IR 05000315/1993020
| ML17331B165 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/27/1993 |
| From: | Kobetz T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17331B163 | List: |
| References | |
| 50-315-93-20, 50-316-93-20, NUDOCS 9401040382 | |
| Download: ML17331B165 (28) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos.
50-315/93020(DRP);
50-316/93020(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 1 and
Inspection At:
Donald C. Cook Site, Bridgman, MI Inspection Conducted:
October 20, through December 7,
1993.
Inspectors:
J. A. !som D. J. Hartland G.
M. Nejfelt
~
Approved By:
T.
z, Acting Chief Reactor Projects Section 2A a
e Ins ection Summar:
Inspection from October 20, 1993 through December 7,
1993 (Report Nos.
50-315/93020(DRP);
50-316/93020(DRP))
Areas Ins ected:
Routine unannounced inspection by the resident and region-based inspectors of: plant oper ations; engineering and-technical support/maintenance; actions on previously identified items; reportable events; and safety assessment/quality verification.
Results:
Two Severity Level IV violations were identified.
A valve test failure was not recognized as such.
As a result, required actions were not taken within the time limits specified.
A modification to an emergency diesel resulted in the installation of components which were not suitable to their application.
This resulted in one diesel being inoperable for an unknown period of time.
En ineerin and Technical Su ort:
Licensee performance in this area was mixed.
The licensee's ultimate team approach and management involvement in the investigation of the trip and throttle valve problem for the turbine-driven auxiliary feedwater pump was a strength.
Al'so, the licensee's Inservice Testing Program was quite effective in identifying equipment deficiencies in the plant.
Further, the reduction of non-outage corrective job orders was a strength.
However, System Engineers lacked complete knowledge of Condition Reports assigned to their systems.
In addition, the licensee's initial investigation into the reactor head conoseal leak did not provide technical justification for its conclusions.
9401040382 931228 PDR ADOCK 05000315, PDR
'"'
Safet and Assessment:
Licensee performance in this area was mixed, The Quality Assurance (QA) organization identified some substantive issues during their review of 1992 integrated leak rate testing activities.
However, the licensee failed to identify that they had violated ASHE Code Section XI requirements during stroke testing of the Unit 2 Turbine-Driven Auxiliary Feedwater Pump trip and throttle valve, and did not declare the valve inoperative as require DETAILS 1.
Persons Contacted
- A. A.
- K. R.
L. S.
J.
E.
B. A.
- T. P.
P.
F.
D. L.
L. J.
T, K.
- S. A.
- P.
G.
- J. S.
L, H.
- G. A.
D.
C.
M. L.
Blind, Plant Manager Baker, Assistant Plant Manager-Production Gibson, Assistant Plant Manager-Projects Rutkowski, Assistant Plant Manager-Technical Support Svensson, Executive Staff Assistant Beilman, Maintenance Superintendent Carteaux, Training Superintendent Noble, Radiation Protection Superintendent Hatthias, Administrative Superintendent Postlewait, Design Changes Superintendent Richardson, Operations Superintendent Schoepf, Project Engineering Superintendent Wiebe, Safety 8 Assessment Superintendent Vanginhoven, Site Design Superintendent Weber, Plant Engineering Superintendent Loope,Chemistry Superintendent Horvath, guality Assurance Supervisor 2.
The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
- Denotes some of the personnel attending the Management Interview on December 13, 1993.
Plant 0 erations 71707 71710 42700 The inspector observed routine facility operating activities as conducted in the plant and from the main control rooms.
This included monitoring the performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of Auxiliary Equipment Operators including procedure use and adherence, records and logs, communications, and the degree of professionalism of control room activities.
The licensee's evaluations of corrective action and response to off-normal conditions were reviewed.
This included compliance with any reporting requirements.
a.
Unit 1 status:
The licensee operated the unit at full power throughout the inspection period, with no significant operational problems note b.
Unit 2 status:
The licensee operated the unit at 75 percent power throughout the inspection period, with no significant operational problems noted, c.
