IR 05000382/1990001
| ML20012A801 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 02/20/1990 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20012A796 | List: |
| References | |
| 50-382-90-01, 50-382-90-1, NUDOCS 9003120596 | |
| Download: ML20012A801 (17) | |
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. APPENDIX B'
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P-U.S.: NUCLEAR REGULATORY COMMISSION '
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REGION IV
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t NRC: Inspection Report:
50-382/90-01 Operating License:
NPF-38 Docketi 50-382'
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k Licensee:
Louisiana Power & Light Company (LP&L)
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317 Baronne Street
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P New Orleans,' Louisiana 70160
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_ Facility Name: Waterford Steam Electric, Station,- Unit 3 (Waterford 3)
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Inspection At:
Taft, Louisiana'
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Inspection Conducted:
January 1-31, 1990 J
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' Inspectors:
W. F. Smith, Senior Resident Inspector i
Project Section A, Division of Reactor Projects n
S. D. Butler, Resident Inspector Project Section A, Division.of Reactor Projects
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R. C. Haag, Backup Resident Inspector
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Project Section A, Division of Reactor Projects 2-20- N
/ Approved:
w D. D.UChamberlain, Chief, Project Section A Date InspecticF Summary-
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Inspection Conducted January 1-31, 1990 (Report 50-382/90-01)
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 10 CFR report followup.
Resultsi One violation was identified (paragraph 3.b) involving failure of the licensee to. assure that operator license conditions were met for licensed operators on duty.
Based on a sampling of operator qualification records, at least 10 operators failed to meet the license condition that they have biennial
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medical ~ examination', while assigned duties as operators / senior operators.
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Failure to adequately track such licensee conditions demonstrated a weakness
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.that the licensee has initiated steps to correct.
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The licensee demonstrated strengths in the planning and execution of the p,
January 1990 outage. A conservative approach to safety was taken to shut down
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- and'make needed repairs before-any of-the problems caused a forced ~ shutdown.
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9' -.The plant:was successfully shut down, cooled; repaired..and started up without-l
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incident.. The NRC was kept well' informed of the licensee's progress: during L.-i this unsc,heduled outage.
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DETAILS L-1.
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 i
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-
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R. F. Burski, Manager of Nuclear Safety and Regulatory Affairs.
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R. S. Starkey, Operations Superintendent i
- T. H. Smith, Plant Engineering Superintendent.
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- J. J. Zabritski, Operations QA Manager
- f. J. Gaudet, Site Licensing Support Engineer
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- Present at exit interview.
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In addition to the above personnel, the inspectors held discussions with
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various operations, engineering, technical support, maintenance, and administrative members of the licensee's staff.
l 2.
Plant Status (71707)
At the beginning of this inspection period, the plant was operating at L
full power and remained at full power until January 22, 1990. At about l
11:30 p.m., a normal plant shutdown was initiated to investigate
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l abnonnally high unidentified reactor coolant system leakage and the
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failure of two control element drive motor (CEDM) cooling fan motors.
See paragraph 3 below for details. As of the' end of the inspection period, the plant was in cold shutdown (Mode 5) with-preparations underway to i
pressurize and begin heating up the plant for a startup.
i 3.
Onsite Followup of Events (93702)
a.
Unscheduled Shutdown for Repairs On December 28, 1989, RCS unidentified leak rate exceeded normal values of 0.6 to 0.8 gallons per minute (gpm) but-had not yet reached the TS limit of 1.0 gpm. The licensee investigated and found the hinge caps on Check Valve SI-512B leaking inside containment. The caps were tightened and on December 30, 1989, the unidentified leak rate was back to normal. On January 2, 1990, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> later, the 1*
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leak rate had ihcreased again.- The licensee searched for leaks inside and outside containment and found two pressurizer surge line:
sample valves (PSL-206 and -2061) leaking by their seats. The licensee also found leakage out of Valves CYC-101 and -103 packing leakoff drains. A station modification was considered to eliminate'
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the drains as.was previously done on other similar valves. This could not be accomplished without high radiological exposures, so the
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modification was placed on the outage repair list.
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The licensee also noted small leaks at the reactor head from what
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appeared to be movable incore instrument (ICI) distribution box drain tubing. The inspectors questioned how the licensee determined that t
thet this leakage was not reactor coolant system (RCS) pressure boundary leakage, since the source of leakage could not be seen. -It s
was explained to the inspector's satisfaction that movable ICI tubes-l were the only credible source of leakage at that location, and that l
the ICI tubes-would not fail catastrophically. The orifice size of a completely failed ICI tube, being smaller than RCS instrument i.-
penetration orifices, would be well within charging pump makeup capability. The licensee committed to investigate the leak and verify no boric acid deposits on carbon steel parts of the reactor L
vessel head during the next outage.
