IR 05000244/1995008
| ML17263B071 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 06/02/1995 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17263B070 | List: |
| References | |
| 50-244-95-08, 50-244-95-8, NUDOCS 9506120461 | |
| Download: ML17263B071 (24) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION I
Inspection Report 50-244/95-08 License:
DPR-18 Facility:
Inspection:
Inspectors:
R.
E. Ginna Nuclear Power Plant Rochester Gas and Electric Corporation (RG&E)
March 12 through May 6, 1995 T. A. Moslak, Senior Resident Inspector, Ginna E.
C. Knutson, Resident Inspector, Ginna P.
D. Drysdale, Project Engineer, Region I Approved by:
M.
.
azar Chief R
r Pro ects Section 3B INSPECTION SCOPE Date Plant operations, maintenance, engineering, plant support, and safety assessment/quality verification.
9506120461
'950605 PDR ADOCK 05000244
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Operations INSPECTION EXECUTIVE SUNNARY On Narch 27, 1995, hydrogen leakage from the main generator was classified, after the fact, as an unusual event; as the conditions no longer existed, no event declaration was 'made.
State and local authorities and the NRC were promptly notified.
On April 30, 1995, while increasing main turbine speed during startup following the cycle 25 annual refueling and maintenance outage, high noise was observed coming from the No.
3 main bearing.
The main turbine was tripped and the reactor was placed in hot shutdown conditions.
The cause was determined to be inadequate lubrication to the No.
3 bearing, due to improper installation of the upper bearing half.
The bearing was replaced and plant start-up activities recommenced.
Naintenance On April 7, 1995, with the reactor in cold shutdown mode, an automatic safety injection system initiation occurred during the course of a primary plant instrument calibration.
The cause of the event was weak procedural guidance and technician error.
The event had no significant effect on plant conditions.
On April 30, 1995, NOV-4007 (Notor driven auxiliary feedwater pump A discharge valve) failed to open during performance of a monthly surveillance test.
The cause was determined to be that the valve was bound in the closed position due to overtorquing during its previous closing cycle.
The cause of the overtorquing was determined to be that the close torque switch set screw had loosened due to vibration and allowed the close torque setpoint to drift to its maximum value.
The valve was repaired and testing indicated that no damage to the actuator had occurred.
However, the inspector determined that a
contributing factor to this event was that no torque switch limiter plate had been installed, as required by the licensee s
GL 89-10 program.
This item is unresolved pending review of the licensee's root cause analysis.
Engineering During annual eddy current inspection of steam generator U-tubes, an incomplete weld was identified at the upper end of a previously sleeved U-tube.
Investigation determined the cause to be a combination of 1)
difficulties associated with a specific type of sleeve installation, and 2)
incorrect interpretation of acceptance inspection data by a single, relatively inexperienced inspector.
All previously sleeved SG tubes that satisfied these two criteria were subsequently re-inspected.
One additional sleeve was identified as having an incomplete weld, and six sleeves were evaluated as having questionable weld fusion.
All eight affected SG tubes were subsequently removed from service by plugging.
During transition to hot shutdown, a small through-weld leak was identified in the B-safety injection pump recirculation line.
Plant conditions were ii
(EXECUTIVE SNNARY COHTINUEO)
stabilized, with reactor coolant system temperature just below hot shutdown, and the licensee entered a 72-hour action statement.
The leak was determined to be a small crack, and was repaired by excavating and rewelding.
Root cause analysis of the condition is in progress.
The licensee minimized the impact of this emergent maintenance on the outage schedule by conducting control rod drop testing at slightly reduced temperature.
Plant Support The licensee declared a local radiation emergency April 2, 1995, when floor drains in the auxiliary building were discovered to be overflowing into the intermediate and lower levels.
Surface smears of the affected areas were taken and found to be slightly contaminated (greater than 1100 disintegr ations per minute).
All area radiation monitors and local air samples indicated normal.
The problem was determined to be due to blockage in a line to the waste holdup tank that occurred while dewatering a resin liner.
Significant improvements were noted in reducing collective radiation exposure and personnel contaminations from those of past outages.
For the current outage, the total dosage was 118 person-rem, compared with 124 person-rem and 155 person-rem for the 1994 and 1993 outages, respectively.
Personnel contaminations remained low with 73 cases, with no internal uptakes nor hot particle contaminations experienced.
Safety Assessment/guality Verification management utilized various resources to assure that work met acceptance standards and that the underlying causes of plant incidents were identified and expeditiously corrected.
These resources included having comprehensive human performance evaluations and root cause analyses performed to establish the factors that resulted in the inadvertent release of hydrogen gas from the main generator and the incorrect installation of a main turbine bearing.
The guality Assurance organization provided oversight for various surveillance tests and maintenance activities including the accumulator discharge check valve testing and verification of weld repairs to a safety injection system recirculation lin EXECUTIVE SUMMARY.
