IR 05000131/2003020
| ML17332A737 | |
| Person / Time | |
|---|---|
| Site: | Cook, 05000131  |
| Issue date: | 04/03/1995 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17332A734 | List: |
| References | |
| 50-315-95-05, 50-315-95-5, 50-316-95-05, 50-316-95-5, NUDOCS 9504240043 | |
| Download: ML17332A737 (35) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos.
50-315/95005(DRP);
50-316/95005(DRP)
Docket Nos. 50-315; 50-316 Licensee:
Indiana Michigan Power Company, 1 Riverside Plaza Columbus, OH 43216 License Nos.
Donald C.
Cook Nuclear Power Plant, Units'
and
Inspection At:
Donald C. Cook Site, Bridgman, MI Inspection Conducted:
January 31 through March 20, 1995 Inspectors:
J.
A. Isom D. J. Hartland C.
N. Orsini D.
G. Passehl J.
A. Gavula Approved By:
Wayne
.
K p
,
h f Reactor Projects Section 2A Date Ins ection Summar
Ins ection from Januar
throu h March 20 1995 Re ort Nos.
50-315 95005 DRP
. 50-316 95005 DRP Areas Ins ected:
Routine, unannounced safety inspection by the resident and region-based inspectors of:
action on previous inspection findings, operational safety verification, onsite event follow-up, current material condition and housekeeping, radiological controls, security, safety assessment/veriFication, maintenance activities, surveillance activities, and engineering technical support.
Results:
'Of the 10 areas inspected, one violation and three inspection follow-up items (IFIs) were identified.
A violation with respect to the inadequate engineering review of calculations associated with the leak sealant injection of the turbine-driven auxiliary feedwater and the pressurizer spray valves was identified (paragraph 6.a).
One IFI was identified which pertained to the inspectors'eview of the licensee's investigation of an apparent deviation from the Updated Final Safety Analysis Report (UFSAR) with regards to boric acid transfer pump operation (paragraph 3.a. 1).
The second IFI was identified which pertained to the inspectors'eview of the licensee's interpretation of Technical Specification (TS) 4.0.4 which allowed, under some circumstances, the plant to change operational modes with the associated surveillance requirements in "grace" (paragraph 4.b).
The third IFI identified pertained to the inspector's review of the licensee's investigation of V2H card failures (paragraph 6.b.).
Additionally, one unresolved item was 9504240043 950405 PDR ADOCK 05000315
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r identified regarding the inspectors'eview of qualifications of Plant Nuclear Safety Review Committee (PNSRC) alternate members (paragraph 4.c.).
The following is a summary of the licensee's performance during this inspection period:
Plant 0 erations:
Overall, the operator performance in this area was good as noted by operator performance during the Unit 2 reactor trip and the subsequent reactor start-up.
The inspectors had concerns with the operation of the boric acid transfer pumps in a configuration other than what was described in the Updated Final Safety Analysis Report (UFSAR).
Safet Assessment ualit Verification:
Licensee performance in this area was mixed.
The identification of issues in the licensee's guality Assurance audits and surveillances were good.
However, the inspectors had concerns with the qualifications of PNSRC alternate members and the justification used by the licensee for classifying some events as not reportable.
aintenance and Surveillance:
Generally, the licensee performance in this area was good during the inspection period.
The quality of maintenance performed by the craft was good.
However, the inspectors were concerned with the over-injection of sealant in the clamp installed on the Unit 2 pressurizer spray valve by a contractor.
En ineerin and Technical Su ort:
Overall, the licensee performance in this area was satisfactory.
However, the inspectors were concerned that the NRC identified deficiencies in engineering calculations which were performed to support leak sealant injection of ASHE inservice inspection (ISI) Code Class I and 2 valves.
As a result, a violation was identified with the licensee's failure to ensure that the leak sealing package was reviewed to verify that contractor documents and calculations are adequate and correct for the proposed leak repair.
Although there were no operability concerns which resulted from the calculational deficiencies associated with the leak sealant injections, the inspectors were concerned that these deficiencies occured.
Similar problems had already been identified in past inspection reports, 50-315/94002(DRP);
50-316/94002(DRP)
and by the licensee's guality Assurance organization in audit gA 94-09,
"On-line Leak Sealing."
DETAILS 1.
Persons Contacted:
2.
Indiana Michi an Power Cook Nuclear Plant A. A. Blind, Site Vice President/Plant Manager
- K. R. Baker, Assistant Plant Manager-Operations
- L. S. Gibson, Assistant Plant Manager-Technical J.
E. Rutkowski, Assistant Plant Hanager-Support
- W. J.
Fl'aga, Maintenance'epartment Production Supervisor D. L. Noble, Radiation Protection Superintendent T. K. Postlewait, Site Engineering Support Manager, J., S. Wiebe, guality Assurance 5 Control Superintendent L. H. Vanginhoven, Project Engineering Superintendent
- H. J. Stark, Plant Engineering Section Supervisor J.
