IR 05000413/1998001

Insp Repts 50-413/98-01 & 50-414/98-01 on 980111-0221. Violations Noted.Major Areas Inspected:Operation,Maint, Engineering & Plant Support

ML20217G566
Person / Time
Site:	Catawba
Issue date:	03/23/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20217G543	List: ML20217G540 ML20217G555 ML20217G566
References
50-413-98-01, 50-413-98-1, 50-414-98-01, 50-414-98-1, NUDOCS 9804020423
Download: ML20217G566 (33)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-413. 50-414 License Nos: NPF-35. NPF-52 Report Nos.-: 50-413/98-01. 50-414/98-01 Licensee: Duke Energy Corporation Facility: Catawba Nuclear Station. Units 1 and 2-Location: 422 South Church Street Charlotte. NC 28242 Dates: January 11 -' February 21, 1998 Inspectors: D. Roberts. Senior Resident Inspector R. Franovich, Resident Inspector M. Giles. Resident Inspector.(In Training)

N. Economos.-Reactor Inspector RII (Sections M1.1, M1.2)

M. Widmann Resident Inspector. Vogtle (Sections 04.1. F2.1)

Approved by: C. Ogle. Chief Reactor' Projects Branch 1 Division of Reactor Projects

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Enclosure 2 9804020423 '900323

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EXECUTIVE SUMMARY Catawba Nuclear Station. Units 1 and 2

, NRC Inspection Report 50-413/98-01. 50-414/98-01 This. integrated inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 6-week '

period of resident ins)ection: in addition, it includes the results of I announced inspections )y a regional reactor inspector and a visiting resident inspecto Doeration A Unit 1 shutdown on January 18, 1998, and power reduction activities on February 20. 1998, were conducted well. On February 20. 1998. operators particularly did well during the coordinated effort to swap 0-ring leak detection paths, including the establishment of effective communications between the control room and containment building, and the monitoring of -

diverse leak detection sources. (Section 01.1)

- Control-room operators appropriately identified and corrected a fault in the control room ventilation system. An Unresolved Item was opened pending NRC review of the basis for assuming that the control room ventilation system is allowed to be inoperable for five minutes following a safety injection, radiation release within the plant or a chlorine lea (Section 01.2)

. A Violation with four examples of failure to follow plant operating and administrative procedures was identified. These included two separate events resulting in the inadvertent injection 6f emergency core cooling system water into the reactor coolant system, and inappropriate actions regarding the by]assing of an automatic feature following a manual reactor trip wit 1 the plant already shutdown. Procedural weaknesses contributed to the fourth example regarding containment chilled water .

i pump operation. (Sections 04.1. 08.1. 08.2. and 08.3)

- The Plant Operations Review Committee meeting which was convened to discuss plans to swap the Unit 1 reactor vessel flange 0-ring leak detection from the inner 0-ring to the outer one was conducted in accordance with commitments contained in the Updated Final Safety Analysis Report Chapter 16. Selected License Commitments, with adequate representation and a quorum present. The committee exhibited good questioning attitude regarding issues associated with the leak detection capability while aligned to the outer 0-ring. (Section 07.1)

Maintenance

• Cleaning of.the 2 B component coolirg water heat exchanger was well planned, managed and executed with sufficient oversight from the cognizant engineer who displayed a good working knowledge of the

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personnel, including welders, were adequately trained to perform their ,

assigned tasks. Procedures were followed tests were performed and )

records were complete and accurat (Section M1.1) j

. Replacement of certain isolation valves on the service water system used on the control room air chillers was consistent with applicable code requirements for material and processes. Engineering overview was adequate. Welders assigned on the job lacked adequate knowledge in the licensee's welding process control program which resulted in a work stoppage. The licensee's inability to establish a strong working program to address these problems was regarded as a weaknes (Section M1.2)

. An Unresolved Item was open pending further NRC review of a Technical Specifications compliance issue associated with containment valve injection water system valve 2NW-190A. (Section M2.1)

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. The licensee's scaffolding program was in compliance with the I

requirements of Title 29 Code of Federal Regulations Part (CFR) 192 Safety Standards for Scaffolds Used in the Construction: Final Rul With the exception of a discrepancy identified between actual internal l

contamination levels and the amount posted radiological handling and I

storage of scaffolding material was adequate. (Section M2.2)

. One Non-Cited Violation was identified for the failure to follow maintenance procedures which resulted in an unapproved aluminum packing spacer being installed in the Unit 1 B steam generator main feedwater regulating valve. (Section M2.3)

Enaineerina.

. An Inspector Followup Item was opened to assess the licensee's dose analysis calculation for emergency core cooling system leakage outside containment after discrepancies were identified between assumptions made by the licensee and those discussed in the Updated Final Safety Analysis Report. (Section E3.1)

- The licensee's identification of a refueling water storage tank level transmitter design deficiency was commendable. Their initial inspcction of the level transmitter boxes failed to reveal moisture in one of the The licensee's corrective efforts to address the inadequacy of their initial inspections were appropriate. (Section E7.1)

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A-Violation of 10 CFR 50.59 was identified for the licensee's failure to perform a. safety evaluation, including an unreviewed safety question determination, for compensatory actions assot.iated with the realignment of the auxiliary feedwater system pumps' normal suction sources. Inis

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issue also involved poor decision making in the licensee's implementation of the clearance process (instead of the temporary modification process). (Section E8.1)

Plant Sucoort

- Radiation protection activities were generally adequate. with minor discrepancies identified in the radiological labeling of some scaffolding containers. (Section R1.1)

- One Non-Cited Violation was identified for failure to establish compensatory fire watches after several fire detection zone alarms malfunctioned for greater than 14 days. The inspectors identified a weakness concerning the lack of written guidance to operators on how to effectively monitor the fire detection panel alarms. (Section F2.1)

