IR 05000413/1993027
| ML20058P742 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 12/01/1993 |
| From: | Freudenberger, Lesser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058P733 | List: |
| References | |
| 50-413-93-27, 50-414-93-27, NUDOCS 9312270255 | |
| Download: ML20058P742 (20) | |
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UNITED STATES
/pa tro% #- NUCLEAR REGULATORY COMMISSION -
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" REGloN 11 101 MARIETTA STREET. N.W., SUITE 2900 7
% y ATLANTA, GEORGIA 303234109
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Report Nos.: 50-413/93-27 and 50-414/93-27 ,
Licensee: Duke Power Company P.O. Box 1006 -!
Charlotte, Docket Nos.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52 ,
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Facility Name: Catawba Nuclear Station Units 1 and 2
Inspec' tion Conducted: October 3, 1993 - vember 6, 1993 ,
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dent % spector Dat'e S'igned l
gg., R. JTFretfdenberger, P. C.-Hopkins, Resident Inspector, Catawba C. Y. Yates, Intern, Catawba L. P. King, Reactor Inspector, Region II R. L. Watkins, Project Engineer, Region II Approved b . /A/i/93 MarR S. Lesser, Chief Date Signed i Projects Section 3A Division of Reactor Projects SUMMARY Scope: This resident inspection was conducted in the areas of review of plant operations, maintenance, engineering, plant support and ,
review of previous inspection' findings and Licensee Event Report :
Backshift inspections were conducted on October 4, thru 7,11 thru 17, 19, 21, 26, 27, 29, 30, November 1, thru 3, 5, and 6.-
Results: In the operations area, administrative controls for shutdown operations were considered to be comprehensive and appropriate to .
minimize risk during shutdown operations (paragraph 3.a). The '
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quality of Catawba Safety Review Group reviews of operational !
problems was good. In-plant reviews were limited in scope and generally resulted in recommendations for minor procedural revisions. Catawba Safety Review Group trending of-issues reported through the Problem Identification Process has supported, '
but not independently identified, areas in need of management attention (paragraph 3.b). :
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9312270255 931201 i PDR ADOCK 05000413 G PDR
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In the maintenance area, actions to identify, evaluate operability .
of, and propose corrective actions for a weeping leak from the 2B ,
Component Cooling Heat Exchanger were technically sound (paragraph 4.a).
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In the engineering area, to resolve long term fouling of the Nuclear Service Water System and associated flow degradation, the licensee plans to dedicate additional resources to the system team (paragraph 5.). ;
In the plant support area, an Emergency Response Organization I staff augmentation drill was successful and helpful in identifying areas for improvement in call out equipment and procedure .
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I REPORT DETAILS PERSONS CONTACTED Licensee Employees S'. Bradshaw, Shift Operations Manager J. Forbes, Engineering Manager T. Harrall, Safety Assurance Manager J. Lowery, Compliance Specialist ,
- W. McCollum, Station Manager W. Miller, Operations Superintendent
- K. Nicholson, Compliance Specialist D. Rehn, Catawba Site Vice-President
- Z. Taylor, Compliance Manager Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personne NRC Inspectors
- R. Freudenberger, Senior Resident Inspector P. Hopkins, Resident Inspector C. Yates, Intern, Catawba ;
R. Watkins, Project Engineer, Region II ;
L. King, Reactor Inspector, Region II
- Attended exit intervie l Acronyms and abbreviations used throughout this report are listed in the last paragrap . PLANT STATUS Unit 1 Summary Unit 1 began the report period at-full power. A core coast down prior to the end of cycle 7 refueling' outage began on October 1 The outage began on October 2 Cold Shutdown was achieved on October 31. The unit remained shut down for the remainder of the perio ,
, Unit 2 Summary Unit 2 operated at or near full power for the entire perio : Inspections and Activities of Interest During the week of November 1, a team inspection of the licensee's !
implementation of the Station Blackout Rule was conducted. The results of this inspection were documented in NRC Inspection .
Report 50-413,414/93-2 .
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F 2 3. OPERATIONS (NRC Inspection Procedures 71707 and 40500) :
Throughout the inspection period, facility tours were conducted _to observe operations and maintenance activities in progress. The tours ;
included entries into the protected areas and the radiologically !