TABLE OF CONTENTS
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TABLE OF CONTENTS iv 1.0 OPERATIONS (71707)
1.1 Operational Experiences
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1.2 Control of Operations
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1.3 Unusual Event Notification 1.4 Operations with Reduced Reactor 1.5 lain Turbine Bearing Failure
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Coolant System Inventory 2.0 IlAINTENANCE (62703, 61726)
2. 1 Preventive Maintenance 2.1.1 Routine Observations 2.2 Surveillance Observations
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2.2. 1 Routine Observations 2.2.2 Safety Injection Accumulator Check Valve Operabil Test 2.2.3 Inadvertent Safety Injection System Actuation
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2.2.4 Control Rod Drop Testing 2.2.5 Notor Operated Valve (NOV) Failure
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PLANT SUPPORT (71750)
4. 1 Radiological Controls
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4. 1. 1 Routine Observations 4.1.2 Local Radiation Emergency 4.1.3 Outage ALARA Review.
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4. 2 Secur ity 4.2.1 Routine Observations 4.3 Fire Protection
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4.3.1 Routine Observations 3.0 ENGINEERING (71707, 37551)
3. 1 Incomplete Welding of Steam Generator 3.2 B-Safety Injection Pump Recirculation I
4.0
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13 5.0 SAFETY ASSESSMENT/qUALITY VERIFICATION (71707)
5. 1 Periodic Reports 5.2 Licensee Event Report
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6.0 ADNINISTRATIVE 6. 1 Backshift and Deep Backshift Inspection 6.2 Exit Neetings
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1.0 OPERATIONS (71707)
1.1 Operational Experiences DETAILS At the beginning of the inspection period, the plant was operating at full power (approximately 98 percent).
On March 26, 1995, at 3:00 a.m.,
a planned power reduction began in preparation for the cycle 25 annual refueling and maintenance outage.
The plant went off-line at about ll:00 a.m.,
March 26, 1995, and achieved cold shutdown conditions at 5: 15 a.m.
on March 27, 1995.
Following successful completion of a reactor coolant system hydrostatic test on April 29, 1995, plant start-up activities commenced.
Reactor criticality was achieved on April 29, 1995 at 6: 15 p.m.
Following zero power physics testing, power was escalated to about 2 percent and secondary plant start-up activities were initiated.
On April 30, 1995, while increasing main turbine speed, high noise was observed coming from the No.
3 main bearing and control room turbine vibration instrumentation indicated increasing vibration with subsequent alarms.
Shift management ordered tripping the main turbine and shutting down the reactor.
The reactor was placed in hot shutdown conditions.
The cause of the high turbine vibration was determined to be inadequate lubrication to the No.
3 bearing, due to improper installation of the upper bearing.
Following an inspection of the affected main turbine components and installation of a replacement bearing, plant start-up activities recommenced with criticality achieved at 5:50 a.m.
on May 3, 1995.
The main turbine successfully achieved operating speed, reactor power was escalated to 23 percent, and the main generator output breakers were closed at 1:45 p.m.
on May 3, 1995, ending a 39 day outage.
Full operating power of 97 percent was achieved at 5:34 p.m.
on May 7, 1995.
1.2 Control of Operations Control room staffing was as required.
Operators exercised control over access to the Control Room.
Shift supervisors maintained authority over activities and provided detailed turnover briefings to relief crews.
Operators adhered to approved procedures and were knowledgeable of off-normal plant conditions.
The inspectors reviewed control room log books for activities and trends, observed recorder traces for abnormalities, assessed compliance with technical specifications, and verified equipment availability was consistent with the requirements for existing plant conditions.
During normal working hours and on backshifts, accessible areas of the plant were toured.
No operational inadequacies or concerns were identified.
Throughout the outage, daily safety assessments were performed by the outage coordinators to evaluate the availability of reactivity control systems, core cooling systems, electrical supplies, containment integrity, and reactor coolant inventory make-up paths during system configuration changes.
Effective communication was maintained between the work control center, outage management, and the control room, to assure close coordination of activitie.3 Unusual Event Notification On Narch 27, 1995, with the plant in cold shutdown, a main generator hydrogen panel alarm was received at approximately 8:35 a.m.
Operations personnel in the area discovered that hydrogen was escaping from main generator seals.
Operators contacted the Plant Safety Coordinator and increased turbine building ventilation.
An Auxiliary Operator (AO) was immediately dispatched to check operation of the seal oil system.
As a precaution, all work in the turbine building was halted, and unnecessary personnel were requested to leave the building.
At approximately 8:50 a.m.,
due to concerns related to seal oil system operation, control room operators directed an AO to initiate degas of the main generator.
At approximately 9:00 a.m.,
Narch 27, 1995, local air sampling by the Plant Safety Coordinator indicated hydrogen concentration was below the flammable limit. 'owever, he estimated from his indications that hydrogen concentration had probably exceeded the flammable limit for a few minutes shortly after the hydrogen gas began escaping.
