IR 05000382/1989017
| ML20247L726 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 07/14/1989 |
| From: | Chamberlain D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20247L699 | List: |
| References | |
| 50-382-89-17, NUDOCS 8908010336 | |
| Preceding documents: |
|
| Download: ML20247L726 (14) | |
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Y" APPENDIX B
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S. NUCLEAR REGULATORY COMISSION
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REGION IV
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NRC Inspection'eport:.50-382/89 17 Operating License:
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. Docket:. 50-382
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Licensee: Louisiana Power & Light. company-(LP&L).
~317 Baronne' Street.
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New Orleans,. Louisiana 70160 j
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.aterfordSteamElectricStation,; Unit 3(Waterford-3)
l Facility Name:
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. Inspection At: Taft,- Louisiena
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Inspection Conducted:.' June,;1-30,1989
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W. F. Smith, Senior Resident Inspector.
' Inspectors:
Project Section A, Division of Reactor. Projects T. R. Stakerk ResidentLlnspector..
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Project Section A, Divis'on of Reactor Projects
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- Approved: h D. D. Chamberlain, Chief. Project Section A
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Date t. Division'of' Reactor. Projects Inspection Summary.
Inspection' Conducted-June 1-30, 1989 (Report 50-382/89-17)
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Areas Inspected: soutine, unannounced inspection of plant status', onsite-followup of events,-monthly maintenance observation, monthly surveillance observation, operational safety verification, followup of previously identified iter.s, licensee ' event report followup, and balance of plant inspection.<
m Results: Three. violations were identified. The first violation involved two; s
examples (paragraphs ~4.b.(1) and (2)) of failure to follow procedures. ~In the
,, first example, a section of the primary sampling, system was not properly tagged-to provide assurance that a vent path existed to facilitate breaching the
system and welding new' tubing upstream. The'one valve omitted was a normally
- open valve and was in the correct position.> In the second example, there was
--apparent disregard.for the cleanliness integrity of the primary sampling.
system.~. New replacement tubing was staged at the jobsite on the floor and left unattended with no protective covering over the openings, contrary to the
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licensee's cleanliness procedure requirements.
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The second violation involved three examples (paragraphs 6.a, 6.e, and 7.f) of failure to provide adequate operating procedures. Two of the examples resulted in improper operation of the emergency diesel generator (EDG) fuel oil duplex strainers and filters by placing them in a simplex mode, contrary to the instructions in the EDG vendor manual. This was of significant safety concern because, had the EDGs been called upon to operate in an emergency, a clogged filter or strainer would have caused the EDG to shut down instead of an operator simply' shifting strainers or filters to the clean side upon receiving a high differential pressure alarm.
In the third example, the' Component Cooling Water System design configuration was changed (though improperly so)
but the operating procedure was not revised to reflect the change. This demonstrated a breakdown in the design drawing change process at Waterford-3.
The third violation (paragraph 7.f) involved another breakdown in the design drawing change process mentioned above. A change was implemented without first being reviewed by the Plant 0perations Review Committee (PORC). As it turned out, the change was inappropriate and degraded the design configuration of the Component Cooling Water System, because a non-nuclear safety portion of the system was left with an open path to the safety-related portion.
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DETAILS 1.
' Persons Contacted Principal Licensee Employees
- R. P. Barkhurst, Vice President, Nuclear Operations
- J. R. McGaha, Plant Manager, Nuclear P. V. Prssankumar, Assistant Plant Manager, Technical Support D. F. Packer, Assistant Plant Manager, Operations and Maintenance-J. J. Zabritski, Quality Assurance Manager D. E. Baker, Manager of Nuclear Operations Support and Assessments
- R. G. Azzarello, Manager of Nuclear Operations Engineering W. T. Labonte, Radiation Protection Superintendent
- G. M. Davis, Manager of Events Analysis Reporting & Responses
- L. W. Laughlin, Onsite Licensing Coordinator T. R. Leonard, Maintenance Superintendent A. F. Burski, Manager of Nuclear Safety and Regulatory Affairs R. S. Starkey, Operations Superintendent A. S. Lockhart,-Management Systems Manager
- Present at exit interview.