controlled areas of the plant. During these inspections, discussions
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were held with operators, radiation protection, instrument and electrical technicians, mechanics, security personnel, engineers, supervisors, and plant management. Some operations and maintenance activity observations were conducted during backshifts. Licensee meetings were attended by the inspectors to observe planning and management activities. The inspections confirmed Duke Power Company's o compliance with 10 CFR, Technical Specifications, License Conditions, and Administrative Procedure Reactor Coolant System Reduced Inventory /Midloop Operations :
In preparation for the Catawba Unit 1, End of Cycle 7 Refueling Outage, the resident inspectors reviewed the licensee's administrative controls for operation of the reactor coolant system in reduced inventory and midloop conditions. At Catawba, plant administrative procedures consider the plant to be in a reduced inventory condition when the reactor coolant system level is below the reactor vessel flange with fuel in- the core. This corresponds to a plant reference elevation of 574 feet 2 inches or'. ,
25 percent as indicated on reactor vessel level' indication. _ l Midloop is defined as reactor coolant system water level below'the -
top of the flow area of the hot legs at the junction of the hot legs to the reactor vessel with fuel in the core. This t corresponds to 7.25 percent as indicated on reactor vessel level *
indication. For conservatism and simplicity, level below e percent reactor vessel level is considered midloop operations !
according to licensee administrative procedure The planned schedule for the outage included two periods of ,
operation in reduced inventory /midloop conditions to facilitate installation and removal of steam generator nozzle dams and reactor head disassembly and reassembly. The first period was to be performed with high decay heat loads, prior to core off-loa This period is scheduled to begin on November 6 and last approximately five days. The second period of reduced inventory /midloop conditions .is scheduled to begin December-10 and -
last approximately seven day Prior to plant operation with the reactor coolant system in reduced inventory /midloop conditions, the following items were ;
completed by the resident inspectors:
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Generic Letter 88-17 and associated licensee correspondence was reviewe _ .
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Site Directive 3.1.30, Unit Shutdown Configuration Control, which defines the requirements and plant conditions necessary to maintain safe unit shutdown configuration control with fuel'in the core or in the spent fuel pool was reviewed. Site Directive 3.1.30 includes administrative requirements for reduced inventory /midloop operation Since the previous outage, Site Directive 3.1.30 was revised to add a requirement that fire detection and protection equipment associated with components that are required-to be functional, available, or operable by the directive will be 4 operable or its action statement will be satisfied. This-addition was based on information included in NUREG-1449, Shutdcwn and Low-Power Operation at Commercial Nuclear Power Plant:, (September 1993).
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Supplemental briefings were conducted by training department personnel to refamiliarize the operating shifts with management expectations and concerns during reduced inventory /midloop operations beginning on November The inspector observed one complete briefing and portions of ,
others. The briefings were detailed and thoroughly addressed industry events and lessons learned. The ,
inspector noted, however, that the briefings'were conducted :
on shift while the attention of some participants was diverted due to plant monitoring responsibilitie A " Defense in Depth" plant status sheet, which assesses plant status based on reactivity control, decay heat removal capability, containment, inventory, power availability, and ,
spent fuel cooling, was performed on a shiftly basis by the ,
Shift Manager on duty. This information was also discussed '
on a daily basis at the outage management meeting The ,
inspectors reviewed this data on a routine basi '
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The licensee's outage plans included provisions to have.two '
offsite and two onsite AC power sources available (although :
not necessarily operable by TS definition) during both !
periods of reduced inventory /midloop operation The inspectors verified that procedures were active and in use for the following criteria: CONTAINMENT CLOSURE CAPABILITY FOR MITIGATION OF RADI0 ACTIVE ,
RELEASE i Containment Closure, defined as a functional barrier to l fission product release by Site Directive 3.1.30,. Unit :
Shutdown Configuration Control, was required during high decay heat reduced inventory /midloop and low decay heat ~
midloop conditions with no exceptions. During low decay .
heat reduced inventory conditions, up to ten exceptions were allowed including the personnel airlocks and equipment i
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hatch. A dedicated reactor operator in the work control center had responsibility for~ containment closure.
n Exceptions were to be approved only provided that a timed !
walkthrough of the exception had.been performed and the time to achieve containment closure was less than the thermal margin time included on the " Defense in Depth" sheet. The inspector noted that the administrative requirements for ?
containment closure established by the licensee were more stringent than the industry nor ,
2. RCS TEMPERATURE-- AT LEAST TWO INDEPENDENT, CONTINU0US-INDICATIONS THAT ARE REPRESENTATIVE OF CORE EXIT CONDITIONS-ARE OPERABL ;
Site Directive 3.1.30, Unit Shutdown Configuration Control, .
delineated that two incore thermocouples were to be in I service while the head was installed. The' duration of operation without the incore thermocouples was limite Reactor coolant system Resistance Temperature Detectors were to be used to monitor reactor coolant system temperature ,
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3. RCS LEVEL INDICATION - AT LEAST TWO INDEPENDENT, CONTINU0US-WATER LEVEL INDICATIONS ARE OPERABLE (CALIBRATED).