At approximately 9:03 a.m.,
March 27, 1995,=the Operations Shift Supervisor conservatively assumed that conditions may have previously existed that would have warranted classification and declaration of an Unusual Event, had they been recognized at that time.
In accordance with EPIP 1-0,
"Ginna Station Event Evaluation and Classification," Step 4.6, the Operations Shift Supervisor has the option of only classifying, but not declaring, an Unusual Event under these circumstances.
Therefore, he classified (but did not declare) this as an Unusual Event in accordance with Emergency Action Level (EAL) 8.3.3,
"Report or detection of toxic or flammable gases that could enter or have entered within the protected area boundary in amounts that could affect the health of plant personnel or safe plant operation."
Off-site agency notifications were made per EPIP 1.5, "Notifications," using the Emergency Notification System (ENS)
as a matter of consistency and timeliness.
At approximately 9:22 a.m.,
Narch 27, 1995, the Plant Safety Coordinator determined that the turbine building was available for unrestricted access.
By this time, a carbon dioxide purge had been established on the main generator and all operational/safety concerns had been eliminated.
Site management promptly initiated an investigation to establish the cause of the hydrogen release.
Following discussions with turbine craft personnel and outage management, it was determined that the high pressure oil seal backup pump had been secured before the main generator had been degassed.
Completion of this evolution without completing the prerequisite hydrogen venting, in conjunction with a hydrogen seal oil system check valve leak-by, resulted in a depressurization of the seal oil system and subsequent release of hydrogen.
In response to this finding, site management reemphasized to supervisors and technicians the need for additional attention-to-detail when reviewing equipment hold requests to assure that the sequencing is appropriate for plant conditions.
Additionally, operations personnel in the work control center are to assure all hold requests have initialed authorization by the outage planners before taking systems out of service'.
Factors that apparently
contributed to this incident were the large number of turbine/main generator hold requests to be reviewed and new personnel involved in the review process.
Site management directed that a Human Performance Enhancement System (HPES)
analysis be performed to identify the root causes of this incident.
The inspector determined that operations personnel acted promptly in evacuating the turbine building, and degassing and purging the main generator, following identification of the hydrogen release.
Operations management determined after the fact, that this event should have been classified as an Unusual Event and promptly notified state/county/NRC emergency response organizations.
To preclude a recurrence of inappropriately taking a subsystem out-of-service, outage management took definitive measures to improve control of hold requests.
1.4 Operations with Reduced Reactor Coolant System Inventory During the outage, reactor coolant inventory was reduced on Narch 29, 1995 and April 17, 1995 to the mid-loop level to permit installation and removal, respectively, of steam generator nozzle dams.
The inspector determined that the licensee's preparations for establishing mid-loop operations were thorough.
Operating Procedure 0-2.3. 1, "Draining and Operation at Reduced Inventory of Coolant System,"
was implemented to ensure redundancy, availability, and reliability of on and off-site sources of electrical power and coolant make-up sources/paths.
0-2.3. 1A, "Containment Closure Capability in Two Hours During RCS Reduced Inventory/Operation,"
was in place to accomplish rapid containment closure if required.
management directed that no operations be conducted during these periods that would compromise a safe plant configuration.
Outage management informed maintenance personnel of the vulnerabilities that existed during this operational mode and sensitized them to industry experience at other facilities.
Operators performed this significant change of plant conditions in a slow, deliberate manner.
Operators were knowledgeable of expected indications as well as of symptoms of potential equipment problems.
Particular attention was given by the operators to higher RCS temperatures when initially entering into mid-loop conditions that resulted from an accelerated schedule and a higher decay heat load.
No significant deviations from expected system response occurred and no operational deficiencies were noted.
guality Assurance personnel conscientiously monitored the conduct of these mid-loop operations.
1.5 Nain Turbine Bearing Failure On April 30, 1995, during plant start-up activities, the main turbine speed was being increased to synchronous speed.
At about 600 revolutions per minute, operators heard abnormal noise coming from the No.
3 turbine bearing and control room turbine vibration monitors indicated increasing vibrations with a subsequent alarm (main control board annunciator I-27, "Rotor Eccentricity/Vibration").
Upon receiving this alarm, the Shift Supervisor directed that the turbine be tripped and Abnormal Procedure (AP-TURB.3,
"Turbine Vibration") be implemented for appropriate actions.
Accordingly, main condenser vacuum was broken and air ejectors were secured to facilitate a
rapid slow down of the main turbin Subsequent examination of the No.3 bearing revealed a wiped babbitt surface on both bearing halves, indicative of inadequate lubrication.
Inadequate lubrication resulted from an incorrect reassembly of the upper bearing in which the bearing was 180 degrees out of alignment with the lower bearing, resulting in the upper/lower lubricating oil flow ports not aligning.