L. St.
Amand, Mechanical Engineering Section Supervisor
- W. H. Hodge, Plant Protection Superintendent R. A. West, Licensing Coordinator
- H. Depuydt, Licensing Coordinator
- Denotes those individuals attending the exit interview conducted on March 21, 1995.
The inspectors also had discussions with other licensee employees, including: members of the technical-and engineering staffs, reactor and auxiliary operators, shift engineers and foremen, maintenance personnel, and contract security personnel.
Action on Previous Ins ection Findin s:
(92701)
'a ~
Closed Ins ection Follow-u Item 50-315 94024-04'5-16 424-N: ii i i i i iiiidiiiii i i
ii guidance provided in the licensee's Operations Standing Order (OSO) 095, Rev.
1, "Four Loop Injection Requirements and Possible Loss of RHR Hini-Flow."
OS0.095 provides guidance on the configuration of the discharge cross-tie valves for the residual heat removal (RHR)
and safety injection (SI) systems.
The OSO requires that the cross-tie valves for at least one-of the two systems be maintained open at all times.
Because the RHR pumps have a connected recirculation flowpath, the RHR system cross-tie valves were normally closed to eliminate the possibility of dead-heading the weaker RHR pump.
The inspector reviewed the guidance concerning operation of the cross-tie valves with respect to the Technical Specifications (TS), the Updated Final Safety Analysis Report (UFSAR),
and the individual plant examination (IPE).
The UFSAR analyses, for both the small and large break loss of coolant accident (LOCA), make conservative'ssumptions regarding the cross-tie valves.
The
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small break LOCA (SBLOCA) and the large break LOCA (LBLOCA)
analyses demonstrate that unit operation was acceptable as long as one set of either RHR or SI cross-tie valves was open.
The inspector also reviewed the plant's IPE and verified that the same conservative assumptions were made in the SBLOCA and LBLOCA scenarios.
Therefore, if the SI cross-tie valves were closed, the RHR cross-tie valves must be opened.
Additionally, because there was a potential t'o dead-head an RHR pump, the OSO requires that one RHR pump be taken to the pull-to-lock (PTL) position with the RHR cross-tie valves opened.
The OSO also states that "if an event occurs that requires RHR injection, the locked out pump should be returned to service as soon as the RHR system begins injecting into the reactor coolant system."
Since having the RHR cross-tie valves open was an abnormal configuration, and intended to last for a short duration (limited to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with an RHR pump in PTL by TS 3.5.2),
the inspectors determined that the operators would be cognizant of the configuration and take the appropriate actions if required.
The inspectors have no further concerns with the guidance provided by OS0.095.
0 en Unresolved Item 50-316 94024-01:
The inspectors reviewed the licensee's investigation of condition report (CR) 94-2162 and had some questions regarding the justification for classifying the condition as not reportable.
The inspectors concluded that the licensee's justification, which was based on retroactively applying.the successful completion of testing, was questionable.
The licensee initiated the CR on October 20, 1994, to document hourly fire watches which were missed while redundant chemical volume control system (CVCS) unit cross-tie valves were unavailable.
At the time, the licensee was performing maintenance on one of the two unit.cross-tie valves, 2-CS-536, with an expired surveillance, including the grace period, on the remaining cross-tie valve, 2-CS-535.
At least one of the two valves was required to be operable by TS 3.1.2.3.b to provide a flow path from Unit 2 for support of Unit I shutdown functions.
With both valves unavailable, the licensee was required to provide equivalent shutdown capability by performing the fire watches in the affected areas of Unit 1.
After the event had occurred, the licensee concluded that the condition was not reportable based on a successful surveillance for 2-CS-535 on October 25, 1994.
However, the inspectors concluded that because the licensee was required to satisfy TS required action statements when applicable surveillances time intervals had expired, the inspectors questioned the licensee's method of retroactively applying the successful completion of a
surveillance for the purpose of determining reportability of events.
C.
During follow-up discussion with the licensee, the inspectors determined that the condition was not reportable for another reason.
The TS action statement required that, without equivalent shutdown capability, the licensee place Unit 1 in Hot Standby within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Since the fire watches were missed for only 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the licensee did not violate the action statement.
The inspectors also identified two other similar examples involving reportability.
The first example was documented in the licensee's investigation of CR 94-0658, regarding an event which occurred on April 2, 1994.
The CR documented an unintended entry into TS 3.0.3, due to the inoperability of both trains of Unit 2 engineered safety feature exhaust (AES) fans.
The licensee had placed the control switch for the 2HV-AES-2 fan in the "stop" position after starting the 2HV-AES-1 fan for post-maintenance testing (PHT), thus making both fans inoperable.
The licensee had taken AES-1 fan out of service for a high efficiency particulate absorption (HEPA) filter replacement.