Site Directive 3.1.30, Unit Shutdown Configuration Control, includes requirements for two independent indications of '
reactor coolant system level when below 25% level. These instruments had separate transmitters and did not ~ include ,
the sightglass or tygon tubin . RCS PERTURBATIONS SHOULD BE AVOIDED Site Directive 3.I.30, Unit Shutdown Configuration Control, ,
included steps for midloop operations which stated that .
reactor coolant system level disturbances must be minimize . RCS INVENTORY ADDITION - AT LEAST TW0' ADDITIONAL MEANS OF *
ADDING INVENTORY TO THE RCS MUST BE AVAILABLE, IN ADDITION -
TO THE PUMPS THAT ARE PART OF THE NORMAL RHR SYSTEMS -
VERIFY OPERABILIT Site Directive 3.I.30, Unit Shutdown Configuration Control, required two independent makeup paths of borated water; the high head path must be operable, and the other was required to be functional. In addition, the Site Directive required charging pump and safety injection pump availability until a vent through a steam generator manway was available. . .This '
allowed for decay heat removal by feed and bleed on a loss of the residual heat removal syste .;
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,. N0ZZLE DAMS / LOOP STOP VALVES - REASONABLE ASSURANCE IS j
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OBTAINED THAT ALL HOT LEGS ARE NOT BLOCKED SIMULTANEOUSLY l UNLESS A VENT PATH IS ESTABLISHED TO PREVENTLPRESSURIZATION l OF-THE UPPER PLENUM 0F THE_R fi p
Site Directive 3.1.30, Unit Shutdown Configuration Control, required vents to be through only steam generator primary
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manways without nozzle dams or. diaphragm ;;; LICENSEE HAS CONTINGENCY PLANS TO REPOWER VITAL BUSSES FROM: :
ALTERNATE SOURCE IF PRIMARY SOURCE IS LOS Site Directive 3.1.30, Unit Shutdown Configuration Control, .
required four AC power sources to be. available during reduced; 4
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inventory /midloop conditions. Power restoration would be in accordance with plant procedures.- Part'of the review of.on-site j AC power availability performed by the inspector included a' :
verification that the emergency diesel generator non-essential '
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trips were bypassed when the diesel is started due to an i undervoltage condition on the essential busse ;
In summary, the licensee's administrative controls for shutdown operations were considered to be comprehensive'and appropriate fo ,
minimizing risk during shutdown operation '
b .~ Catawba Safety. Review Group The Catawba Safety Review Group (CSRG). .is the principal on-site quality assurance presence and reports to the'on-site Manager of:
Safety Assurance, who advises the Plant Manager and reports.to th Site Vice President. The CSP,G is 'responsib_le for'the coordination-of the site Problem Investigation Process, including establishment of problem identification and significance screening criteria, operability and reportability determination, application of root-cause determination techniques ~, and tracking of problem status from identification through resolution and completion of-corrective action. A separate Human Performance Enhancement System group works closely with the CSRG and has responsibility--
for human error reductio The inspector reviewed CSRG monthly activity reports for the _
previous year, a selection of in-plant audit' reports from the same, period, and Licensee Event Reports associated with two recent events, as well as several Licensee Event Reports for closure as'.-
documented in other sections of this repor The quality of CSRG reviews of operational problems is' goo Licensee Event Reports prepared by the CSRG-include detailed background information and significance evaluations. Corrective actions were focused on root cause and significant contributor In-plant reviews were limited in scope and generally resulted in recommendations for minor procedural revisions. CSRG trending of I
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i issues reported through the Problem Identification Process has supported,' but not independently' identified, areas in need of management attentio Nuclear Safety Review Board Meeting The inspector attended several sessions of the licensee's ' Nuclear Safety Review Board (NSRB) Meeting, conducted on October 26, 27 and 28. The purpose of the NSRB meeting was to discuss several issues of generic application to all Duke Power Company nuclear stations and operational activities and design aspects that pertain to Catawba specifically. According to TS, the NSRB shall function to provide independent review and audit of~ designated ,
activities in the areas of nuclear power plant operations, nuclear engineering, chemistry and radiochemistry, metallurgy, instrumentation and control, radiological safety, mechanical and ,
electrical engineering, and administrative control and quality-assurance practices.. The board reports to and advises the _;
Executive Vice President, Power Generation Group, on the adequacy .;
of, implementation of and compliance with regulatory requirements >
of Duke nuclear safety-related policies, programs and procedure I The inspector noted that, during the session of the meeting to discuss the effectiveness of corrective action programs, several ,
concerns were brought the the board members' attention, . including !
