IR 05000413/1998007
| ML20236V748 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 07/27/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20236V728 | List: |
| References | |
| 50-413-98-07, 50-413-98-7, 50-414-98-07, 50-414-98-7, NUDOCS 9808040183 | |
| Download: ML20236V748 (44) | |
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l U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-413. 50-414 License Nos: NPF-35, NPF-52 Report No /98-07. 50.414/98-07 !
Licensee: Duke Energy Corporation Facility: Catawba Nuclear Station. Units 1 and 2 Location: 422 South Church Street Charlotte. NC 28242 j Dates: May 24 - July 4. 1998 Inspectors: D. Roberts. Senior Resident Inspector R. Franovich Resident Inspector M. Giles. Resident Inspector (In Training)
W. Stansberry. Physical Security Specialist. RII (Sections S1, S2. and S3)
G. Wiseman Reactor Inspector. RII (Sections F1.1 - F8.3)
Approved by: C. Ogle. Chief Reactor Projects Branch 1 Division of Reactor Projects I
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Enclosure 2
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9808040183 900727 PDR ADOCK 05000413 G PDR i
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EXECUTIVE SUMMARY l Catawba Nuclear Station. Units 1 and 2 l NRC Inspection Report 50-413/98-07. 50-414/98-07 This integrated inspection included aspects of licensee operation ' maintenance, engineering. and plant support. The report covers a 6-week period of resident ins)ection: in addition, it includes the results of l announced inspections )y a regional reactor safety inspector and a physical security specialist. [ Applicable template codes and the assessments for items inspected are provided.]
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Ooerations
. In general, plant operations were conducted wel (Section 01.1:
'[1A - POS])
. A violation was identified for inadequate operating and abnormal operating procedures related to the operation of condensate system valve ICM-127 and design basis implications for the auxiliary feedwater l
system. (Section 08.1: [1C, 4A - VIO])
. The loss of control power to the Unit 1 turbine-driven auxiliary l feedwater pump on November 17, 1997-. did not render the system l inoperable. The licensee pursued aggressive corrective actions once the l
deficiency was identified. (Section 08.2: [5C - POS])
l . Unit I was shutdown on June 27, 1998, in order to repair a pipe leak i associated with auxiliary feedwater nozzle tempering flow to the C steam generator. (Section 01.1: [2A - NEG])
Maintenance l . In general, maintenance and surveillance activities were performed well f with proper adherence to procedural compliance, equipment calibration.
i and radiation protection requirements. The inspectors noted that the l welding procedure used during the repair to Unit 1 auxiliary feedwater
! tempering flow piping contained adequate precautions on the use of purge paper as damming material. (Section M1.1: [2B.3A - POS])
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. An inspector followup item was opened to address gas accumulation in i
emergency core cooling system discharge piping, as well as the adequacy
'of related venting procedures. (Section M1.1)
j e The licensee's inaction to address the loss of power range nuclear l instrument accuracy during end-of-life moderator coefficient testing to
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ensure that reactor trip setpoints would remain valid caused the high flux reactor trip function to be in a degraded condition for over four hour (Section M1.2: [1A. 2A, 3C - NEG])
. An unresolved item was opened pending further NRC review of the implications for power range nuclear instrument operability and compliance with Technical Specification surveillance requirements during L _ -_----- _ -_----_-- - _ - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ---------- --- --
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l the conduct of an end-of-core-life moderator temperature coefficient
- tes (Section M1.2: [3A - URI])
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A non-cited violation was identified for failure to have adequate slave
! relay test procedures for containment sump recirculation valves. cold leg accumulator valves, and component cooling water containment isolation valve (Section M8.2: [4C - NCV: SC - POS])
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The licensee took conservative actions re arding Technical Specification Limiting Condition for 03eration entry fo lowing the identification of a pin-hole leak in two-inc1 auxiliary feedwater tempering flow piping.
l The leak was effectively repaired during the subsequent Unit 1 forced outage. The licensee's short and long-term corrective actions were adequate. (Section E2.1 [48, IA. SC - POS])
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A violation was identified for failure to take prompt corrective actions to prevent recurrence of a significant condition adverse to quality for the May 7, 1998, upper surge tank over-temperature even (Section E8.1-
[5A, SC - VIO])
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A non-cited violation was identified concerning the inoperability of the Unit 10 steam generator main steam isolation valve between March 1995 and August 1996. (Section E8.2: [1A. 2A, - NCV: SC - POS])
Plant Sucoort
. The licensee's redesigned alarm stations and new personnel access control system to the protected and vital areas met the criteria of the current Nuclear Security and Contingency Plan and appropriate security procedures. (Section S1: [1C. 2A.- POS])
. The licensee used testing and maintenance programs and procedures that would ensure the reliability of the new security equipment and device (Section S2: [1C. 2B - POS])
. In prep 1 ration of implementing Revision 7 of the Physical Security Pla the licensee had appropriate compensatory measures for potential failures of the new security equipment or for impaired equipment performanc (Section S2: [1C - POS])
. The new and revised security procedures reviewed did not decrease the effectiveness of the Nuclear Security and Contingency Plan. (Section S3: [1C - POS])
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. During 1997 and 1998, there were a low number of incidents of fire !
within safety-significant plant areas. When fires occurred, licen.see !
personnel identified and extinguished the fire in a timely manner and !
prevented the' fires from spreading to other equipment or cable l (Section F1.1: [3B - POS])
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The implementation of procedural requirements for using and storing transient combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly implementing their responsibilities for combustible material control. (Section F1.2: [2A - POS])
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The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant workers. (Section F1.2: [3A
- POS])
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The general material condition of the fire pumps and the fire protection water supply was goo (Section F2.1: [2A - POS])
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The physical separation of the redundant fire pumps was well maintained and met the criteria described in the Updated Final Safety Analysis Report. (Section F2.1: [4A - POS])
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Sufficient procedural guidance was provided to verify that the reactor coolant pump oil collection tanks were normally maintained empty and that the plant operators could identify an oil leak from the lubrication system of any one of the reactor coolant pump motors and take a]propriate action. The reactor coolant pump oil collection system met t1e performance criteria of 10 CFR 50. Appendix R.Section II (Section F2.2: [1C - POS]).
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The low number of inoperable or degraded fire protection components indicated that appro]riate emphasis had been placed on the maintenance and operability of t1e fire protection equipment and component Impaired fire timely manner. protection components (Section F2.3: [2B - POS]) had been restored to service in a
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A non-cited violation was identified for failure to maintain required fire barrier penetration seals operable between areas containing redundant safe shutdown equipmen (Section F2.4: [4A - NCV: SC - POS])
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The scope and content of the inspection and surveillance test program procedures for the fire protection hose stations and standpipes were sufficient to ensure that the fire protection design and surveillance water flow requirements specified in the Updated Final Safety Analysis Report were met. (Section F3.1: [1C - POS)]
. A non-cited violation was identified for failure to conduct the required l inspection of fire hose gaskets. (Section F3.2: [2B - NCV: SC - POS])
- . The maintenance inspection and surveillance test orogram for the l emergency eight-hour battery lighting system was sufficient to ensure that the emergency lighting performance criteria established in the Updated Final Safety Analysis Report and 10 CFR 50, Appendix R. were met. (Section F3.3
- [2B - POS])
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The fire brigade organization and drill program met the requirements of the site procedures. The performance by the fire brigade as documented by the licensee's drill evaluations was good. (Section FS.1: [1C. 3B -
Pos])
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The 1998 Triennial Fire Protection Audit of the facility's fire protection program was comprehensive and effective in identifying fire protcction program performance to plant management. (Section F7.1: [5A
- POS])
. The licensee complied with the guidance provided by NRC's Generic Letter 86-10 when the fire protection equipment operability and surveillance requirements were removed from the Catawba Technical Specifications and relocated in the Catawba Selected License Commitments. (Section F8.2:
[4C - POS])
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The licensee's fire protection impairment and surveillance program implementation was good in that impaired fire protection features had been restored to service in a timely manner. (Section F8.2: [2A 2B -
POS])
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Reoort Details Summarv of Plant Status Unit 1 began the period operating at 100 percent power. On May 28, 1998. a power reduction was initiated when a hotwell pump discharge temperature high alarm setpoint of 128 F was reached. Power was reduced to 95 percent in order to _ decrease the discharge temperature below the setpoint to maintain auxiliary feedwater system operability. Hotwell pump discharge temperature had increased following the removal from service of the 1C1 heater drain pump, which had experienced high motor winding temperatures. Following the replacement and return-to-service of the heater drain pump motor. hotwell temperatures returned to normal and the unit was returned to 100 percent power on May 31, 1998. The unit operated at 100 percent power until June 28. 199 when it was shut down to Mode 3 (and subsequently Mode 4 on June 29) in order that a through-wall pin-hole leak, which had developed in the 1C steam generator auxiliary feedwater tempering flow piping, could be repaired. The leak developed in an elbow fitting that was cut out and replaced. Unit restart was commenced on June 30. 1998, and the reactor was taken critical on July 1. 1998. The Unit reached 100 percent power on July 2. 1998, and operated at that level for the remainder of the inspection perio Unit 2 operated at or near 100 percent power until June 6. 1998, when a power reduction was initiated in preparation for end-of-life (EOL) moderator temperature coefficient (MTC) and turbine control valve movement testin Power was reduced to 93 percent for the MTC test and subsequently 88 percent for control valve testing on June 7. 1998. Following completion of both evolutions, power was increased to 100 percent on June 8, 1998. After the licensee identified concerns regarding the accuracy of the EOL MTC test results, power was again reduced to 93 percent on June 9. 1998, to re-perform the test. After successful completion, the unit was returned to 100 percent power on June 10, 1998, where it operated for the remainder of the inspection perio I. Operations 01 Conduct of Operations 01.1 General Comments (71707)
The inspectors conducted frequent control room tours to verify proper staffing. operator attentiveness and communications, and adherence to approved procedures. The inspectors attended operations shift turnovers and site direction meetings to maintain awareness of overall plant status and operations. Operator logs were reviewed to verify operational safety and compliance with Technical Specifications (TS).
Instrumentation and computer indications were periodically reviewed, i
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i 2 along with equipment removal and restoration records, to assess system availability. The TS Action Item Log books for both units were reviewed for potential entries into limiting conuitions for operation (LCO)
action statements. The inspectors conducted plant tours to observe material condition and housekeepin Problem Identification Process
' reports (PIPS) were routinely reviewed to ensure that potential safety
_ concerns and equipment problems were resolve Unit 1 was shut down'on June 28, 1998, in order to repair a piae leak associated with auxiliary feedwater nozzle tempering flow to t1e C steam generator (refer to Section E2.1 for a discussion of the pipe leak).