The licensee concluded that since the PHT on AES-1 fan was successfully completed, the event was not reportable because AES-1 fan was capable of performing its intended function at the time AES-2 was stopped.
However, the licensee's normal practice is to consider a system or component inoperable until a
PHT was successfully completed.
The second example was documented in the licensee's investigation of CR 94-2517.
This CR documented the licensee's failure to log the axial flux difference (AFD) as required by TS 4.2. 1. l.b. when Unit 2 power was raised above 15 percent power on December 14, 1994, with the AFD monitor alarm inoperable.
Again, the licensee's justification for classifying the event as not reportable was that the operability surveillance for the alarm was successfully completed later, when the power was raised to 30 percent.
This unresolved item will remain open pending further review and resolution of the acceptability of the licensee's practice of retroactively applying successful surveillances for the purpose of determining event reportability.
Closed Unresolved Item 50-315 94002-14 DRP 50-316 94002-
~le DRP
The inspectors initiated this item based on the deficiencies found in the calculations performed to support the leak sealant injection of ASHE Section III, Class valves.
This item is closed based on the issuance of a violation which is discussed in paragraph G.a of this report.
No violations or deviations were identifie.
Plant 0 erations:
The licensee operated Unit 1 at full power with no significant events during the inspection period.
The licensee was operating Unit 2 at full power during the inspection period until February 23, 1995, when the unit tripped following a spurious closure of a feedwater regulating valve.
This event is discussed further in paragraph 3.b.
The unit remained in Mode 3 to repair a leaking pressurizer spray valve.
The licensee returned the unit to service on March 1, 1995, and continued operation at full power for the remainder of the inspection period.
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0 erational Safet Ver'fication:
(71707)
The inspectors verified that the facility was being operated in conformance with the licenses and regulatory requirements, and that the licensee's management control system was effective in ensuring safe operation of the plant.
On a sampling basis, the inspectors verified proper control room staffing and coordination of plant activities, verified operator adherence with procedures and technical specifications, monitored control room indications for abnormalities, verified electrical power was available, and observed the frequency of plant and control room visits by station management.
The inspectors reviewed applicable logs and conducted discussions with control room operators throughout the inspection period.
The inspectors observed a number of control room shift turnovers.
The turnovers were conducted in a professional manner and included log reviews, panel walkdowns, discussions of maintenance and surveillance activities in progress or planned, and associated LCO time restraints, as applicable.
The inspectors made the following observations with regards to operator performance during the inspection period:
(1)
On the morning of February 6, 1995, during a routine
. walkdown of the Unit 2 control panels, the inspectors obse} ved that neither boric acid transfer (BAT) pump was operating.
The inspectors found the condition to be inconsistent with UFSAR Section 9.2 and operations procedure 12-OHP 4021.005.001,
"Boron Makeup System Operation," which require that one of the pumps be normally running in slow speed.
The licensee did not know at the time the basis for the requirement.
Unit 2 had been operating with no running BAT pump from about 3:00 a.m.
on February 5 to the morning of February 6,
1995.
At that time, the licensee declared the No.
BAT pump inoperable due to an apparent blockage in the flowpath.
The operators were able to borate the reactor coolant system (RCS) using the No.
BAT pump.
However, the pump was shut
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off after boration because of degraded No.
BAT pump seals and bor ation flow into the RCS could not be reestablished using the No.
4 BAT pump.
About 16-1/2 hours later, the operators found that they were unable to obtain boration flow into the RCS using the No.
BAT pump.
As a result, the licensee declared the boration flow path from the boric acid storage tanks (BASTs) inoperable and entered the
hour LCO as required by TS 3.1.2.6.
An auxiliary equipment operator (AEO) was dispatched to the No.
4 BAT pump and started.it in slow speed.
.The operators observed normal discharge pressure (30 psig) but negligible flow from the BASTs.
The operators shifted the pump to fast speed and were able to established the required flow of about 80 gallons per minute (gpm).
The licensee then declared the flow path operable and, as compensatory action for this apparent intermittent blockage problem, started the No.
BAT every four hours to verify flow.
The operators continued the compensatory action without incident until the inspectors questioned the inconsistency between what was stated in the UFSAR with regards to BAT pump operation and the present BAT pump situation.
Shortly afterwards, upon recommendation from the system engineer, the operators started and ran the No.
BAT pump on a
continuous basis until the discrepancy could be resolved.
The licensee also initiated CR 95-0180 to investigate the inspectors'oncern.
The inspectors'eview of the licensee's investigation into the apparent deviation from the UFSAR is an inspection follow-up item (50-315/95005-01(DRP);
50-316/95005-01(DRP) ).
(2).
On February 27, 1995, during a routine walkdown of the Unit 2 control room panels, the inspectors observed that the operators had not established auxiliary feedwater (AFW) flow through the test line of each motor-driven pump.