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the need for clearer criteria for initiating a PIP. The licensee indicated that these concerns are being addressed through the ,
Quality Improvement Project (QIP), which is evaluating the i engineering aspects of the corrective action' program. The QIP !
charter includes clarification of the PIP initiation criteria and '
training as well as other factors that influence the effective implementation of the PIP progra No violations or deviations were identifie i 4. MAINTENANCE (NRC Inspection Procedures 62703, 61726, and 40500)
The inspectors observed maintenance and surveillance activities to verify that correct equipment clearances were in effect; work requests and fire prevention' work permits, as required, were issued and being i followed; quality control personnel performed inspection activities as i required; procedures were being used; qualified personnel wer .)
conducting the activities; tests were _ adequate to verify. equipment operability; calibrated equipment was utilized, and TS requirements were appropriately implemente i Component Cooling Heat' Exchanger Flaw Evaluation On October 8, during preparations for painting, a weeping leak was identified in the vicinity of a support on the bottom of the 2B Component Cooling Heat Exchanger. Light grinding and polishing to facilitate examination resulted in the leakage increasing to several ;
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i drops per minute. The _ examination determined that a through-wall; flaw : 1 existed within the circumferential butt weld of'two cylinders ~ of _the - !
heat exchanger shell. The licensee's' evaluation _ determined that- the j flaw was due to existing porosity in the weld,_ not due to-fatigue. An 'i operability. evaluation of the' heat exchanger, and calculations' for - l performing a temporary non-code repair in accordance with' Generic Letter !
90-05 methodology were prepared by the licensee and reviewed by the i inspector. . The flaw and minor leakage was determined to have no. impact . 1 on operability for the remainder of the operating. cycle. ~ The licensee
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planned to submit a relief request to the NRC from--immediate code repair _ !!
of the flaw since the repair would require unavailability of safety l systems supported by the component cooling water system which was not- ;
commensurate with the safety _ significance of the flaw. _The licensee l plans not to apply a temportry repair to enable continued inspection of !
the flaw to identify any unexpected growth._ The inspector. considered ;
the licensee's actions to identify, evaluate operability, and propose- y corrective actions to be technically soun i a
No violations or deviations were identifie !
5. ENGINEERING (NRC Inspection PrctAdures 37828 and 40500) .;
Nuclear Service Water System Flow Degradation '
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n NRC Inspection Report 50-413,414/93-18, paragraph 5.b discussed apparent :
flow degradation in the "A" train of the Nuclear Service Water System J identified during' surveillance testing in June -1993. The inspection i report included a discussion of leakage through' the clam backwash valve ~ i as a cause for low pump flows as well as a description of compensatory ~ -!
actions to maintain the system operabl '
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Repairs to the clam backwash valve were performed during the week of-July 19, 1993, with no appreciable impact on system performance. The- i compensatory actions remained in effec !
On October 21, a test to determine the cause of the flow degradation-in l the "A" train was performed. This test identified that the flow control i valves located on the outlet of the component cooling heat exchangers in :
the Nuclear Service Water System were creating a pressure. drop- ~
i considerably greater than design when open, therefore, thase valves were l suspected in contributing to the overall system flow degradation. .The' ;
licensee plans to inspect these valves during the IE0C7 outage which ;
began October 3 :j t
Thel test also identified a section of piping which exhibited'a ..
l significant pressure drop. 'The eight inch piping.was the supply and i return lines from the Control Room Area Chiller condenser. Previous'. l data.from Nuclear Service Wateriflow bLlance tests supported a reduction 1 of' flow to the Control Room Area Chillers and indicated that the'"B" l train was more limiting. Since no flow instrumentation exists in, this section of the system, the flow was estimated. and the operability of the ,
Control Room Area Chillers was demonstrated by the performance of a heat j f5'
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t capacity test of the "B" Control Room Area Chille i operability i evaluation was performed by the licensee which concluded the Control Room Area Chillers remained operable provided the ultimate heat sink (Lake Wylie and the Standby Nuclear Service Water Pond) remain below .
85'F, and chiller condenser performance and calculation of Nuclear :
Service water flow to the condenser is monitored monthly. The inspector observed portions of the heat capacity test, reviewed the test results,: ;
and the operability evaluatio :
To resolve this issue, the licensee plans to install isolation valves in !
the Nuclear Service Water supply and return lines to the Control Room <
Area Chillers during the IE0C7 outage which began on October 30. The .
valves will facilitate mechanical cleaning of the lines with the units- ;
on-line following the outag ,
t To resolve long term fouling of the Nuclear Service Water System and i associated flow degradation, the licensee plans to dedicate additional :
resources to the system team. This is identified as Inspector Followup Item 413/93-27-01: Nuclear Service Water Flow Degradatio j No violations or deviations were identifie .
6. PLANT SUPPORT (NRC Inspection Procedures 71707 and 40500) l
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Staff Augmentation Drill 1
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On October 5, the licensee conducted an off-hours staff augmentation _
dril The purpose of the drill was to demonstrate that the CNS i Emergency Response Organization had the capability to man the emergency -!
response facilities within the time frames delineated in CNS Directive i 3.8.4, Emergercy Organizatio One position in the Emergency Operations Facility, the Accident l Assessment Manager, was manned five minutes after the seventy-five 1
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minute criteria. The licensee's critique of the drill . identified-several contributing causes to the deficiency. Voice pagers, used as primary notification to the emergency organization, did not provide full-coverage with many pagers providing garbled messages. The secondary, !
computerized telephone call out system encountered a failure of one of t the computers compounded by a telephone operator who did not properly .