Ins ector Tours:
During a tour of the facility, the inspector identified the following items which were either corrected by the licensee or were identified for work:
A material which appeared to be packing tape was found on the circuit board used in the Unit 1 anticipated transient.
without scram (ATWS) mitigation system actuation circuit (AMSAC) inverter.
The 18C production supervisor indicated that the tape appeared to be baked on so that its removal at this time was not recommended.
Instead, the production supervisor planned to remove it during the upcoming Unit
outage in February of 1994.
In the meantime, the supervisor contacted the 18C engineer in the plant engineering department who stated that the tape should not adversely effect the operation of the Unit
AMSAC inverter.
The Unit
AMSAC inverter cabinet was dusty.
The IKC production supervisor verified that there was a plant preventive maintenance (PM) activity for cleaning and inspecting the inverter.
This PM is performed on an outage frequency.
This PM was performed during the last Unit
outage in 1992 and was planned to be performed again during the upcoming Unit 1 outage in early 1994.
No violations, deviations, unresolved or inspector followup items were identified.
En ineerin and Technical Su ort 37828 Maintenance 62703 61726 42700
The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office.
The purpose of this monitoring was to assess the adequacy of these functions supporting other areas such as operations, maintenance, testing, training, fire protection and configuration management.
The inspector also reviewed maintenance activities as detailed below, The focus of the inspection was to assure the maintenance activities were conducted in accordance with approved procedures, regulatory guides and industry codes or standards, and in conformance with Technical Specifications.
The following items were considered during this review:
the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicabl Slow 0 enin Times Associated With Unit 2 Turbine-Driven Auxiliar Feedwater TDAFW Pum Tri
& Throttle Valve:
In September, 1993, routine testing disclosed slow opening times associated with the Unit 2 TDAFW pump trip & throttle valve (T&TV).
The inspector reviewed the licensee's investigation to determine the causes behind the problem and reviewed the quality of the investigation conducted by the licensee.
Testing History IST test results from Harch 1988 to September 1993 for the Unit 2 T&TV showed that the valve testing program was quite effective in identifying abnormal or erratic valve stroke behavior.
During this period, the IST program identified about 10 instances in which the valve stroked near or above its acceptance criteria of 20 seconds.
Host normal valve stroke times ranged from 14 to
seconds.
On September 2,
1993, the T&TV failed to open on the first attempt.
The second attempt exceeded the maximum IST time of 20 seconds, The third attempt provided acceptable results.
An augmented test schedule was implemented following this occurrence.
On September 7,
1993, the TDAFW pump failed to start during the first three attempts.
On each of the first three attempts, the switch was held for about 3 to 5 seconds.
On the fourth attempt, the switch was jiggled and the pump started.
The operators, who suspected a dirty contact at the handswitch, declared the pump inoperable and initiated a priority 10 action request, which required repairs be commenced immediately.
The switch was replaced later in the day on September 7,
1993.
After the switch replacement, the licensee restroked the valve and obtained a
stroke value of I6.7 seconds.
A review of Condition Reports from the late 1990 period to September 1993 showed that the problems encountered on September 7,
1993 were the first documented occurrences in which the operators were unable to obtain movement of the T&TV when the switch was held in the open position.
For this reason, the licensee convened a team to investigate this issue.
A review of the control circuit associated with the T&TV, as well as results of testing conducted to investigate the intermittent T&TV failure problem, showed that power to the motor-operator for the T&TV should be available almost immediately.
By design, there is only about a
100 millisecond time delay between when the operator places the handswitch to the open position, and when both the auxiliary and the open contactors shut and provide power to the motor-operato ZS
ii) Investigation The inspector found the licensee's team investigation (attachment to the October 1,
1993 memorandum from T.A. Kratt to G. A. Weber and R.
W. Hennen)
was thorough and well done.
The goals of the team were to:
ll determine the root cause of the T&TV problem and provide recommendation for repair to prevent an equivalent failure in the future.
continually monitor the conditions of the ThTV and its associated control circuitry to establish confidence for continued operability.
The team's approach involved reviewing past IST information, maintenance history, and obtaining additional data through continuous on-line monitoring of contacts and voltages in various parts of the TKTV control circuit.
The team initially tested the valve on a shiftly basis, and eventually increased the frequency of testing to every other day to prevent the valve from possibly being inoperable beyond the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS requirement.