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Reoort Details Summary of Plant Status Unit 1 operated at or near 100 percent power until January 16, 1998, when a power reduction was initiated due to erratic operation of steam generator B feedwater control valve ICF-37. Power was reduced to approximately 30 aercent power for valve repair. Power escalation to 79 percent was completed w1en continued erratic operation resulted in the unit being shutdown for valve repairs. The unit entered Mode 2 and then Mode 3 on January 18, 199 Following repair of ICF-37, reactor startup (Mode 2) commenced on January 20, 1998. The unit was placed on-line January 20, 1998, and power was increased to 100 percent on January 21. 1998. On February 20, 1998. reactor power was reduced to approximately 15 percent power to realign the reactor vessel flange 0-ring leakoff valve leak detection from the inner 0-ring to the outer 0-rin Power escalation commenced on February 20. 1998, and the unit was returned to 100 percent power on February 21, 1998. The unit operated at or near 100 percent power for the remainder of the inspection perio Unit 2 operated at or near 100 percent power until February 15, 1998. when reactor power was reduced to approximately 90 percent power for main turbine control valve movement testing. Following test completion, the unit was returned to 100 percent power on February 16, 1998. The unit operated at or near 100 percent power for the remainder of the inspection perio Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments While performing inspections discussed in this report. the inspectors reviewed j the applicable portions of the UFSAR that were related to the areas inspecte The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures, and/or parameters. One discrepancy concerning assumptions made in accident dose calculations is discussed in Section E3.1. Also, a 10 CFR 50.59 violation concerning changes made to the plant affecting the normal suction source for the AFW pumps is detailed in section E I. Doerations 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 i approved procedures. The inspectors attended operations shift turnovers l and site direction meetings to maintain awareness of overall plant j status and operations. Sperator logs were reviewed to verify operational safety and compliance with Technical Specifications (TS).

' Instrumentation, computer indications, and safety system lineups were periodically reviewed, along with equipment removal and restoration

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2-tagouts, to assess system availability. The TS Action Item Log (TSAIL)

books for both units were reviewed daily for potential entries into limiting conditions for operation (LCO). action statements. The inspectors conducted plant tours to observe material condition and housekeeping. Problem Identification Process (PIP) reports were routinely reviewed to ensure that potential safety concerns and equipment probler were resolve A Unit 1 shutdown on January 18, 1998, and power reduction activities on

. February 20, 1998, to support a feedwater regulating valve repair and swapover to reactor vessel flange outer 0-ring leak detection path, respectively, were conducted well. Operators particularly did well during the coordinated effort to swap 0-ring leak detection paths, including the establishment of effective communications between the

. control room and containment building, and the monitoring of diverse leak detection source . 01.2 Loss of Control Room Ventilation a. Insoection Scoce (71707)

On February 4. 1998, following maintenance on the B-train control room ventilation (VC) system, an open access door on a VC air handling unit (AHU) compromised the ventilation system's pressure boundary when the AHU was returned to normal alignmen To determine the subsequent impact on system operability and reportability, the inspectors discussed the issue with licensee personnel and reviewed the applicable TS, reportability requirements, and station PIP 0-C98-047 b. Observations and Findinas On February 4, 1998, maintenance activities were 3erformed on the B-train VC system to replace access doors on AHU 2CR-AHU-1. Ventilation dampers 2CR-D-1 and 2CR-D-4 were closed to isolate 2CR-AHU-1 for work execution. The A-train VC system was o)erating to maintain a aositive control room pressure in accordance wit 1 the VC system design ) asi Early on February 5.1998, after maintenance was completed ventilation dampers 2CR-D-1 and 2CR-D-4 were reopened. and the air handling unit was realigned to the system's flowpat Soon afterwards, control room operators noticed a change in the noise level and temperature in the control room. A control room access door was opened to determine if the control room was pressurized. Air flow into the control room from the opened door indicated that positive pressure may have been lost. Ventilation dampers 2CR-D-1 and 2CR-D-4 were closed.~and control room pressure returned to normal.

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The licensee determined that an access Janel to the air handling uni located in the auiliary building, had )een o)ened.during the .

maintenance activity. - At the completion of t1e maintenance activitie the access door was not latched closed. When the isolation dampers were opened, flow from the operating A-train of VC was diverted through the open access door and into the auxiliary building. The opened access door to the air handling unit compromised the control room pressure . .

boundary. The licensee estimated that the faulted air handling unit had been in the system alignment for approximately five minute Later that day, the licensee determined that both trains of the VC system were inoperable with the breach in pressure boundary. As a result, both units had entered TS 3.0.3 for approximately five minute At approximately 4:30 p.m. the licensee determined that the occurrence was reportable and submitted a 10 CFR 50.72 one-hour notification to the-NRC. The NRC and licensee discussed the cimeliness of issuing the 50.72 report. No violations were identified. However, the licensee stated that a compensatory action existed for maintaining the VC system operable during maintenance activities that compromise the control room pressure boundary. The compensatory action allows the VC system to remain operable provided the pressure boundary can be restored within five minutes of a safety injection signal. a radiation release within

.the plant, a high chlorine alarm at a VC intake, or the sensing of chlorine in the work area. The inspectors requested information pertaining to the basis for the 5-minute window during which VC

. operability was not assumed for accident mitigation, a chlorine leak, or offsite dose calculations. Pending the receipt and further inspector review of this information, this issue is characterized as Unresolved Item 50-413,414/98-01-01: Basis for Five-Minute Period of VC System-Inoperability with Compensatory Actions. This inspector review will include a review of the adequacy of the licensee's post-maintenance testing of the access doo c. Conclusions Control room operators appropriately identified and corrected a fault in the control room ventilation system. An Unresolved Item was opened pending NRC review of the basis for assuming that the control room ventilation system is allowed to be inoperable for five minutes following a safety injection, radiation release within the plant, or a chlorine lea ;3 Doerations Clearances - General Comments (71707)