respond to the failure. These equipment malfunctions resulted'in the i primary responder for the position to receive an unclear notification and the backup responder to receive late notification of the dril Additionally, it was determined that more explicit directions to the '
Emergency Response Organization regarding response to drills was necessary. The drill deficiency and contributing causes were documented ,
in PIP 0-C93-0905. With only one position manned late, the licensee considered the drill a success. Planned corrective actions include an upgrade of the pager system, improved procedures for the contractor to ,
cope with a computer failure, and clarification of expectations ;
regarding the Emergency Response Organization response to drill '
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i Based on the licensee's detailed critique to identify the cause of late manning 'of the position and the planned corrective actions, the
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inspector noted that the drill was successful and identified areas for -
improvemen ,
No violations or deviations were identifie ,
F 7. PREVIOUS INSPECTION FINDING 5 AND LICENSEE EVENT REPORTS (NRC Inspection l Procedures 92700 and 92702) (Closed) LER 413/91-09: Possible Technical Specification a Violation Resulting from Improper Overtemperature Delta-Temperature Circuit Scaling This issue was addressed by URI 50-413,414/91-16-02, discussed below. Corrective actions were reviewed for the followup of the -
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unresolved ite (Closed) URI 50-413,414/91-16-02: Improper Voltage Gain Setting-in Overtemperature Delta-Temperature Reactor Trip Circuitry Resulting in Degraded Trip Function An apparent violation, identified in NRC Inspection Report 50-413,414/91-16, involved improper voltage gain settings applied to components in the overtemperature delta-temperature reactor trin circuitry and the subsequent questionable operability of this
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reactor trip functio There was a concern that the Catawba reactor trip system might not be able to perform its intended safety function under certain conditions. More specifically, on '
July 17,1991, the licensee identified that the Overtemperature Delta-Temperature (0 TDT) reactor trip circuitry would not function correctly over the entire intended range. The gain associated with one of the OTDT calculation constants, K2, was applied such that the electronic circuitry would have been overranged,' causing ;
the circuitry to become inoperable under certain conditions. The K2 constant had been in this condition at Catawba Nuclear Station since initial startup. This issue was identified by the licensee at the McGuire Nuclear Statio NRC concerns relative to the inspection findings were discussed in an Enforcement Conference held on September 6, 1991, for the McGuire and Catawba Nuclear Station By letter dated September 13, 1991, the NRC acknowledged the licensee's identification of the problem and prompt, conservative and comprehensive corrective actions at the Catawba facility. The NRC indicated that the licensee's " questioning attitude" resulted in the identification of this significant' generic safety issu Since the issue was promptly identified and appropriate corrective actions were implemented at the Catawba facility, a Notice of Violation was not issue .. .
10 1 c. (Closed) LER 413/91-10: Feedwater Isolation Due to Unknown Cause
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On May 26, 1991, with Unit 1 in Cold Shutdown, a Feedwater System Isolation occurred wnile the "A" Reactor Trip Breaker was being racked out. No cause for the inadvertent Feedwater System Isolation could be demonstrated by the licensee. A design study determined that the Westinghouse W-2 Cell switches used in the reactor trip breakers should be replaced with General Electric switches for improved reliability although the switches were not proven to be the cause of the problem. The_ licensee has not yet implemented the modification. The inspector determined that the modification will enhance the system but is not required for corrective action and that recurrent failures have not happene d. (Closed) LER 413/91-20: Technical Specification 3.0.3 Entry Due to Two Inoperable Trains of the Control Room Ventilation System i On September 15, 1991, at 1:00 p.m., with Unit I at 98 percent power and Unit 2 in mode 5, cold shutdown, Operations attempted to swap the Control Room Area Ventilation and Chilled Water System from B train to A train. During this activity it was discovered that breaker IEKPG #22, associated with train A was open. This resulted in both trains of the Control Room Area Ventilation and Chilled Water System being inoperable for approximately 90 minutes on September 13, 1991 because neither train would have been i capable of adequately pressurizing the control roo This issue was considered an example of a repeat violation of NRC requirements involving configuration control (see VIO 50-413,414/91-27-01, below. The corrective actions associated with this LER were reviewed as part of the review of the violatio e. (Closed) VIO 413,414/91-27-01: Several Examples of Configuration Control Issues The apparent violation described in NRC Inspection Report 50- '
413,414/91-27 was addressed in an Enforcement Conference held on January 15, 1992 concerning several configuration control issue As a result, a Notice of Violation and Proposed Imposition of Civil Penalty was issued on February 14, 1992 (EA 91-191) which included four other examples of failure to adequately implement plant procedures involving configuration control problems.