During the testing period, the valve never failed the IST acceptance criteria.
However, the team did observe that the open contactor did not respond consistently.
The licensee's analysis of these data indicated the following:
TKTV stroke testing from 1985 to 1990 produced consistent results.
However, the stroke times from October of 1990 to March of 1991 were somewhat more erratic.
The erratic cycle times then disappeared until September of 1993.
The focus of the maintenance activity to address the erratic behavior of the T8TV from October of 1990 to March of 1991 was to clean and lubricate the open contactor assembly.
The open contactor assembly was cleaned and lubricated on a
couple of occasions when it was identified as "sticking."
However, review of the job orders did not identify what was causing it to stick.
After a physical burr on the pivot shaft of the open contactor was found and removed during troubleshooting in March 1991, the open and closed contactor assemblies were interchanged.
Valve operation during the most recent tests verified that:
~
proper voltages were present to the control circuit
~
contacts within the control circuit operated correctly
~
the motor consistently opened the valve at 17.6 seconds.
~
the time for the auxiliary contacts to provide the seal-in feature of the control circuit was consistently about 100 milliseconds.
~
The open contactor provided erratic results.,
The results varied from 100 to 330 milliseconds indicating some mechanism was affecting its closure tim Ji
The inspector noted the following improvements in the investigation and repair effort which were different from the approach taken by the licensee in the past:
a more thorough root cause evaluation was performed a better understanding of the design of the contactor assembly was pursued to formulate possible failure sequences an engineer familiar with the operation and'design of control circuits was assigned to lead the team additional data useful for investigating the problem were obtained discussion with the manufacturer of the contactor assembly to obtain technical information and assistance was conducted The inspector agreed with the team's conclusion that the most likely causes for the slow opening time for the T&TV could be attributed to a combination of the following:
auxiliary contact misalignment potential lack of lubrication of mechanical interlock assembly and other pivot points excessive contactor spring tension The inspector also noted that the licensee had issued procedure PHSO. 144,
"Troubleshooting Teams,"
Revision 0, September 20, 1993, to provide direction on the use of these teams in the future.
The formation of the troubleshooting team was to focus on symptoms and problems which require assistance from several departments to achieve timely understanding and resolution, and to establish appropriate command and control.
This procedure required establishing a troubleshooting team when:
Technical Specification equipment fails to perform or demonstrate its safety-function The root cause can not be identified in a reasonable time frame on Technical Specification equipment failures Reactor/turbine trips Nanagement directives (Plant Hanager, Assistant Plant Nanager, Haintenance Superintendent or Plant Engineering Superintendent)
Licensee management's endorsement of the team approach to conducting investigations was considered a strength.
iii) Naintenagce History The inspector reviewed the following job orders to determine what type of maintenance activities were performed in the past to correct the intermittent slow opening problem of the TKTV:
I
Job Order:
Date Worked:
C0018979 10/28/93 C0018761 9/7/93 B003338 3/21/91 B003333 2/11/91 B000186 10/30/90 Descri tion:
Replace the DC contactor; mechanical interlock; and auxiliary contacts for TKTV control circuit Troubleshoot/r epair TKTV controls; control switch tested satisfactorily; although subsequently replaced when it was dropped during reinstallation.
Contactor sticking; delays opening of T5TV; cleaned and lubricated contactor linkage; removed burr from linkage pin; interchanged open and close contactors T&TV failed ISI stroke test; cleaned and lubricated open contactor Valve failed to cycle open electrically; cleaned and lubricated open contactor Troubleshooting during the 1991 time period and earlier appeared focused on the opening contactor assembly, and contributions from other components appeared not to have been considered.
Additionally, it appeared to the licensee that they had correctly identified the root cause of the problem when the burr was found on the contactor linkage pin on March 21, 1991.
iv) Engineering Involvement / Corrective Action The licensee's investigation found that their corrective action system database, referred to as the
"KTP" database, contained good historical information to demonstrate the repeated nature of the TLTV failures.