The inspectors observed the Unit 1 startup on June 30. 1998. The i startup was conducted in accordance with governing procedure The ins)ector noted that a high flux at shutdown alarm was received during l wit 1drawal of the shutdown bank The alarm setpoint was y decade above l the steady-state count rate and is required by TS 3.3.3.11 to be available when a train of the boron dilution mitigation system (BDMS) is inoperable during modes 3. 4, and 5. The licensee attributed the alarm
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to an overly conservative alarm setpoint, which had been calibrated when the reactor coolant system temperature and the steady-state count rate i were significantly lower. Unit startup was delayed until the alarm
[ setpoint was recalibrates at normal operating temperature. The
- inspectors determined that the Unit 1 'A' train of BDMS had been l inoperable since January 1998 and that the delay in restart would not
! have been necessary if it had been operabl In general, plant operations were conducted wel No violations or deviations were identifie .2 Ooerations Clearances (71707)
The inspectors reviewed the following clearances during the inspection
- period
- Tagout 08-1157 Control Area Chilled Water System
. Tagout 08-1156 Clean RN to YC Chiller A
. Tagout 08-1159 YC Chiller A RN Su) ply Isolation
. Tagout 18-1287 Feedwater System (Repair pin hole leak in piping)
l The inspectors observed that the clearances were properly prepared and :
authorized and that the tagged components were in the required positions with the appropriate tags in place. The inspectors informed the control room shift of concerns associated with a continuing steam leak fol h ing the isolation of a pin-hole in auxiliary feedwater tempering flow piping i (Tagout 18-1287). The lice-see took steps to address the concerns: no {
nuclear safety issues were identifie j i
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08 Miscellaneous Operations Issues (92901)
08.1 Auamented Insoection Team Findinas Related to Vooer Surae Tank (UST)
Over-Temperature Event (See Section E8.1 for related issues regarding l similar events / prior opportunities to prevent recurrence.)
The following discussion provides the results of additional NRC review of operational issues related to the May 7, 1998. Unit 1 UST over-temperature event previously discussed in Augmented Inspection Team i Report 50-413.414/98-06. Further discussion of engineering aspects l related to the event is provided in section E8.1 below. A detailed l system description of key components affected by this event was provided l in Inspection Report 98-06, i
On May 7,1998, control room operators were in the process of rapidly reducing Unit 1 power following the identification of an instrument air l leak affecting main feedwater regulating valve 1CF-55. Since main i feedwater flow to the steam generators is proportional to reactor power.
l condensate and feedwater flow rates were affected. At approximately 40 l percent power, as the operating condensate booster pump flow rates I
approached shutoff values, valve ICM-127 (condensate booster aump
- minimum flow to UST) opened providing recirculation flow to tie UST l dome. As indicated by computer alarm, this resulted in high temperature (~320 F) condensate to the UST, which reached a peak temperature of 234 F. This was in excess of the 138 F design temperature limit for auxiliary feedwater (AFW) suction sources, as well as the Unit 1 UST and l associated piping. Since the UST is a preferred non-safety suction source for the AFW system, the elevated temperature created a condition that was outside the design basis of the UST. Consequently, the AFW system was degraded with respect to performing its intended safety function of mitigating the consequences of a design basis accident.
l This condition existed for approximately three hours until operators determined that the controller setpoint for valve ICM-127 was improperly l set to 14,000 gallons per minute (gpm) instead of the prescribed 5,500 gpm setting.. Operators adjusted the controller setting and returned UST temperature to normal. All three Unit 1 AFW pumps were declared inoperable until further analyses could be performed. The AFW system remained available to provide water to the steam generators, although
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there was a reduced heat removal capacity due to the elevated UST temperatur Pneumatic control valve ICM-127 provides condensate booster pump minimum flow protection when the pump flow rates approach shutoff conditions by 3roviding an alternate flow path from the discharge of the condensate
)ooster pumps to the UST. Valve ICM-127 receives a signal of condensate booster pump flow rate from the discharge of the booster pumas. The valve automatically opens when condensate system flow drops )elow the digital controller setpoint. The controller is normally set at 5500 gam per station operating procedures. This flow path to the UST may also ae
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used during condensate system startup for low pressure (short cycle)
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Based on reviews of Work Management System information. the controller for ICM-127 had been placed in " Manual" mode on A]ril 17. 1998, to perform troubleshooting activities associated wit 1 elevated secondary system dissolved oxygen. The initial valve position from the controller was recorded as " Auto" and " Closed." Following the troubleshooting l
activities, the controller was returned to the " Auto" and " Closed"g l
position: however. according to the information reviewed. the setpoint was not readjusted to the prescribed 5500 gpm setting. The controller
.for 1CM-127 has a "bumpless transfer" feature. When the controller was
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taken from automatic to manual. the controlling setpoint automatically L adjusted to the process flow value which has a top of scale value of
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14.000 gpm. When the controller was returned to automatic, the top of l
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scale process value became the controlling setpoint. This controlling setpoint will remain unchanged unless another value is entered by the operator. The incorrect flow rate setting of 14.000 g approximately two weeks without operator recognition.. pm The remained higher for setpoint allowed ICM-127 to open prematurely during the power reduction l
while condensate system temperatures were high enough to impact UST/AFW
! operability.
! The inspection team reviewed procedures in use and available to
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operators during the event and determined that the procedures (0Ps and APs) did not include: (1) detailed instructions on the operation of the digital controller related to the above-described bumpless transfer for valve ICM-127: (2) verification that AFW suction source temperatures are maintained below 138 degrees F: and (3) clear and definite instructions regarding t M inoperability of the AFW system when suctinn source temperatures exceeded 138 degrees F. Problem (1) involved Procedure OP/1/A/6250/001. Condensate and Feedwater: problem (2) involved Procedure OP/1/A6250/002. Auxiliary Feedwater: and problem (3) involved Abnormal Operations Procedure AP/1/A/5500/006. Loss of Steam Generator Feedwate The failure to have adequate procedures addressing AFW system design basis temperature limits and operation of valve ICM-127 is contrary to the requirements of TS 6.8.1 and is identified as Violation (VIO) 50-413/98-07-01: Failure to Have Adequate Operations Procedures Addressing AFW System Design Temperature Limits and Operation of Valve ICM-12 .2 (Closed) Unresolved Item (URI) 50-413/97-14-01: Control Power Unavailable to the Unit 1 Turbine-Driven AFW Pump (TDAFWP) Trip and Throttle Valve The inspectors reviewed the licensee's operability evaluation concerning blown control power fuse FU-2 associated with the Unit 1 TDAFWP trip and throttle valve (ISA-145) identified by the inspectors on November 17 1997. The blown fuse caused a loss of control power for 1SA-145 from both the turbine control panel and the standby shutdown facility. The blown fuse also rendered the electrical overspeed trip function los The evaluation concluded that the operability of the AFW system was not affected by the loss of control power or electrical overspeed tria function for 1SA-145. The loss of control power did not affect t1e
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pump's ability to automatically start on an AFW actuation signal, but the loss of the electrical overspeed trip function potentially impacted accident mitigation for events where more AFW flow is undesirabl The licensee evaluated accident conditions which requirua securing TDAFWP flow to the steam generator The licensee's evaluation considered the amount of increased flow to the steam generators as a result of the loss of the electrical overspeed trip function. The evaluation concluded that, even with the increased flow margin between the unavailable electrical overspeed trip function and the mechanical overspeed trip function (which had not been affected, but had a-higher trip setpoint), the' loss of the electrical function aid not affect operability. The licensee's operability conclusion was further based on other available means for securing flow from the TDAFWP to the steam generators. The inspectors reviewed the evaluation and identified no concerns or discrepancies. The inspectors verified that no potentially conflicting statements were contained in the UFSAR, Chapters 6.10. or 1 The TDAFWP's primary safety function to provide a minimum feedwater flow to the steam generators during accidents was not degraded since the valve was normally open and remained o)en during the loss of control power. The inspectors' concern that t1is degraded condition was not identified by plant operators was also discussed in PIP 1-C97-3684. The licensee addressed this concern by revising its control board checklis OMP 2-22. Shift Turnover. which now requires operators to verify that the TDAFW pump control power light. labeled "DC Power On~. is illuminated on-the main control boar The licensee also attempted to determine the root cause of the fuse failure by duplicating the circuit on a test bench. Fuse FU-2 is rated
- for 5 amps and normally carries approximately 41 milliama Personnel
- attempted to create a short circuit by replacing a light)ulb in the test circuit with different types and by wiggling the bulb vigorously to create an overload condition. It had been postulated that operators may have caused the biown fuse on November 17. 1997. when initially replacing the bulb after the inspectors' discovery. The fuse failure could not be duplicated. and the licensee's hypothesis that the operators caused a short circuit was considered unlikely. The licensee
~ did not conclusively determine the root cause of the blown fuse, but provided guidance to operators on how to address future losses of control power indication and preserve evidence. A small placard was placed near the "DC POWER ON" indicating lamp for each unit requiring operators to refer to OMP 2-16. Control Rocm Conduct. Revision 17, which was modified to include precautions to take 3rior to changing the light-bulb. such as verifying control power availa)le from the TDAFW pump control panel or the standby shutdown facility and notifying engineerin The inspectors concluded that the loss of control power to the Unit 1 TD AFW pump on November 17, 1997, did not render the system inoperabl The licensee pursued aggressive corrective actions once the deficiency l
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was identifie No violations or deviations were identifie This URI is close II. Maintenance M1 Conduct of Maintenance M1.1 General Comments on the Conduct of Maintenance and Surveillance Activities (62707. 61726)
The inspectors observed portions of the following maintenance and surveillance activities:
. IP/1/A/3145/005 Calibration Procedure for Containment Spray Wide Range Pressure (NS). Approved April 25. 1996
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IP/2/B/3630/0018 D/G-2B Engine Intake and Exhaust System (VN)
(calibration of chart recorder)
. SM/0/A/8140/001 Welding of OA Piping. Valves and Components (Repair effort for pin-hole leak in auxiliary feedwater tempering flow piping). Revision 002
. PT/2/A/4200/006B ECCS Valve Lineup Verification, Revision 30 In general, the referenced maintenance and surveillance activities were performed well with proper adherence to procedural com)liance, equipment calibration. and radiation protection requirements. T1e inspectors noted that the welding procedure used during the repair to Unit 1 AFW tempering flow piping contained adequate precautions on the use of purge j paper as damming materia s The Unit 2 emergency core cooling system (ECCS) valve lineup verification procedure (PT/2/A/4200/006B) was conducted on June 2 . to meet the monthly high point venting requirement contained in TS i 4.5.2.b.(1). The inspectors observed test personnel access several high point vents in the charging, residual heat removal (RHR), and safety injection systems, to relieve air or gas and ensure that piping was full j of water. All accessible test points required by the )rocedure were free of air or gas except two high Joint vents on disc 1arge piping from the 2A residual heat removal (RHR) leat exchanger. Gas was vented from valve 2ND-30 (Train 2A cold leg injection return test vent) for approximately one to two minutes with the valve a quarter-turn ope Much less gas was vented from 2ND-120 (RHR hot leg return cross-connect). The licensee issued PIP 2-C98-2326 to document this problem and request an operability evaluation from engineering.