Since December 1989, the stator winding temperature for Reactor CoolantPumps(RCPs)1 Band 2Ahadbeentrendingupward. Analysis of available parameters seemed to indicate a possibility that there might be a cooling air obstruction or cooling coil fouling. Since
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the temperatures had not increased to the point where the pumps l'
.should be secured, and the trend seemed to be leveling off, the licensee decided to investigate during the next outage.
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The licensee had been planning for a short outage in February 1990 to i
reconnect Unit Auxiliary Transformer (UAT) B after repairs. The
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failure of UAT B was-discussed in NRC Inspection Report 50-382/89-38.
However, on January 20, 1990, control element drive motor (CEDM)
Cooling Fan D tripped on overload and, when Fan B was energized, a ground-appeared on the safety bus. Fan B was then turned off, and the ground disappeared.
Fan C was turned on to provide cooling with Fan A running. As a result, the )lant was left with two of four
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fans, both powered from the same aus. Although these fans were not safety-related, the licensee stated that two fans were needed for adequate cooling for the CEDMs, and both being powered from the same bus was not a good condition.
In light of the above CEDM cooling fan problem, coupled with RCS leakage problems and high stator winding temperatures in RCPs 1B and 2A, the licensee proceeded to develop an outage plan.
On January 22,1990, at 11:30 p.m., a plant shutdown was initiated, and by 1:41 a.m. on January 23, 1990, the plant was in hot standby (Mode 3).
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-5-i nI While perfoming a mactor containment building inspection with the L
licensee after the plant was shut down, the inspectors noted a L
significant amount of boric acid deposits on the upper area of.RCP IB l seal assembly. A small amount of leakage had been observed from the
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seal during the startup from the recent refueling outage and again in December 1989 when the unit was shut down for feedwater regulating
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. valve repairs. The licensee's decision to continue operations with
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_these leaks was-based on the small amount of leakage and only a small amount of boric acid deposits visible.
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The leak on the RCP IB seal was caused by the upper o-ring not-being properly positioned. The licensee stated that leakage by the upper
0-ring is not unusual after reinstallation of a seal assembly. The
0-ring groove is so large that the o-ring does not always seat.until
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pressurized;- however, past experiences indicated that the leakage stops as RCS pressure is increased.
In the case of RCP IB, the o-ring'did not fully seat after being pressurized, thus leaving a
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path for RCS leakage. To improve the o-ring seating _ process, two new
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o-rings were installed in the upper portion of' the seal' assembly.
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addition, the licensee verified that the o-rings were being properly
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compressed during installation. No leakage was observed from the o-ringiseal during the subsequent plant startup. :The licensee is reviewing a-possible design change for the seal assembly with the
' vendor to further improve =the 0-ring sealing characteristics.
On January 26, 1990, when closing Containment Isolation Valves-rVC-103 and--109 in the letdown-portion of the Chemical and Volume Lontrol System, abnormal conditions were identified. CVC-103
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appeared slow to close while CVC-109 indicated midposition after it was closed. This was the first time the valves had been stroked since the plant was shut down on January 23, 1990.
Deposits of boric acid on the bonnet and stem area from packing leakage were observed on CVC-103. The boric acid was removed when the valve was disassembled for installation of a new style packing arrangement.
The buildup of boric acid on the stem and packing area may have contributed to the initial slow closure time of the valve. During subsequent testing, CVC-103 did not-have a problem and stroked satisfactorily.
CVC-109 continued to indicate an intermediate position in.the control room. Adjustment of the close limit switch on CVC-109 corrected the control room position indication. Based on the subsequent satisfactory stroking of the valve and the installation of new packing, the licensee did not consider that any additional action was necessary. CVC-101 and -103 both were modified-to eliminate the packing leak-off piping connections. These valves, and other valves of similar construction, have been a source of reactor coolant leakage in the past. This modification has been successful in reducing leakage by utilizing the entire packing gland in lieu of a gland leakoff with a lantern ring near the center of the packing gland.
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Other sources of'RCS. leakage were also corrected during this outage.
RC-303B, a' check ' valve in the pressurizer spray line had a leaking-1
- It was replaced. Movable incore nuclear hinge pin cap gasket.
. instruments were leaking on and around the reactor head. This was'
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corrected by capping off all of the connections. -The licensee
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' intends to remove the entire distribution assembly during the next
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refueling outage. These are no longer used. The problem with-
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4 elevated temperatures in RCP 18 and 2A stator windings was found to e
L be fouling of the stator cooling heat exchangers with boric acid.