Problem reports (PR)
and condition reports (CR)
associated with the Unit 2 T8TV were closely aligned to the corrective maintenance history:
CR 93-1222(September 7, 1993):
U-2 TDAFW pump failed to start.
CR 93-1201(September 2, 1993):
U-2 TDAFW pump TLTV exceeded it maximum ISI stroke time.
PR 91-0348(March 7,
1991):
U-2 T8TV exceeded the ISI operability limits.
PR 91-0253(February ll, 1991):
U-2 TETV exceeded its maximum ISI stroke time PR 91-0241(February 2, 1991):
U-2 TDAFW pump exceeded its allowable start time PR 90-1547(October 25, 1990):
U-2 TETV is inoperable due to the TKTV exceeding its ISI stroke time
v)
Discussion with the analysis group and the administrative compliance coordinator in the plant engineering department indicated that the engineers in the-analysis section routinely perform searches of the KTP database for those conditions categorized as A, B, or C and attach the results of such searches to the CRs.
This practice has proven beneficial in identifying repetitive failures to the investigators.
On the other hand, the system engineers did not routinely review the KTP database to identify failure trends for equipment or components.
Interviews with several system engineers indicated they were neither assigned nor. trained on how to do so.
Although the system engineers were not routinely tasked with resolving deficiencies identified through the licensee's corrective action system, they were usually contacted by the administrative compliance coordinators (ACCs) within the plant engineering department.
These ACCs perform the investigation to address the CRs.
An informal survey of the system engineers indicated that although they were aware of the more significant CRs, they were not necessarily informed of CRs of lesser significance.
Additionally, it appeared that they would not necessarily be informed of CRs assigned to other departments through the licensee's present program.
However, the Condition Report Assessment Group does informally request that copies of CRs be sent to the system engineer if they conclude that the system engineer would benefit from knowledge of deficiencies identified in these CRs.
Hany of the condition and problem reports which were written on the auxiliary feedwater system from 1990 to the about the end of November 1993, were assigned to departments other than the plant engineering department for resolution.
It appeared that the system engineers'ontribution to the safety and reliability of their system could be further improved through their knowledge of all CRs written on their system.
Preventive Haintenance A limited review of the licensee's preventive maintenance (PH)
program was performed to determine what types of PHs were performed on the auxiliary feedwater system.
The licensee had PHs in the electrical, instrument and controls and mechanical areas.
These PHs involved limitorque limit and torque switch checks and adjustments, refurbishment of motor-operated valve actuators, calibration of various flow switches, pressure and flow transmitters, and testing of various relief valves.
There were a
few PHs which were in their grace period, but none were overdue.
The licensee appeared to have a very extensive PH program.
Discussion with the PH section found that presently there are some 12,000 PHs which are performed by the Haintenance department.
There are additional PHs performed in the chemistry, radiation
t V
g ~ 'L
protection and control and operation department which are not included in this number.
The licensee had been performing PH on the T&TV control circuit cubicle,
"2-AB-N" using procedure
"Preventive Maintenance of Installed Motor and Valve Control Centers, and Overcurrent Testing of Molded Case Circuit Breakers,"
- 12HHP501.082.017 for some time.
This maintenance procedure has since been replaced by
"MCC/VCC Preventive Maintenance and Molded Case Breaker Testing,"
- 12MHP5030.EHP.006 and this later revision includes overcurrent checks and general breaker cleaning and inspection.
The licensee did not have a vendor information controls system (VICS) manual for the contactor assembly.
The licensee is currently considering developing a VICS manual for the contactor assembly to provide available technical information if needed in the future.
vi)Section XI Code Requirements Section 4.0.5 of Unit 2 Technical Specifications (TS) requires that the licensee implement surveillance requirements for inservice inspection and testing of ASME Code Class 1, 2, and
components in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and the applicable Addenda as required by 10 CFR 50, Section 50.55a(g).
The part of ASHE Section XI which deals with testing of valves, Section IWV, requires that corrective action be initiated immediately when a valve fails to exhibit the required change of valve stem position.
On September 2,
1993, the operator testing the T&TV believed that the T&TV control switch was not held long enough at its open position on the first start attempt to make up the seal-in feature of the control circuit.