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The licensee preliminarily determined the source of the gas to be a I known leak from the 2C cold leg accumulator (CLA). Tne licensee hcd i I
been filling the 2C CLA once every three to four days since May 2 '
1998. due to suspected leakage by certain check valves in the syste The licensee informed the inspectors that no air or gas had previously '
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7 been detected from the two high point vents in recent months. The o]erability evaluation was completed within three days and determined !
t1at ECCS system operability was not affected. The inspectors had not reviewed the licensee's operability evaluation by the close of the inspection perio The inspectors reviewed the surveillance procedure carefully and noted that venting from 2ND-120 was only required if gas was vented from 2ND-29 or 2ND-30. Several other accessible high point vents were also conditional, including 2ND-14. 2ND-121. 2ND-122, 2ND-42, 2FW-67. 2FW-68, 3 and corresponding valves in the Unit 1 procedure. The inspector reviewed isometric drawings, noted that 2ND-120 was at an elevation approximately two ' feet higher than 2ND-30. and considered that it was possible for air or gas trapped in the 2ND-120 piping to go undetected if venting the line was contingent on the ]resence of gas in a line at lower elevations. The inspectors raised t1is concern with engineering personnel cognizant of the procedure and were told that the only way for gas to get into 2ND-120 piping and not be in 2ND-30 piping was if maintenance activities involving breaches of 2ND-120 piping were not properly controlle The inspectors concluded that further inspection of this issue was warrante This further inspection will include a review of the licensee's operability evaluation for the gas present in the two high !
point vents in RHR piping. a review of previous months' vent procedure results for potential adverse trend implications, a review of the licensee's plans to correct known leakage from the 2C CLA and a further i review of surveillance test procedures to determine if they meet the intent of TS 4.5.2.b.(1). This issue will be tracked as Inspector Followup Item (IFI) 50-413.414/98-07-02: ECCS High Point Vent Procedure / Gas Vented from RHR Discharge Pipin M1.2 Inaccuracy of Nuclear Instrumentation Durina Moderator Temperature Coefficient Testina Insoection Scooe (61726)
On June 9,1998. the licensee performed the end-of-core-life calculation >
of moderator temperature coefficient (MTC) for Unit 2 using Procedure .
PT/0/A/4150/12B. Revision 7. Moderator Temperature Coefficient of '
Reactivity Measurement. The inspectors observed the performance of the test, reviewed the test procedure and results and reviewed applicable TS.
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, Observations and Findinas l
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The procedure involved borating the reactor coolant system (RCS) to i reduce T defined @ RCS by a temperature predetermined and amount of 6 F from an boron concentratio Theinitial differencetest state in boron concentrations based on sample results between the intermediate and the initial test states was calculated based on primary sample results, and the temperature was increased to its original value by l
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boron dilutio Boron samples were again obtained to determine the from the intermediate value amount to ofvalu the final boric acid This required manipulation tooraise T,f,T.,, was accomplished whij reactor power (as indicated by thermal power best estimate calculation, or calorimetric) was held constant, tinally, a reactivity balance was j
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performed using the results of the bcron-induced temperature !
manipulations, and values of other p rameters affecting reactivity. The June 9. 1998, test was a repeat performance of one conducted two days earlier, because of concerns from reactor engineering personnel about the accuracy of RCS sample results from the first tes The Ts, reduction during each test had an attenuating effect on excore neutron detectors, specifically the power range nuclear instruments (PRNIs) were indicating values less than actual reactor power. The colder, denser RCS water created a shielding effect which reduced the amount of neutron flux detected and indicated by the PRNI Effectively, for every one degree of T reduction, the PRNIs sensed 0.8%lessthanactualreactorpower(aNhoughreactorpowerwasheld constant). Actual reactor power was estimated by the plant computer using a secondary flow balance (the calorimetric), and the computer provided continuous indication in the control room. Since the reduction in T ,, can cause steam pressure to decrease, operators placed the turb,ine control system in megawatt feedback mode to allow the control valves to open as T was changed. Thus, calorimetric indication was c and, unlike the PRNIs. provided a notimpactedbythe.,,hangeinT,f,actualreactorpowe reliable and accurate measure o TS 3.3.1 requires a minimum of three PRNI channels to be operable with a high flux trip atpoint while in Mode 1. The corresponding surveillance requirement, as stated in TS 4.3.1 requires the excore PRNIS to be calibrated daily by comparing the calorimetric indication to indicated excore power and, if the absolute difference is greater than two percent, adjusting the excore channel gains so the PRNI indication is consistent with calorimetric power indication. . During the test on June L 9,1998, the attenuation phenomenon caused all four PRNIs to indicate i nonconservatively in excess of two percent below actual calorimetric l power for over four hours. During this time, the difference between actual power and the PRNIs was as high as between four and five percen When questioned by the inspectors, the licensee stated that TS 4.3.1 did not apply during transient conditions. The licensee invoked a pre-existing TS Interpretation (TSI).. which said that during power maneuvers a non-conservati; e mismatch (between PRNIs and calorimetric) can occu The plant should be allowed 30 minutes to stabilize before comparing the two. If at that point the mismatch is greater than two percent, then an adjustment to the excore channel gains shall be performed, unless i_ another planned power maneuver commences within six hour The day after the test, the licensee issued a statement later documented in PIP 0-C98-2045, claiming that further basis for the non-applicability )
of TS 4.3.1 during transient conditions was the fact that the calibration check was only required once per day, not continuously as
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one might infer from having to adjust the PRNIs to within continuously-provided calorimetric data during the MTC test. The licensee also referenced a June 13, 1990, letter from Westinghouse which stated that excore comparison to calorimetric is only meaningful during steady state conditions. The letter stated that the mismatch was not assumed to be less than or equal to two percent during an anticipated transient or I expected mode of operation resulting in significant power level changes.
i The inspectors noted that the MTC test evolution did not involve a i
' significant (or any) power level change. The planned test did not involve a power maneuver (as referenced in the TSI): it involved a controlled temperature evolution while reactor power was held constan The inspectors also considered that when planned evolutions result in degraded conditions for which specific TS 3arameters are not met, l a)propriate action requirements apply at t1e time of discovery, even if l l
tlat time occurs before the next due surveillance interval. The TSI had been approved on September 24, 199 The inspectors concluded that no
- such exemption from the calibration check requirement was explicitly or implicitly provided in the TS or the TS Bases.
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- TS 2.2.1 requires that Reactor Tri) System Instrumentation shall be set i
' consistent with values shown in Ta)le 2.2.1. This table lists the Power Range Neutron Flux High Trip Setpoint as less than or equal to 109 percent with an allowable value of less than or equal to 110.9 percen With the PRNIs indicating nearly 5 percent less than actual reactor l
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power, the effective trip setpoints (which were not adjusted prior to the test) were possibly as high as 114 percent during the test. The
- inspectors acknowledged that the licensee reduced reactor power. to 93
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percent several hours before the test commence However, this was done
- , to provide operating margin to the trip setpoint and did not reduce the i
trip set)oint to ensure that it would remain within TS 2.2.1 limits during t1e conduct of the test. The inspectors noted that the a)plicable TS Bases stated that the high flux setpoint trip from the PRNI flux channels provided protection during power operations to mitigate the consequences of a reactivity excursion from all power
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levels. The licensee did not conservatively reduce the high flux trip setpoints pricr to the test to ensure that design basis accidents for which a high flux trip is assumed were not affecte !
l The inspectors learned that other nuclear facilities use a smaller '
reduction in Tm to obtain intermediate point test data to minimize the impact of excore detector attenuation. One facility included an option to adjust the gain for the PRNIs in the conservative direction (but
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- still within the two percent limit) to ensure that the attenuated test i values would not exceed the two percent limit in the nonconservative l
direction. The inspectors noted that the licensee did not take any such steps on June 9.1998, to ensure that TS requirements were met during {
the conduct of the tes l l
On June 5.1998, two days before the first test the licensee had I generated PIP 0-C98-2045 questioning the validity of the TSI and I requested an internal staff review. The licensee had not resolved this l
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issue before the tests were conducted on June 7 and 9. 1998. Personnel performing the test proceeded in accordance with the TSI, absent further communication from management on the pending question concerning the-appropriateness of the TSI. Licensee management's. final conclusion of t1e TSI's validity (and accompanying position statement) was not developed until the day after the second test was completed. .In the interim, the licensee' did not pursue an interpretation from the NRC. nor did it pursue a Notice of Enforcement Discretion or a TS change to incorporate an exemption to 15 3.3.1 if one was require The inspectors questioned the operability of the four PRNIs for the four hour period during which the 2% deviation from the calorimetric indication was exceeded. Pending further NRC review, this issue is characterized as URI 50-413.414/98-07-03: Nuclear Instrumentation Deviation from Calorimetric During Moderator Temperature Coefficient Test. The inspectors noted that any potential inoperable condition was cleared within five hours, before the LCO to be in Hot Standby would have expired (seven hours).
l ' Conclusions The inspectors concluded that the licensee's inaction to address the loss of PRNI accuracy to ensure that reactor trip setpoints would remain valid caused the high flux reactor tria function to be in a degraded condition. In addition, all four c t1e PRNIs may have been inoperable i
for over four hours during the test, thereby placing Unit 1 in TS 3.0.3.
l This issue constitutes an unresolved item pending further NRC review of
.the implications for PRNI operability and compliance with TS l surveillance requirements during MTC testing.
l M8 -Miscellaneous Maintenance Issues (92902. 92700, 90712)
M (Closed) LER'50-414/96-01: Loss of Offsite Power Due to Electrical Failure This LER (which was discussed in NRC Inspection Report 50-413.414/98-05)
documents a loss of offsite power (LOOP) that resulted from ground faults on the resistor bushings for 2A Main Transformer X-phase potential transformer and 2B Main Transformer Z-phase )otential transformer. The inspectors verified that 3rocedures lad been updated to implement enhancements to the isolated plase bus system and transformer yard equipment preventive maintenance programs. Corrective actions associated with this item have been satisfactorily complete The LER is close M8.2 (Closed) LER 50-413/96-002-00: Technical Specification 3.0.3 Entries Due to Inconclusive Surveillance Testing This LER documented -inadequate quarterly slave relay testing associated with both trains of containment sump recirculation isolation valves on
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both units. Multiple electrical continuity paths existed for valves 1(2)NI184B and 1(2)NI185A. The continuity path associated with the slave relay being tested for each valve had not been isolated during previous surveillance testing. As a result the licensee could not determine conclusively that the tested relay (and not the parallel circuit path) was actually operating the aforementioned valves. Upon discovery of the testing deficiency on May 3,1996, the licensee declared both trains of valves inoperable and entered TS 3.0.3 and 4.0.3. Following revisions to applicable surveillance procedures. the valves in both units were tested successfully and declared operable within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> The licensee later discovered on May 4. 1996, similar discrepancies with test procedures for the cold leg accumulator discharge isolation valves 1(2)NI54A. 1(2)NI658. 1(2)NI76A. and 1(2)NI88B. Although the valves were normally open and deenergized when the cold leg accumulators were required to be operable, the valves still received an open signal via slave relays in the solid state protection system during a safety injection. The valves were declared inoperable and TS 3.0.3 and 4. were entered. Again, test procedures were revised to properly verify that the associated slave relays changed states. Testing was successfully completed and the valves were declared operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
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Finally. on May 6. 1996, the licensee discovered a similar testing
problem with component cooling water system containment isolation valves associated with the supply and return headers to reactor coolant pump coolers. The valves 1(2)KC338B. 1(2)KC424B. 1(2)KC425A were declared inoperable. test procedures were revised, and the valves successfully retested within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> All of the above testing deficiencies involved Procedure PT/1(2)/A/4200/09A. Auxiliary Safeguards Test Cabinet Periodic Test, and were documented in PIP 0-C96-104 The inspectors determined that the quarterly testing deficiencies had minimal consequences based on the fact that the affected slave relays operated properly when retested with corrected procedures. Additionally, the components had been verified to actuate pro)erly during 18-month engineered safety feature testing. The failure to 1 ave adequate procedures for performing quarterly slave relay
! testing was considered a violation of TS 6.8.1. At the time the above
discrepancies were identified, the licensee had not yet completed its broad review of safety-related logic circuit testing procedures in accordance with Generic Letter 96-01. Subsequent logic testing deficiencies have been identified and were dispositioned in NRC Inspection Reports 50-413.414/97-11 (violation) and 97-15 (non-cited violation). Because the above examples pre-dated these subsequent findings and associated corrective actions, they were considered by the inspectors to be non-repetitive at the time they were identified. This non-repetitive, licensee-identified and corrected violation is identified as a non-cited violation, consistent with section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 50-413.414/98-07- i 04: Failure to Have Adequate Slave Relay Test Procedures for '
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Containment Sump Recirculation Valves. Cold Leg Accumulator Valves, and Component Cooling Water Containment Isolation Valve The LER also reported human errors associated with the improper use of multimeters to determine whether electrical contacts were open or q closed. Specifically, personnel had set the multimeter on too high a 1 range for it to conclusively identify the status of slave relay !