The pumps had been operating for over 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, since the reactor trip on February 23, 1995.
In the past the operators had established flow paths through the test lines to ensure that minimum flow'hrough the AFW pumps were maintained whenever the AFW pumps operate for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
The inspectors were concerned that operation of the AFW pumps with no.test lines open could potentially lead to a situation in which the AFW pumps could operate with less than the required minimum flowrate.
Upon further review, the inspectors did not have any concerns regarding the operability of the pumps.
However, the inspectors found that "Operation of the Auxiliary Feedwater Pumps During Plant Startup and Shutdown" procedure contained some conflicting instructions with respect to test line operatio IJ k
At the time that the inspectors identified the discrepancy, an emergency leak-off (ELO) valve on one of the pumps had just begun to open.
The ELO valve was designed to open when flow to the SGs was reduced to about 110 gpm.
However, the normal recirculation flowpaths through the ELO lines, which provides about 54 gpm, does not support the flow rates required for extended operation of the AFWipumps.
Therefore, the flow path was required to be established through the test lines to ensure that there were adequate flows during extended AFW pump operation.
The inspectors found that operating procedure 02-OHP 4021.056.002,
"Operation of the Auxiliary Feedwater Pumps During Plant Startup and Shutdown," contained'some conflicting instructions.
Paragraph 4.5 of the procedure required that the flow through the test valves be initiated if the motor-driven pumps are operated greater than
hours.
However, paragraph 6. 1.5 required test line flow be established if emergency leak-off flow operation exceeded
hours.
In response, the operators established flow through the test line later that day.
The operators also initiated CR 95-0315 for resolution of when the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> clock should start.
The inspectors will review the licensee's investigation of the CR to ensure satisfactory resolution of the discrepancy.
(3)
On March 1, 1995, the inspectors observed portions of the Unit 2 reactor start-up and power ascension, including the approach to criticality, starting of a main feedwater pump, and turbine roll.
A comprehensive pre-job briefing was given, which the inspectors believe contributed to uneventful performance of these evolutions.
Also, there were no problems observed with paralleling the generator to the grid.
Onsite Event Follow-u
(93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72.
The inspectors reviewed the events onsite with the licensee and/or other NRC officials.
In each case, the inspectors verified that any required notification was correct and timely.
The inspectors also verified that the licensee initiated prompt and appropriate actions.
The specific events were as follows:
(1)
At 4:45 p.m.
on February 23, 1995, the licensee experienced a Unit 2 reactor trip from 100 percent power.
The reactor trip signal was generated by a steam flow/feed flow mismatch coincident with low steam generator (SG) level.
The condition was caused by closure of the feedwater regulating
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valve to the No.4 SG, 2-FRV.-240, due to failure of the valve's controller.
The licensee determined that the controller failure was caused by an overheated transistor on one of the circuit cards.
The circuit card was replaced and has been sent to the vendor for further examination.
The plant response was as expected with the exception of the generator trip system.
The main generator failed to trip because of a malfunctioning limit switch on a main turbine control valve.
The generator trip system is designed so that the output breakers will not trip unless all turbine stop and control valves are closed.
This feature protects the turbine from overspeeding if any control valve remains open.
The operators followed an emergency operating procedures which directed that operators initiate manual trip of the generator after verifying the proper conditions existed.
During a post-trip tour of containment, the licensee identified an unisolable leak on 2-NRV-163, a pressurizer spray valve.
The licensee repaired the leak prior to startup using on-line leak sealing methods.
This repair is discussed further in paragraph 6.a.
On March 6, 1995, the licensee drilled into electrical conduits during installation of supports for a card reader strobe light in the Unit 1 "AB" emergency diesel generator (EDG) room.
The conduit contained the 4 kv cables which connect the EDG to the emergency bus.
The cables were de-energized at the time of the event.
The licensee's immediate actions were to declare the EDG inoperable and issue a "Stop Work Order" on the installation of anchor bolts in concrete'walls pending further investigation.
The licensee determined that no damage occurred to the cables.
The conduits were repaired and the diesel was declared operable on March 7, 1995.
This event was primarily caused by the failure.to recognize the structure being drilled into was a pilaster.
Standard practice at the plant prohibits installing anchors in electrical pilasters.
The licensee determined that the following factors contributed to this failure:
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Site Design believed the structure to be a column, and the drawings provided to site nuclear services (SNS)
did not clearly identify the structure as a colum,, h H
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SNS did not interpret the structure from the drawings as a column, and therefore did not require a drilling permit.
The review required for a drilling permit would have identified that the structure contained an
- electrical conduit.
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A pre-job walkdown did not identify the structure as a
column or pilaster.