Inspections were performed of affected high pressure/low pressure turbine components and a replacement bearing was installed.
Preliminary findings indicate that the alignment dowel pins on the upper bearing were properly mated with the guide holes of the lower bearing, that the shaft vibration sensor was appropriately positioned, and that initial verification of lubricating oil flow showed proper lubrication.
Since these false positive
. indications did not preclude improper reassembly, management directed that a Human Performance Enhancement System (HPES) evaluation be performed to establish the factors that contributed to this incident.
The inspector concluded that control room operators promptly and appropriately responded to the off-normal condition, thereby preventing additional damage to secondary plant equipment.
2.0 NAINTENANCE (62703, 61726)
2.1 Preventive Naintenance 2. 1. 1 Routine Observations
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The ins ector observed por
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Stone slip rings B-emergency diesel generator, observed April 13, 1995; performed at the beginning of RSSP-2.3B (Refueling Shutdown Surveillance Procedure)
Over the course of the outage, the inspector also observed portions of the following major maintenance activities:
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C-Safety Injection pump major overhaul The inspector observed no significant degradation of the interstage separator elastomer seals upon pump disassembly
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Hain condenser retubing
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5A and 5B high pressure feedwater heater replacements
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B-Safety Injection Pump Motor replacement p
tions of maintenance activities to verify that correct parts and tools were utilized, applicable industry code and technical specification (TS) requirements were satisfied, adequate measures were in place to ensure personnel safety and prevent damage to plant structures, systems, and components, and to ensure that equipment operability was verified upon completion.
The following maintenance activities were observed:
2.2 Sur veil lance Observations 2.2.1 Routine Observations Inspectors observed portions of surveillances to verify proper calibration of test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to limiting conditions for operation (LCOs),
and correct system restoration following testing.
The following sur veillances were observed:
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Periodic Test (PT) 50.23, "Differential Pressure Testing of Service Mater System Turbine Building Isolation Valves NOV 4613 and/or 4670",
revision 0, effective date April 5, 1995, observed April 10, 1995
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RSSP-2.3B,
"Diesel Generator B Trip Testing," revision 8, effective date Narch 12, 1994, observed April 13, 1995
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RSSP-2. 1, "Safety Injection Functional Test," revision 48, effective date April 21, 1995, observed April 24, 1995 RSSP-2.2,
"Diesel Generator Load and Safeguard Sequence Test," revision 48, effective date April 21, 1995, observed April 25, 1995
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PT-7, "ISI System Leakage Test Reactor Coolant System," revision 47, effective date April 21, 1995, observed licensee pre-test briefings and reviewed completed procedure for test performed on April 26, 1995 The test was classified as a "Significant Infrequently Performed Evolution (SIPE)" and, as such, was managed in accordance with licensee administrative (A) procedure A-52. 15,
"Conduct of Significant Infrequently Performed Evolutions" revision 3, effective date October 21, 1994.
Each step in establishing test conditions was thoroughly discussed by the SIPE coordinators to assure management and technician responsibilities were undet stood.
In summary, the test involved the following stages:
Establish an initial test plateau with RCS conditions of 330-350 psig, and a
RCS temperature of >330'
but <350'
Perform inspection and correct leakage Establish secondary heat sink and isolate RHR Remove overpressure protection system from service Increase RCS pressure to the 1500 psig plateau, perform inspection and correct leakage, as required Increase RCS pressure to the 2235 psig plateau, perform inspection and correct leakage, as required Depressurize, align overpressure protection system, place RHR in service
Tasks were found to be well coordinated and the test was appropriately conducted.
PT-34. 1, "Initial Criticality and ARO Boron Concentration," revision 20, effective date April 9, 1994, observed April 29, 1995 2.2.2 Safety Injection Accumulator Check Valve Operability Test Early in the outage, RGEE performed a new refueling shutdown surveillance procedure, RSSP-24, to conduct an operability check of safety injection accumulator check valves V-842A, V-842B, V-867A, and V-867B.
The test accomplished the ASNE Section XI inservice test (IST) requirements for full accumulator discharge flow through all four valves.
The procedure was originally written to provide certified data through two means:
1) an installed plant flow instrument coupled with certified measuring and test equipment (N&TE) and a computerized data acquisition system; and 2) non-intrusive diagnostic equipment intended to detect check valve slam at the open and closed positions.
Use of the first means was acceptable because the plant instruments and N&TE were in calibration, and because the data acquisition system was validated and verified for use prior to the test.
However, the second means could not be used for certified data, as originally planned, because an accelerometer and an eddy current power module were not within a
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current calibration period. Results and Test (R&T) personnel acknowledged that the equipment should have been calibrated to perform the test as written.
However, an R&T management memo, written before the test was performed, allowed for limited use of the non-intrusive equipment for qualitative information only.
In the future, RG&E will assur e that all equipment for this test is properly checked for calibration.
The inspector reviewed the validity of calibrations for the test equipment used to obtain certified flow data.