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K flakes and dirt. They were cleaned and,~after starting up the plant
L on February 5,1990, the stators operated at normal temperatures'.-
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During the outage the licensee discovered a winding failure in
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CEDM Fan D motor, and thus replaced the motor. The licensee has
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L initiated a root cause analysis for the failure. The inspectors will
I follow up on the results. CEDM Fan B had a ground in the pothead
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leads, which was corrected. The licensee indicated that the failures
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might have been attributed to vibration.- The licensee is evaluating-possible foundation design changes and, in the meantime, implemented administrative controls to run Fans A and C full time, with Fans B
and D as backup fans only.
By the tine all outage repairs were made, VAT B was repaired and reconnected to its respective load centers and to the isophase bus coming.from the generator.
Subsequent to plant startup on February 5,1990, RCS unidentified leakage was steady at about 0.5 gpm. The licensee's decision to shut down and repair the above problems before any of them deteriorated to cause a forced shutdown was considered by the inspectors as a safe and conservative approach and as such is a strength.
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the licensee kept the inspectors and Region IV management well
infonned of outage activities, problems, and solutions which is indicative of efforts to improve consnunications with the NRC.
b.
Failure to Meet a License Condition for Operators on Shift On January 4,1990, the licensee informed the inspectors that 12 licensed operators had not received their' biennial physical
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examination within the 2 years required by 10 CFR 55.53(1).
" Conditions of Licenses." 'Five of the operators stood watches in the control room at various tines after their physical examination-deadlines had elapsed. This problem was found by the licensee after Region IV staff had notified the licensee that a special report of medical information on two licensed operator' was overdue. This report was a license condition under 10 CFR d5.53(j); however, these two operators were not assigned control room shif t duties while the
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report was' delinquent. The licensee informed the inspectors that physical examinations would be completed as required before any operators went back on watch. On January 17, 1990, the inspectors reviewed 19 licensed operator / senior operator records, including
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those identified by the licensee as-delinquent, to verify completion of the' required physical examinations. The inspectors-found that all of the operators on the watch bill were current except for one shif t supervisor initially identified by the licensee on January.4,1990.
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That particular shift supervisor was on watch during this review.
Licensee management was notified and the shift supervisor was relieved. The licensee had failed to inform him that his physical
was overdue before he reported for duty. Another five operators were identified by the inspector as having stood watches over the past.
2. years while their physicals were expired.
One stood as few as j
15 duty days, and another stood 136 days.
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The above deficiencies were discussed with the licensee, who was taking corrective actions which included a 100 percent QA audit of licensed operator / senior operator records, implementation of a
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computerized recall system, and implementing annual physicals. The licensee initiated a Quality Notice to initiate corrective actions.
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On November 30, 1989, there was a meeting in NRC Region IV to discuss, among other things, problems related to licensed operators assuming watches when they were not qualified to do so. Specifically, going beyond the 2-year medical period was discussed.
LP&L training supervision attended the meeting. One was a licensed operator who was already 2 weeks delinquent on his special medical report.
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Despite these discussions, action was not taken to verify that i
licensed operators at LP&L were current until the NRC contacted LP&L
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to-inquire about the delinquent special medical reports on the two operators.
Failure of the licensee to ensure that operators on duty
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meet all individual operator license conditions is a violation of NRC
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regulations (382/9001-01),
c.
High Pressure Safety Injection (HPSI) Pump B
On January 15,1990, during routine quarterly inservice testing as R
required by the ASME Boiler and Pressure Vessel Code Section XI, HPSI Pump B recirculation flow through the fixed orifice was 0.3 gpm over the required action high value of 28.4 gpm established by the l
licensee's procedure. The licensee declared the pump inoperable and
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entered the appropriate 72-hour action statement under TS 3.5.2.a.
The licensee then commenced an investigation to determine the cause of the variance.
In March 1989, there was an NRC inspection conducted on surveillance
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testing and maintenance of HPSI Pump B.
The inspection report
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addressed anomalies associated with recirculation flow, but that was a reduced flow condition that has since been resolved (see NRC-
. Inspection Report 50-382/89-09 dated April 6,1989). As part of the corrective action taken in response to that inspection, the licensee
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assigned acceptance criteria consistent with Table IWP-3100-2 of the ASME Code.
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=The-licensee checked the calibration of the flow instrument.
- evaluated vibration data, radiographed the flow orifice, verified-that the flow instrument (a Barton differential pressure gauge calibratedingpm)wasnotmisread,checkedmotor-to-pumpaligament, reviewed current and historical pump inservice testing data, and found only one-possible cause for the slight increase in flow.