The inspectors reviewed the following clearances during the inspection period:

• Tagout 17-643 Unit 1 CA Pumps Suction from CA CST

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- Tagout 27-1139. Unit 2 CA Pumps Suction from CA CST 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 were concerned with the length of time these clearances had been in place to maintain the auxiliary feedwater system operable. -The clearances were first' alaced on May 15, 1997, and had been in place ever since. Aspects of tais concern are discussed further in Section E8.1 of this repor Operator Knowledge and Performance 04.1 Containment Chill Water Pumo Trio Insoection Scone (71707)

The inspectors reviewed PIP 2-C98-0447 and the circumstances surrounding the trips of the operating Unit 2 containment chilled water pumps on February 3. 1998. The inspectors reviewed the PIP and Procedure OP/2/A/6450/020. Containment Chilled Water System. Revision 32. The inspectors also interviewed the operator involved and discussed with licensee management their review of this issu Observations and Findinas

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On February 3. 1998. an operator attempted to place in service containment chilled water pump number 3 which resulted in the operating pumps being automatically tripped due to low flow. During performance of OP/2/A/6450/020. Enclosure 4.5. Swapping Operating Chiller Units, the operator inadvertently performed Section 2.1 One Chiller Operation, rather than Section 2.2. Swapping a Chiller with Two Chillers in Operation. Although chiller system temperature increased from 42 degrees Fahrenheit to the high alarm setpoint of 60 degrees, containment temperature was not effected by this error and two chillers were subsequently placed in service without inciden Based on discussions with the operator. the inspectors determined that performance of the improper section of the arocedure occurred due to personnel error. The operator stated that le concentrated on steps necessary to support placing the number 3 chiller pum) in service and did not recognize that he was in the wrong section. ) lacing a third pump in service required securing one of the operating chiller units and the subsequent opening of a hot gas bypass valve that was recently installed as part of a modification. The o)erator stated that maintenance personnel normally mani Julate t1e valve: however, on this day he was requested to place the cailler Jump in service and manipulate

the valv Due.to being unfamiliar with tie valve, the operator failed

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to recognize what section of the procedure he initiated and, as a result, the chiller pumps trippe The inspectors determined that the failure of the operator to perform the proper section of Procedure OP/2A/6450/020 was primarily due to personnel error. The inspectors also noted that the format of the procedure contributed to the event. The procedure's structure lent to the error by having multiple sections together in one enclosure rather than in separate attachments. This aspect was discussed with plant management who indicated that, in light of this and other recent procedure adherence and format problems, a further review would be considered. The failure to follow procedure on behalf of the operator in this case was of minor safety consequence since plant equipment was not rendered inoperable nor was the long term operation affecte However, this incident was one of four examples of operators failing to follow procedures noted throughout this report and is characterized as Violation 50-413.414/98-01-02: Failure to Follow Plant Operating and Administrative Procedure c. Conclusion 1 One example of a violation was identified for failing to follow the appropriate section of a procedure for placing a containment chilled water pump in servic Quality Assurance in Operations 07.1 Plant Ooerations Review Committee (PORC) Meetina a. Insoection Scoce (40500)

The inspectors attended a PORC meeting on February 19, 1998, which was convened to discuss plans to reduce reactor Jower on Unit 1 the next day to swa) the reactor vessel flange 0-ring leat detection valve lineup from 11e inner to the outer 0-ring. The inspectors attended this meeting to verify that the required representatives and quorum were present, and that safety aspects associated with the planned swapover evolution were covered adequatel '

b. Observations and Findinos Since the beginning of the current fuel operating cycle for Unit 1 in January 1998, operators in the control room had been receiving intermittent indications of a reactor vessel flange inner 0-ring lea Approximately once every two or three days, the reactor vessel flange 0-ring leak detection high temperature alarm would enunciate when the tell-tale leak-off line temperature spiked to approximately 250 degrees Fahrenheit, then decayed quickly to normal temperatures. The ar,ount of

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. leakage caused slight increases in reactor coolant. drain tank levels, none of which, however, indicated leakage greater than Technical Specification limits. As a result of the inner 0-ring leak, plant management decided to isolate the inner 0-ring leak detection path and

. swap to the outer 0-rin Because the outer.0-ring differed from the inner 0-ring in that it was not provided with the same notched groove in the reactor vessel which would channel 0-ring leakage directly to the tell-tale piaing, a 10 CFR 50.59 safety evaluation was performed to evaluate the pro) ability and consequences of a potential outer 0-ring leak not being detected. The engineering staff determined that an unreviewed safety question did not exist based primarily on the _ belief that some of the potential leakage would end up in the tell-tale piping and cause a control room alar After discussions of various design aspects of the reactor vessel flange to support this belief, and logistical details of the swapover evolution

. including communications between the control room operators and those in containment, and diverse methods to be used to detect any 0-ring leakage. the PORC ap3 roved the safety evaluation and the plan to swap to the outer 0-ring leac detection pat The inspectors observed that the PORC exhibited good questioning attitude concerning the various aspects of this issu Conclusions The PORC meeting which was convened to discuss plans to swap the Unit 1 reactor vessel flange 0-ring leak detection from the inner 0-ring to the outer one was conducted in accordence with commitments contained in the UFSAR Chapter 16. Selected License Commitments. with adequate representation and a quorum present. The committee exhibited good questioning attitude regarding issues associated with the leak detection capability while aligned to the outer 0-rin Miscellaneous Operations Issues (92700. 92901)

0 (Closed) Licensee Event Reoort (LER) 50-414/96-07: Cold Leg Accumulator Discharg This LER documented an inadvertent discharge of the Unit 2 cold leg accumulators (part of the emergency core cooling system) into the RCS cold legs. The discharge occurred on December 16. 1996, during a shutdown to Mode 5 when RCS pressure decreased to the accumulator discharge setpoint of.600 pounds per square inch gauge (psig). The accumulator discharge isolation valves had been o)ened following RCS pressure boundary check valve testing, although t1ey should have been closed in accordance with Step 2.31 of OP/2/A/6100/02. Controlling Procedure for Unit Shutdown, approved November 25, 1996 (see NRC

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Inspection Report 50-413.414/96-20 for additional information).