In addition to the above personnel, the NRC inspectors held discussions with various operations, engineering, technical support, maintenance, and administrative members of the licensee's staff.
2.
Plant-Status (71707)
The plant was operating at full power at the start of the inspection period. For a short period on June 10, 1989, power was reduced to 87 percent for monthly turbine inlet valve and reactor control element assembly testing. On June 13, 1989, power was reduced to 65 percent because of failure of the Auxiliary Component Cooling Water Puma A with the Emergency Diesel Generator B out of service.
(This is furtier l
discussed in paragraph 3.)- The plant was returned to full power later that day.
On June 16, 1989, because of low system demand, power was reduced to 87 percent.
Full power was again attained on June 19, 1989, and the plant remained at full power through the end of the inspection period.
3..
Onsite Followup of Events (93702)
a.
Reactor Power Excursion to 104.6 Percer,t At 6:55 a.m. on June 6,1989, while the plant was at 100 percent
)ower, t1e extracMon steam supply valve (ES-109) for No.1 feedwater 1 eater went shut. Reactor power increased to as high as 104.6 percent and was above 102 percent for roughly 12 minutes.
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'then, the operators determined what had happened, and actions were promptly taken to lower power to less than 100 percent. After troubleshooting, the licensee determined that a high feedwater heater water level switch was out of adjustment. The switch was designed to protect the main turbine by shutting ES-109 when the condensed water in the heater steam side could potentially back up to the turbine.
The switch cover was loose, and there was evidence that workers had pulled or stepped on the switch assembly while working on another valve. The switch was repaired, and ES-109 opened shortly thereafter. The NRC inspectors looked at the switch and the other valve that was worked on and concluded that the above cause was credible. The licensee checked for loose switch covers on the adjacent feedwater heaters and found none. The NRC inspectors checked the switch covers on all the feedwater heaters and found no problems. This appeared to be an isolated incident requiring no further action.
The licensee reviewed the deportability of this. incident pursuant te 10 CFR 50.72 and -73.
After some discussion, it was determined that the incident was not reportable because it was an analyzed transient, reactor protective limits were not exceeded, and the operators took timely action to restore power to below licensed steady state limits, b.
Failure of Auxiliary Component Cooling Water (ACCW) Pump A At 1:28 a.m. on June 13, 1989, while the plant was operating at full power, the ACCW Pump A outboard bearing temperature alarm tripped.
At the; time, EDG B was out of service (inoperable) for routine maintenance. At 1:31 a.m., control room personnel were informed that the outboard bearing cap appeared overheated (the paint was blistered and discolored). At 1:33 a.m., the shift supervisor declared the pump inoperable.
Since ACCW Pump B did not have an operable emergency power source (EDG B was inoperable), Technical Specification (TS)3.0.3wasentered,andat1:41a.m.,theoperators commenced reducing power to 5 percent in preparation for a plant shutdown within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. The NRC duty officer was notified within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> pursuant to 10 CFR 50.72.
Upon discussing the event with the duty plant manager, the Shift Supervisor determined that ACCW Pump B was not inoperable because of EDG B, and EDG A was not inoperable because of the failure of ACCW Pump A.
However, TS 3.8.1.1.d required a plant shutdown within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The basis of this redirection was previous discussion between licensee management and NRC, Region IV, on the subject nf cascading TSs. See paragraph 4 of NRC Inspection Report 50-3Bc,d9-06, dated March 28, 1989, for previous discussion on similar circumstances.