l l The licensee responded by letter dated March 16, 1992, that
! included corrective steps that would be taken to avoid further violations. The corrective actions adequately addressed the problems associated with the configuration control issues. All corrective actions were complete as verified by the inspecto The actions have been successful in reducing the frequency of occurrence and safety significance of component mispositioning
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f. (0 pen) IFI 413,414/91-25-01: Emergency Operating Procedure Team- ;
Inspection Items Which Require Additional Review The inspector reviewed IFI 413,414/91-25-01 to determine which ;
portions of the IFI could be close Inspection report 50-413,414/91-25 was an Emergency Operating Procedure followup inspection to inspection 50-413,414/89-09. The inspector was informed by the licensee that several of the items remained ~ open pending a rewrite of the Emergency' Operating Procedures and '
Abnormal Operating Procedures. The licensee had scheduled a completion date of June 1,1994 for the following items in 1 Appendix B of report 89-09. Item la, Ib, 2, 3, 4, and 8. These items will remain open pending review of the licensee response when the procedure revision is complet The following items. in Appendix B were closed: ,
Ic A new enclosure was added to Emergency Operating l Procedure /03 to respond to this concer Id New enclosures were added for establishing seal injection from the Safe Shutdown Facility to all ,
applicable Abnormal Operating Procedures and Emergency Operating Procedure Key numbers will be included in the procedure ]
6 The procedures are correct as writte The licensee response to not add this valve to the checkoff list because it is a normally closed valve is acceptabl ,
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9 The licensee response that the current level of ,
reliance on the Operator Aid Computer is reasonable !
and that sufficient training is provided to allow diagnosis and mitigation of accidents without the use of the OAC was considered accep';able. The inspector reviewed on the job training that required the operators to take local reading t 10 Step 13 of the procedure was changed so that ,
initiation of containment closure and containment i evacuation are the first actions taken in preparation .
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for feed and blee i Section 3a of Inspection Report 413,414/91-25 remains open pending !
further revie Section 3b was closed based on the addition of a foldout page to the procedur I i
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g. (Closed) IFI 413,414/91-19-01: Documentation of Methods Used t j
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Qualify Trainees and/or Note Deficiencies is Wea l The inspector reviewed training records and responses to all nine-items of the list generated as a result of the IFI and verified ,
that acceptable responses have been implemente ;
h. (Closed) LER 413/92-03: Technical Specification 3.0.3 Entered for L Both Units Due to Three Nuclear Service Water Pumps Being Inoperabl :
On March 16, 1992, with Units 1 and 2 at 100% power, operations I personnel began tagging Nuclear Service Water System, B Train, in ,
preparation for various work activitie During the isolation, i the crossover isolation valves were closed as intended, but no :
minimum flow path was established for the operating nuclear service water pump. The pump ran for approximately 40 minutes.in the low flow condition. Upon discovery of this alignment the Unit l
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2 Operator at the Controls immediately opened the Nuclear Service Water heat exchanger 2A inlet and outlet isolation valves and also ,
instructed the Unit 1 Operator at the Controls to open the Nuclear ,
Service Water heat exchanger IA inlet and outlet isolation valve Flow increased to approximately 10,000 gallons per minute. The 2A Nuclear Service Water pump was declared inoperable pending testing to confirm no damage had occurred. Due to three pumps being inoperable simultaneously, with the B train out of service, both .
units entered Technical Specification 3.0.3. Both trains were later returned to service and Technical Specification 3.0.3 was exited at 8 a.m. on March '.7, 1992 The licensee attributed the incident to three causes. A !
management deficiency existed due to the lack of a task specific procedure. A management deficiency existed for less than adequate' ;
verbal instructions and insufficient supervision. The operators -
failed to respond properly to a valid high discharge' pressure i alarm when the crossover isolation valves were isolate The inspector reviewed the corrective actions which included a communication package from Operations Shift Management which '
directed the shift management to include all shift personnel ,
during pre-shift briefing and reenforced the required actions.in Operations Management Procedure 1-8, Revision 18, regarding ;
operator response to alarms. In addition to calling out the annunciator alarm received, the operator was directed to state the reason for the annunciato The inspector noted that the I.ER statement "None of the previous f events involved nuclear service operations procedures; therefore, . !