Operator activities associated with this event were contrary to the requirements of TS 6.8.1.a. and Regulatory Guide 1.33. Appendix A: and constituted a second example of failure to follow procedure, characterized as Violation 50-413.414/98-01-02: Failure to Follow Plant Operating and Administrative Procedure This LER is closed and the licensee's corrective actions will be tracked'

with the response to the Notice of Violation.

08.2 (Closed) URI 50-413.414/97-15-01: Failure to Follow Procedures Resulting in Inadvertent Injections of ECCS Fluid into the Reactor Coolant System (RCS).

On December 29, 1997. an inadvertent Unit 1 safety injection pump discharge into the RCS occurred during cold leg accumulator fillin The licensee attributed the event to failure to follow the cold leg accumulator operating procedure. Unresolved item 50-413.414/97-15-01 was opened pending further NRC review of the human performance issues associated with the event. The evolution was governed by Procedure OP/1/A/6200/009, Cold Leg Accumulator Operation, Revision 61. Step 2.3.3 which directed the operator to close valve 1NI-118A, safety injection Jump 1A cold leg injection isolation valve-, was inadvertently missed. T1is was contrary to requirements contained in TS 6.8.1.a and Regulatory Guide 1.33. Appendix A. and constituted a third example of failure to follow 3rocedure, characterized as Violation 50-413.414/98-01-02: Failure to rollow Plant Operating and Administrative Procedures.

08.3 (Closed) URI 50-413/97-15-02: Appropriateness of Operator Actions During Control Rod Testin This item involved concerns associated with operator response to a Unit 1 manual reactor trip following a loss of rod position indication during rod manipulations on December 29, 199 While manually tripping the reactor, which was already shut down to Mode 4. control room operators held in the Main Feedwater (MF) Isolation reset pushbuttons on the main control board to prevent an unnecessary secondary plant transien Following the reactor trip. Abnormal Operating Procedure AP/1/A/5500/0 ' Reactor Trip or Inadvertent Safety Injection Below P-10. Revision 1 Step 29.a. directed control room operators to manually initiate feedwater isolation. Again, operators decided to avoid a secondary plant transient and skipped Step 29.a. The inspectors questioned the rocedure ap)ropriateness-(A)). Operations of deviating Procedure Management from the abnormal [ operating] p/ Abnormal (0MP) 1-7. Emergency Procedure Implementation Guidelines. Revision 13. provided guidance for deviating from Emergency Procedures. However, deviation from APs was not addressed. A separate procedure. OMP 1-4. Use of Procedure Revision 59. Section 8.1.N stated "Unless specified by a procedure, an

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automatic signal shall Dat be defeated from performing its intended function." According to OMP 1-4. Section 8.4.E. if there is reason to believe that a procedure step does Dat have to be performed and is not applicable (N/A), then several criteria must be met: (1) two operator one of whom is a supervisor who holds a senior reactor operator (SRO)

license, shall approve the decision to deviate from the procedure: (2)

the performer of the step shall initial'the step marked N/A: and (3) the initials of the approving SR0 shall be documented on the working copy of the )rocedure beside the applicable step along with a brief description of tie reason for the deviation. Step 9.6 of OMP 1-4 also states that, whenever an AP is used, a Procedure Evaluation Form shall be completed and forwarded along with the completed procedure to the 0)erations Support Manager. The form is intended to provide feedbacc to ensure that APs are kept current and usabl The inspectors reviewed the procedure that was in use the night of the manual trip and post-trip response. Step 29.a had not been marked N/A:

nor had the initials of the procedure performer or an approving SR along with a descri] tion of the reason for the deviation. been provided on the procedure.- r eedback provided in the Procedure Evaluation Form was "None - or No Comments. The person who filled out the form began to provide additional information but struck it ou No reference to the appropriateness of MF isolation could be gleane The inspectors did not identify plant safety concerns associated with the decision to bypass MF isolation during and after the manual reactor trip from Mode 4. However, defeating the MF isolation function and failing to document the decision to deviate from the AP indicating the persons accountable and their justifr.ation in accordance with the OM exhibited in this case an informal regard for the AP as well as the administrative requirements governing deviation from it. This failure to comply with OMP 1-4 constituted a fourth example of Violation 50-41 /98-01-02: Failure to Follow Plant Operating and Administrative Procedure II. Maintenance M1 Conduct of Maintenance M1.1 Comoonent Coolina Water (KC) 2B Heat Exchance (HX) Tube Cleanina

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a. Insoection Stone (62700/62707/55050)

The inspectors determined by work observation and document review. the adequacy of maintenance activities relative to cleaning the 2B KC HX tubing and replacement of vent and drain lines associated with this heat exchanger. Cleaning of tubes was performed under Work Order 97111777-0 Replacement of vent and drain lines was done under Work