The flow orifice is a multistage device which may have inherent instabilities, because it depends on flow direction changes as well
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as orifice pressure drops to reduce flow. Since the internal orifices are offset and the plates are not locked in place, one may j
have moved sightly to cause a slight change in flow characteristics.
The licensee then throttled recirculation f1'ow down to the reference j
value of 27.6 gpm as required by Article IWP-3100. All parameters were well within the acceptable range.. The pump was then declared a
operable. A written engineering evaluation was published and reviewed by the inspectors. The actions.taken by the licensee were
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prompt and appropriate to the circumstances; however, this experience-added some insights into_how the pump.could be tested and comply with the ASME Code. The licensee committed to revise the surveillance test procedure to allow throttling of the recirculation flow to the
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reference value, as'the code describes, until other methods of testing are developed.
For the long term, the licensee is evaluating the, appropriateness of existing instrument accuracies, the adequacy I
of vibration data taken during inservice testing, and the
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i possibilities of testing pumps at higher, more stable flows in lieu'
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of recirculation miniflow.. The licensee's estimated completion date for these actions is June 30, 1990. The inspectors will continue to
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monitor progress in this area.
d.
Failure to Conduct Visual Inspections (VT-3)
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l On January 10, 1990, during closure review of the snubber reduction
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program design change documentation, the licensee identified four
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pipe supports on the shutdown cooling return line for RCS Loop 2,-
which had not had a quality control visual inspection (VT-3) in
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accordance with ASME Code Section XI requirements. This inspection was required by the licensee's procedure as the final retest to assure the structural integrity of the system, The licensee entered Nuclear Operations Procedure N0P-019, "Nonconformance/ Indeterminate Qualification Process," which precipitated an engineering evaluation to assist the contal room staff in making-an operability determination. This evaluation concluded that adequate documentation-existed to show that the work was done as intended, and that torque values were properly applied and inspected. Containment closure surveillance video tapes taken by Health Physics also had footage showing each of the supports in place. One of the supports was L
accessible while at power, so the VT-3 was performed with satisfactory results. The remaining three supports were declared operable with planned action to perform the 'VT-3 during the next outage, which was planned for late February 1990; however, it was completed
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1990. The licensee initiated a potentially satisfactorily in January (No.90-002) on January reportable event report 10, 1990, to initiate corrective action as to cause and to evaluate reportability pursuant-to 10 CFR 50.73. The adequacy of the licensee's root cause determination and corrective actions taken will require review during
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a future inspection and be tracked as inspector followup
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item (IFI) 382/9001-02.
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Monthly Maintenance 0bservation (62703)
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The station maintenance activities'affecting safety-related systems and-components below listed were observed and documentation reviewed to ascertain that the activities were conducted in accordance with approved procedures, TS, and appropriate industry codes or standards.
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On' January 10 and 11,1990, the inspector observed work in progress on Essential Chiller A.
The chilled water unit was out of service for preventive and corrective maintenance. The unit was properly L
isolated and drained for the work to be perfomed and was replaced -
I with Essential Chiller A/B to comply with the TS requirement for two l
independent essential chilled water units. The inspector reviewed the following work authorizations (WAs) for work in progress:
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h WA 01051130, " Alignment and Lubrication of Chilled Water Pump
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Motor A"-
WA 01050548, " Replacement of Compressor Oil and Oil Filters"
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WA 01006036, " Replacement of Condenser Sight Glass"
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ic WA 01048337, " Cleaning of Condenser Tubes"
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i WA 01051135 " Inspection of Economizer Damper Floats"
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WA 01049733, " Repacking of Chilled Water Pump"
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The WAs were properly prepared and were approved for performance by-the shift supervisor. They were adequate for the tasks being performed. The workers demonstrated familiarity with the work to be done and several workers with less experience working on the chilled water units were obtaining on-the-job training. Selected replacement parts were observed to be as called for in the appropriate WA.
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Measuring and test equipment was properly calibrated.
The inspector noted that the work being done required climbing over and standing on various parts of the chiller unit with significant potential for damage to lagging, components, wiring, and instrumentation. No measures were being taken to protect the unit from damage during maintenance. This observation was discussed with licensee management.
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During the inspection of the economizer damper floats, it was noted
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that a baffle on one of the damper float balls was becoming detached.
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J from the ball. The baffle was attached to.the ball with epoxy glue.
On previous designs the baffle was welded to'the ball, but this caused stress corrosion cr&cking of the ball in the heat affected zone of the weld.. 'The design was changed by the vendor to use epoxy
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glue. The licensee. contacted the chiller unit-vendor, and they stated that loss of the baffle would not adversely affect the
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operation of the damper' float. The licensee planned to inspect the-other units during upcoming maintenance outages.