By 8:13 a.m., EDG B was restored to an operable status and
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TS 3.8.1.1.d was exited. At that time, power had been reduced to
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65 percent. By 7:56 p.m., power was restored to 100 percen __
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-5-l ACCW Pump A failed as a result of a thrust assembly retaining nut
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backing off the end of the pump shaft. The nut rubbing against the end plate created the heat and then the alarm tripped. This was repaired on June 13, 1989. The licensee reported that the same
problem occurred on ACCW Pump B in 1987 and is evaluating for
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possible generic implications. The retaining nut had one set screw locking it in place, with no provision to prevent the set screw from
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Inspector Followup Item (pectors will follow up on this action under backing out. The NRC ins IFI) 382/8817-01.
The issue of cascading TS has been under review at Region IV.
In the meantime, the licensee issued Memorandum W3P89-3064 on June 15, 1989, which took the approach that if a supporting system or component addressed in a TS became inoperable, then only that TS must be
followed. The memorandum also briefly discusses taking appropriate l'
. actions to assure supported system reliability and prohibits activities which adversely affect redundant trains. This memorandum does not appear to provide sufficient guidance to preclude removal of redundant safety components from service while a required support system is inoperable. The licensee will be required to respond to concerns in this area by separate correspondence as a followup to NRC Inspection Report 50-382/89-06.
c.
Fire Seal Inspection and Repair programs The licensee's efforts to identify and correct all fire seal deficiencies at Waterford-3 have been documented in NRC Inspection Reports 50-382/88-28, -88-31, -89-03, -89-06, -89-08, and -89-12.
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' addition, the licensee identified the problem in LER 382/88-030, dated December 12, 1988. Of the 2014 seals inspected, 634 required restoration. Of these 634 seals, 476 have been restored to the proper configuration, thus there were 158 lef t to correct by the end of this inspection period.
No violations or deviations were identified.
4.
Monthly Maintenance Observation (62703)
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 codas or standards.
a.
Work Authorization 01037682. On June 1, 1989, the NRC inspector observed the vibration analysis of EDG A while it was running fully loaded in accordance with the routir.e operability surveillance. This was accomplished in accor.iance with Maintenance Procedure MM-004-002, Revision 4, " Vibration Measurements and Limits for Rotating
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-6 EquipmentNfTheworkauthorizationalsocalledforrecordingEDG w
cylinder pressures, which the NRC inspector witnessed. Though the
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. technicians. appeared to be obtaining pressure through the cylinder vents in a proper manner, there was.no procedure referenced by,the work' authorization nor.did there appear to be one at the jobsite.
The NRC inspector. questioned the system engineer. He stated he was
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not aware of any p'rocedures, but that the maintenance technicians
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were trained;to perform this activity, and the data was' turned over to.the system engineer for predictive maintenance trending. This was discussed with licensee management. The licensee'statedLthatLit had already.been recognized that there was a need for a procedure for future reference, and that'.the' system engineer was tasked to develop it. 'Since'the individuals observed appeared to be adequately trained to perform this routine preventive maintenance activity in a proper
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- manner without'a procedure and the licensee committed to publish one
~by November 30, 19.89, no purpose would be served by issuing a Notice
--of Violationsfor, failure to implement,a procedure controlling this safety-related~ work.. Issuance of an appropriate procedure by the
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committed date above shall be tracked under IFI 382/8917-02.
b.
Work Authorization 01038288.
On. June 3, 1989, the NRC inspector observed portions;of the replacement of a secticn of the reactor
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coolant pressurizer steam volume _. sample line. :The 3/8-inch stainless
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Primary Sample Sink Valve PSL-306 had a pin hele leak. The NRC inspector also reviewed the work documentation. package and the a
clearance record. Four problems were identified and discussed with
.the licensee during this inspection.
(1) The clearance-tagout (Number 89-673 of June'.2,.1989) was incomplete in that one of the valves.in the vont path to the primary sample sink, PSL-3081, was not tagged.
