
The frequency of venting / draining the quench tank increased from twice daily to more than once per 8-hour shift, so the licensee lowered pressurizer pressure (and thus reactor coolant system pressure) from 2200 psia to
2150 psia. This was still within the limits of the Technical i
Specifications (the lower limit being 2025 psia) and, based on engineering evaluations and simulator data, would not cause a safety injection actuation signal from low pressurizer pressure during an uncomplicated reactor trip. This was proved valid when the reactor tripped on March 29, 1990 (paragraph 3.c).
As of the end of this inspection period, leakage was roughly 3 gallons per hour, trending very slowly upward. The l
operators have been maintaining quench-tank pressure and temperature within normal operating limits without difficulty. The licensee is i
l developing guidance for operator actions should any of the parameters change significantly. The inspectors will continue to monitor this area i
l and keep Region IV management informed, i
l On March 14, 1990, the inspectors attended the itcensee's second quarter ALARA meeting. Of particular interest was the fact that temporary l.
shielding had been installed on a safety injection check valve i,1 Safety l
Injection Pump Room B for over 4 years and was still conside.ed temporary.
i The licensee's procedure for the installation of temporary shielding, HP-001-114, Revision 3, " Installation of Temporary Lead Shielding,"
required consideration of such shielding for a permanent installation if
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it was in place for over 6 months.
The inspector noted that this installation was still under consideration. Tiie only significance of having a temporary shield installed for extended periods is the resource
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and possible additional man rem expenditures to ensure that the temporary I
shield remains as installed through monthly inspections. This was discussed with the licensee, who was evaluating the best approach from a
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manpower and man rem perspective. Other open issues were discussed at the
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meeting, and the inspector observed management involvement and an atmosphere of commitment to reduce exposures to as ALARA.
No violations or deviations were identified.
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7.
Followup of Previously Identified Items (92701,9270D a.
(Closed) Unresolved Item 382/8920-01:
Review of root causes and corrective actions taken by the licensee with regard to a failed pump shaft on Essential Chilled Water Pump B.
During the period October 10-13, 1989, inspectors from the Materials and Quality Programs Section (MQPS), Division of Reactor Safety, conducted a followup inspection and review of actions taken by the licensee.
See NRC Inspection Report 50-382/89-30, dated October 30, 1989. As of that inspection, the root cause investigation had not been completed, thus the item was left open.
On January 25, 1990, the root cause investigation was completed and a copy of the report delivered to y
Region IV.
The document was reviewed by MQPS and determined to adequately address the root causes of the failures.
The recommended corrective actions appeared to be sufficient to correct the causes, Principally, the root cause was identified as a poor manufacturing process which allowed the manufacture and acceptance of a replacement pump shaft with improper dimensions. This was accompanied by inedequate vendor support from the original pump manufacturer and poor judgement on the part of LP&L to allow use of old shaft dimensions as the reference for manufacturing a new shaft.
Corrective actions included initiation of a design change for an improved pump shaft, revision of the licensee's fabrication procedure, and manufacturing quality enhancements were implemented on the replacement pump shaft. The above actions were considered adequate by the inspectors.
This item is closed.
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(Closed)IFI 382/8930-02:
Review of the final evaluation report on l~
main steam isolation valve stem failures.
During the period
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l October 10-13, 1989, inspectors from MQPS conducted a followup inspection on the causes and corrective actions associated with the stem failure.
See NRC Inspection Report 50-382/89-30, dated October 30, 1989. The inspector concluded from the information gained that the Lp&L evaluation approach appeared appropriate for the known failure scenario.
However, the final evaluation report was not i
yet published. On January 29, 1990, the report was delivered to l
Region IV, and a review was performed by MQPS. The report was well l
organized and addressed the appropriate questions. The failed valve l
stems were replaced with new stems having a larger radius at the point of previous failure.
The licensee is considering other design changes for the valves to help minimize the possibility of future failures. The licensee also addressed the issue in the voluntary LER closed in paragraph 8 of this inspection report. This item is closed.
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c.