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WA 01048192. On January 23, 1990, the inspector reviewed work in-
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progress on the control element drive mechanism control
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system _(CEDMCS). A power supply was being replaced and' calibrated in j
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accordance with Maintenance Procedure MI-5-473, "CEDMCS Calibration."
l The work package was reviewed and found to be properly prepared and J
approved for performance. The work package was adequate for the work in progress and was being followed by the workers involved. No
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problems were identified.
c.
On January 30, 1990, the inspector observed the postmaintenance run of Emergency Diesel Generator (EDG) A per Operating Procedure OP-009-002, Revision 10. " Emergency Diesel Generator." 'On
' January 28, 1990, when testing the manual start synchroniration circuit, the EDG tripped after 10 seconds on low turbocharger lube
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oil pressure. -Investigation by the licensee revealed that the inbe-oil in the pressure sensing unit had deteriorated and may have caused a sluggish response. The pressure sensing unit was cleaned and bench tested. After reinstallation of the sensing unit, the EDG operated satisfactorily. A review by the licensee determined that no other pressure sensing units on the EDGs had similar installation p
characteristics as the.turbocharge lube oil pressure sensing unit.
- Upon inspection the sensing unit on EDG B did not reveal deteriorated
In addition, the lice'nsee noted that, if the EDG had been
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called upon to start due to an undervoltage signal or a safety injection signal, the: low turbocharger lube oil pressure trip would have been bypassed. Thus the EDG would have 3erformed its
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intended safety function. The licensee indicated tlat this would be reported to the NRC as a nonvalid failure in accordance with
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L TS 4.8.1.1.3.
d.
WA 01053531. On January 31, 1990, the inspector observed the-adjustment of the trip collar on Main Steam Isolation Valve (MSIV) B.
This collar is attached to the valve stem and actuates trip arms and
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limit switches during valve movement. During an earlier surveillance test, the valve would not indicate fully open. Troubleshooting
identified that the trip collar had moved down on the stem approximately 11/4 inches, which prevented actuation of the upper limit switch when the valve was open.
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a The inspector reviewed Technical Manual (TN) 457000129, " Instruction
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Manual ~ MSIVs " which was invoked by the WA for adjustment of the trip collar. The electricians were using Addendum A of the TM which provided installation instructions fer the updated MSIV limit switch
assembly. A general statenent in the addendum stated that all bolts t
and nuts should be torqued to.the recommended values given in the-
MSIV manual. -While a specific value was-not given in the MSIV manual
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for the trip collar fasteners, a " Torque Table" in the manual did
provide a torque.of 60 foot-pounds for 1/2-inch fasteners.
l The inspector questioned the licensee as to why the-fasteners were not torqued to a specific value after adjustnent of the trip collar.
The design of the trip collar appeared to rely on the preload of the fasteners to maintain the split collar arrangement at the. correct.
position on the stem.
The proper torquing of the fasteners appeared to be an important step in the installation of the trip collar to prevent future slippage.
The licensee's maintenance engineers took
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the position that the application of specific torque values was not a a
requirement in this case but, rather, was a reconsnendation that they did not consider necessary. The~ licensee stated that this was the.
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first time the collar had slipped and, when readjusting, the i
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mechanics made sure the fasteners were tight. The inspector questioned this approach and licensee management stated that they would contact the vendor for guidance on the collar. installation.
The-inspectors will monitor licensee actions on this matter during
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future-inspections, j-No violations or deviations were identified.
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5..
Monthly Surveillance Observation (61726)
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'The 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 TS. The applicable-procedures were
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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.
a.
Procedure OP-903-102, Revision 4, " Safety Channel Nuclear Instrumentation Functional Test Safety Channel D."
On January 21, 1990, the inspector observed the performance of the logarithmic j
channel test, rate test, and linear safety channel test of excore nuclear instrument (NI) Channel D, while the plant was at full power.
The test was conducted satisfactorily with results within the acceptance criteria; however, the inspector discussed the following minor procedural discrepancies with the licensee:
(1) Step 4.16, under " Precautions and Limitations," stated "In order l
to minimize the effects of temperature drift, this procedure j
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should be perfonned with the safety channel drawer closed."
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This was not practical during the subchannel gain verification when making test noter corinections, thus the operator could not I
comply. The step should be clarified.
j (2) Step 8.2.3.1 directed the operator to energize the test power
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supply located in safety Channel A.
At the end of the i
procedure, restoration Step 8.5.1.7 turned it off, imply 49 to i
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the operator that the test power supply should have be', an throughout the entire procedure. However, since the plant was at power, the procedure bypassed Step 8.2.3.1.