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Orders 97013977-01 and 97013976-01. The two-inch line on isometric Drawing 2RN-424. was safety-related QA Condition 1. Duke Class C and the 3/4-inch diameter line was noncode, nonsafety. Duke Class G classification. The controlling procedure for cleaning was MP/0/A/7650/056 C. Heat Exchanger Corrective Maintenance. Revision Observations and Findinas Cleanina of 2B KC HX Tubina - At the time of this inspection, cleaning of the 2B KC HX tubes was in )rogress. The inspectors noted that the tubes were cleaned by using tie propelled brush method during which individual cleaner brushes are inserted in the tube-ends and shot through the tubes with a specially designed lance-gun, under sufficient water pressure to achieve the desired cleaning. The inspectors verified that technicians were adhering to procedural requirements including installation of individual brushes in each tube; establishment of good communication on the inlet and outlet ends of the HX: a clean full tube stream of water followed the brush and the muddy water: sufficient light was provided at both ends of the HX to assure good visibility: and procedure sign-offs were in line with job completion. Through discussions with the cognizant component engineer, the inspectors ascertained that in 1995, the 2B KC HX was re-tubed with stainless steel Type 316 tubing as a protective measure against copper contamination in the syste However, the licensee indicated that out of a maximum of 800 tubes that could be plugged. 318 of the original tubes were plugged and left in the H For the most Jart, these tubes were located in the periphery of the HX's tubesheet. T1ese tubes were made from brass material and were allowed ;

to remain in the HX because of the difficulty in removing and replacing i them from that location of the tubeshee l t

Reolacement of 28 KC HX Vent and Drain Lines - The vent and drain lines in the 2B KC HX were replaced due to pipe wall degradation from general corrosion. The replacement pipe sections were made of seamless carbon l steel pipe, two-inch and 3/4-inch diameter schedule 40 Type 106 Grade l B. material. This material was the same as the piping replaced. The 1 inspectors observed welding in progress on the 3/4-inch line: observed completed welds: and reviewed quality records for the filler metal, replacement piping, welder qualifications and in-process control documentatio Weld appearance was satisfactory and the documents and records were complete and accurat Conclusions Cleaning of the 2B KC HX was well planned managed and executed with l sufficient oversight by the cognizant engineer who displayed a good l working knowledge of the components and took an active role in the '

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activity. Technical personnel. including welders, were adequately trained to perform their assigned tasks. Procedures were followe tests were performed and records were complete and accurat M1.2 Reolacement of Certain Isolation Valves on the Nuclear Service Water ;

(RN) System. Associated with the Control Room Air Chillers (Unit 1) l Insoection Scone (62700/62707/55050)

The inspectors determined by work observation and document review the adequacy of work activities with regards to the replacement of certain manually operated isolation valves associated with the control room air chillers. The governing codes for this activity were the American Society of Mechanical Engineers (ASME) Sections III and XI. Editions 1974 and 1989 respectively. The replacement was being handled as minor modification CE-8790 which was executed using work orders 97042493. -9 . -96. -97, and -9 l Observation and Findinas At the time of this inspection, sections of the RN piping were undergoing modification to facilitate installation of the replacement valve Through discussions with the cognizant engineer and a review of controlling documents, the inspectors ascertained the following information: five manually operated butterfly isolation valves; identified by tags 1RN-238. -243. -247. -298, and -303: were being removed from service due to material deterioration which precluded them from performing their intended functions. The replacement valves were similar in size except that they were manufactured from stainless steel ,

material which provided improved performance in their applications. The i inspectors' review of the licensee's valve replacement evaluation, verified that the stress calculation CNC-1206.02-84-2010. Revision 14 for these valves was acceptable, and that the 10 CFR 50.59 safety evaluation was satisfactory. Also, because the replacement was regarded as a routine valve maintenance and re)lacement activity, it did not require inclusion in the Catawba UFSA1. Through this document review, the inspectors ascertained that existing piping would have to be cut ,

back slightly and rewelded to accommodate a three-inch difference in i valve take-out dimension Welding was being controlled by requirements of the applicable code and the licensee's Procedure SM/0/A/8100/001. Revision 1. Welding of 0A Piping and Valves. The piping system was rated as ASME Class "C."

Replacement piping was made from eight-inch diameter pipe Schedule 4 carbon. steel material Type SA-105. Grade B. The inspectors reviewed-material certification reports, personnel qualification records, weld process control records, and observed welding of certain welds during

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effort, the inspectors verified that on February 4.1998, a. welding QC-inspector had quizzed certain welders who were working on this job to determine their knowledge of welding process control practices at Catawb Based on his questions, the welding OC inspector determined that the welders' responses indicated that their knowledge of weld process control practice.s was not fully adequate and stopped work on the job. The licensee's immediate corrective action was to conduct training to assure that supervisors and welding personnel had a good understanding of the process control program before returning to the jo The licensee documented this finding with PIP 0-C98-0479 and initiated a root cause investigation to address the long-term questions and corrective measures to address this problem. Through discussions with technical personnel, the inspectors determined that the probable cause of this problem was a lack of adequate screening of incoming welders and appropriate pre-job training to ensure that welders had a good working knowledge of the licensee's weld process control program. The welders involved in this problem were from the licensee's Electrical System Support (ESS) organization, and had been brought in to weld on this modification. The welders were qualified to applicable code requirements and the quality of welds they had fabricated was not in question. An example of inadequate screening and training of welders brought in to weld on safety-related main feedwater piping had been previously identified as a weakness in NRC Inspection Report 50-413.414/97-15. The problem identified by the liceasee during the present inspection was another example of inadecuate site screening and training of welders before allowing them to welc on safety-related QA Condition 1 components. In response to these problems, the licensee took certain corrective measures'that will provide for screening and pre-job training of welders before assigning them to the jobs where superior skills and knowledge of the program were require c. Conclusions Replacement of certain isolation valves on the RN system used on the control room air chillers was consistent with applicable cod requirements for materia, and processes. Engineering's overview was adequate. We'ders assigned on the job lacked adequate knowledge in the licensee's welding process control program which resulted in a work stoppage. The licensee's inability to establish a strong working program to address these type of welding problems. was regarded as a weakness.