It was subsequently found in the correct (normally open) position after the NRC.ir1spector informed the shift: supervisor of the error and the valve was added to the clearance. Procedure UNT-005-003, Revision 7. " Clearance Request, Approval, and Release,"
Attachment 6.3, stated when systems containing radioactive fluids are to be drained and vented, the drain and vent paths shall be tagged in their required position. This is the first.
example of failure to follow procedures (Violation 382/8917-03).
(2) Approximately 12 feet of replacement tubing did not appear to be cleaned to the cleanliness of the system to which it was to be e
connected. The work package designated the system as'" Class 8,*
in accordance with Procedure UNT-007-005, Revision 2
" Cleanliness Control." which is a high level of cleanliness i
applicable to reactor coolant components. The new tubing was
also not capped to prevent entry of foreign materials as
required by UNT-007-005, Scction 5.2.3.
This the second example of failure to follow procedures (Violation 382/8917-03). The line was flushed out after the work was done.
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Apparently PSL-303 and 304, the'inside and outside 1/2-inch (3).
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containment isolation valves, leaked by when subjected to pressurizer pressure..The remote operated sample isolation
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valve inside the containment (RC-319), which is supposed to fail.
closed, appeared to have failed open. The open indication light stayed on regardless'of the. remote switch position, and there-
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was apparent flow..On the control. panel, the valve switch.was-
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misla)eled "RC-317" when it should have been "RC-319."
The licensee stated that they were evaluating this condition.
Correction shall be tracked ~iinder IFI 389/8917-04.
(4)' The 1/2-inch stainless steel piping between the containment penetration and PSL-304 represented a personnel hazard. This piping had been subjected to pressurizer steam volume
. temperature and pressure'and was within the reach of personnel-
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in the area. As.of. June 23; 1989., no action. appeared to have been taken to place a " hot pipe" sign or insulate the pipe.
This was discussed with the licensee as early as June 3, 1989, when the NRC inspector burned his hand on the pipe. The NRC inspector noted,'during a tour.on June 23, 1989, that the licensee had insulated the tubing downstream of PSL-304 in way.
of thb passageway to protect passers-by.
c.
Work Authorization 01020514. The NRC inspector observed the reassembly and installation of the EDG B left side, No. 5, crank case explosion device. The device was removed and disassembled to investigate and correct minor oil leakage. An 0-ring was found torn and was replaced prior to reassembly.
During reassembly, several deficiencies with the adequacy of the-technicians' knowledge of cleanliness cod rol requirements and document control were observed.
These deficiencies were also identified and documented by the licensee for corrective action on Quality Assurance Surveillance Report QS-89-021 and a quality notice.by the licensee's quality assurance inspector, therefore, no violation will be issued at this-time.
d.
Work-Authorization 01035167 On June 15, 1989, the NRC inspectors monitored the application of the freeze seal on a 3-inch stainless c
vertical pi3e which was on the discharge of relief Valve BM-135. The relief disc 1arge header could nct be drained, so the seal was applied to permit removal of the relief valve for corrective maintenance.
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The seal was applied using liquid carbon dioxide in accordance with Maintenance Procedure 191-006-010, Revision 5,." Freeze Seal Application." Some difficulty was experienced in obtaining a freeze,
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due partly to the size and configuration of the )ipe, the characteristics of liquid carbon dioxide, and tu>ing problems. The i
licensee proceeded cautiously, followed the procedure, and used a
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mockup to help gain confidence in the process. A satisfactory freeze i
seal was achieved, f
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Work Authorization 01038690. On June 20, 1989, the NRC inspector-p j
witnessed replacement of the high speed motor connection Okonite F
splices on Dry Cooling Tower (DCT) Fan 6B. This work was'part of the licensee's planned program to replace these splices since it was noted that some of them were overheating-due to corrosion oflthe lugs. The primary cause of this corrosion was determined by.the licensee to be a wick effect of the conductor-jacket braiding which was previously not removed as part of the splicing process. During F
this' replacement, the braiding was removed so that a proper seal could be achieved. The splice was properly done in accordance with
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the approved work authorization; however, the NRC inspector noted p
that the motor lead access cover gasket was of a hard material such as " Garlock" gasket material. The gasket was broken, but the
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electricians commented that they were told not to be concerned at this time.. The NRC inspector expressed concern to the licensee that.
since these safety-related, totally enclosed motors are out in the weather, there should have been concern over making sure the motor lead l access covers were properly sealed.