Therefore, when the switch spring-returned to the neutral position, and the operator observed no valve motion, he incorrectly concluded that he had made an invalid attempt to open the valve based on not holding the T&TV operating switch long enough.
The switch was held for about one second on the first attempt.
His second attempt appeared to validate his understanding of the control circuit.
This time the switch was held for about 6 seconds, during which time valve motion started and the T&TV stroked in 22.42 seconds.
The maximum stroke time allowed by the licensee's IST program is 20 seconds.
Because the operator discounted his first attempt as an invalid attempt, and because Operations Standing Order 74, in effect at the time, allowed immediate retest of the valve if it exceeded the IST cycle time on the first attempt, the operator cycled the valve for a third time.
On the third attempt, an acceptable stroke time of 16.7 seconds was obtained.
Based on the success of the third attempt, the operator declared the valve operable and did not initiate any corrective action.
However, subsequent tests conducted by the licensee's engineers to measure the open and auxiliary contact closure times found that
holding the T8TV switch for one second will allow the seal-in portion to actuate.
Through revision 5 to the Operations Standing Order 74, the licensee has prohibited declaring the turbine-driven auxiliary feedwater pump operable until the first valve test failure has been resolved.
The inspector concluded that the failure of the TDAFW pump to start on the 2nd of September constituted a valve failure, based on the design of the valve control circuit.
Additionally, because of this valve failure, the licensee should have initiated immediate corrective action to make repairs to the T8TV.
Because neither the operators nor the.condition assessment group (CAG)
recognized that the first attempt constituted a valve failure, corrective action to repair the valve was not undertaken and the licensee did not implement the requirements of their inservice test program.
The licensee's failure to take immediate action to correct the deficient T8TV condition which was identified through the first attempt on September 2,
1993 is considered a violation of Technical Specification 4.0.5 (Violation 50-316/93020-01(DRP)).
vii) Conclusions In the end, the inspector concluded the following with respect to the Unit 2 T8TV:
b.
The licensee's team approach in investigating the problem was a strength.
Management endorsement of such approach through their new procedure was also considered good.
Once the problem was recognized, the licensee demonstrated good management involvement in a safety significant issue.
Involvement and assistance by the appropriate engineering discipline contributed significantly to the successful resolution of the problem.
The licensee's IST program was effective in identifying equipment deficiencies.
The KTP database contained good information on historical system performance.
The system engineer's knowledge of their respective system could be enhanced through:
being aware of all condition reports written on their systems
periodic review of the KTP database Non-Outa e Corrective Job Orders:
The inspector discussed the status of the non-outage corrective job order status with members of plant management and found that they had achieved their 1993 year end goal of reducing the number of non-outage corrective job orders to less than 1000.
These job orders numbered about 2400 at the beginning of 1993.
Based on the ability to complete about 300 to 400 job orders a month, the remaining 1000 translated to about 3 to 4 months of work.
Having
e F
already achieved their 1993 goal, the licensee revised their goal to 683 non-outage corrective job orders by the beginning of the 1994 Unit 1 refueling outage.
The reduction of non-outage job orders to about a month of work for both units was considered a
strength.
One violation, and no deviations, unresolved or inspector followup items were identified.
Actions on Previousl Identified Items 92701 92702 a ~
(Closed) Violation 50-315/89007-01; 50-316/89007-02:
Failure to Calculate Combined T
e B and C Test Results IAW A endix J This violation concerned the licensee not using the maximum pathway acceptance criterion for Type B and C leak rate testing.
The licensee corrected this error in the special test procedures (STPs)
governing leak rate tests by assigning the highest leakage rate for the group of valves measured.
The inspector verified the leakage rate penalties applied, using the maximum pathway method, for the 1992 Unit 1 and Unit 2 integrated leak rate tests.
This violation is closed.
b.
(Closed) Violation 50-315/89007-03; 50-316/89007-04:
Failure to Haintain Penetration Pressure Durin T
e B and C Testin C.
This violation occurred because the licensee neglected the local leak rate testing (LLRT) pressure drop between the test equipment and the penetration tested.
By modifying the test equipment, the licensee provided a pressure tap adjacent to the volume tested.