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~ 12 M2 .Haintenance and Haterial Condition of Facilities and Equipmen M2.1 Seal Water Valve Iniection Inservice Testina Insoection Scone (61726)

On; January 28, 1998. troubleshooting activities were performed.to determine the cause of indication problems associated with 2NW-190 Seal Water Supply Isolation Valve to 2NI-121A. which is the A-train Safety Injection Pump Discharge to RCS Loops B and C Hot Legs Isolation Valve. The licensee determined that 2NW-190A was unable to open due to a large differential pressure across the valve. The inspectors discussed the valve's safety function with engineering and operations personne b. Observations and Findinas-

~The containment valve injection water (NW) system prevents leakage of containment atmosphere past certain gate valves used for containment isolation following a loss of coolant accident. This is accomplished by injecting seal water at a pressure (150 asig) that exceeds the peak containment accident 3ressure (15 psig) Jetween the two seating surfaces of the flex-wedge dis (s. In October 1997, the licensee encountered a '

position indication problem associated with 2NW-190A. Specificall with the valve in the closed position and receiving an open demand signal. an open indication light would come on, but the closed indication light would not go out. The licensee suspected that the problem was limited to indication onl On January-28, 1998, the licensee was aerforming troubleshooting activities to determine the cause of tie indication problem. During troubleshooting, technicians encountered difficulty in opening the valv The valve was removed from the system and bench teste The valve stroked on the test bench with no difficulty and no signs of foreign material were identified. The valve was reinstalled in the system the~ evening of the January 29, 1998, and the next day, failed an inservice valve stroke test. The maintenance technicians determined that the valve was not opening. The cause was attributed to reactor coolant system leakage past two safety injection check valves and two containment valve water injection system check valves. The licensee hypothesized that the associated back pressure had caused the valve to become unable to open due to a large differential pressure across the

. valve. To verify this hypothesis the licensee vented the piping and attempted to open the valve. The valve opened without difficulty. and an inservice valve stroke test was successfully performed several hours later.

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The inspectors questioned the valve's ability to perform its safety function. which was to provide containment valve injection water to 2NI-121A (a containment isolation valve) on a containment isolation signa Valve 2NI-121A is normally closed. The valve is opened for hot leg recirculation following the injection and cold leg recirculation phases of ECCS operation. The licensee responded that the valve would not be required to perform a containment isolation function until the associated section of piping had depressurized (some time after accident initiation). The inspectors asked if the containment isolation signal to 2NW-190A that is generated early in the accident would still be present at the point when the valve would no longer be pressure-boun The licensee provided electrical diagrams demonstrating that a seal-in circuit' ensured that a containment isolation signal would be maintained to 2NW-190A (and other_ valves in the system) as long as the valve injection water signal is not reset. The inspectors independently verified that the seal-in circuit existed and that it was being tested in accordance with monthly and quarterly slave relay testing requirements. The' inspectors' review concluded that the valve injection water signal could not be reset without resetting the Containment Phase A signal firs The licensee indicated that PT/2/A/4200/027, NW Valve Inservice Tes Revision 28 would be revised to provide a step to vent 2NW-190A before performing future in-service tests. The licensee r,tated that venting does not establish " ideal conditions" for the test, but establishes the design conditions to demonstrate its design function (to open at less than 150 psig differential pressure). The licensee has addressed the long-term resolution of NI and NW system check-valve leakage in station PIP 2-C98-0391. The inspectors questioned whether or not the valve would meet Technical Specification surveillance requirements. Pending further NRC review, this is characterized as Unresolved Item 50-414/98-01-07: Operability of Valve 2NW-190 c. Conclusions An Unresolved Item was open pending further NRC review of a Technical Specifications compliance issue associated with containment valve injection water system valve 2NW-190 M2.2 Scaffoldina Proaram And Handlina Of Scaffoldina Material Insoection Scone (62707)

The inspectors reviewed the licensee's scaffolding program and the methods of handling scaffolding material. This included the-review of station procedures for the erection and removal of scaffolding and for the removal of items from radiation controlled

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area Discussions were conducted with health physics and scaffolding crew personne b .' Observations and Findinas Discussions with the scaffolding supervisor indicated that three scaffolding systems were used at Catawba; the wedge lock system, the tube and coupler system, and the welded frame system. The system normally selected for use to su] port maintenance activities was the system that could be erected t1e fastest and could conform to the physical limitations of the local area. Regardless which scaffolding system'was chosen, com)leted scaffolding, ready for use, was erected in accordance wit 1 the station's Power Group-Scaffold Manual and MP/0/A/7650/115. Revision-004. Erection And Removal Of Scaffolding. Inspectors verified the Power Group Scaffold Manual was in compliance with OSHA standard 29 CFR Part 1926. Safety Standards for Scaffolds Used in the Construction Industry: Final Rule, effective date November 29, 1996. The licensee also indicated that all scaffolding was erected by cualified builders who receive 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> of instructional training curing the qualification process. The inspector did not observe scaffolding being constructed or the cutting and prefabrication of scaffolding material due to the limited amount of scaffolding work being performed during the time of the inspection. Controlled areas set up specifically for cutting and preparing scaffolding material were also not available for inspection. However, the '

inspector noted from a review of licensee procedures that the unconditional release of material from a radiologically controlled area including material associated with scaffolding. included surveys for potential contaminatio Scaffolding material is stored in the auxiliary building in one of seven scaffolding storage boxes located on different elevations and behind the auxiliary building in three large cargo-type i storage boxes. According to the licensee, the storage boxes j located in the auxiliary building are primarily used to store a material for scaffolding jobs in the auxiliary building and the large cargo-type storage boxes hold scaffolding material used mostly in containment during refueling outages. The storage boxes

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contained various material and building hardware required for the erection of scaffolding. Some of the material was wrapped but the bulk of the material was unwrapped. Materials being transported '

.from one controlled area to another are required by station

. procedures to be wrapped. The inspector did not observe the .

transporting of scaffolding material but did observe scaffolding-material that was being wrapped and stacked for transport as the material was being taken out of a potentially contaminated area in the radiation controlled area. The material was easily accessible u . .. .. .. .. .. .. .. . .. .