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no previous corrective actions would have prevented the occurrence of this incident." did not address all the causal actions given
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for the event. It only addressed one cause and the previous LERs may have been factors in the reasons for those LER [
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The inspectors reviewed procedure OP/0/A/6400/06C, Nuclear Service Water System, to ensure that steos were included to prevent a reoccurrence of this even i. (Closed) LER 413/92-09: Technical Specification Violation Due To An Inoperable Turbine Sump Radiation Monito On July 22, 1992, a Turbine Building Sump System pipe. rupture occurred. The turbine building sump pumps were removed from service and temporary pumps were placed in the sump and began transferring the contents of the sump through temporary fire hoses. The operability of the Turbine Building Sump Discharge Monitor was questioned and it was determined to be operable since it was still capable of sampling inventory, detecting, and alarming upon detection of activity levels above the high radiation trip setpoints. However, the monitor was not operable since the trip function would not have automatically terminated flow from the sump as designed. Technical Specifications require that a grab sample be taken every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to allow discharge.,
The licensee failed to take grab samples until July 27, 199 This issue was the subject of NCV 50-413/92-21-01, documented in NRC Inspection Report 50-413/92-21, detail The inspectors reviewed the licensee's corrective actions. .The actions included; an enhancement of the red tag program to print a note on the pump tagout to evaluate operability of the monitor, a standing compensatory action to detail the necessary steps to maintain monitor operability with temporary pumps in the sump, and discussions of the event in operator requalification trainin j. (Closed) LER 414/91-12: Unexpected Engineered Safety Feature Actuation During Unit 2 Shutdown for Refuelin On October 17, 1991, with Unit 2 in Mode 1, Power Operation, while-in the process of reducing reactor power, an unexpected Engineered'
Safety Feature Actuation occurred at approximately.7:53 Control Room Operators had successfully reduced reactor power level from 100 to ~45 percent. Turbine impulse pressure was approximately 260 psig. The operators were closely monitoring turbine impulse pressure in anticipation of an automatic reset of the Anticipated Transient Without Scram Mitigation System and-Actuation Circuit (AMSAC). The automatic reset. should occur approximately two' minutes after turbine impulse pressure is less than 260 psig. When the operators realized the AMSAC did not properly reset, action was taken, per procedure, to manually bypass and deactivate the AMSAC circuit. Subsequently, an unexpected, partial actuation of AMSAC occurred. resulting in an autostart of the Auxiliary Feedwater System Pump' 2B and . isolation
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of the Steam Generator Blowdown System (and the steam generator sampling portion of the Nuclear Sampling System).
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14 Corrective Actions included operations procedure revisions, a ;
design change to preclude the relay cycling problem, and an :
evaluation.of the turbine impulse pressure indications available
'in the control roo l The inspector verified that the appropriate procedure revisions i were performed, the design change was implemented, and the ;
evaluation of the control room indications determined they were within toleranc ,
i (0 pen) LE' 414/91-14: Unit 2 Engineered Safety Feature Actuation Due to Essential Bus Undervoltage Condition-On November 5,1991, at 11:00 p.m., Unit 2 was defueled. An I Engineered Safety Feature Actuation occurred as a result of an undervoltage signal generated on A Train 4160V essential bus 2 ET The undervoltage condition was caused when one of the fuseholder connection stabs of the Undervoltage Relay Potential Transformer did not make contact with the essential bus. Subsequent investigation revealed that the connection stab had been bent as a-result of a loose fuseholder. The loose fuseholder was caused by improper removal of fuses from the.fuseholder. The licensee attributed this incident to a management deficiency, inadequate training of personnel performing high-voltage fuse remova i Planned corrective actions included the resolution of responsibility over high-voltape equipment manipulatiow, procedure ,
enhancement and development, and additional trainin l Currective actions that had been completed included the following: [
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(1) Changes were made to the Doble Test Procedure ;
MP/0/A/2004/01/AE to inspect and tighten bolts that secure .
the potential transformer fuseholder during each test, j (2) OP/l(2)/A/6350/01 was revised to include a method for verifying appropriate bus voltage before related load ,
sequencers are energized, !
(3) Unit 2, B train fuse holders were inspected during the 2E005 outage, ;
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(4) Operations has accepted responsibility for higher voltage ,
equipment manipulations. Training has been completed, and ,
(5) Tech Memos 11-31 and 21-30 were issued on 12/17/91 regardingi the importance of proper alignment of potential transformer i connection stab during the potential transformer powe ,
restoration proces [
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, Corrective action not completed; (1) Inspection of Unit 18 train potential transformer fuse holders (to be inspected during IEOC7 outage) and_ Unit IA Train potential transformer fuse holders (to be inspected during 1E0C8 outage). !