This test equipment alteration gave a representative static pressure of the test volume.
The inspector verified the accuracy and precision of the test equipment by observing bench testing for various leak rates.
Personnel performing the 1992 Type B and Type C leak rate testing received two days of LLRT training to properly set up and take test readings in a pilot training program.
The licensee tracked the formalization of this LLRT training within their training program.
This violation is closed.
(Closed)
Unresolved Item 50-316/90006-01 (DRS): Review to Determine Whether CCW S stem Can Be Classified as Closed Loo With Re ard to CILRT This unresolved item concerned the applicability of Type C testing requirements for the component cooling water (CCW) system.
The licensee required no local leak rate testing for the component cooling water system (CCW), because the licensee classified the CCW system as a "closed" system.
The response to Final Safety Analyses Report (FSAR) guestion 022.6 supported the licensee's position.
The NRC accepted the view that the CCW system was a closed system
for this FSAR question response, because:
the CCW piping and components located in the reactor containment were designed as Seismic Class 1;
the CCW system was not an extension of the reactor coolant system (RCS),
and therefore, not subject to a
loss of coolant accident (LOCA) breaching its piping.
This unresolved item is closed.
(Closed)
IFI 50-315/93011-06; 50-316/93011-06:
Licensee Audit to Verif Conse 'uences to A
endix B of 10 CFR Part
This item required followup review of the licensee's gA Program to verify that audits required by paragraph 6.5.2.8.d of Technical Specifications (TS) were performed.
This requirement committed the licensee to perform audits of activities of the criteria of 10 CFR Part 50, Appendix B, on a 24 month interval.
The inspector closed this item based on satisfactory review of licensee audits and their audit planning process.
EI Subsequent to the initiation of this item, the licensee's Nuclear Safety and Design Review Committee performed an audit that verified that the licensee fulfilled this commitment.
In addition, the inspector reviewed the licensee's audit planning process and determined that it provided adequate controls to ensure that licensee regulatory commitments were addressed.
(Closed)
Unresolved Item 50-315/93018-02(DRP);
50-316/93018-02(DRP):
Licensee Root Cause Determination of Leakin Conoseal This item required follow-up on the licensee's root cause evaluation of deficiencies associated with a leaking reactor head conoseal.
The licensee discovered the leaking lower conoseal on August 2, 1993, during a post-trip containment walkdown on Unit 2.
This was the third conoseal leak that had occurred on this unit since 1991.
Although the licensee's root cause determination was not considered absolute, this item was closed based on the satisfactory corrective action taken by the licensee.
During disassembly of the leaking conoseal, the licensee discovered that the cap screws used to attach the clamp ring to the conoseal flanges were easily loosened.
These screws were required to be torqued to 120-126 foot-pounds by the licensee's conoseal assembly procedure.
The licensee attributed the loose cap screws to boric acid corrosion and stress relaxation of the clamp ring assembly.
However, the licensee's initial investigation, as documented in CR¹ 93-1143, failed to provide technical justification to support this conclusion.
In response to additional questioning, the licensee performed a followup
review which validated the initial investigation and provided adequate technical justification.
The affected components were not saved, so independent examination, to test the validity of the licensee's hypothesis, was not possible.
However, based on the amount of effort required to torque the cap screws to 120-126 foot-pounds on the mock-up conoseal assembly, the inspector concluded that the licensee's hypothesis was plausible.
However, personnel error during assembly was perhaps a more likely root cause, a theory which was also considered as possible by the licensee.
In addition, the licensee determined that the deformation on the, conoseal seating surface that caused the leak was originated during the conoseal assembly at the end of the last refueling outage.
The licensee also determined that the jack screws used to seat the upper conoseal that were found bent were probably installed in that condition.
As corrective action, the licensee is considering plans to replace the conoseals during the next refueling outage.
Regardless of the modification, the licensee has instituted more rigorous controls during the reassembly of the conoseal assembly.
The inspector will continue to monitor licensee activities related to conoseal maintenance, (Closed)
Inspector Fol1owup Item 50-316/92018-03:
Loss of Turbine Driven Auxiliar Feed Water TDAFW Pum Flow Retention Due To Inaccurate Flow Heasurements.