It appeared that the reliability of the fan motor would be degraded if rain water leaked in, wetted the slow speed motor leads (which still.had braiding entering their splices), and caused corrosion and eventual failure.
c The licensee committed to evaluate this concern and take appropriate action. -The NRC-inspectors will follow up to ensure the DCT fan motors are properly sealed (IFI 382/8917-05).
f.
Work" Authorization 99000257.
Because of seismic qualification considerations, the positioner and regulator on auxiliary component cooling water temperature control Valve ACC-126B were replaced during June 6-7, 1989. The NRC inspector observed portions of the postinsta11ation calibration and noted that deficiencies-in the data sheet caused improper alignment of the positioner.
This was discovered when cycling the valve.
The licensee has revised the data sheet format to correct the deficiencies.
In addition, the NRC inspector observed that a dust cover was torn on the actuator shaft.
A condition identification was written to correct this only after the NRC inspector identified it to supervisory personnel.
The above deficiencies were identified to licensee management while discussing concerns over maintenance planning and implementation. The NRC inspectors will continue to watch for improvements in the maintenance area.
5.
11onthly Surveillance Observation (61726)
The NRC inspectors observed the surveillance testing of safety-related systems and components belew listed to verify that the activities were being performed in accordance with the TS The applicable procedures were reviewed for adequacy, test instrumentation was verified to be in calibration, and test data was reviewed for accuracy and completeness.
The NRC inspectors ascertained that any deficiencies identified were properly reviewed and resolved.
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a.
Procedure OP-903-068, Revision 6 " Emergency Diesel Generator (EDG)
. Operability Verification." On June 1, 1989, the NRC inspecu r witnessed the start and loading of ECG A to 4.4 megawatts, the I-hour run, and the unloading of the' EDC upon completion of the test. The operators performed the test in a professional, deliberate, step-by-step manner in accordance with'.the procedures. The results were satisfactory.
No problems were identified.
b.
Procedure OP-903-046, Revision 7,," Emergency Feed Pump OperaM 11ty Check." On June 15, 1989, the NRC inspector observed inserv;ce testing of the steam driven emergency feedwater pump. The stroke times for the emergency feedwater flow control valves were also measured. All procedural acceptance criteria were met, and no problems were identified.
No violations or deviations were identified.
6.
Operational Safety Verification (71707)
The Ocjectives of this inspection were to ensure that this facility was being operated safe'y and in conformance with regulatory requirements, to ensurc that the licensee's management controls were effectively discharging the licensee's responsibilities for continued safe operation, to assure that selected activities of the licensee's radiological protection prrg ams are implemented in conformance with plant policies and procedures and in compliance with regulatory requirements, and to inspect the licensee's empliance with the approved physical security plan.
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Tna NRC inspector: conducted control room observations, plant inspection tours, and reviewed logs and licensee documentation of equipment problems.
Through in-plant observations and attendance of the licensee's plan-of-the-day meetings, the NRC inspectors mainSined cognizance over
- ant status and TS action statements in effect.
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On June 1, 1989, the licensee found a pin hole leak in the wall of the high pressure stainicss steel tubing for the pressurize steam volume sampling line. The leak was located between the outer containment isolation Valve FSL-104 and the sample sink, in a vertical run in the-4 feet elevation wing area passa m ay. At about 5 p.m., an hour after the leak was identified, the NRC inspector entered the area to observe the leak end found water on the floor :oming from the primary systein leak.