The test used an installed flow transmitter and digital voltmeter that were well within calibration.
A computer interpreted the voltage signals and calculated equivalent flow values.
The computer itself could not be "calibrated," but the software used for this application was validated prior to the test.
This was accomplished by comparing pr etest flow data with the main control board (NCB) flow instrument.
The inspector considered this to be an acceptable validation method.
However, the validation procedure did not provide an acceptable tolerance band for comparing the computer output with the NCB reading, and it also did not record the data being compared from both sources.
I&C personnel typically use the standard two percent tolerance for installed plant instrumentation, but RG&E should consider the need for stating the tolerances in the procedure, and actually record the values that were used to validate the computer software.
The RSSP-24 procedure also did not contain a place to record serial numbers and calibration dates for all of the test equipment used.
The test procedure did verify that the data acquisition computer system for non-intrusive equipment was in calibration, but that did not include a check of peripheral components such as accelerometers.
R&T acknowledged that the procedure should have a place to record all N&TE equipment.
The accelerometer and an eddy
current power module were not in the site's NLTE program because these devises belonged to a contractor involved in the test.
The accumulator check valve flow tests were successfully completed using calibrated instruments and the new RSSP-24 procedure.
The IST acceptance criteria for the check valves (>6000 gpm) were satisfied with over 35 percent excess flow margin in all cases.
The new procedure provided adequate instructions to perform the test, with only minor field revisions.
However, it lacked certain details that prevented the test from being performed with multiple instrument sets, as originally intended.
The procedure was approved for use within a week prior to the test, and the inspector concluded that better coordination between the RLT, ILC, Naintenance Diagnostics, and the contractor could have communicated the need for all instruments to be calibrated NLTE devices.
RLT intends to make procedure enhancements requiring all equipment used in this test to be placed in the site's NLTE program and recorded in the test procedure before this test is performed again.
2.2.3 Inadvertent Safety Injection System Actuation On April 7, 1995, with the reactor in cold shutdown mode, technicians were performing pressurizer pressur e transmitter calibrations.
As an initial condition for this work, the instrument inputs to the associated reactor protection system (RPS) channel were defeated.
When calibration of pressure transmitter PT-431 was completed, input to RPS channel 3 was not reinstated due to other in-progress instrument calibrations associated with that RPS channel.
Instead, the technicians proceeded to conduct calibration of pressurizer pressure transmitter PT-429.
This did not conflict with the calibration procedure, which indicated that it was not required to verify operability of the other pressurizer pressure channels when plant temperature was less than 350'F.
As part of the procedure to block the instrument inputs to RPS channel I, safety injection (SI) was defeated by placing the SI unblock bistable proving switch for pressurizer pressure channel P-429 in the tripped position.
By design, automatic initiation of SI is reinstated if more than one SI unblock bistable proving switch is tripped; since P-431 had not yet been restored, this action caused SI to be unblocked and resulted in an automatic initiation of SI due to low steam line pressure.
The automatic initiation of SI had no significant effect on plant operations because the SI equipment was out of service consistent with plant conditions.
Pressurizer pressure channel P-431 was reinstated, which restored the ability to block automatic SI initiation.
After verifying proper systems response and equipment operation, operators reset SI and restored normal plant configuration for cold shutdown.
The licensee determined that the principal causes of this event were weak procedural guidance and technician error.
Corrective action to address procedural inadequacies and additional training requirements were under review at the close of the inspection period.
The inspector reviewed this event and concluded that the inadvertent automatic initiation of SI had not adversely affected plant operations.
The inspector attended the PORC meeting at which the event and proposed corrective actions were discusse.2.4 Control Rod Drop Testing On April 28, 1995, while operators were raising RCS temperature to establish hot shutdown conditions, a weld flaw was identified in the SI pump recirculation line (discussed in section 3.2 of this report).
In response to this discovery, operators stopped the RCS temperature increase (at the time, RCS temperature was approximately 10'F below the hot shutdown lower temperature limit of 540'F)
and stabil,ized plant conditions.
Mhen the B-SI pump was subsequently declared inoperable, continued heatup to hot standby was precluded until after repairs to the recirculation line were completed.
To minimize the impact of this emergent maintenance on the outage schedule, the licensee reviewed outage activities that were to be performed in hot shutdown to determine if any could be performed under the existing plant conditions.
In this process, the licensee determined that plant conditions were acceptable for conducting control rod drop time testing.
The applicable test procedure, RSSP-7.0,
"Control Rod Drop Test," requires average RCS temperature to be at least 540'F; however, the licensee determined that performing the test at a slightly lower temperature (a minimum of 530'F) would be more conservative, in that the denser water would offer greater resistance to control rod travel and therefore result in longer drop times.
The proposal was approved by PORC and control rod drop testing was performed in parallel with the SI recirculation line repair.