The inspector closed this follow-up item administratively because the licensee did not have an opportunity to continue with their troubleshooting in 1993.
The first opportunity for them to continue their investigation will-not be until Unit 2 is shutdown for an outage in late 1994.
The licensee plans to install a
modification, RFC-4126, to relocate the flow orifice further downstream, away from the bends and other components which might have an effect on the flow readings.
The licensee's completion of investigation and correction for the root cause of the flow retention element inaccuracy will be an inspector follow-up item (Item 50-316/93020-02).
No violations, deviations, or unresolved items were identified.
One new inspector followup item was identified.
Re ortable Events 92700 92720 The following Licensee Event Reports (LERs) were reviewed by means of direct observation, discussions with licensee personnel, and review of records.
The review addressed compliance to reporting requirements and, as applicable, that immediate corrective action and appropriate action to prevent recurrence had been accomplishe JL ~
(Closed)
LER 315/92001-LL: Slabs at fl 621'6
in the West Main Steam Enclosures for Units
and 2 Did Not Meet Desi n Basis Re uirements Due to Inade uate Confi uration Controls in 1973 The inspector closed this LER based on adequate licensee root cause determination and corrective action.
On January 28, 1992, the licensee discovered that slabs located in the Unit
and 2 West Main Steam Enclosures could have potentially collapsed in an uncontrolled manner in the event of a design basis high energy line break (HELB) in the enclosures.
The licensee discovered the condition during an investigation into a discrepancy between the slabs and their design drawings.
By a subsequent analysis, the licensee determined that the slabs would have remained functional in the event of an HELB, but that some cracking would have resulted in some areas.
The licensee determined that the root cause, was inadequate configuration/design control in conjunction with the original safety analysis performed in 1973.
As corrective action, the licensee completed a design change during the 1992 refueling outages to correct the design deficiency.
This condition involved a violation of Criterion III of 10 CFR 50, Appendix B, "Design Controls";
however, the condition had minimal safety significance.,
In addition, the licensee properly reported the condition and took appropriate corrective action.
Therefore, pursuant to the NRC enforcement policy (10 CFR 2, Appendix C), the NRC is exercising enforcement discretion for this matter, and no Notice of Violation will be issued.
(Closed)
LER 315/92014-LL: Unmonitored Release of a Waste Gas Deca Tank Due to Com onent Leaka e and Pe} sonnel Error This LER was closed based on adequate licensee root cause determination and corrective action.
On November 6, 1992, the licensee identified an unmonitored release flowpath from the waste gas decay tank via the steam generators during nitrogen sparging.
The licensee subsequently determined that the radioactivity released to the environment was insignificant.
The licensee determined that the root causes of the event were seat leakage through the nitrogen isolation valve to the tank and the mispositioning of a nitrogen header isolation valve.
As corrective action, the licensee repaired the leaking valve.
The licensee reviewed the system valve repair history and concluded that the valve leakage was an isolated incident.
The licensee also took appropriate administrative action with regard to the personnel involved with the mispositioned valve.
This event involved a violation of TS 6.8. 1 for failure to implement plant procedures with regards to equipment control (valve line-ups).
However, the event did not result in a significant radioactivity release.
In addition, the licensee properly reported the event and took appropriate corrective action.
Therefore, pursuant to the NRC enforcement policy (10 CFR 2, Appendix C), the NRC is exercising enforcement discretion for this matter, and no Notice of Violation will be issued.
(Closed)
LER 50-316/92004-LL:
Emer enc Diesel Generator EDG Ino erabilit Due To Inade uate Desi n Mar in In Startin Air
~Sstem This item was closed based on adequate licensee root cause evaluation and corrective action.
However, a Severity Level IV violation was identified involving inadequate licensee design controls which resulted in the event.
In the fourth quarter of 1991, the licensee initiated Minor Modifications 12-MM-253 and 12-MM-241 to replace pilot operated valves (POVs) in the starting air systems of each of the plant's emergency diesel generators (EDGs).
POVs made by a different manufacturer were purchased due to obsolescence of the original valves.
During routine surveillance testing on December 16, 1991, the time response of one of the new POVs was abnormally slow.