This LER will remain open until the licensee has inspected the -'
Unit 1, A and B train fuse holders to verify the material condition of these component . (Closed) LER 414/91-16: Technical Specification Violation Due to Failure of Pressurizer Power Operated Relief Block Valve 2NC-31B ,
On December 9, 1991, at 2:30 a.m., Unit 2 was in Mode 5, Cold Shutdown. The pressurizer failed to pressurize during an ,
attempted nitrogen fill. A pressurizer PORV Block Valve, 2NC-31B, was found closed with open indication preventing nitrogen flo Valve 2NC-318 remained closed because the stem had separated from the wedge assembly. The pressurizer PORVs had been closed in the auto-open mode since December 2 at 8:00 p.m. With the pressurizer safety relief valves in place, Technical Specifications require tha'. an inoperable pressurizer PORV be returned to service within 7 days or the NC system be depressurized and vented within the nex',8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Due to the failure of valve 2NC-318, one of the two P0Fis required to be operable was not available and the TS action reqeirement was not satisfied. Therefore, a TS violation occuri'd. The licensee attributed this event to equipment ,
failur The remaining Unit I and 2 pressurizer PORV block valves were radiographed to verify they were open. Valve 2NC-318 was ,
replaced and an analysis of the failure of the stem was performe '
Interim corrective actions included verification of block valve ,
position following stroke tests by radiograph Corrective actions that had been completed included the following:
(1) A detailed failure analysis was performed on the failed j stem. The root cause of the stem failure was material 4 degradation (embrittlement) caused by exposure of a susceptible material (17-4PH) to high temperatures (650'F) i combined with high stress loads imposed by the motor operator on the " tee-head" portion of the valve ste '
(2) A temporary procedure required radiography of the pressurizer block valves after each valve stroke for verification of disk position. This procedure applied until the valve stems were replaced with stems manufactured from a -i more suitable material (Inconel) duriag the IE0C6 and 2E005 j outages. A new procedure requires visual stroke and '
radiography every two year (3) Other valves manufactured from similar material that were l
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potentially exposed to a high-temperature environment were ;
evaluated for vulnerability to the same degradation. No corrective actions were required and adequate justification was provided for this determination for each valve evaluate '
(4) The licensee is continuing sample inspections of 17-4PH materials in less severe applications to ensure that no new problems are identifie Corrective actions not completed:
(1) The licensee plans to revise Specification DPS-1205.00-00-0002 to include a precautionary note concerning the use of 17-4PH stems in high-temperature applications. Inspector .
evaluation of corrective action status determined that actions completed to date were sufficient for this LER to be i close ;
m. (Closed) LER 414/92-01: Turbine / Reactor Trip as a Result of Possible Equipment Failure / Malfunction During Main Turbine Hydraulic 011 System Testin This issue involved a reactor trip as a result of a turbine tri The turbine tripped because of a momentary loss of hydraulic ;
system oil pressure during a Main Turbine Hydraulic System Weekly Trip Test. The system is equipped with two 100% variable-delivery hydraulic oil pumps. During the course of the test the test push ,
button was depressed which caused the standby pump to start as-required. A momentary decrease in oil pressure below the trip set point caused the turbine trip and a reactor tri The inspector discussed the corrective actions with the system l engineer and found'that the conditions were not able to be duplicated on subsequent testing. The licensee's corrective ;
actions were: add a two second time delay on low hydraulic fluid '
pressure trip, change the heater cut-on from 85 to 100'F, change-the alarm set points on the computer from 65/150*F to 95/145'F, replace the 2A hydraulic oil pump, replace the air' bleed valve, replace suction piping-with a continuous _ section of piping, ,
replace the pump compensator and remove the pump inlet straine !
The actual cause of the low pressure was not determined. The !
inspectors verified that the corrective actions had been complete j c
The inspector noted that the LER discussed the fact that the unit response to the trip was normal with the exception that all four S/G levels dropped below the to Lo level setpoint causing the !
Auxiliary Feedwater system to actuate. There was no discussion i l the LER as to why this occurred. The inspector discussed this ;
fact with the licensee and determined that although the described .;
conditions existed following the trip, it should not have been 1
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considered abnormal. The auxiliary feedwater system generally actuates following a reactor trip from high power levels on
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i No violations or deviations were identifie . EXIT INTERVIEW The inspection s' cope and findings were summarized on November 10, 1993, ,
with those persons indicated in paragraph 1. The inspector described the areas inspected and discussed in detail the inspection findings listed below. No dissenting comments were received from the license The licensee did not identify as proprietary any of the materials ,
provided to or reviewed by the inspectors during this inspectio ,
Item Number Description and Reference IFI 413/93-27-01 Nuclear Service Water Flow Degradation (paragraph 5.)
9. ACRONYMS AND ABBREVIATIONS AMSAC - Anticipated Transient Without Scram Mitigation System and Actuation Circuit CFR Code of Federal Regulations CNS -
Catawba Nuclear Station CSRG - Catawba Safety Review Group DPC -
Duke Power Company E0C -
End of Cycle IAE -
Instrument 'and Electrical IFI -
Inspector Follow-up Item ISEG - Independent Safety Engineering Group LER -
Licensee Event Report MMP -
Maintenance Management Procedurt NCV -
Non-Cited Violation NLO -
Non-Licensed Operator 0AC -
Operator Aid Computer OP -
Operating Procedure'
PIP -
Problem Investigation Process
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PORV - Power Operated Relief Valve PSIG - Pounds per Square Inch Gauge PT -
Periodic Test )
R&R -
Removal and Restoration (Tagging Order) :
RCS -
Reactor Coolant System 1 RHR -
Reactor Operator l SG -
SR0 -
Senior Reactor Operator TS -
Technical Specifications
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TSM- - Temporary Station Modification !
URI -
Unresolved Item WO -
Work Order WR -
Work Request j
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