The inspector reviewed the change to RSSP-7.0 and concluded that it satisfied the requirement of technical specification 3. 10.3 for determination of control rod drop times.
The inspector had no additional concerns on this matter.
2.2.5 Notor Operated Valve (NOV) Failure On April 30, 1995, NOV-4007 (Notor driven auxiliary feedwater (AFM) pump A
discharge valve) failed to open during performance of monthly surveillance test PT-16.3A,
"AFM Pump A Discharge NOV and Check Valve Test."
The test was conducted during the plant power ascension following the refueling outage, and was to verify that NOV-4007 automatically opens and properly throttles feedwater flow upon start of the AFW pump.
NOV-4007 must open fully and then automatically throttle to 200-230 gpm.
However, NOV-4007 did not open on demand, and the valve disk remained locked in its seat under full motor torque.
The actuator motor did not trip out under the high overcurrent condition because its thermal overload heater relay did not function.
Overheating damaged the motor that had to be replaced.
Operations personnel issued Station Event Report A-25. 1/95-065 to document the NOV failure.
The failure was proceeded on April 21, 1995, by a quarterly IST surveillance test, PT-169-A, "Auxiliary Feedwater Pump A - quarterly," during which an unusually high level of vibration and noise were noted in NOV-4007.
The high noise and vibration occurred when NOV-4007 was manually throttled, as required by the test procedure.
The licensee concluded that the high vibration was caused by a maximum differential pressure across the valve with atmospheric pressure in the steam generator.
The vibration was high enough to cause the
valve actuator's manual handwheel to vibrate off its shaft.
RG&E initiated Work Request/Trouble Report 19501434 to replace the handwheel, but did not investigate the high vibration at that time.
After the valve failure on April 30, 1995, maintenance and engineering personnel disassembled the valve to investigate the cause of the problem.
The valve internals exhibited damage on the stem and plug, and the stem and motor had to be replaced.
Some of the actuator internal components were examined and appeared to be free of damage.
However, the close torque switch set screw was loose and the close torque setpoint had drifted to its maximum value.
RG&E concluded that the high vibration caused the close torque switch setting to loosen the set screw.
No limiter plate was installed on the torque switch and the thermal overload relay contactor was stuck in place.
The thermal overload relay was also replaced.
Testing NOV-4007 is part of the licensee's generic letter (GL) 89-10, "Safety-Related Notor Operated Valve Testing and Surveillance,"
program and was set up to overcome the "A" pump's full design-basis discharge pressure of 1495 psid with minimum pressure in the steam generator.
Prior to the valve failure to open, the actuator was overtorqued to 157 percent of its rating (250 ft-lbs)
when the valve was last closed.
NOV-4007 is classified as a high risk-significant valve, and overtorquing could potentially cause another failure without corrective actions, such as an actuator inspection and evaluation.
However, the valve was repaired, and static testing revealed no cyclic loading in the actuator.
RG&E's policies toward the use of torque switch limiter plates are established in engineering work request (EWR)-5111 and require that limiter plates be installed on all GL 89-10 NOV torque switches to prevent potential overtot quing.
The licensee indicated that several other NOVs in the GL 89-10 program also do not have limiter plates installed.
To date, RG&E has not formally determined why the limiter plate was not installed on NOV-4007, nor identified the missing limite} plate as a root cause of the failure.
The root cause analysis (95-051)
was not complete before the end of this inspection.
Pending completion of the root cause analysis and further NRC review of RG&E's corrective actions, this item is unresolved (URI 50-244/95-08-01).
NOV-4007 currently has a
6 year preventative maintenance (PN) interval.
The inspector considered that 6 years may be too long between checks of the torque switch setting since the valve is susceptible to high vibration.
Cognizant RG&E engineering personnel stated they would review the maintenance interval for this valve, and would also place the thermal overload heaters and relays into a PN program for periodic setpoint testing.
The inspector considered these actions to be prudent.
Within the GL 89-10 program, the design-basis capability of NOV-4008 (AFW pump B discharge valve)
was established by "grouping" with NOV-4007.
The torque switch setting on NOV-4007 was lowered during the last static test, and the effect on NOV-4008 by changing the setup on NOV-4007 had not been examined or documented by the licensee.
The licensee indicated that grouping of valves 4007 and 4008 for 89-10 will be addressed in a larger context with other GL 89-10 program valves and will be formalized prior to program closure.
RG3E also stated that they will dynamically test NOV-4008 during the next refueling outage.
3.0 ENGINEERING (71707, 37551)
3.1 Incomplete Melding of Steam Generator Tube Sleeves Steam generator (SG) U-tubes are routinely inspected during refueling outages for indications of defects.
Such defects can occur due to a variety of chemical corrosion mechanisms, as well as due to mechanical wear.
Annual eddy current inspection provides indication of developing defects, such that the affected U-tube can be repaired (by welding a concentric sleeve inside the portion of the U-tube where the defect exists) or removed from service (by plugging the U-tube inlet and outlet) before it develops into a through-wall condition (that is, a reactor coolant system leak into the secondary side of the SG).