The licensee's immediate corrective actions included:
(3)
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reviewing all in progress or planned designs to ensure that no anchors have been designed for installation in electrical pilasters
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revising procedure
- 12CHP5021.CCD.020,
"Expansion Anchor Bolt Installation Procedure,"
to require documented determinations of the type of structure by a field engineer prior to drilling
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Training all SNS and Site Design personnel on the above changes and similar industry events The licensee's long term preventive actions will be determined based on the completion of the investigation for CR 95-0355 concerning this event.
On March 14, 1995, the licensee made a
CFR 50.72 notification to the NRC to report a condition outside the design basis of the plant.
The licensee identified that certain cabling located in Unit 1 containment did not meet the requirements of 10 CFR 50 Appendix R, which stated that cables of redundant trains must be separated by more that
feet with no intervening combustibles or fire hazards.
The affected cables provided steam generator local shutdown indication (1-BLP-120, BLP-130, and BLP-142).
The licensee identified the condition during the ongoing'Appendix R
Revalidation Project.
As immediate compensatory action, the licensee verified that thermistor strings located in the affected cable trays were operable and the containment temperatures were recorded hourly.
The licensee then installed fire stops in the trays to correct the deficiency.
The inspectors will review the licensee's LER submittal to verify that an adequate root cause evaluation is performed and appropriate preventive actions are taken.
Current Material Condition and Housekee in
(71707)
The inspectors performed plant and selected system and component walkdowns to assess the general and specific material condition of
the plant, to verify that work requests had been initiated for identified equipment problems.
Walkdowns included an assessment of buildings, components, and systems:
identification, tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and unusual conditions.
Unusual conditions included but were not limited to water, oil, or other liquids on the floor or equipment; indications of leakage through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting.
The inspectors also monitored the status of housekeeping and plant cleanliness for fire protection and protection of the safety-related equipment from intrusion of foreign matter.
The inspectors observed that overall plant housekeeping,and material condition was very good during the inspection period.
On Harch 3, 1995, during a routine plant tour, the inspectors observed that the normally-closed "roll-up" fire door to the Unit 2 "West" motor-driven auxiliary feed water pump room was open and unattended.
The inspectors notified the shift supervisor, who inspected the area and closed the door.
During further review, the licensee determined that the door was probably open for approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The licensee initiated CR 95-0353 to investigate the deficiency.
The inspectors learned that the safety significance of the open door was minimal, as the door was equipped with a fusible link which would have allowed it to close in the event of a fire.
In addition, the door was located behind a missile door which would have minimized the affect of a high energy line break (HELB) in the adjacent turbine building.
The inspectors will review the licensee's CR investigation for adequate root cause determination and corrective action.
Radiolo ical Controls:
(71707)
The inspectors verified that personnel were following health physics procedures for dosimetry, protective clothing, frisking, posting, etc.,
and randomly examined radiation protection instrumentation for use, operability, and calibration.
The inspectors did not identify any significant deficiencies in this area during the inspection period.
~Securit
- (71707 0 81070)
Each week during routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security plan.
The inspectors noted that persons within the protected area displayed proper photo-'identification badges and those individuals requiring escorts were properly escorted.
The inspectors also verified that checked vital areas were locked and alarmed.
Additionally, the inspectors also observed that personnel and packages entering the protected area were searched by appropriate
equipment or by hand.
The inspectors did not identify any significant deficiencies in this area during the inspection period.
No violations, one inspection follow-up item and no deviations were identified.
Safet Assessment ualit Verification (40500 and 92700)
Licensee Event Re ort LER Follow-u (92700)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, that immediate corrective action was accomplished, and that corrective action to prevent recurrence had been or would be accomplished in accordance with TS.
Closed LER 316 94002:
Fire Watch Tour Omitted Due To Personnel Error.
On January 21, 1994, the licensee declared fire door 2-DR-AUX344 for the 609 foot elevation of the turbine building inoperable..
This rendered the 'CO, suppression system for fire zones 46A, 46B, 46C, and 46D inoperable.
The licensee properly implemented the appropriate Technical Specification action item, which consisted of hourly fire tours, until April 30; 1994.
At ll:08 p.m.
on April 29, 1994, an hourly fire watch toured the above described area.
At ll:30 p.m.
on April 29, 1994, the licensee held a shift turnover and issued new fire tour sheets.
The new firewatch tour sheet omitted inspection of zones 46A, 46B, and 46D.
Shortly thereafter, the licensee recognized that the fire tour area was omitted from the newly issued fire tour sheets.
The fire watch supervisor contacted the fire watch and had the tour point added to the tour and to the tour sheet.
The tour of the area was completed shortly after midnight on April 30, 1994.
The event was of minor significance since fire detection systems for the area were operable.
Further, the length of time the area was without a fire tour was small.
To prevent further occurrences, the licensee now requires an independent review of the tour sheets prior to use.
No similar event has occurred since.
This LER is considered closed.
b.