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for ins)ection. The inspectors noted that all storage containers were la)eled identifying the radiation levels and contamination levels present. Random smear surveys were taken from different materials from all storage boxes to verify that the stored material were within the limits as specified on the storage container and the method of storage was appropriate based on the actual contamination levels. All smear surveys were counted and

.found to be less that 1000 dpm/100cm2. The inspectors noted however that smear survey results from external surfaces of stored material in two of the three large cargo type storage boxes exceeded the contamination levels stated on the container labe This discrepancy was considered to be of minor significance since all survey results were less 1000 dam /100cm2, the level of loose contamination which would require tie storage containers to be posted as contaminated per 10 CFR Part 2 Conclusions The inspectors concluded that the scaffolding program was in compliance with the requirements of 29 CFR Part 1926. Safety Standards for Scaffolds Used in the Construction: Final Rul With the exception of the minor discrepancy identified between actual internal contamination levels and the amount posted, radiological handling and storage of scaffolding material was adequat M2.3 Main Feedwater Reaulatino Valve 1CF-37 Problems Insoection Scoce (62707)

The inspectors reviewed circumstances surrounding the forced Unit 1 shutdown associated with the erratic performance of main feedwater regulating valve ICF-37. which controls feedwater flow to the B steam generator, Observations and Findinas On January 16, 1998, control room operators experienced problems controlling B steam generator (SG) level when valve ICF-37 responded erratically to control input signals. The operators swapped from automatic to manual valve control and were better able to maintain the SG level within the normal operating band. Later, power was reduced to approximately 20 percent ~ to allow the valve to~ be isolated for

' troubleshooting. Initially, the valve's packing was adjusted and testing was performed demonstrating freedom of movement and that the valve's pneumatic control system was functioning properly. After the valve was returned to service and reactor power was increased on January 17, 1998, operators again experienced the same symptoms as before with

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erratic SG level control. Plant management elected to shut down the plant to allow full draining and isolation of the piping associated with ICF-37 for troubleshooting. Technicians discovered a galled aluminum s)acer in the valve packing cavity which was im) acting stem movemen T1e spacer had been replaced during the recent Jnit I refueling outage following planned valve maintenance. Plant personnel determined that the installation of the aluminum spacer (placed in the packing cavit below 5 graphite and rope packing rings) was unapproved for this. valv The controlling. Maintenance Procedure. MP/0/A/7600/83. Main Feedwater Regulating Control Valves Corrective Maintenance.. Revision 4. specified in step 11.1.10 to install a carbon spacer (if removed) in the packing cavity. Licensee personnel generated PIP 1-C98-0218 to document the problems with this valve. The aluminum spacer was replaced with a new carbon one and the system and plant were successfully returned to operatio The inspectors reviewed Procedure MP/0/A/7600/83 and confirmed that it specified using a carbon spacer instead of an aluminum one. The inspectors discussed this issue with maintenance personnel and management who indicated that on December 9.1997, during the refueling outage, technicians working on the valve discovered that its original carbon packing spacer was damaged and needed replacemen There was no carbon spacer available and the technicians discussed with a maintenance technical assistant the possibility of using an aluminum spacer instead

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of a carbon one. The decision was made to use the aluminum one. The technician failed to bring the procedure with him during these discussions which might have prompted the technical assistant to further scrutinize the use of an aluminum spacer. The technician later failed to annotate the spacer material deviation in the procedur The safety consequences of this error were minimized by the fact that the feedwater regulating valve performs a backup isolation function to the main feedwater motor-operated isolation valves located in the steam doghouses. Additionally. )lant engineers performed an operability evaluation (documented in )IP 1-C98-0218) demonstrating that valve ICF-37 would have been able to perform its isolation function even with the increased frictional forces caused by the galled packing space Licensee management appropriately addressed the human performance issues associated with the aluminum spacer installation. The inspectors considered the licensee's investigation and corrective actions to be appropriate and thorough. The failure to properly follow MP/0/A/7600/83 on December 9. 1997 was contrary to the requirements of TS 6.8.1.a and Regulatory Guide 1.33. Revision 2. 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 50-413/98-01-03. Failure to Install Correct Packing Spacer in Feedwater Regulating Valve ICF-3 . ..

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One Non-Cited Violation was identified for the-failure to follow maintenance procedures which.resulted in an unapproved aluminum packing spacer being installed in the Unit 1 B steam generator main feedwater regulating valv III. Enaineerina E3 Engineering Procedures and Documentation E3.1 Calculation of Accentable Emeraency Core Coolina System (ECCS)

Leakaae Outside Containment Insoection Scone (37551)

The inspectors reviewed the established program for monitoring ECCS leakage outside containment and the methodology used for determining acceptable leakage limits. This review included discussions with operations and engineering personnel, and review of plant procedures and aaplicable portions of the Updated Final Safety Analysis Report (U SAR). Observations and Findinas On January 21, 1998. following an inservice surveillance test of the 1A centrifugal charging pump. an inboard seal leak was observed while the pump was in standby. The leakage was measured by the licensee at approximately 350 milliliters per minute (ml/ min). On January 23. 1998, a surveillance test was performed on the 2A centrifugal charging pump. When this pump was secure an outboard seal leak was observed and later measured to be greater than 400 ml/ min. Inspectors questioned when the pumas were to be declared inoperable based on their respective leacage contribution to the total ECCS leakage outside containment for each individual unit. Discussions with engineering personnel indicated that this amount of leakage did not render either centrifugal charging pump inoperable. It was noted. however, that no current dose analysis calculation had been performed to