(Closed) Unresolved Item 382/8934-01: During an inspection in October 1989, the licensee was unable to produce documentation supporting their position that Containment Penetrations 45, 46, 48,
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53, 54, 66, and 67 would not have failed to perform their intended safety function with seismic support anchors installed too close to the penetrations.
The nonconformance was in the design, and Ebasco (the Waterford 3 architech-engineer) was performing an evaluation to determine if such a failure could have occurred during plant operation. The problem was identified during the third refueling outage, and by the end of the outage, the design was corrected and
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the hardware altered (Design Changes 3247 and 3249).
Since this problem was identified by Ebasco nearly 2 years after a similar problem was identified and corrected on Penetration 47, the inspector questioned why Ebasco waited so icng to identify the others. During a followup inspection in November 1989 (NRC Inspection Report 50-382/89-37), this issue was addressed again, but the documentation still was not made available to the inspector, so this unresolved item was left open. On March 8, 1990, the inspector reviewed Ebasco Letter LW3-90-005, dated January 8, 1990. The letter
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summarized the result of the evaluations, which was that none of the penetrations were rendered inoperable by the design deficiency, thus there were no violations of Technical Specification limiting conditions for operation. The licensee also had the documented evaluations on site.
In the letter, Ebasco explained why LP&L was not told of the potential problem at the time of the discovery.
The explanation was lengtny and appeared to involve a 2 year exchange of documentation, response to questions, and historical research within the Ebasco organization until October 4, 1989, when Ebasco determined that a potentially reportable problem existed and informed LP&L.
LP&L has since altered the contracts with several service organizations such as Ebasco to require prompt telecon notification of LP&L when a problem arises, regardless of whether it has been established as an NRC reportable issue.
This item is closed.
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d.
(Closed) Violation 382/8934-03: This violation involved a failure to meet the initial conditions required by an EDG surveillance test.
The surveillance test required the EDG to be aligned for " STANDBY,"
but the operator was not aware that one set of turbocharger lube oil filters was out of service. This illustrated a weakness in the licensee's control of safety-related system status. There was no mechanism for tracking valves or breakers out of normal or standby alignment, except when they were danger or caution tagged or when a procedure took them out of position and restored them.
The licensee committed to implement appropriate controls by March 2, 1990.
On March 9, 1990, the inspector determined that, effective March 2, 1990, as committed, the licensee implemented Procedure 01-027-000, Revision 0, " Deviation Tracking Log." The inspector noted that there was a valve / breaker status tracking log in the control room, which included an index for easy reference. The inspectors will monitor the utilization of this log as part of the routine safety verification inspections.
This violation is closed.
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No violations or deviations were identified.
8.
Licensee Event Report (LER) Followup (92700. 90712)
The following LER was reviewed and closed. The inspectors verified that i
reporting requirements had been met, causes had been identified, corrective actions appeared approprinte, generic applicability had been considered, and that the LER forms were complete.
The inspectors
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confirmed that unreviewed safety questions and violations of Technical Specifications, license conditions, or other regulatory requirements had been adequately described.
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(Closed) LER 382/89-023, " Fatigue Failure of the Main Steam Isolation
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Valve Stem Due to Cyclic Stress." This was a voluntary LER.
Although none of the problems encountered with " POW-R-SEAL" gate valves manufactured by W-K-M Product Division of Cooper Industries
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met the reportability criteria of 10 CFR 50.73 or 10 CFR 21, the licensee felt that these problems may be of generic interest to the nuclear industry.
No violations or deviations were identified.
9.
Engineered Safety Feature (ESF) System Walkdown (71710)
The inspectors initiated a walkdown of the accessible portions of the h
Containment Isolation System, Trains A and B, to verify system operability.
The inspectors started this inspection on March 5, 1990, by reviewing selected operating procedures and system drawings.
No problems were identified during this inspection period, however, the bulk of the inspection will be performed during the next inspection period.
The results of the entire inspection will be documented in NRC Inspection Report 50-382/90-07.
No violations or deviations were identified.
10.
Exit Interview The inspection scope and findings were summarized on April 4, 1990, with those persons indicated in paragraph 1 above. The licensee acknowledged the inspectors' findings.
The licensee did not identify as proprietary any of the material provided to, or reviewed by, the inspectors during this inspection.
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