During the 1995 outage, approximately 750 previously repaired (sleeved)
SG U-tubes were inspected.
Recent advances in technology have lowered the threshold of detectable indications and, as a result, eleven (one in the A-SG and 10 in the B-SG) previously undetected indications were identified in sleeve upper welds.
Fiber optics were used to visually examine these indications, and all but one were determined to be minor defects that were characteristic of the sleeve installation process.
The remaining defect, however, was determined to be an incomplete weld; specifically, a single spot weld was found, rather than the expected 360-degree circumferential weld.
This condition was of concern, because it should have been identified during
. the acceptance inspections following sleeve installation in 1990.
Subsequent investigation by the licensee determined the cause to be a
combination of I) difficulties associated with a specific type of sleeve installation, and 2) incorrect interpretation of acceptance inspection data by a single, relatively inexperienced inspector.
In response, the licensee expanded the inspection to include all previously sleeved SG tubes that satisfied these two criteria.,
One additional sleeve was identified as having an incomplete weld, and six sleeves were evaluated as having questionable weld fusion.
All eight affected SG tubes were subsequently removed from service by plugging.
The problem of incomplete welds in previously installed SG U-tube sleeves was examined in depth by an NRC specialist inspector.
Results of this inspection are presented in inspection report 50-244/95-11.
3.2 B-Safety Injection Pump Recirculation Meld Failure On April 28, 1995, while technicians were conducting a routine cleaning of the B-safety injection (SI)
pump casing/piping, water was observed to be seeping (approximately one drop every six seconds)
from a pipe-to-valve (891C) weld on the recirculation line.
Upon informing management and the control room, operators declared the B-SI pump inoperable and entered into a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condition for Operation (LCO), pursuant to Technical Specification
ll 3.3. 1.4.
Following the identification, Naterial Engineering and Inspection Services (LEIS) and site maintenance personnel performed the following:
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Surface examinations using liquid penetrant were made of 13 welds in near proximity to the failed weld.
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The leaking weld was excavated and tested with liquid penetrant to verify the total removal of the defect.
The crack was found to be 1/8 inch long.
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After the weld repair, liquid penetrant tests revealed no additional indications.
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Being an ASIDE Section XI, Class 2 system, a hydrostatic test at 2000 psig and VT-2 visual examination were performed on the affected piping.
Test results were acceptable.
After the hydrostatic test, additional dye penetrant tests were performed on other welds (approximately 65) in the recirculation piping to the A-and C-SI pumps.
The results were acceptable.
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LEIS is conducting a metallurgical evaluation to determine the failure mechanism.
In parallel with these activities, system engineering is performing a
Root Cause Analysis to establish causes for the weld failure.
Upon being informed of the weld failure, the inspector observed weepage from the failed weld and followed the response of the licensee to the deficient condition.
Additionally, the inspector conducted a walkdown of accessible portions of the safety injection system to verify operability of the remaining two pumps.
The inspector observed that prompt actions were taken by cognizant technicians, control room operators, and management to assure that the plant was maintained in a safe configuration, that the scope of potential failure was characterized, and repairs were appropriately carried out.
guality Control personnel appropriately conducted weld examinations and hydrostatic testing.
Subsequent to weld testing, a post-maintenance test (PT-2. 1N) was successfully performed on the B-SI-pump, returning it to service in approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, thereby removing LCO constraints.
4.0 PLANT SUPPORT (71750)
4.1 Radiological Controls 4. 1. 1 Routine Observations The inspectors periodically confirmed that radiation work permits were effectively implemented, dosimetry was correctly worn in controlled areas and dosimeter readings were accurately recorded, access to high radiation areas was adequately controlled, survey information was kept current, and postings and labeling were in compliance with regulatory requirements.
Through observations of ongoing activities and discussions with plant personnel, the inspectors concluded that the licensee's radiological controls were effectiv. 1.2 Local Radiation Emergency On April 2, 1995, a radiation protection technician informed the control room that floor drains in the auxiliary building were backing up and overflowing onto the floor on the intermediate and lower levels.
Surface smears of the affected areas were taken and found to be slightly contaminated (approximately 1100 disintegrations per minute).
All area radiation monitors were indicating normal and local. air samples taken by radiation protection technicians also read normal.
Since the cause of the backup was not immediately apparent and contamination could potentially be spread from drain piping, the Shift Super visor, with Health Physics Management concurrence, declared a Local Radiation Emergency.
Site management was promptly notified and additional radiation protection technicians were called in to assist with remediation measures.
All access points to these areas were restricted, with ropes, warning signs, and step-off pads installed.
Subsequently, it was determined that the source of the problem was an ongoing resin liner dewatering task.
The task involved removing water from a fresh resin liner, that was being prepared for use in the liquid radwaste system.