NSRC Alternate member ualifications During observation of a weekly licensee Plant Nuclear Safety Review Committee (PNSRC) meeting, the inspectors noted that two of the alternate members present were not management personnel.
One of the individuals, repres'enting the safety and assessment functional area, was a licensing activity coordinator who reported
e
directly to the Nuclear Safety L Analysis Department Supervisor.
The other individual, representing the maintenance functional area, was a production control supervisor who had no direct reports and worked for the IKC Production Supervisor.
The inspectors found that TS 6.5. 1.2 required that the PNSRC be
"composed of Assistant Plant managers, Department Superintendents, or supervisory personnel reporting directly to the Plant Hanager, Assistant Plant Managers or Department Superintendents..."
Although the individuals met the minimal qualifications of ANSI N18.1-1971 for membership, as referenced in TS 6.5.1.2, the inspectors were concerned that the licensee appeared to not be in compliance with the TS requirement.
In addition, the inspectors were concerned that the individuals may have limited managerial experience of activities and issues in their respective areas.
The inspectors further review of the qualifications of PNSRC alternate members is an unresolved item (50-315/95005-03(DRP);
50-316/95005-03 (DRP) ).
ualit Assurance De artment Audits and Surveillances:
The inspectors'eview of the following surveillances and audits found that the licensee were identifying issues which degrade the quality of plant operations or safety.
The inspectors intends to follow-up on some of the issues identified in the surveillances and audits to verify the effectiveness of the licensee's resolution to some of the issues.
Specifically, the inspectors reviewed the following surveillances by the guality Assurance Department:
2-95-03 12-95-02 12-94-51 12-94-50 2-94-49 2-94-48 2-94-47 2-94-45 2-94-44 2-94-43 2-94-42 2-94-40 12-94-39 12-94-36
"CETNA Canopy Seal Weld Repair"
"Background Screening Information"
"Auxiliary Feed Water Pump Performance"
"Long and Short Term Staging/Storage Areas"
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"Unit 2 Outage Mork In-Progress"
"Unit 2 Outage Work In-Progress"
"Unit 2 Outage Work In-Progress"
"Unit 2 Outage Work In-Progress"
"Unit'2 Outage Work In-Progress"
"Unit 2 Outage Mork In-Progress"
"Unit 2 Outage Work In-Progress"
"Reactor Cavity Seal Installation"
"Certification of guality Assurance and Control (gA&C)
Personnel"
"Cooling Fans Breaker 1-52C-5 Operating Experience (OE) fl Some of the issues identified in the surveillances included:
poor performance with the plant auxiliary feedwater pump with respect to packing and oil leaks; ability to maintain
proper oil level; turbine governor over speed trips; and
,trip and throttle valve malfunctions.
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Instrument and Controls technicians encountered difficulty performing a surveillance for the reactor coolant system protection set because the test leads would not stay attached to the test points.
Contrary to plant instructions, a clearance permit did not adequately ensure that the piping system upstream of a valve had been drained as requested prior to starting the repair activity.
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Several tool accountability and violation of foreign material exclusion requirements were observed during core alterations.
Mechanics failed to have a in-hand procedure for maintenance of a valve at the job site.
Additionally, the inspectors reviewed the following audits by the Corporate guality Assurance Department:
gA 94-09,
"On-line Leak Sealing" gAVP 94-12,
"Check Valve Program" gA 94-08,
"Motor Operated Valves (MOVs)"
Some of the issues found during the audits included:
Calculations provided by the'urmanite corporation to support leak sealing work were not of sufficient detail to understand their methodology or design basis.
Plant guidance established by the on-line leak sealing procedure did not control the limitations on the applied process such as injection port location, number or type of allowed injection ports and the number of sealant injection authorized.
~
Weaknesses in the check valve program were noted with capturing all check valve inspections, tracking all check valve problems identified via the condition reporting system, and tracking valve replacements.
No violations, one unresolved and one inspection follow-up items were identified.
Maintenance Surveillance:
(62703
& 61726)
a.
Maintenance Activities: (62703)
14'
Routinely, station maintenance activities were observed and/or reviewed to determine compliance with approved procedures, regulatory guides, industry codes, industry standards, and
'Technical Specifications (TS).
The following items were also considered during this review:
Limiting Conditions for Operation requirements met while components or systems were removed from service; approvals obtained prior to initiating work; functional testing and/or calibrations performed prior to returning components or systems to service; maintenance of quality control records; and activities accomplished by qualified personnel.
Portions of the following Job Order (JO) activities were observed and reviewed:
JO C28573 JO C27718 JO C28204 JO C28020 AR A88033 AR A87804 JO R28287 JO R41576 JO R31887 JO R31886 JO C25154 JO R36897
"Leak Seal 2-NRV-163"
"Repair No.