contacts. To address this problem, training was provided to test personnel with instructions on the appropriate method of connecting a multimeter into a circuit for measuring voltage, current, and resistance. Also, specific instructions were included in the revisions to Procedure PT/1(2)/A/4200/09A regarding the setting for the voltmeter (or multimeter) and the readings expected for open and closed circuit While reviewing the changes made to Procedure PT/1(2)/A/4200/09A, the inspectors identified a minor typographical error related to valves 1(2)KC 338 A parenthetical reference to the valves erroneously identified them as 1(2)KC 333B on page 4 of Enclosure 13.46 in both the Unit 1 and 2 procedures. This was identified to licensee personne Other changes to Procedure PT/1(2)/A/4200/09A were verified by the inspectors to be complet The inspectors determined that one of the licensee's planned corrective actions as specified in the LER had not been com)leted. Specificall planned action number 1 was not done to revise t1e Operations Test Group (OTG) qualification guide for performance of PT/1(2)/A/4200/09A and ensure proper training was 3rovided to OTG personnel performing continuity verification. T1e licensee documented in PIP 0-C96-1041 that the training guide was sufficient as it was and would not be revised at the time. The inspectors reviewed the slave relay testing training and qualification guide (Task # PF-135-C) and verified that it required demonstration of knowledge by performance of the subject test procedure on slave relays. Since this task required using a multimeter, the inspectors identified no concerns related to the adequacy of the training guid The licensee's decision not to revise the training guide was not consistent with statements contained in the LER. Problems with the licensee's commitment tracking practices were recently addressed in 1997 (Deviation 50-413.414/97-14-02) for which corrective actions were take The failure to complete the planned actions specified in LER 50-413/96-02 predated the above corrective actions: therefore, no further enforcement action is warranted. The LER~is close M8.3 (Closed) VIO 50-413/96-08-02: Failure to Follow Procedure When Adjusting Nitrogen Accumulator Pressure to Backseat Leaking Main Feedwater Isolation Valve (MFIV)
This item addressed the licensee's failure to follow procedure IP/0/A/3010/09B, Nitrogen Charging for Main Feedwater Isolation Valve
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Actuators. Step 10.2.24, which directed technicians to check the accumulator nitrogen pressure and, if appropriate, adjust the nitrogen pressure as close as possible to desired pressure. The licensee reduced the' pressure significantly below the desired pressure for approximately two minutes. At the reduced nitrogen accumulator pressure, MFIV 1CF-42 was potentially incapable of performing its safety functio The licensee's response to the violation, dated August 1,1996, listed the corrective actions to resolve this issue. These included review of management expectations with respect to deviating from procedure steps due to changing plant conditions: updating work order package 95024430-01 for 1CF-42 nitrogen check to document procedure deviations and associated reasons; communicating with all maintenance personnel the l need to perform a thorough evaluation of working conditions prior to and during work activity execution: and developing a training package for all site personnel to reinforce the requirements NSD 704. Technical Procedure Use and Adherence, with emphasis on procedure adherence and when it is acceptable to deviate from approved procedures. The
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inspectors verified performance of the corrective actions, which were documented in PIP 1-C96-1341. This item is closed.
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III. Enoineerina l E2 Engineering Support of Facilities and Equipment E2.1 Forced Shutdown due to Throuah-Wall Leak on ASME Code Class B Pioina in Auxiliarv Feedwater ( AFW) System
. Insoection Scoce (37511)
The inspectors reviewed the licensee's activities following the identification of a through-wall leak on an elbow fitting in a two-inch section of piping in the auxiliary feedwater system. The inspectors reviewed the licensee's handling of regulatory issues associated with ASME Code Class B (or Class 2) piping integrity, containment integrity, and short and long-term corrective actions to address the pipe lea Observations and Findinas On June 24, 1998, a small pin-hole leak was identified on an elbow fitting in a two-inch section of piping in the AFW system tempering flow line to the Unit 1 C steam generator. The leak was discovered in piping between the containment vessel and outside automatic containment isolation valve ICA-187. Upon discovery of the leak, the licensee entered TS 3.4.10. Structural Integrity, which requires the structural integrity of ASME Code Class 1. 2. and 3 components be maintained in
. accordance with Specification 4.4.10, which specified inservice inspection and testing requirements. Because the leak involved Code
. Class 2 piping, the licensee entered TS 3.4.10 limiting condition for operation (LCO) action statement b, which indicates that with the structural integrity of any ASME Code Class 2 component not conforming .
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to the above requirements, restore the structural integrity of the affected component to within its limit or isolate the affected com)onent prior to increasing the reactor coolant system (RCS) temperature a)ove 200 degrees Fahrenheit (F). With Unit 2 RCS already above 200 degrees F. the licensee entered TS 3,0.3 for approximately 20 minutes until the piping was isolated by closing motor-operated valve ICA-187 (upstream of the leak) and manual valve ICA-225 (downstream of the leak).
The licensee also entered the TS 3.6.1.1 action statement which requires primary containment integrity. be maintained. They exited this action statement when 1CA-225 was closed. Several hours after the valves were closed, caproximately 1 to 2 gallons per minute leakage was still issuing from the pipe elbow. The' inspectors reviewed applicable flow diagrams (CN-1591-1.1, Rev. 24. and CN-1592-1,1, Rev. 20) and the UFSA Section 6. and confirmed that the affected piping was part of a closed loop system )enetrating containment. The system / penetration design complied witi 10 CFR 50. A)pendix A. General Design Criterion 57 with respect to having an opera)le automatic isolation valve outside containment. Because this system was neither part of the reactor coolant system pressure boundary nor directly connected to containment atmosphere, the inspectcrs concluded that containment integrity was being maintained even with leakage still evident from the affected steam generator tempering flow line. The inspectors also concluded from their review of system drawings that AFW system operability was not affected by the leak or the closing of valves 1CA-187 or 22 After several unsuccessful attempts to stop the leak by closing valves in the main feedwater system upstream of 1CA-187 (which ultimately isolated tempering flow to all four Unit 1 steam generators). Unit I was shutdown'to Mode 4 on June 28-30. 1998, to affect repair Approximately two feet of carbon steel piping was replace The inspectors studied the removed section of piping and observed that the pin-hole leak was due to erosion in a very localized area in the elbow fitting. The licensee attributed the erosion to excessive tempering flows through this piping during previous operating cycle Auxiliary feedwater tempering flow had been reduced from approximately 200 to 100 gpm after sections of piping had to be replaced following several years of operating at the higher flow rate. The inspector noted that the general condition of the removed piping and fittings was good, with no obvious signs of erosion except for the localized degradation at the hole locatio Piping in the AFW system tempering flow lines was included in the licensee *s erosion / corrosion progra However, the inspectors were informed by licensee personnel that, due to the location and nature of the pin-hole (near a socket weld joining the elbow fitting with straight pipe) and because of geometric limitations associated with ultrasonic testing equipment, the erosion / corrosion program would not likely have detected this or similar erosion in other elbow fittings. As a result, the licensee did not include test points for these elbow fitting Another elbow that was removed during the replacement effort, which was
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in series with the one that was leaking, exhibited similar localized erosion characteristics. Toward the end of the inspection period, due to lingering concerns with the potential for similar pin-hole leak licensee management isolated the tempering flow to the AFW nozzles for the remainder of the operating cycle until the piping can be replaced with more erosion-resistant piping during the Spring 1999 refueling outag The licensee's Plant Operations Review Committee approved (by telephone) a Unit 1 restart on June 30, 1998, following an engineering presentation of the findings related to the pin-hole lea Unit 2. for which tempering f' low is not normally aligned to the steam generator auxiliary feedwater nozzles, was not affected by this specific issue, c. Conclusion The licensee took conservative actions regarding TS Limiting Condition for Operation entry following the identification of a pin-hole leak in two-inch auxiliary feedwater tempering flow piping. The leak was effectively repaired during the subsequent Unit 1 forced outag The licensee's short and long-term corrective actions were adequat E8 Miscellaneous Engineering Issues (92903, 92700. 90712)
E8.1 Auamented Insoection Team Findinas Related to UST Over-Temperature Event (See Section 08.1 for related issues involving operating procedures.)
An NRC review of findings documented in Inspection Report 50-413.414/98-06 related to the May 7, 1998. Unit 1 UST over-temperature event concluded that the licensee nad prior opportunity to recognize and correct the potential for an adverse system interaction on:
. January 20.1996 - Unit 1 experienced a similar incident where UST temperature exceeded the AFW design temperature for ap3roximately 98 minutes with a peak temperature of 211 degrees F. lad the AFW system been actuated at this time, the water temperature would have exceeded the design temperature for the suction of the AFW pumps (UFSAR Tables 10 4.9-1 and 10.4.9-2 specify the pump design temperature as 138 degrees F). The licensee's records did not indicate that the licensee was aware that the AFW system was beyond its licensing / design basis. The licensee did not take adequate measures to prevent future recurrence. The licensee's engineering staff had assumed that since the UST was connected by a 16-inch line to the Condenser Hotwell, that the maximum temperature that the UST could reach was saturation temperature for 24 inches vacuu . January 11. 1998 - The Unit 1 UST temperature reached a maximum of 135 degrees.F and remained near this value for four days until the licensee closed isolation valve 1-CM-126 (upstream of 1-CM-127).
No problem identification process reports (PIPS) were initiated by the licensee. This event similarly did not prompt the licensee to take adequate measures to prevent future recurrence.
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l Relative to these UST high temperature events, th9 engineering staff i-demonstrated a poor questioning attitude and lack f rMor in the performance of root cause evaluations and determinat e of corrective actions.
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The licensee's failure to identify and take prompt corrective actions following the Unit 1 UST over-temperature events on January 20, 1996, and January 11.-1998, led to the. recurrence of- an adverse system
. interaction and a significant condition adverse to quality (specifically the inoperability of the AFW. system). This failure was contrary to 10 CFR 50, Appendix E. Criterion XVI, and is identified as Violation 50-413/98-07-05: Failure to Take Prompt Corrective Actions to Prevent
, Recurrence of UST Over-Temperature Events and AFW System Inoperability.