Water removed was directed through a piping system to the waste hold-up tank in the basement of the auxiliary building.
A filter in the resin liner (designed to prevent resin loss during dewatering)
had failed, resulting in fresh resin flowing to the inlet of the WHT.
The resin clogged the loop seal to the WHT, causing water to back-up through the floor drains.
Actions were taken to expeditiously clear the blockage.
On April 5, 1995, PORC reviewed the plant incident report addressing this incident.
Through interviews with cognizant technicians, the cause was attributed to a failed screen filter installed in the resin liner.
Failure of this filter permitted resin to be transferred to the WHT piping system, clogging the inlet.
PORC directed that procedures be revised to assure that the liner filters are changed annually to assure effectiveness.
The inspector examined plant areas affected by the overflow.
No electrical equipment was wetted.
Air sampling results and contamination survey data did not exceed licensee administrative control levels.
An appropriate level of site management was present to provide oversight for the clean-up operations.
Appropriate radiological controls were in place to mitigate contamination spread; pipefitters used appropriate techniques to unclog the blockage without exacerbating plant conditions.
Shift management acted conservatively and prudently to promptly rectify the clogged line and drain overflow.
PORC took proper action to preclude repetitive failures.
4.1.3 Outage ALARA Review During the 1995 outage, significant improvements were noted in reducing collective radiation exposure and personnel contaminations from those of past outages.
For the current outage, the total dosage was 118 person-rem, compared with 124 person-rem and 155 person-rem for the 1994 and 1993 outages, respectively.
Personnel contaminations remained low with 73 cases, with no internal uptakes nor hot particle contaminations experienced.
The inspectors concluded that these improvements have resulted from a strong management
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commitment to reducing personnel exposures through creating a Station Outage Reduction Committee, establishing a challenging 125 person-rem goal, and further integrating engineering support to resolve ALARA issues.
Several in-containment modifications were completed to reduce general area and transit dose, including installing permanent shielding on the pressurizer spray line and the regenerative heat exchanger.
The inspectors determined that routine radiological controls were aggressively implemented and updates were provided at daily planning meetings regarding ALARA performance and potential problem areas.
Throughout the outage, the inspectors observed good adherence to Radiation Work Permits, detailed pre-job briefings, effective use of the surrogate tour system, good housekeeping practices, and prompt identification of changing radiological conditions with timely implementation of mitigating controls.
4.2 Security.
4.2.1 Routine Observations During this inspection period, the inspectors verified that x-ray machines and metal and explosive detectors were operable, protected area and vital area barriers were well maintained, personnel were properly badged for unescorted or escorted access, and compensatory measures were implemented when necessary.
No unacceptable conditions were identified.
4.3 Fire Protection 4.3. 1 Routine Observations The inspectors periodically verified the adequacy of combustible material controls and storage in safety-related areas of the plant, monitored transient fire loads, verified the operability of fire detection and suppression systems, assessed the condition of fire barriers, verified the stationing of fire watches, and verified the adequacy of required compensatory measures.
No discrepancies were noted.
5.0 SAFETY ASSESSMENT/gVALITY VERIFICATION (71707)
5.1 Periodic Reports Periodic reports submitted by the licensee pursuant to Technical Specification 6.9. 1 were reviewed.
Inspectors verified that the reports contained information required by the NRC, that test results and/or supporting information were consistent with design predictions and performance specifications, and that reported information was accurate.
The following reports were reviewed:
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monthly Operating Reports for Narch and April 1995 No unacceptable conditions were identifie.2 Licensee Event Report A Licensee Event Report (LER) submitted to the NRC was reviewed to determine whether details were clearly reported, causes were properly identified, and corrective actions were appropriate.
The inspectors also assessed whether potential safety consequences were properly evaluated, generic implications were indicated, events warranted additional follow-up, and applicable requirements of 10 CFR 50.73 were met.
The following LER was reviewed ( Note: date indicated is event date):
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95-002, Loss of Individual Rod Position Indication, Due to Elect ical Short Circuit (February 12, 1995).
The inspector concluded the LER met regulatory requirements and appropriately evaluated the safety significance.
6.0 ADNINISTRATIVE 6. 1 Backshift and Deep Backshift Inspection During this inspection period, deep backshift inspections were conducted on Narch 18, 26, April 1, 2, 8, 9, 23, 29, and 30, 1995.
Q 6.2 Exit Neetings
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At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of inspections.
The exit meeting for inspection report 50-244/95-06 (NOV test program, conducted Narch 27, 1995 - April 7, 1995 and April 17-21, 1995)
was held by Hr,. Leonard Prividy on April 24, 1995.
The exit meeting for inspection report 50-244/95-09 (Health physics, conducted April 3-7, 1995)
was held by Hr. James Noggle on April 7, 1995.
The exit meeting for the current resident inspection report (50-244/95-08)
was held on Nay 16, 199 ~,
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