At that time, the licensee was unable to determine the root cause of the slow response, but the POV was replaced and post-maintenance testing successfully completed.
The licensee then performed routine surveillance testing on December 23, 1991 without incident.
On January 13, 1992, the Unit 2 AB EDG failed to reach rated speed within the time limit required by TS 4.8. 1. 1.2.a.4 during routine surveillance testing (10.38 versus 10 seconds).
Based on review of previous tests results, the licensee determined that the EDG may not have been capable of automatically starting within the required time limit for a period in excess of that allowed by the TS action statement.
The licensee attributed the EDG failure on January 13, 1992, to sluggish response of the POVs.
The valves were rated to operate with a pilot air pressure of between 35 and 150 psi.
However, during discussions with the vendor, the licensee determined that, when used with 40 psi pilot air pressure, the valves would have been required to be cycled very frequently (on the order of once or twice a minute) to ensure performance in the required response time.
In their application as part of the EDG starting air system, the POVs were intended to be cycled only once or twice per month.
The failure of the licensee's design change'eview and dedication processes to identify this deficiency is a violation of
CFR Part 50, Appendix B, Criterion III, "Design Control" (50-316/93020-03(DRP)).
P
The inspector reviewed licensee records and determined that the Unit 2 AB EDG had typically started within eight to nine seconds in the past.
The inspector also confirmed that, although the EDG failed the surveillance, the EDG still would have been able to respond to a design basis accident.
However, had the EDG not been able to reach 95 percent of rated speed within 11 seconds, it would have tripped and operator action would have been required to restart it.
d.
Although a
POV on another EDG also exhibited a slow response time, the other EDGs successfully passed their surveillances during this time period.
As immediate corrective action, the licensee replaced the new POVs on all the EDGs with the original valves.
As long-term action, the licensee systematically inspected and repaired/replaced components in the air start systems.
The licensee also initiated some minor design improvements to enhance system reliability.
EDG performance records since the events above show that no problems with air start systems have resurfaced.
Since the licensee has adequately completed corrective action for this event, response to this violation is not required and the inspector has no further concerns regarding this matter.
(Closed)
LER 315/92012-LL: Turbine Tri Reactor Tri Due to the Turbine Thrust Bearin Wear Device Not Bein Set Followin Maintenance This item was closed based on adequate licensee root cause evaluation and corrective action.
On October 28, 1992, during power escalation from a refueling outage, Unit 1 tripped from 16 percent power due to a misaligned main turbine bearing wear detector.
The licensee had removed the detector during the outage to support other work activities on the turbine.
The job order directing work on the turbine included detector restoration, but did not contain instructions to perform post-installation testing on the detector.
In addition, licensee personnel who were aware of the potentially misaligned detector assumed that the condition would be corrected by another work activity and did not generate an action request.
To prevent recurrence, the licensee implemented administrative guidance on the use of the Nuclea'r Plant Maintenance (NPM)
computer system to identify and track work activities to ensure that components are operable/functional prior to being placed in service.
In addition, the licensee performed a review of turbine preoperational/start up activities to ensure that adequate measures were in place for reliable system start up.
Three violations, for which licensee corrective actions were already completed satisfactorily, were identified.
No deviations, unresolved or inspector followup items were identified.
f 6.
Safet Assessment ualit Verification 37701 38702 40704
~92720 A Review of ILRT Activities The inspector reviewed guality Assurance (gA) activities with regards to integrated leakage rate testing (ILRT) during the 1992 refueling outages and noted that they identified some substantive issues.
For example, during the Unit 1 ILRT, a gA surveillance noted two testing discrepancies.
These observations were; not performing computation of test data after a dew cell failure, and using the instantaneous leak rate measurement rather than the average leakage rate value for the induced verification leakage.
After a rigorous review of these gA concerns by site and corporate engineering, the Unit" 1 ILRT remained successful.
No violations, deviations, unresolved or inspector followup items were identified.
7.
Mana ement Interview The inspectors met with licensee representatives denoted in Paragraph
on December 13, 1993 to discuss the scope and findings of the inspection.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents or processes as proprietary.
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