The safety significance of the above violation was mitigated by the fact that the system was degraded for a short time and the AFW pumps remained functional. although there was a reduced heat removal capacity due to elevated UST temperatures. The regulatory significance of the UST temperature event was high because a safety-related system designed to mitigate the consequences of an accident was rendered inoperable by the mispositioning of a single nonsafety-related component, valve ICM-12 ,
E8.2 (Closed) LER 50-413/96-08: 0 Closure Response Time Exceeded for Main Steam Isolation Valve 1SM-1, B Train This LER documented the past inoperability of main steam isolation valve (MSIV) ISM-1, which had exhibited an excessive stroke time during surveillance testing on March 7,1995, during the Unit 1 End-of-Cycle
, (EOC) 8 refueling outage. The valve passed a subsequent surveillance l test on March 17. 1995. In early 1996, the licensee determined that the wrong root cause of the slow stroke time had been identified in March 1995. Station PIP 0-C96-751 was initiated to document a past operability evaluation for ISM-1: this PIP referenced PIP 0-C95-2136 for a current operability determination. According to PIP 0-C95-2136 (which i documented an issue concerning testing of valves in dual-train solenoid H
valve arrangements), the licensee considered the valve operable because the March 17, 1995, test had been successfully completed and, thereby,
. demonstrated valve operability. The inspector noted that the operability determination documented in PIP 0-C95-2136 was made in the context of a dual-train solenoid testing philosophy error, not-in the context of a surveillance test failure for which a root cause had not been identified and corrected. The inspector considered this inappropriate because the evaluation did not address the unknown and uncorrected root cause of the March 7, 1995, surveillance test failur During the following refueling outage (IEOC9), the licensee determined
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that the B-train exhaust solenoid valve internals had caused the test failure. The solenoid valve problem associated with the B-train solenoid valve caused the excessive stroke time of ISM-1 during ESF testing, However, the inspectors concluded that the A-train solenoid
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valve did not exhibit performance problems and would have properly functioned to ensure tlat ISM-1 would have performed its safety function. Therefore, the past inoperability of 1SM-1 did not constitute a significant safety concer The licensee replaced all of the existing Unit 1 MSIV solenoid valve internals with newer components during 1EOC9. The Unit 2 MSIV solenoid valve internals were replaced during 2E0C8 in March and April 1997. The inspector reviewed the work orders associated with the solenoid component replacements and verified that they were completed. The inspectors also verified that changes associated with procedure IP/0/A/3030/007H. Maintenance and Functional Test Procedure for Main Steam Isolation Valve and Sub-base Manifolds. Revision 3 were implemented to address adequate testing and maintenance of the MSIV solenoid valves. The inspectors concluded that these corrective actions were adequate to address the equipment failur The LER identified the spurious failure of the B-train exhaust solenoid valve as the root cause of the event. The spu.-ious failure was in turn caused by the B-trein solenoid valve " sticking" and marginal spring force to overcome the resistance incurred by the sticking valve. The inspector noted that, although the root cause of the MSIV test failure had been identified as described in the LER, the root cause of the {
l valve's past inoperability for 17 months (following the spurious failure on March 7, 1995) had not been addressed. The LER did not identify the licensee's failure to invoke the corrective action process (PIP). If a PIP had been written to document the test failure._ problem ' resolution via the corrective action process would have prompted formal operability and root cause evaluations. . This process would have afforded the licensee an opportunity to identify and correct the internal spring )
problem before Unit 1 restart. The inspectors concluded that the '
licensee performed an audit of their corrective action program in 1996 to determine if equipment problems were being documented in PIPS for formal evaluation and resolution (refer to NRC Inspection Report 50-413.414/96-13). Although human performance issues regarding the failure
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to initiate a PIP to document the March 7, 1995, surveillance test failure were not addressed as a contributing root cause of the past inoperability, adequate corrective action had been taken to resolve i concerns regarding PIP initiation.
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Unit 1 o)erated in a condition prohibited by TS 3.7.1.4. which states ,
, that eac1 main steam isolation valve shall be operable during Modes 1. 2 l l and 3. This non-repetitive, licensee identified and corrected violation )
l 1s characterized as- a Non-cited Violation (NCV) consistent with Section I l VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 50- i t
413/98-07-06: Unit Operation with an Inoperable MSIV. This issue is close I
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E8.3 (Closed) VIO 50-414/96-03-02: Failure to Follow Procedure for Event Recorder Alarms This issue (which was discussed in NRC Inspection Report 50-413.414/98-05) involvea event recorder alarms that were received on February , prior to a loss of offsite power (LOOP) event that occurred February 6, 1996. The license 9 failed to respond to the alarms and take prompt corrective action to prevent the LOOP event. The licensee took corrective actions to upgrade the event recorder and provide a response procedure (the Electrical Events Recorder Points Response) in the control room. However, the event recorder alarm screen did not reference the response procedure. To ensure that operators had clear guidance to refer to the response sheet, the licensee incorporated the 3 j
response information into the Operator Aid Computer. The inspectors I considered this action appropriate but concluded that the response sheet should have been incorporated into the OAC during 0AC replacement projects performed in 1996 and 1997 (for Unit 1 and Unit- respectively). The absence of operator guidance on the OAC for responding to event recorder alarms resulted from an oversight during the OAC replacement project. This item is close i E8.4 (Closed) V10 50-413.414/96-13-02: Inadequate Procedures - Two Examples Exanple one addressed a procedure change that directed operators to close valve 2ND-53. 2B residual heat removal (RHR) heat exchanger inlet manual isolation valve, while warming up the 2B RHR pump and associeted suction and discharge piping to within 50 degrees F of the reactor coolant system temperature for startup of the RHR system during normal plant cooldown. T1is procedure change was designed to prevent thermal deformation of the pump casing and subsequent casing leakage. The procedure caused thermally induced pressure locking of valve 2ND-5 The valve could not be opened manually by hand. A valve wrench was used in an attempt to open the valve. which resulted in a stem-to-disc failure that rendered the B train of RHR inoperable. Corrective actions consisted of drilling a hole in the upstream disc of valve 2ND-5 developing a management procedure for use by system engineers in their review of operations procedure revisions that will include manual valves susceptible to thermally induced pressure locking in addition to those valve types already identified in Generic Letter 95-02. The licensee provided notification to Westinghouse and the Institste of Nuclear Power Operations to alert other utilities to the possible Pfects of warming t1e RHR pump as recommended in " westinghouse Technical Bulletin ESBU-TB-96-03-R These corrective actions were documented in PIP 2-C96-200 ann were verified complete by the inspector Eaample two addressed PT/1/A/4700/14. Retype 0. Auxiliary Shutdown Panel IB Functional Test. Enclosure 13.9. Control Room / Auto Closure of INI-65B and INI-88B. This enclosure listed eight effects of the manipulation of three transfer relays used to simulate control transfer from th.: control room to auxiliary shutdown panel (ASP) 1B. The enclosure was inadequate in that valve 1RN-58B. Nuclear Service Water Loop B Return to Standby Nuclear Service Water Pond Isolation Valve, and valve IRN-843B Nuclear E______--------_-----__---_-----_-------- - - - - - - - - - - - - -
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Service Water to Conventional Low Pressure Service Water Isolation Valve, were inadvertently realigned during performance of the testin As a result, the valves repositioned, isolating flow to a portion of the nuclear service water system that was in service to support a liquid radioactive release. Corrective actions included restoring the nuclear service water system to its proper alignment and implementing procedure corrections to oreclude any repeat occurrences. These corrective actions (documented in PIP 0-C96-2123. which was closed on November 2 ) were verified complete by the inspectors. This item is close IV. Plant Supoort e S1 Conduct of Security and Safeguards Activities Insoection Stone (81070. 81074.-81084)
.The inspectors evaluated the licensee's redesigned alarm stations and new personnel access control system (PACS) for the protected area. This was to ensure compliance with Chapters 5 through 8 and 10 of the Nuclear Security and Contingency Plan (PSP). Observations and Findinas Alarm Stations (81084)
The inspectors verified that annunciation of protected and vital area (PA/VA) alarms occurred audibly and visually in the redesigned alarm stations. The licensee continued to equip the central and secondary alarm stations (CAS/SAS) with closed circuit television (CCTV)
assessment capabilities and communication equipment. Alarms were still tamper-indicating and self-checking. and provided with an
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uninterruptable power supply. The CAS and SAS operators were
! knowledgeable of the functions of the redesigned stations. The stations continued to be independent yet redundant in operation. The licensee i did not alter the bullet resistance of the alarm stations. The i
operability of internal and external security communication links were not changed, and continued to be appropriate for their intended l function.
l Protected Area Access Control - Personnel (81070)
The inspectors verified that the licensee controlled access to the PA with new hand geometry equipment, card readers, and turnstiles. The licensee controlled access to VAs with new card reader The licensee implemented a new picture badge identification system for o personnel who were authorized unescorted access to the Catawba Nuclear Station PA. This new badge was part of the new Duke Energy Company-wide Video Badge Network (VBN) system for the three nuclear stations and corporate office. The new badges were numerically coded to authorize unescorted access to PA and/or VAs. The code corresponded to designated controlled areas that the licensee had selected for authorized access by
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cleared individuals. Once the licensee issued the new badge to an individual, the individual was responsible for the security of the badg Personnel were authorized to take the badges outside the PA and
! off sit Personnel were denied PA access if they did not have their badge with them or until a new one was made. Visitors authorized l escorted access to the PA were issued a badge that showed that an escort I was required, and were escorted by licensee-designated escorts while in the PA. The licensee had compensatory measures for defective or inoperative access control equipment. The licensee had revised
appropriate procedures for the new PA access control system. The access l control program records were the basis of the VBN. The VBN contained sufficient information for identification of persons authorized access to the PA and VA A new multi-redundant computer network system controlled the new access f'
control hardware and VBN system. The licensee interfaced the corporate office and three nuclear power sites for total system information ,
integratio Access Control - Vehicles (81074) /
Security officers searched all vehicles entering the PA through the vehicle access portal (VAP). Personnel accompanying the vehicles were processed through primary access control porta Conclusions
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The licensee's redesigned alarm stations and new personnel access control system to the protected and vital areas met the criteria of the ,
current Nuclear Security and Contingency Plan and appropriate security procedure S2 Status of Security Facilities and Equipment Inspection Scooe (81042 and 81064)
The inspectors evaluated the testing, maintenance and compensatory measures for the new PACS. This was to ensure compliance with PSP commitments and regulatory requirement ! Observations and Findinas i
Testina and Maintenance
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The licensee's program for testing and maintenance had been updated to l l include the new PACS and security computer modification. Seven new '
' testing security procedures were developed and eleven security testing .
procedures were revised for the im) lamentation of the access control and I security computer modification. T1e inspectors observed performance tests for the entrance turnstiles (Security Procedure 317) and four hand 1 l
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geometry units (Security Procedure 320). All the equipment tested performed as required by the appropriate security procedures. Each
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I 21 I access control device was tested at the beginning and end of any 1 operational period and at least once every seven days during continuous !
use. Records documenting tests and maintenance on new access control !
equipment were on hand and properly maintaine Compensatory Measures Compensatory measures were reviewe The measures were found equal to l the failed or damaged component of the new access control and security l computer system, as described in Revision 7 of the PSP and in j appropriate security procedures. These measures consisted of equipmen '
additional security force personnel, and specific procedures to assure that the effectiveness of the security system was not reduce Conclusions The licensee used testing and maintenance programs and procedures that )
would ensure the reliability of the new security equipment and device j In preparation of implementing Revision 7 of the PSP. the licensee has '
appropriate compensatory measures for potential failures of the new security equipment or for impaired equipment performanc l S3 Security and Safeguards Procedures and Documentation Insoection Scone (81018)
The inspectors reviewed security procedures to determined their adequacy and compliance with 10 CFR Part 5 b. Observations and Findinas PSP Chanaes Revision 7 to the PSP describes the implementation and commitments of the new access control and security computer system modification. The licensee had not implemented Revision 7 as of this inspection. It will be effective for each Duke Power Nuclear site upon the completed, tested and accepted implementation of the new security computer and PACS at each site. Catawba will be the first site to implement Revision followed by McGuire and Oconee. Then, each site will insert Revision 7 pages into the applicable chapters of the Duke Power Nuclear Security ;
and Contingency Plan for that sit !