On his own
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initiative, the Operator turned the power supply on and then i
raised the question as to whether or not the power supply was
needed for the parts of the test to be done Nith the plant at
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power. The shift supervisor directed him to turn the power i'
supply back off and do the test as written.
Satisfactory results were obtained by conducting the procedure with the test
power supply off. The procedure should have contained a step at i
the end of the specific section requiring the power supply to be energized, instructing the operator to turn it off.
(3) Step 8.4.1.20 rwquired the operator to log the measuring and
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i test equipment (M&TE) number for the test meter in the M&TE trackinglog(01-013-000). The log and its implementing
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procedure had been deleted since December 13, 1989. The procedure should have stated where to log this data.
l (4) Step 8.2.1 used the word " verify" to place the appropriate
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reactor trips in the trip bypass state. The licensee's
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procedure writer's guide doesn't appear to use the word " verify" in this nenner but does state that clear and concise commands l
should be used. To the inspector " verify" implied that the operator should expect to see the trips already bypassed, but
they were not.
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OP-903-102 had not been human factored by the licensee's current procedures upgrade program, because the biennial review was not due
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until April 1990. The above observations were noted to bring to the
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attention of the licensee that the procedure needs some improvement.
- lione of the above noted deficiencies effected test results.
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The inspector reviewed the completed data package and found no problems.
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6..
Operational Safety Verification (71707)
The objectives of this inspection were to ensure that this facility was l
being operated safely and in conformance with regulatory requirements, to
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ensure that the licensee's mar,agement controls were effectively discharging the licensee's responsibilities for continued safe operatien, to assure that selected activities of the licensee's radiological protection programs are implemented in conformance with plant policies and f
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w-13-i procedures and in compliance with regulatory requirements, and to inspect the licensee's compliance with the approved physical security plan.
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The inspectors conducted control room observations and plant inspection tours and reviewed logs and licensee documentation of equipment problems.
l Through in plant observations and attendance of the licensee's plan-of-the-day meetings, the inspectors maintained cognizance over plant status and TS action statements in effect.
On January 23, 1990, during the outage, the inspector toured accessible areas of the containment building.
The inspector accompanied system
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engineers who were performing inspections to identify RCS leakage and I
boric acid accumulations that could affect critical components in the RCS.
General containment conditions appeared satisfactory for' power operations.
Minor boric acid accumulation was noted in several areas and documented by k
the engineers.
Significant leakage was noted from a check valve (RC-303)
on the pressurizer spray line and from the seal area of RCP 18.
There was minor leakage in the reactor head area.
These were discussed in detail in paragraph 3 above.
l No violations or deviations were identified.
7.
Followup of Previously Identified Items (92701, 92702)
a.
(0 pen) Violation 382/8813-03:
This violation was a failure to
identify and correct deficiencies involving equipment marking.
The inspector reviewed the licensee's response dated August 17, 1989, and
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corrective action which involved revisions to Procedures OP-100-004 and OP-100-013 used to identify and tag safety-related equipment.
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The licensee also established a comprehensive system.and component
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labeling program with the issuance of NOP-M2, Discussion with the system engineering supervisor indicated that sg!)m walkdowns by responsible system engineers to further identify labeling problems
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were not completed on December 31, 1989, as scheduled.. The licensee
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indicated that their schedule was revised to complete the walkdowns
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by February 15, 1990.
This violation will remain open until the inspector can verify that the system walkdowns are completed.
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b.
(Closed) Violation 382/8816-03, EA 88-144 (listed as EA 88.144.1 on the licensee's tracking system).
This violation involved failure on the part of the licensee to take adequate measures to preclude a repetition of the July 1986 loss of shutdown cooling event.
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The licensee's corrective action for this violation was primarily in response to closed Violation 382/8816-04, which is discussed below.
The net results of those actions were excellent with respect to the RCS inventory control.
During the Fall 1989 refueling outage, the licensee demonstrated continuous and precise control over RCS level, and, thus, did not have any shutdown cooling incidents.
The inspectors noted that operator training, procedure implementation, and administrative controls to prevent activities that might cause
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RCS level perturbations all contributed to the licensee's success in this area.
In addition, an inspection was conducted in May 1989 to
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follow up on the licensee's expeditious actions related to Generic i
Letter 88-17. The results indicated that the licensee was developing j
comprehensive procedures and controls related to shutdown cooling
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operations at reduced RCS inventory. See NRC Inspection
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Report 50-382/89-13 dated June 15, 1989. This violation is closed.
t c.