The water was not being ceught by any absorbent material or a catch pan and was at the edge of the contamination barrier, headed for the passt,eway. The NRC inspector notified Health Physics (HP) personnel, who acted to contain the spill. The HP supervisor initiated a radiological deficiency report to document tne incident and initiated corrective actions as to cause. The NRC inspector expressed concern to licensee management that such poor radiological work practices were unacceptable L
and could cause the spread of contamination.
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-10-in June 6,1989, the MC inspector witnessed the drawing of a reactor coolant sample in accordance with Chemistry Procedure CE-003-327, Re'ision 5, " Operation of the Primary Sample Panel," and the analyses for Fit orides, Chlorides, pH, Lithium, Boron, Gross Activity, Gross Equivalent Iodine, Conductivity, Hydrogen, and Oxygen. The analyses appeared to have been conducted properly in accordance with the applicable controlling procedures. The chemist demonstrated a high degree of proficiency and professionalism. The results were all within the appropriate acceptance criteria.
On. June 8, 1989, while conducting an inspection related to EDG fuel sampling, a Region IV'NRC inspector found the EDG duplex fuel oil filter and strainer outlet selector valves left in a simplex mode, that is, all elements in service at the same time. This defeated the duplex feature discussed in the EDG technical manual (45700-1225, Volume 1). The significance of this finding was that if the EPG was running to perform its intended safety function and the filter or strainer became clogged, the EDG would shut down on fuel starvation.
In the duplex mode, the operator could simply shift to the clean side upon getting a high filter or strainer differential pressure alarm.
The licensee was informed of this problem on June 8, 1989. The NRC inspectors pursued the matter further and found the following deficiencies:
a.
The EDG technical manual stated that the fuel oil duplex filters and strainers should have the outlet selector valve handles positioned to circulate the fuel through half of.the unit so that if a high differential pressure indicates a clogged element, the valve can be repositioned to' select the clean side. Then the dirty sice can be serviced. The licensee's operating procedure, OP-009-002, Revision.10. " Emergency Diesel Generator," did not include these valves in the valva lineup. The valves were labelled EGF-1222 A(B)
and EGF-1228 A(B). This is the first example of the licensee's failure to implement adequate procedures which is in violation of NRC Regulations (382/8917-06).
b.
The licensee lointed out that the EDG technical nanual required the duplex turbocharger oil filter to be operated with all elements in service. Since the lube oil system was a closed loop and there was a large simplex full flow filter upstream, this appeared to be a " final filter" not likely to become clogged as easily as a fuel filter might.
However, Procedure OP-009-002 valve lineup required the outlet valve to be "open" when it should have been "both."
Also, the outlet valve for EDG B was listed in the procedure as EGL-2148, but the valve was labelled EGL-215B.
These editorial errors were discussed with the licensee.
c.
Surveillance Procedure MM-003-015, Re"ision 6, "Energency Diesel Engine Inspection," Section 8.15, appeared to leave the fuel oil i
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filters and strainers in the "both" position after filling and venting. As a human factor' improvement, the procedure should have.
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"right" position. This was identified to the licensee.
d.
Sections 8.14 and 8.15 of Procedure MM-003-015 go into step-by-step detail.on the inspection and cleaning of the full flow lube oil filters and strainers and the fuel oil filters and strainers, respectively. The procedure did not have the same level of detail for the turbo charger lube oil filter inspection and cleanliness.
In Step 8.14.16 it stated, " Replace turbocharger lube oil filters in accordance with the Tab 14D, Section 5, (Page 6)."
Presumably, the intent was to refer to the EDG technical manual. As a human factors improvement, the NRC inspectors suggested that the turbocharger lube oil filter inspection and cleaning should receive equivalent procedural detail, e.
Operating Procedure OP-600-007, Revision 2, " Annunciator Response for Emergency Diesel Generator A or B Local Panel," Attachment 8.27, operator response to a high fuel oil filter or strainer did not include shifting strainers. The response appeared to support the previously incorrect position ("both") found on the fuel oil filters and strainers. This is the second example of the licensee's failure to implement adequate procedures which is in violation of NRC regulations (382/8917-06).