Security Procedures The inspectors randomly reviewed the latest changes to 18 security
) procedures and 7 new security procedures concerning the new access l
j control and security computer system. The inspectors also interviewed i l security force personnel to determine their familiarity with the documents reviewed. The reviewed procedures pertained to alarm station ;
operations and operators. testing and maintenance, security officers' l duties, and compensatory measure '
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c. Conclusions The new and revised security procedures reviewed did not decrease the effectiveness of the Nuclear Security and Contingency Pla F1 Control of Fire Protection Activities F1.1 Fire Reoorts and Investigations a. Insoection Scooe (64704)
The inspectors reviewed the plant fire emergency reports and the resulting Problem Investigation Process (PIP) forms for 1997-98. to assess trends of maintenance-related or material condition problems with plant systems and equipment that may initiate fire events. The inspectors verified that plant fire protection reporting requirements were met in accordance with Nuclear System Directive (NSD) NSD-112. Fire Brigade Organization. Training and Responsibilities. Revision 0, when fire-related events occurre b. Observations and Findinas The fire emergency reports and associated PIPS indicated that there were two incidents during 1997-98 in which the fire brigade responded to reported fires within safety significant plant areas. Only one of these incidents was an actual fire condition. It involved an electrical transformer failure in a vital inverter. Licensee personnel identified and extinguished the fire condition in a timely manner and prevented the fire from spreading to other equipment or cable J c. Conclusions I During 1997 and 1998, there was a low number of incidents of fire within safety-significant plant areas. When fires occurred, licensee personnel identified and extinguished the fire in a timely manner and prevented the fire from spreading to other equipment or cable F1.2 Combustible Material Controls / Fire Hazards Reduction a. Insoection Scoce (64704)
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To determine if the licensee satisfied the combustible control and housekeeping objectives established in its approved fire protection program, the inspectors reviewed the licensee's administrative Nuclear System Directives. NSD-313. Control of Combustibles and Flammable L Material. Revision 1: NSD-116. Nuclear Chemical Control Program, j Revision 0: and NSD 104. Housekeeping Material Condition, and Foreign Material Exclusion. Revision 13. The inspectors also toured selected plant areas to inspect the licensee's implementation of these procedures.
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23 Observations and Findinas CNS-1465.00-00-0006. Plant Design Basis Specification for Fire Protection. Revision 0, outlined the program for control of combustibles and housekee)ing at the Catawba facility. Administrative Nuclear System Directives, 150-313. NSD-116. and NSD-104 were the fire protection program documents that 3rovided the facility's standards and practices for control of combusti]les and housekeepin During plant walkdowns with the licensee's fire protection engineer, the inspectors observed that controls were being maintained for combustible liquids in areas containing lubrication oil and diesel fuel, such as the diesel generator room Lubricants and oil's were placed in approved safety containers and properly stored within ap3 roved fire-resistive flammable liquids storage cabinets. The flamma)le liquid storage cabinets were located only in those safety-related areas designated by the )lant procedures. Storage cabinet doors were properly closed and latcled. The inspectors verified that the majority of the wood used i
during work activities was treated to make it fire-retardant. The inspectors observed that the work areas were cleaned of unnecessary l material. Waste material trash cans utilized safety cover lids and were
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emptied regularl The inspectors concluded that the observed practices met the requirements of the licensee's procedures as described in the UFSA The various plant departments were properly implementing their responsibilities for combustible material contro The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant worker Conclusions l
l The implementation of procedural requirements for using and storing
! transient combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly im)lementing their responsibilities for combustible material control. T1e observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant worker F2 Status of Fire Protection Facilities and Equipment F2.1 Fire Pumos and Fire Protection Water Sucolv Insoection Scoce (64704)
The inspectors conducted a walkdown of the licensee's fire protection water supply system to verify that the system met the requirements described in UFSAR Section 9.5.1.2. Fire Protection System. and Supplemental Safety Evaluation Report 3 (SSER) Section 9.5.1.7. Fire Protection Water Supply Syste _-_________________-- _ _ _-
24 Observations and Findinos The inspector' observed that the fire protection water supply was provided by e.ectric-driven fire pumps supplied with water from Lake Wylie. There were three 2500 gallon per minute (gam) fire pumps, one 200 gpm pump, and two 25 gpm jockey fire pumas eac1 rated to maintain system pressure at 125 pounds per square inc1 gauge (psig).
Section 9.5.1.7 of the Catawba SSER 3. stated that an L-shaped concrete block fire-rated wall separated the redundant A and B fire pumps located in the same bay in the intake structure. This feature, later verified by the ins)ectors. assured that a fire at the intake structure would not damage ~ bot 1 fire pumps. The inspectors noted that the maintenance and material condition of the fire pumps and supporting equipment was goo Conclusion The general material condition of the fire pumps and the fire protection water supply was good. The physical separation of the redundant fire pumps was maintained and met the criteria described in the UFSA F2.2 Reactor Coolant Pumo (RCP) Oil Collection System Insoection Scooe (64704)
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The inspectors reviewed the design. operation, and maintenance of the oil collection system for the reactor coolant pumps to verify that the requirements of UFSAR Section 9.5.1 and 10 CFR 50. Appendix R.Section III.0 were me Observations and Findinas The inspectors reviewed UFSAR Section 9.5.1. ' Catawba Safety Evaluation Report. Section 9.5.1.8. Fire Protection for Specific Plant Areas -
Containment: CNS-1465.00-00-0006. Plant Design Basis Specification for Fire Protection. Revision 0: RCP oil collection system flow diagram drawing number CN-1553-1.3. Revision 13: operation procedures OP/1/2/A/6150/002B Enclosure 4.5. Draining the NC Pump Motor Oil Reservoirs, and OP/1/2/A/6100/001. Enclosure 4 2, Operations Pre-Heatup Checklist. Revision 3: and other related documentatio The inspectors reviewed the procedures and interviewed the system engineer and concluded that sufficient procedural guidance was provided l to verify that the RCP oil collection tanks were normally maintained ematy and that the plant operators could identify an oil leak from the lu)rication system of any one of the RCP motors and take appropriate action. This met the performance criteria of 10 CFR 50. Appendix Section 11 l
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! 25 Conclusions Sufficient procedural guidance was provided to verify that the RCP oil l collection tanks were normally maintained empty and that the plant operators could identify an oil leak from the lubrication system of any one of the RCP motors and take appropriate action. The RCP oil collection system met the performance criteria of 10 CFR 50 Appendix R Section 11 F2.3 00erability of Fire Protection Facilities and Eauioment Insoection Scooe (64704)
The inspectors reviewed the impairment log for 1998, for fire protection components and features to assess the licensee's performance for returning degraded fire protection components to service. In addition, walkdown inspections were made to assess the material condition of the t
plant's fire protection systems, equipment, and feature Observations and Findinas l
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As of June 1.1998, there were eight fire protection components or systems listed on the impairment log as degraded. This indicated that appropriate emphasis had been placed on the maintenance and operability of the fire protection equipment and components. Most of the eight i impairments involved breached penetration seals. Discussions with the facility fire protection staff indicated that these breached penetration seals were associated with repair activities for inoperable seals identified during a recent Triennial Fire Protection Audit. The inspectors verified that appropriate compensatory measures (fire watches) had been implemented for the degraded components, where requi red. The inspectors toured the plant and noted that the operable fire protection systems were well maintained and the material condition was very good, l
The inspectors reviewed previous impairments listed in the fire !
protection impairment log and noted that for the 97 impairments listed within the time period, the inoperable features had been restored to service within an average of about 65 hour7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> Conclusions l
The low number of inoperable or degraded fire rotection components )
indicated that appropriate emphasis had been p aced on the maintenance
, and operability of tie fire protection equipment and components.
t Impaired fire j timely manner. protection features had been restored to service in a i
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F2.4 J_nocerable Fire Barrier Penetration Seals Insoection Scoce (64704. 92700)
The inspectors reviewed an issue involving the failure to maintain operable fire barrier penetration seals between areas containing redundant safe shutdown equipmen The inspectors reviewed the 10 CFR 50.72 NRC Notification of non-compliance with Facility Operating License Conditions 2.C(8) (Unit 1), and 2.C.(6) (Unit 2): the Unit 1 Facility Operating License: UFSAR Selected License Commitments (SLC) Section 16.9. Auxiliary Systems - Fire Protection Systems: drawings CN-1105-6 through -13. Fire Boundary Walls Revisions 4-15: Work Requests / Work Orders (WO/WR) Nos. 98049736. 98049737, and 98044764 and Special Repor Inoperable Fire Barrier Penetrations, dated June 2.1998. The inspectors walked down and observed the repairs made to six penetration seals and discussed with the site fire protection engineers the installation and repair history of the seal b. Observations and Findinas On May 5.1998, during a Triennial Fire Protection Audit, the licensee determined that one penetration seal (F-AX-348-W-134) in an auxiliary building fire barrier wall that separated the Unit 1 A and B train component cooling (KC) Pumps and a number of embedded circular sleeve floor penetration seals (K-AX- 657-F-79 to -155) in the control building that separated the main control room from cable spreading rooms were not operabl The auxiliary building fire barrier penetration seal was found to have a gap in the silicone foam that extended through the barrier. The control building silicone foam seals were found to have had an inadequate depth of foam installed within the concrete floor slab. The fire barriers were declared inoperable and fire watches were established for the affected fire zones in accordance with the fire I protection program requirements. The ins)ectors verified that the l licensee made a 24-hour notification to tie NRC for the non-compliances 4 per License Condition 2F (both Units) and 10 CFR 50.72. A written special report concerning the inoperable fire barrier penetrations was ,
submitted to the NRC on June 2, 199 j The inspectors verified that plant aersonnel documented these problems in PIP 1-C98-1683 and 1-C98-1690. w1ich included evaluations of the causes of the silicone foam penetration seal problems and proposed corrective actions to repair the penetration seals. The inspectors *
review of the PIPS the fire boundary seal drawings. WR/W0s procedural guidance for fire penetration seal repairs, and observation of repaired seals. found that these seals had been properly repaired to their required design configuratio Catawba Facility Operating License condition 2.C.(8) for Unit 1 and 2.C.(6) for Unit 2 state that Duke Energy Corporation implement and maintain in effect all provisions of the approved fire protection program, as amende UFSAR commitments contained in SLC. Section 16.9-5. Fire Barrier Penetrations, states that all fire barriers and all I
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l l 27 sealing devices in fire barriers ) penetrations....as identified on drawings CN-1105...shall be operaale.