(Closed) Violation 382/8816-04, EA 88-144 (listed as EA 88.144.2 on the licensee's tracking system). This violation involved failure to -
follow Operating Procedure OP-1-003, " Reactor Coolant System Drain i
Down," which contributed to the near loss of shutdown cooling in May 1988, described above under closed Violation 382/8816-03. The
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licensee focused corrective actions for the May 1988 event on this
violation, with primary emphasis on correcting procedural violations
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and deficiencies. Specific actions to prevent a recurrence of the
May 1988 shutdown cooling incident were completed prior to the fall 1989 refueling outage. These included counseling of operations,
engineering, and plant management staff. Requalification training on i
shutdown cooling events and concerns was completed on January 30,
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1989. The licensee comitted to have an operator dedicated to monitoring the draindown process. The inspectors observed this
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practice during the fall 1989 rifueling outage. The draindown procedure was revised as comitted. Thestationmodification(SM)
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process was upgraded as committed.
There were two inspections during
1989 confiming the licensee's new SM program as being a strength.
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See NRC Inspection Reports 50-382/89-29 dated November 30, 1989, and
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50-382/89-37, dated December 18, 1989. As committed, the licensee
established a corrective action program task force and provided a
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supplemental response on January 31, 1989, which outlined the implementation schedule for corrective action program enhancements.
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In June 1989, an inspection was conducted in this area confirming implementation of the licensee's comitments.
See NRC Inspection
Report 50-382/89-18, dated July 17, 1989. This violation is closed.
i d.
(Closed) Violation 382/8901-05: This violation involved several examples of failure to follow equipment control procedures. The
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inspector reviewed the licensee's response dated May 22, 1989, and their corrective action.
Corrective action included changes to MD-1-014. " Conduct of Maintenance," and personnel counseling which was verified as completed. However, the violation of the licensee's danger-tagging procedure was repeated on August 23, 1989. This was subsequesntly identified as another violation which is discussed in paragraph 7.g below. This violation is closed, e.
(Closed) Violation 382/8901-06: This violation involved a failure to follow Maintenance Procedure ME-4-121, Revision 3 because certain steps were inappropriately marked "N/A" by the electricians. The inspector reviewed the licensee's response, dated May 22, 1989, and their corrective action. An engineering evaluation was performed to
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ensure that the deleted steps in the maintenance procedure did not i
affect the operability of the specific switchgear. The licensee
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revised their maintenance procedures for all electrical switchgear to i
make them consistent with regard to the deleting of steps that were
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not applicable to certain circumstances.
In addition, they i
instituted periodic training to ensure worker understanding of the i
change in procedural requirements for electrical switchgear
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maintenance. This violation is closed.
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(Closed) Violation 382/8901-09: This violation involved a failure to l
follow the plant lubrication manual. The inspector riviewed the licensee's response, dated May 22, 1989, and their corrective action.
i The valve operators suspected of containing mixed grease were cleaned and lubricated with the specified grease. The licensee's lubrication
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manual was revised to specify a single grease for motor operated i
valves to prevent confusion in the future. This violation is closed.
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g.
(Closed) Violation 382/8923-02 (EA 89-192): This violation resulted
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in an enforcement conference due to repeat examples of failure to i*
follow plant procedures for the control of danger-tagged equipment.
This enforcement conference did not result in escalated enforcement
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action. The inspector reviewed the licensee's response, dated December 20, 1989, and corrective action which included individual i
counseling with personnel, disciplinary action taken for the specific violation, procedural changes to emphasize the importance of not operating danger-tagged components, and increased emphasis in general
employee training on the requirements of not operating danger-tagged j
lf components. This violation is closed.
8.
Licensee Event Report (LER) Followup (92700,90712)
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p The following LERs were reviewed and closed. The inspectors verified that
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reporting requirements had been met, causes had been identified, I
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corrective actions appeared appropriate, generic applicability had been
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considered, and the LER forms were complete. The inspectors confirned
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that unreviewed safety questions and violations of TS, license conditions, l
or other regulatory requirements had been adequately described, j
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a.
(Closed)LER 382/85-013. " Automatic Actuation of RPS."
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b.
(Closed)LER 382/88-011, " Penetration Fire Seal Impaired Due to Error in Initial Construction." This LER was partially closed in NRC
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L Inspection Report 50-382/88-26, dated November 17, 1988. The remaining action to be reviewed for LER closure was a revision to the i
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i licensee's surveillance procedure to require that a fire impairnent be issued whenever a condition identification report is issued for a
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fire seal. The inspectors reviewed Change 1 to Procedure ME-3-006, Revision 3 " Fire Barrier Penetration Seals," and confirmed that the
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l appropriate change was implemented on August 1,1988, as committed in l
the LER. This LER is closed.
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c.