4 BAT Pump"
"Replace 1-65X-TDTV Control Solenoid"
"Replace 1-DG-115A"
. "Repair Unit 2 SI Pump Room Card Reader"
"Repair 2-MRV-211 Leakby"
"Replace ASCO Control Solenoid Valve, 1-XSO-932"
"Replace solenoid, 1-XSO-934"
"Lube and clean 2-CRDMG-2N '(motor and generator)"
"Lube and clean 2-CRDMG-2N Coupling"
. "I-WRV-762,. Replace valve and actuator ass'embly"
"Perform GEN-POP BATLIT Operation Test (GP-M-119)"
In regards to JO C28573, the licensee's guality Control inspector identified that the Furmanite contractor had added'ore leak sealant compound than what was authorized by the plant engineers.
The licensee wrote CR 95-0340 to document this problem, and the plant engineers performed calculations to determine any potentially deleterious effect on the spray valve from the additional sealant injection.
The engineers concluded that injection of an additional box of sealant compound was acceptable.
Additionally, the operators satisfactorily stroked the spray valve to verify that the additional injections caused no adverse effect on the valve.
Initial calculations called for injection of 24 boxes or 288 sticks of sealant.
The actual amount which was injected was
boxes or 300 sticks of sealant.
The guality Control inspector's identification of an unauthorized addition of leak.sealant by the Furmanite contractor was found to be a strength.
Surveillance Activities:
(61726)
During the inspection period, the inspectors observed technical specification required surveillance testing and verified that testing was performed in accordance with adequate procedures, instrumentation was calibrated, results conformed with technical specifications and procedure requirements, and any deficiencies
al
identified during the testing were properly resolved.
The inspectors also witnessed portions of the following surveillances:
02-OHP 4030.STP.027CD,
"CD Diesel Generator Operability Test,"
Rev.
7.
02-OHP 5030.001.001,
"Operations Plant Tours," Rev. 3.
02-IHP 4030.STP. 152, "Pressurizer PORV Functional Test,"
Rev.
02-OHP 4030.STP.018,
"SG Stop Valve Dump Valve Surveillance Test,"
Rev.
11.
C.
02-OHP 4030.STP. 19F,
"SG Stop Valve Full Stroke Test,"
Rev.
- 1IHP6030. IMP.309,
"4KV Loss of Voltage and 4KV Bus Degraded Voltage Relay Calibration," Rev. 3.
- 1IHP4030STP.411,
"Reactor Trip SSPS Logic and Reactor Trip Breaker Train "B" Surveillance Test (Monthly)," Rev.
TS 4.0.4 Inter retation During review of the inspection follow-up item discussed in paragraph 2.b. of this report, the inspectors noted that paragraph 3. 1.4.d of Plant Manager's Instruction (PMI) 4030,
"Technical, Specifications Review and Surveillance," allows, under some circumstances, entering operational modes with the associated surveillance requirements in "grace."
The "grace" period is the 25 percent extension of the specified surveillance time interval allowed by TS 4.0.2.
The licensee's procedure appears to conflict with TS 4.0.4, which allows entry into a mode only if the surveillance requirements have been performed within the stated interval, which suggests that'the grace period is not included.
The inspectors'eview of this concern is an inspection follow-up item (50-315/95005-02(DRP);
50-316/95005-02(DRP)).
~
No violations or deviations were identified.
En ineerin 8 Technical Su ort: (37700)
The inspector monitored engineering and technical support activities at the site including any support from the corporate office.
The purpose was to assess the adequacy of these functions in contributing to other functions such as operations, maintenance, testing, training, fire protection, and configuration management.
a ~
On-line Leak Sealin
(1)
Steam Su
Valve to.the Turbine-driven Auxiliar Feedwater Pum Valve 1-MCM-221
The licensee performed an on-line leak seal in the pressure seal gasket area for this valve by drilling, tapping and-installing shutoff adapters in the valve body.
A total of four adapters were eventually installed.
The first sealant injection with two adapters failed to stop the steam leak.
The calculations and work procedure associated with this effort were documented in Furmanite Procedure No. N-95036, Revision 2, dated February 22, 1995.
The following deficiencies were identified by the NRC during a review of this document:
(a)
The original design code for the valve, American National Standard ANSI B16.34, required auxiliary connections to have a minimum effective thread length of 0.41 inches for the installed 3/8-inch shutoff adapters.
Procedure step 5.2 gave directions to drill and tap the valve body, but did not specify that the minimum effective thread length had to be attained.
(b)
The portion of the calculation that determined the resulting valve body longitudinal stress evaluated the internal pressure only and did not consider seismic or actuator thrust loads.
In 'addition, this calculation utilized I/8-inch diameter holes, instead of the actual 3/8-inch diameter holes that were created in the valve body.
In addition'o the above, the documentation given in the work package did not provide the basis for valve operability with the potential introduction of sealant into the system.