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The' inspectors verified that the licensee's Triennial Fire Protection Audit. SA-98-100(ALL)(RA), identified that a number of penetration seals in the control building and auxiliary building were not installed as
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L required and were not operable as evidenced by inadequate depth of silicone foam and gaps in the silicone foam that extended through the l barrier wall. This failure had affected the fire barriers since their l installation during construction of the plant. Licensee management has appropriately addressed the factors that caused the above non-compliances in its corrective actions as described in PIP 1-C98-1683 and PIP 1-C98-1690. This non-repetitive. licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 50-413.414/98-07-07: Failure to Maintain Required Fire Barrier Penetration Seals Operabl Conclusions l One non-cited violation was identified for failure to maintain required fire barrier penetration seals operable between areas containing redundant safe shutdown equipmen F3 Fire Protection Procedures and Documentation F3.1 Surveillance Procedures for Hose Stations and Standoices Insoection Scooe (64704)
The inspectors reviewed the design and surveillance tests for the interior manual standpipe and fire hose station system to determine compliance with UFSAR Section 9.5.1. Fire Protection System, and UFSAR Section 16. Selected Licensee Commitments (SLC). Item 16.9.4. Fire Hose Station Observations and Findinas The inspectors selected the inspection and surveillance requirements
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from the UFSAR Section 16. SLC Item 16.9.4. for the manual fire hose station system to verify that the system performance criteria for adequate water flow through the fire hose station components had been incorporated into the appropriate surveillance procedures. A review of design calculation CNC-1223.49-02-0001. RF-Fire Protection Pressure Drop
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Calculation in the Auxiliary Building, Revision 0; periodic test arocedure PT/0/A1/4400/01S. R(-Fire Protection Flow (Underground)
l 3eriodic Test. Revision 5: the vendors' performance data for the installed fire hoses and fire fighting nozzles: and discussions with the facility fire protection engineer revealed that the scope and content of
the inspection and aeriodic test procedures were sufficient to perform verification that t1e fire hose station placement, water flow, and water l
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pressure requirements established in UFSAR Section 9.5.1 were met, l Conclusions The scope and content of the inspection and surveillance test program procedures for the fire protection hose stations and standpipes were sufficient to ensure that the fire protection design and surveillance water flow requirements specified in the UFSAR were me F3.2 Surveillance Procedures fer Fire Hose Gaskets Insoection Scoce (64704. 92700)
The inspectors reviewed an issue involving the failure to inspect fire hose coupling gaskets every 18 months. The inspectors reviewed the 10 CFR 50.72 NRC Notification of non-compliance with Facility Operating License Conditions 2.C(8) (Unit 1), and 2.C.(6) (Unit 2); the Unit 1 Facility Operating License: UFSAR Selected License Commitment Section 16.9.4. Fire Hose Stations, and Special Report. Missed Ins)ection of Fire Hose Gaskets, dated May 12. 199 The inspectors walced down the Units 1 and 2 turbine building, auxiliary building and control building and observed the material condition of fire hose stations and fire hoses installed in these areas to determine compliance with UFSAR SLC. Item 16. Observations and Findinas On April 15. 1998, during an engineering self assessment CER-04-98. Fire Protection Testing and Surveillance Program, the licensee determined !
that a requirement to inspect fire hose coupling gaskets every 18 months I had not been performed. Each fire hose station hose uses gaskets where j the hose cou the nozzle. ples to the Upon hose station discovery root valve the licensee and the inspected thehose couples to fire hose J l
coupling gaskets and determined that they were in good material condition. A preliminary NRC review of the licensee actions was documented in Integrated Inspection Report 50-413.414/98-05, Section 0 The inspectors verified that plant personnel documented the issue in PIP 0-C98-1401. The licensee's PIP evaluation determined that the cause of the missed inspection was the failure to transfer inspection requirements from one 3rocedure to another. The requirement to inspect fire hose coupling gascets every 18 months was omitted in April 1994, when the original fire hose inspection implementing procedure PT/0/A/4400/010 was deleted and merged with procedure PT/0/A/4' ";/01 l The inspectors' review of the PIP indicated that corrective actions to revise the fire hose inspection procedures were in place. The inspectors' observations of material condition of selected fire hose stations and fire hoses found that the fire hoses were in good repair and the nozzles free of foreign material. The lack of wet areas around the hose station or water-filled hoses indicated that the hose station l l
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root valves were not leaking and the hose, couplings gaskets, and nozzles were well maintaine Catawba Facility Operating License condition 2.C.(8) for Unit 1 and 2.C.(6) for Unit 2 : tate that Duke Energy Corporation implement and maintain in effect all provisions of the approved fire protection program, as amende UFSAR commitments contained in SLC. Section 16.9-4, Fire Hose Stations states that all fire hose stations listed in Table 16.9-2 shall be operable. Testing requirement 16.9.4(a)(ii>(2)
requires all fire hose gaskets be inspected at least once per 18 month A licensee Engineering self-assessment identified that the requirement to inspect fire hose coupling gaskets every 18 months had not been performed since 1994 when the requirement was inadvertently omitted from the inspection procedure during the transfer of inspection requirements from one procedure to another. Licensee management has appropriately addressed the factors that caused the above non-compliance in its corrective actions as described in PIP 0-C98-1401. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation consistent with Section VII.B.1 of the NRC Enforcement Policy, and is identified as NCV 50-413.414/98-07-08: Failure to Conduct Required Inspection of Fire Hose Gasket c. Conclusions One non-cited violation was identified for failure to conduct the required inspection of fire hose gasket F3.3 Surveillance Procedures for Aooendix R Emeroency Lichtina ) Inspection Scone (64704)
The inspectors reviewed the design, operation, and maintenance of the ,
eight-hour battery powered emergency lighting system to verify that the -
requirements of UFSAR Section 9.5.3.2.4. Emergency 8 Hour Battery Lighting and 10 CFR 50 Appendix R.Section III.J were me b. Observations and Findinas The inspectors reviewed UFSAR Section 9.5.3.2.4. and Table 9-3 Catawba Safety Evaluation Report. Section 9.5.1.5 Lighting and Communications. CNS-1465.00-00-0006. Plant Design Basis Specification for Fire Protection. Revision 0. and IP/0/B/3540/002. Emergency Battery Lighting (ELD) Periodic Maintenance and Testing. Revision 21. and other
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related documentatio The inspectors toured the plant and noted that the operable emergency battery lighting was well maintained and the material condition was very good. The inspectors' review of the maintenance and testing procedure and discussions with the facility fire protection engineer indicated that the scope and content of the maintenance inspection and periodic test procedure was sufficient to perform a thorough verification of the
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emergency battery lighting units' performance. The procedure was well written and verified that the emergency battery lighting units were l
operable, correctly aimed to illuminate aost-fire alternate shutdown equipment and the working condition of tie lighting unit's batteries was of adequate capacity. This provided thorough verification that the emergency eight-hour battery lighting system met the performance criteria of UFSAR Section 9.5.3.2.4 and 10 CFR 50 Appendix R.Section II Conclusions The maintenance inspection and surveillance test program for the emergency eight-hour battery lighting system was sufficient to ensure that the emergency lighting performance criteria established in the UFSAR and 10 CFR 50. Appendix R were ma F5 Fire Protection Staff Training and Qualification F5.1 Fire Bricade Organization and Drills Insoection Scone (64704)
The inspectors reviewed the fire brigade organization and drill program for compliance with plant procedures and the approved fire protection program as described in UFSAR Section 9.5.1.5, Personnel Qualification and Trainin Observations and Findinas The inspectors verified that the organization and drill requirements for the plant fire brigade were established by CNS-1465.00-00-0006. Plant Design Basis Specification for Fire Protection. Revision 0, and NSD 11 Fire Brigade Organization. Training and Responsibilities. Revision The inspectors reviewed the licensee's fire brigade training matrix reports and records for the fire brigade members and verified that the required training records were up-to-date, and a sufficient number of qualified personnel to meet the facilities fire brigade procedure requirements were assigned per shift. The facility utilized off-site qualified state certified fire brigade training instructors and a state fire training facility to perform the annual fire brigade training and practical fire trainin A fire brigade drill was not observed during this insaection period. To evaluate drill performance, the inspectors reviewed t1e drill evaluation data for the shift drills conducted for the fourth quarter of 1997 and
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first quarter of 1998 and verified that the fire brigade response and l
participation for these drills satisfied the requirements of the site procedures.
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31 Conclusions The fire brigade organization and drill program met the requirements of the site procedures. The performance by the fire brigade as documented by the licensee's drill evaluations was goo F7 Quality Assurance in Fire Protection Activities F7.1 Fire Protection Audit Reoorts Insoection Scooe (64704)
The inspectors attended a telephonic exit interview that discussed the results of a Triennial Fire Protection Audit. SA-98-100(ALL)(RA), which had been conducted onsite May 4-8, 199 b. Observations and Findinas The QA organization performed an onsite evaluation of the fire protection program during the time period of May 4-8, 1998. This audit included an oversight assessment of the fire orotection program as applied to fire protection systems, fire barrier penetration seal program, fire loading, fire protection equipn.ent, maintenance and surveillance procedures, training and qualification, transient combustible controls, plant modifications, operability of the standby shutdown facility (SSF) and emergency lightin The inspectors noted that the audit team identified six potential significant finding These findings were under review for resolution by the licensee. The
' audit team also made four less significant recommendations for improvement. The ins)ectors concluded that the 1998 Triennial Fire Protection Audit of t1e facility's fire protection program was comprehensive and effective in identifying fire protection program i performance issues to plant managemen c. Conclusions The 1998 Triennial Fire Protection Audit of the licensee's fire protection program was comprehensive and effective in identifying fire protection program performance issues to plant managemen F8 Miscellaneous Fire Protection Issues (92904, 92701, 92702)
F8.1 (Closed) VIO 50-413.414/97-07-05: Failure to Repair Degraded Suction l Screen Filters for Fire Pumps in a Timely Manner The violation involved the fire pump water supply screen filters which had not bee fully installed.to the bottom of the screen frame resulting in an area ir the bottom of the pump . suction pit not being filtere The inspect . .; reviewed the corrective actions identified by the licensee in a letter dated June 23,1997. and verified that the actions were reasonable and complete. The inspecn es also reviewed the
l 32-licensee's evaluation provided in PIP 0-C97-1149 initiated to address the issu The evaluation substantiated the violation and identified that licensee divers inspected the fire pump filter screen tracks and frames on May 14, 1997. The underwater inspection determined that the screen frames were not lined up properly and were binding in the screen tracks. The inspectors reviewed licensee work order task No. 9101792001 and determined that the screen filter frames had been removed, straightened, and were reinstalled and verified to be properly in place on the bottom frame by divers on May 17, 199 The inspectors conducted c walkdown of the licensee's fire protection water supply system and the fire pump water supply suction screen filters at the intake structure. The inspectors observed that the screen filter frames were properly positioned in the screen tracks and the material condition of the filter screens was good. This item is close F8.2 (Clcsed) IFI 50-413.414/97-07-06: Time Limits for Restoration of )
Inoperable Fire Protection Components j This item concerned Catawba's UFSAR Chapter 16.9. Selected Licensee Commitments (SLC). Specific restoration times were not identified for inoperable fire suppression equipment, fire barriers or other inoperable fire protection feature In 1990. the licensee elected to remove the fire protection equipment operability and surveillance requirements from the Catawba TS. These requirements were placed in UFSAR Chapter 16.9. Selected Licensee Commitments. The inspectors reviewed UFSAR Chapter 16.9. PIP No. 0-C97-
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2621 (initiated to address this issue), and NSD-316. Fire Protection l Impairment and Surveillance. Revision 0, to evaluate the licensee's actions in this are The inspectors determined that the SLC included essentially the same o)erability and surveillance requirements that were formerly included in t1e TS. This complies with the guidance provided by NRC's Generic Letter 86-1 The licensee developed NSD-316 in December 1997. to provide site direction. requirements, and responsibilities for reporting fire l protection featuras impairments and ensuring their timely restoration.