- (Closed) LER 382/89-010, Revision 1,." Technical Specification not Complied with due to Miscommunication."
d.
(Closed) LER 382/89-014, "ACC 116A and 116B not Included in In-Service Test Program due to Misinterpretation of Requirements."
This LER was previously inspected in NRC. Inspection
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Report 50-382/89-34.' After further discussion with the' licensee, it L
was determined that a supplemental LER was not necessary.
During this inspection period, the licensee received NRC approval of their ASME Code relief request to exclude these valves.
This LER is closed.
e.
(Closed) LER 382/89-017, Revision 1 " Reactor Trip due to Complications Associated with Control Element Assembly Malfunction."
This LER was previously inspected in NRC Inspection Report 50-382/89-34 and,-since then, the licensee submitted the
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necessary additional information in Revision 1.
This LER is closed, f.
(Closed) LER 382/89-018 " Failure to Declare Main Steam Safety Valve Indeterminate."
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(Closed) LER 382/89-019, " Loss of Voltage to a Safety Bus due to Personnel Error."
h.
(Closed) LER 382/89-020, " Containment Fan Cooler Assumed Operable.
. Without Adequate Surveillance Test."
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(Closed) LER 382/89-021r " Failure to Perform Off-site Power
' Verification Surveillance due to Personnel Error." ~
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(Closed) LER 382/89-022,:" Failure to Perform Diesel Generator Surveillance due to Technical Specification Misinterpretation."
No violations or deviations were identified.
9.
10 CFR 21 Report Followup (90712)
~The' objective of this inspection was to determine whether the licensee had received, evaluated, and taken appropriate and timely corrective action in response to selected 10 CFR 21 reports.
a.
(Closed) 10 CFR 21 report, dated January 18, 1989, from Cooper-Bessemer Reciprocating (Region IV Tracking No. 89-01).
This
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report discussed a failed E.0G rocker arm at the Palo Verde plant and
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the potential impact on Waterford 3, which also has Cooper-Bessemer EDGs.- The licensee received the report and implemented the corrective action recommended by Cooper-Bessemer, which was to inspect the rocker arms on the Waterford 3 EDGs for cracks.
In accordance with WA 01031501, EDG A was inspected on February 6, 1989, and EDG B was inspected on February 20, 1989.
No cracks were found.
This item is closed.
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b.
(Closed) Potential 10 CFR 21 Report, dated January 30, 1989, from the AutomaticSwitchCompany(ASCO)(RegionIVTrackingNo.89-02). The l
report informed the NRC that certain ASCO series NP solenoid valves
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delivered to a number of nuclear plants (including Waterford 3) may j
fail to function due to a problem with the solenoid return springs
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disengaging from the solenoid cores. The licensee received this
report and conducted an evaluation that determined for Waterford 3, that the issue is not reportable because all 10 valves bought under
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Order No. WP022807 by LPAL were still in the warehouse as spares. As
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recommended by ASCO, the licensee returned the 10 solenoid valves
(NP830A185E) on February 3,1989.
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c.
(Closed) Potential 10 CFR 21 Report, dated April 4,1989, from
Control Components, Incorporated (Region IV Tracking No. 89-04). The
report discussed concerns over potential failures of the steam
gensrator atmospheric dump valves (ADVs). At Palo Verde Unit 3, the
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ADVs failed to open when called upon. This was also discussed in NRC
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Information Notice 89-38, dated April 5,1989. Waterford 3 has ADVs manufactured by the same vendor but of slightly different dinensions.
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I The licensee received the 10 CFR 21 report and discussed the issue with Region IV management on April 12, 1989.
An evaluation was
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performed concluding that based on: the frequent operation of the
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ADVs at Waterford and the physical differences between the ADVs at
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Waterford 3 and Palo Verde the present condition of Waterford 3 ADVs was not a safety concern. This evaluation also provided for manual operation of the ADVs if needed.
In addition, the licensee stroked
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the ADVs on April 14, 1989, alerted the operators via LP&L t
Memo W3089-0032, and scheduled the vendor's reconmended modification to the ADVs for the Fall 1989 refueling outage. This was described
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in a letter to the Regional Administrator, W3P89-3011, dated
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April 13,1989.
In November 1989, during the third refueling outage, the inspectors observed implementation of SM 3215 on both ADVs and i
noted completion and acceptance testing accomplished on November 22
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1989. This item is closed.
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No violations or deviations were identified.
10.
Exit Interview
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The inspection scope and findings were sunmarized on February 8,1990, with those persons indicated in paragraph I above. The licensee acknowledged the ins 3ectors' findings. The licensee did not identify as proprietary any of tie material provided to, or reviewed by, the
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inspectors during this inspection.
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