Justification for the first injection stated that the sealant was only injected in the pressure seal of the valve, and that this would not impair the normal function of the valve.
However, the sealant volume for the second injection was calculated assuming that the void inside the valve body, between the bottom of the bonnet and top of the disk-piston, was filled.
The basis was not documented regarding why the potential introduction of sealant into the system was acceptable.
Additional discussions with licensee personnel determined that the valve functionality was adequately demonstrated by a post modification test; however, the lack of documented basis was considered a weakness.
Pressurizer S ra Valve 2-NRV-163 A body-to-bonnet leak was resolved by installing a custom designed temporary sealant enclosure around the valve body.
This approach eliminated the need to drill and tap into any part of the valve.
The calculations associated with the design of this enclosure were documented in Furmanite Procedure No. N-95105, Revision 2, dated February 28, 1995.
A review by the NRC noted that the calculation'ailed to consider the load induced in the six flange bolts due to the moment caused by the thrust force.
Subsequent analyses performed by the licensee indicated that the bolts were above the assumed allowable design value.
However, there was no immediate operability concern because any bolt failure would depressurize the enclosure.
The licensee will provide the revised analysis when it becomes available.
The deficiencies associated with leak sealant injection of valves 1-MCM-221 and 2-NRV-163 were considered to be examples of a violation of Technical Specification 6.8.
and licensee procedure 12MHP5021.001.051, Control of Temporary On-Line Leak Sealing, in that the leak repair documents and calculations were not adequately reviewed.
(50-315/95005-04; 50-316/95005-04(DRP)).
V2H Ca'rd Failures The inspectors reviewed circumstances regarding multiple failures of reactor protection system (RPS) cards which were installed as part of the analog-to-digital modification during the last refueling outage for both units.
The cards are a Class lE-isolation point between protection and indication/control racks.
The licensee has not yet determined the root cause of the failures.
Between May and June 1994, three card failures occurred on Unit
after only a few months in service.
At that time, the licensee attributed the failures to an incorrect fuse specification.
The licensee increased the rating of the fuse on the cards from a 1/4 to 1/2 amp to be more compatible with the possible current draw of the output supply.
In August 1994, a card with a 1/2 amp fuse installed failed.
Upon further investigation, the licensee noted that the failures appeared to be limited to a lot of 63 cards.
The Instrument and Control technicians began to replace the suspected cards as replacements became available'.
Most recently, the failures of some of'the replacement cards have occurred, which has led the licensee to question the reliability of a lot of 18 cards.
None of the failures to date have caused any significant plant transients.
As compensatory measures, until the card could be replaced, the licensee ensured that critical control loops that contained the'uspected cards were switched so as to prevent a plant transient in the event of a card failure.
The licensee intended to contract an independent laboratory to perform a review of the design and quality of manufacturing of the cards.
The inspectors will follow-up on the licensee's investigation to verify that an adequate root cause is determined and appropriate corrective
r at
action is taken.
This is an inspection follow-up item (50-315/95005-05 (DRP).
c.
Part
on Safet In'ection Pum:
The inspectors reviewed the applicability of a PART 21 (Headquarters Event no.
28412)
from Westinghouse which identified a defect on the pressure reducing sleeve locknut for "JHF" model safety injection (SI)
pump. manufactured by the Ingersoll Dresser Pump (IDP) company.
Part 21 stated that all 416SS parts made from IDP heat numbers 15899 and 28144 are sus'ceptible to the same failure mechanism as the pressure reducing sleeve locknuts.
Although the safety injection pumps at the plant were manufactured by the Pacific corporation, the engineers learned that the IDP company supplied parts to the Pacific corporation during the assembly of the SI pumps.
The engineers informed the inspectors that the SI pumps were of the '"JTCH" model type.
Because there is a possibility that the parts made from heat numbers
¹15899 and
¹28144 could have been used to assemble the "SI" pumps at the plant, the licensee had initiated condition report CR 94-2347 to address this potential problem.
The licensee had become aware of this problem earlier through Westinghouse Nuclear Safety Advisory Letter 94-023, dated October 26, 1994.
The inspectors will review
'the result of the condition report investigation to determine the applicability of this issue at the plant.
One violation and no deviations were identified.
Ins ection Follow-u Items:
Inspection follow-up items are matters which have been discussed with the licensee involving action on the part of the NRC or the licensee or both.
Inspection follow-up items disclosed during the, inspection are discussed in paragraphs 3.a. 1,'.b.
and 6.b.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable'tems, violations, or deviations.
An unresolved item disclosed during the inspection is discussed in paragraph 4.c.
Heetin s and Other Activities:
Exit Interview (30703)
The inspectors met with the licensee representatives denoted in paragraph 1 at the conclusion of the inspection on March 21, 1995.
The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection report.
The licensee acknowledged -the information and did not indicate that
any information disclosed during the inspection could be considered proprietary in nature.
k II I