Sheet 2 of Attachment 8.27 applied to high fuel oil strainer differential pressure and listed clogged fuel oil filters and standby fuel oil pump discharge check valve failures as aossible causes.
These causes did not appear to be credible and s1ould be reconsidered. The l'1censee committed to revisit the causes and nake appropriate corrections.
Failure to have th: 70G duplex fuel oil filters and strainers in the configuration required by the EDG technical manual while the EDGs were operating could have resulted in an otherwise avoidable shutdown. This l
would have been particularly significant if the EDGs had been called upon to operate in an emergency, and the filters or strainers became clogged.
The NRC inspectors reviewed the minutes of the licensee's second garter ALARA comittee meeting. This is an ongoing program to reduce radiation exposures to personnel "As Low As Reasonably Achievable (ALARA)." Besides revier.ing selected ALARA improvement reports, the licensee reported the 5-month status of 1989 exposure to be at 13 Man-Rem, which is far belcw l
the 32.5 Pan-Rem goal. Also, the contaminated area status was reported to l
be approximately S000 square feet, which represented less than 5 percent l
of the radiologically controlled areas in the plant (excluding the reactor containment).
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'7.
Followup of Previously Identified Items (92701, 92702)
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a.
(Closed) Unresolved Item 382/8724-02:
NRC review of safety l
evaluations pertaining to design intent of Swing Bus A/B.
The
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b.
(Closed)OpenItem 382/8805-01: Licensee completion of modifications to the post accident sampling system, thus enabling successful
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testing of the reactor coolant degasification portions of the system.
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The modification was completed during the April-May 1988 refueling outage, the chemistry technicians were appropriately trained by July 26, 1988, and on July 15, 1988, satisfactory hydrogen concentration analyses were completed. This item is closed.
c.
(0 pen)OpenItem 382/8819-06: TS change and clarification of the diesel-driven fire pump surveillance test acceptance criteria. The Waterford-3 TS have been changad, and thus fire pump surveillance requirements have been deleted. The test requirements were addressed in UNT-005-013, " Fire Protection Program." Although the licensee considered this item closed, the diesel fire pump surveillance test acceptance criteria in OP-903-056, Revision 6. " Fire Protection System Functional Test," have not been revised as required. This item remains open until the acceptance criteria in OP-903-056 are revised.
d.
(Closed) Deviation 382/8821-03:
Failure to complete Engineered Safety Features (ESF) walkdown corrective actions by committed date.
Over the past year, there have been no significant problems with LP&L over the administration of commitment dates. The licensee has been committing to realistic dates, and when the commitments could not be met, they were extended for satisfactory reasons. This item is closed.
e.
(Closed) Violation 382/8903-01: The NRC inspector verified that the licensee corrected the identified procedure deficiency by issuing a
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revision to Procedure OP-903-053, " Fire Protection System Pump l
Operability Test." The NRC inspector noted that continuous operation of the motor-driven fire pump during surveillance testing was permitted by the revised procedure. This violation is closed.
f (Closed)UnresolvedItem 382/8908-04: Resolution of the safety
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significance and extent to which NRC regulations may have been i
violated as a result of an inappropriate position change for i
Component Cooling Water (CCW) System Valves CC-80310B and CC-8062.