! NSD-316.7 requires immediate notification of fire protection feature L impairments to the site fire arotection engineer and maintenance of an impairment log including traccing of the duration of the impairmen The procedure does not rely upon compensatory measures to justify an extension of an impairment. The inspectors reviewed the impairment log for 1998. The results of the inspectors * review of these features is located in Section F3 of this repor The inspectors concluded that the licensee complied with the guidance l provided by NRC's Generic Letter 86-10 when the fire protection equipment operability and surveillance requirements were removed from l
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.the Catawba TS and relocated in the Catawba SLC. The licensee's fire protection impairment and surveillance program implementation was good in that impaired fire 3rotection features had been restored to service in a timely manner. T1is item is close F8.3 (Closed) IFI 50-413.414/97-07-07: Audit Frequency Requirements for Activities other than OA Condition 1 Function This item concerned the control of fire protection program QA audit frequencies.
l The inspectors reviewed RA 5.1. Regulatory Audits. Revision 2. The inspectors determined that RA 5.1. Section 5.1.4.C. which had been-revised to require that a trending analysis of performance for non-0A Condition 1 fire protection functions be conducted on an annual basis (beginning for 1998) to determine the need and scope for audit (s) during the coming year. The results of the trending analysis would be documented and retained until the next annual analysis. The inspectors determined that the licensee's annual trending analysis of performance for non-0A Condition 1 fire protection functions provided a consistent specified frequency that alleviated the inspectors * concern. These actions comply with the guidance provided by NRC's Generic Letter 86-1 therefore, this item is close F8.4 (Closed) URI 50-413.414/98-05-01: Fire Protection Program Noncomplianc The issues covered by this unresolved item were discussed in Sections F2.4 and F3.2 of this report. Non-cited violations were issued for each issue. This unresolved item is close V. Manaaement Meetinas X1 Exit Meeting Summary The inspector presented the inspection results to members of licensee
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management at the conclusion of the inspection on July 8,1998. The licensee acknowledged the findings presented. No proprietary information was identifie X2 Escalated Enforcement Results On May 14, 1998, a Predecisional Enforcement Conference for EA Case N , covered in Ins)ection Report 50-413,414/98-03, was held in the Regional Office with t1e licensee in attendance. The following apparent violations (EEIs) were discussed:
EEI 50-414/98-03-01 EEI 50-414/98-03-02 EEI 50-414/98-03-03 EEI 50-414/98-03-04 EEI 50-414/98-03-05 t-
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EEI 50-414/98-03-06 EEI 50-414/98-03-07 EEI 50-414/98-03-08 Following the conference, a Notice of Violation (NOV) was issued on June 11, 1998, Based on the NOV issued, the above Eels are closed and the violations identified in the above Notice of Violation will be tracked as:
VIO EA 98-208-01013 Failure to Comply with Technical Specification 3.7.7 with One Train of the Unit 2 Auxiliary Building Filtered Exhaust (VA) System Inoperable VIO EA 98-208-01023 Failure to Take Corrective Action for a Low Flow Condition Associated with the Unit 2 A-train VA System VIO EA 98-208-01033 Failure to Follow Procedures Related to Operability and Surveillance Testing VIO EA 98-208-01043 Failure to Verify Full Modification Implementation in Accordance with the Modification Manual VIO EA 98-208-01053 Failure to Provide Adequate Test Control in Accordance with 10 CFR Part 5 Appendix B. Criterion XI, and ANSI N510-1980 VIO EA 98-208-02014 Failure to Revise the UFSAR Description of Normal VA System Operation-l
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PARTIAL LIST OF PERSONS CONTACTED Licensee R. Bain. Safety Review Group Manager M. Birch Safety Assurance Manager M. Boyle. Radiation Protection Manager B. Emmons. Organizational Effectiveness Manager R. Glover. Operations Superintendent P. Herran. Engineering Manager R. Jones. Station Manager M. Kitlan Regulatory Compliance Manager J. Minnicks Security Supervisor G. Peterson. Catawba Site Vice-President R. Propst. Chemistry Manager D. Rogers. Maintenance Manager NRC P. Tam. Project Manager NRR M. Chatterton, Nuclear Engineer. NRR I
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l INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance IP 62707: Maintenance Observation IP 64704: Fire Protection Program IP 71707: Plant Operations IP 71750: Plant Support Activities IP 81018: Security Plan and Implementing Procedures IP 81042: Testing and Maintenanc IP 81064: Compensatory Measures IP 81070: Access Control - Personnel IP 81074: Access Control - Vehicles IP 81084: Alarm Stations IP 90712: LER Review IP 92700: Onsite Followup of Written Reports of Nonroutine Events IP 92701: Followup IP 92702: Followup on Corrective Actions for Violations and Deviations IP 92901: Followup - Operations IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support ITEMS OPENED. CLOSED, AND DISCUSSED Ooened 50-413/98-07-01 VIO Failure to Have Adequate Operations Procedures Addressing AFW System Design Temperature Limits and Operation of Valve ICM-127 (Section 08.1)
50-413.414/98-07-02 IFI ECCS High Point Vent Procedure / Gas Vented from RHR Discharge Piping (Section M1.1)
50-413.414/98-07-03 URI Nuclear Instrumentation Deviation from Calorimetric During Moderator Temperature Coefficient Test (Section M1.2)
50-413.414/96-07-04 NCV Failure to Have Adequate Slave Relay Test Procedures for Containment Sump Recirculation Valves. Cold Leg Accumulator Valves, and Component Cooling Water Containment Isolation Valves (Section M8.2)
50-413/98-07-05 VIO Failure to Take Prompt Corrective Actions to Prevent Recurrence of UST Over-Temperature Events and AFW System Inoperability (Section E8.1)
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- 50-413/98-07-06 NCV Unit Operation with an Inoperable MSIV (Section E8.2)
i 50-413.414/98-07-07 NCV Failure to Maintain Required Fire Barrier l Penetration Seals Operable (Section F2.4)
50-413.414/98-07-08 NCV Failure to Conduct Required Inspection of l Fire Hose Gaskets (Section F3.2)
l l EA 98-208-01013 VIO . Failure to Comply with Technical
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Specification 3.7.7 with One Train of the l Unit 2 Auxiliary Building Filtered Exhaust )
(VA) System Inoperable (Section X2)
EA 98-208-01023 VIO Failure to Take Corrective Action for a Low Flow Condition Associated with the Unit 2 A-train VA System (Section X2)
- EA 98-208-01033 VIO Failure to Follow Procedures Related to Operability and Surveillance Testing (Section X2)
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EA 98-208-01043 VIO Failure to Verify Full Modification
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Implementation in Accordance with the Modification Manual (Section X2)
EA 98-208-01053 VIO Failure to Provide Adequate Test Control in Accordance with 10 CFR Part 5 Appendix B. Criterion XI. and ANSI N510-1980 (Section X2)
EA 98-208-02014 VIO Failure to Revise the UFSAR Description of Normal VA System Operation (Section X2)
Closed 50-413/97-14-01 URI Control Power Unavailable to the Unit 1 Turbine-Driven AFW Pump's (TDAFWP) Trip and Throttle Valve (Section 08.2)
50-414/96-01-00 LER Loss of Offsite Power Due to Electrical
- Failures (Section M8.1)
50-413/96-02-00 LER Technical Specification 3.0.3 Entries Due to Inconclusive Surveillance Testing l (Section M8.2)
50-413/96-08-02 VIO Failure to Follow Procedure When Adjusting Nitrogen Accumulator Pressure to Backseat Leaking MFIV (Section M8.3)
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50-413/96-08-00 LER Closure Response Time Exceeded for Main Steam Isolation Valve 1SM-1 B Train (Sectico E8.2)
50-414/96-03-02 VIO Failure to Follow Procedure for Event Recorder Alarms (Section E8.3)
50-413.414/96-13-02 VIO Inadequate Procedurcs - Two Examples (Section E8.4)
50-413.414/97-07-05 VIO Failure to Repair Degraded Suction Screen Filters for Fire Pumps in a Timely Manner (Section F8.1)
50-413.414/97-07-06 IFI Time Limits for Restoration of Inoperable Fire Protection Components (Section F8.2)
50-413.414/97-07-07 IFI Audit Frequency Requirements for Activities other than 0A Condition 1 Functions (Section F8.3)
50-413.414/98-05-01 URI Fire Protection Program Non-Compliances (Section F8.4)
50-414/98-03-01 EEI Failure to Follow Surveillance Test Procedure (Section X2)
50-414/98-03-02 EEI Failure to Follow Administrative Procedures Governing Operability - Three Examples (Section X2)
50-414/98-03-03 EEI Failure to Follow Administrative Procedures Governing Testing (Section X2)
- 50-414/98-03-04 EEI Failure to Comply with Actions Required by ;
TS 3.7.7 with One Train of the VA System '
Inoperable for More than Seven Days (Section X2)
o 50-414/98-03-05 EEI Failure to Verify Full Modification Implementation in Accordance with the Modification Manual (Section X2)
50-414/98-03-06 EEI Failure to Take Timely Corrective Actions for Degraded Flow Conditions that Affected Unit 2 A-Train Auxiliary Building l l Ventilation System Operability (Section X2)
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50-414/98-03-07 EEI Failure to Provide Adequate Test Control in Accordance with 10 CFR Part 5 Appendix B. Criterion XI. and ANSI N510-1980 (Section X2)
50-414/98-03-08 EEI Failure to Revise the UFSAR Description of Normal VA System Operation (Section X2)
Auxiliary Feedwater ASME - American Society of Mechanical Engineers ASP -
Auxiliary Shutdown Panel AP -
Abnormal (Operating) Procedure BDMS - Boron Dilution Mitigation System CAS -
Central Alarm Station l
CFR -
Code of Federal Regulations CLA -
Cold Leg Accumulator EA -
Enforcement Action EEI -
Escalated Enforcement Violation (Apparent Violation)
EOC -
End-of-Cycle EOL -
End-of-Life ESF -
Engineered Safety Feature GPM -
Gallons Per Minute IFI -
Inspector Followup Item LCO -
Limiting Condition for Operation LER -
Licensee Event Report MFIV - Main Feedwater Isolation Valve MSIV -
Main Steam Isolation Valve MTC -
Moderator Temperature Coefficient NCV -
Non-Cited Violation NRC -
Nuclear Regulatory Commission NRR -
Nuclear Reactor Regulation NSD -
Nuclear System Directive OAC -
Operator Aid Computer OMP -
Operations Manual Procedure OP -
Operating Procedure OTG -
Operations Test Group PA -
Protected Area PDR -
Public Document Room PIP -
Problem Investigation Process report PRNI -
Power Range Nuclear Instrumentation PSIG -
Pounds per Square Inch Gauge PSP -
Physical Security Plan OA -
Quality Assurance
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RCP -
Reactor Coolant Pump RCS -
Regulatory Guide
, RHR -
Secondary Alarm Station SLC -
Selected License Commitments i-
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SSER -
Supplemental Safety Evaluation Report SSF -
Standby Shutdown Facility T -
Average Reactor Coolant System Temperature {
T0kFWP- Turbine-Driven Auxiliary Feedwater Pump TSI -
Technical Specification Interpretation UFSAR - . Updated Final Safety Analysis Report .
URI -
Unresolved Item UST -
Upper Surge Tank 1 VA -
Vital Area VA -
Auxiliary Building Ventilation System VAP -
Vehicle Access Portal VBN -
Video Badge Network VIO -
Violation WO/WR - Work Order / Work Request l
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