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The NRC inspectors reviewed the licensee's " detailed" engineering l
evaluation, dated April 10, 1989, and the licensee's LER 382/89-006,
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dated April 26, 1989. The LER stated that a preliminary evaluation by Design Engineering personnel has shown there would be at least a
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1.1-hour margin assuming a combined leakage of 441 gallons per minute j
from a postulated break in the nonnuclear safety piping with
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C;-803108 and CC-8062 open. The LER also stated that this would have allowed operators sufficient time to detect and isolate a leak, thus
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-13-m this event did not threaten the health or safety of the public or
. plant personnel. The 1.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> were based on a preliminary evaluation, dated March 28, 1989, which' stated that a-detailed engineering evaluation will be required to quantify the amount of leakage and the impact on the CCW system during a postulated design basis earthquake. The " detailed" engineering evaluation stated that as the valves were closed as part of the immediate corrective action, there was no.1 cager an existing nonconforming condition, and, therefore, no engineering evaluation of the impact on plant safety was required. The LER also did not commit to a final evaluation and was indicated as a final report (no supplemental report expected.).
The progranatic breakdowns associated with this event resulted in the plant being outside of its design configuration. There were two examples of the licensee's failure to comply with TS 6.0.
Prior to implementation, the change was not reviewed by the PORC which is contrary to TS 6.5.1.6.d.
This is in violation of NRC regulations (382/8917-07). Upon impicmentation of the drawing change nctice, Operating Procedure OP-002-_003, " Component Cooling Water System," was not changed to reflect the new (but erroneous) required position'for the valves in the standby valve lineup, which is contrary to TS 6.8.1.a.
This is another example of failure to provide adequate procedures (332/8917-06).
8.
Licensee Event Report (LER) Followup (90712,92700)
t The following LERs were reviewed and closed. The NRC inspectors verified that reporting requirements had been' met, causes had been identified, corrective actions appeared appropriate. generic applicability had been considered, and that the LER forms were complete. The NRC inspectors confirmed that unreviewed safety questions and violations of TS, license conditions, or other regulatory requirements had been adequately doscribed.
a.
(Closed) LER 382/89-001, " Potential Unmonitored Release Point due to Inadequate Documentation of Design Change Qualification."
b.
(0 pen) LER 382/89-C03, " Inadvertent Actuation of Low Pressure Safety Injection Pump due to Personnel Error."
The LER described the root cause of this event as personnel error.
As corrective action, those personnel responsible were counselled by the operations superintendent, emphasizing a more cautious and thorough approach when following procedures.
Subsequently, Operating Procedure OP-903-011, Revision 4, "High Pressure Safety Injection Pump Preservice Operability Check," the procedure that the operators failed to foller. was updated and reformatted to conform to the licensee's new procedures guide. When a similar operation was performed again on May 26, 1989, the NRC inspector noted that
' 0-903-011, Revision 5, contained three separate steps in place of the step in the previous revision which had these actions in one l
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-14-step. Each step had a performance signoff and a verification signoff. The' operators rapidly proceeded through the three steps, along with two others, then signed off the five steps for performance and verification. When the NRC inspector questioned this as a
" cautious and thorough approach," the operators explained it was not practical to sign each step as it was performed, due to the sequence of events. The NRC inspector pointed out the poor hem 4n factors
aspect of the revised procedure, which in effect defeated the LER
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corrective action. As of June 23, 1989, the problem had not been corrected. This was discussed with licensee management, who committed to promptly correct the procedure. This LER will be closed upon completion of the committed action.
No violations or deviations were identified.
9.
Balance of Plant (BOP) Inspection (71500)
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The purpose of this inspection was to verify the effectiveness of the preventive and corrective maintenance programs for B0P systems, to determine the effectiveness of management attention to the correction of B0P problems, and to determine the adequacy.of the licensee's root cause analyses as they relate to BOP problems.
The NRC inspectors did not complete the inspection in sufficient depth to report any conclusions. As of the end of this inspection period, most of the instrument and controls portion of maintenance and the Availability improvement Program have been reviewed.
No problems were identified.
This inspection is scheduled to be completed by the end of July 1989.
10.
Exit Interview The inspection scope and findings were summarized on July 6, 1989, with those persons indicated in paragraph 1 above. The licensee acknowledged the NRC inspetors' findings. The licensee did not identify as proprietary any of the material provided to or reviewed by the NRC inspectors during this inspection.
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