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substantiate this operability determinatio ECCS leakage outside containment is monitored during normal o)erations on each unit to ensure total leakage would not clallenge the post-accident dose rates as specified in 10 CFR 10 when in cold leg or hot leg recirculation alignment following a large break loss of coolant accident. PT/1/A/4150/002. Revision 026. Visual-Inspection Of Radioactive Systems Outside Containment, performed on a weekly basis, is the procedure used to monitor all

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ECCS systems, components, and related piping that could come in contact with reactor coolant from the containment recirculation sump. This procedure was reviewed by the inspectors and it was verified that the seal leakage from the 1A and 2A centrifugal charging pump was being monitore Upon further investigation and rev'N of Catawba's UFSAR, Section 15,6. Decrease in Reactor Coolant Inventory, the inspectors identified various conservative assumptions that were outlined in the Standard Review Plan 15.6.5. Appendix B, and required to be included in the analysis of the offsite dose effects attributable to Engineered Safety Features (ESF) leakage. Discussions with engineering methodology, personnel and concerning whether all current dose required conservative analysis assumptions were included in current dose analysis calculations, revealed that Catawba's dose analysis calculations were in the process of being modified. Current dose analysis calculations were not consistent in the assumptions used, and those as specified in the UFSA Specifically, the UFSAR states that no credit was to be taken for auxiliary building ventilation system for iodine removal. As documented in existing PIP 0-C95-1938, current dose analysis assumptions take credit for this factor. Proposed resolution of this inconsistency was given an internal due date of May 31, 1998, by the license Based on the inconsistency in the dose analysis assumption used and the ongoing revision in the dose analysis calculation, the inspectors could not verify the accuracy of the licensee's dose analysis calculation and methodology used. The inspectors therefore determined further review was warranted. This review will be tracked under Inspector Followup Item (IFI) 50-413.414/98-04: Assess the Licensee's Dose Analysis Calculation For ECCS Leakage Outside Containmen c. Conclusions An Inspector Followup Item was identified to assess the licensee's dose analysis calculation for ECCS leakage outside containmen E7 Quality Assurance in Engineering Activities E7.1 Environmental Qualification of Refuelina Water Storace Tank Level Transmitters a. Insoection Scoce (37551)

On January 27, 1998, the licensee discovered that the Refueling Water Storage Tank (RWST) level transmitters were not qualified for a

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postulated submerged environment. The inspectors discussed the issue with plant personnel and NRC subject matter experts: inspected a sample of RWST level transmitter boxes: reviewed station PIPS 0-C97-0190 and 0-C98-361: reviewed design basis documentation: and reviewed construction records'and cable conduit dam installation procedure Observations and Findinas During a recent review of a possible modification to eliminate sources of RWST level instrument inaccuracy, plant engineers determined that the RWST level transmitters were not qualified for a submerged environmen The licensee assumed that these transmitters (which are located between

.the outer tank wall and a missile shield which surrounds the tank) will be submerged under water during a specific design basis event. The accident scenario involves a tornado-generated missile that is assumed to puncture the tank. The RWST inventory would issue from the resulting-hole, and the surrounding enclosure would then flood. The transmitters, which are located just above ground level outside the tank and inside the missile shield, would be submerged under approximately 12 feet of water. The tornado also is assumed to damage one main steam line. The main steam line break would cause a safety injection on low pressurizer pressur Since the RWST level transmitters were assumed to be submerged during this tornado event, and the transmitters were not qualified for a submerged environment, the licensee identified a concern that instrument failure might give a false low RWST level indication. The auto-swapover level setpoint is 37 percent, and emergency procedures direct control room o pumps)perators to secure when the RWST all operating level indicates ECCS less than pumps (including 5 percent. The concerncharging was that an instrument failure would occur prior to safety injection system termination, thereby resulting in either a premature swap to the containment sump or loss of reactor coolant pump seal injectio To address the concern, the licensee devised a plan to verify that cable penetrations into the transmitter boxes, which also were not qualified for a submerged environment, were sealed. The licensee reasoned that if the seal dams (which had been installed during construction) were present, then they would provide a suitable barrier to water inleakag An acceptance criterion for a maximum hole diameter was calculated, and on January 29, 1998, the licensee inspected the RWST instrument boxes to identify visible holes: to ensure the gasket sealing around the box doors was intact: and to verify that the dams were present. The inspection results were that all enclosures and transmitters were in sound condition with no apparent leaks or holes. Based upon the inspection, the licensee concluded that all Unit 1 and Unit 2 RWST level transmitters were operable (eight transmitters in total).

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The inspectors conducted an independent inspection of the transmitter boxes'on January. 30 and identified water droplets and moisture around a cable 3enetration in one of the Unit 2 boxes (2TB0X0010). Noting that there lad been no precipitation for two days, the inspectors asked why the moisture had not been identified during the licensee's inspection the previous day. On February 2. Engineering personnel verified that moisture was present in 2TB0X0010: on February 3. the associated level channel 3 was declared inoperable, appropriate TS action was taken, and PIP 2-C98-0434 was generated to document the inspectors' observatio The inspectors determined that the licensee failed to identify the degraded condition during initial inspections, and the licensee initiated a root cause evaluation to address the adequacy of their initial-inspections. The licensee refurbished 2TBOX0010 and declared it operable on February Within their corrective action program, the licensee is considering several alternatives to address the design deficiency for long-term resolutio Conclusions The licensee's identification of the design deficiency was commendabl Their initial inspection of the RWST level transmitter boxes failed to reveal moisture in one of the boxes. The licensee's corrective efforts to assess the adequacy of their initial inspections were appropriat E8 Miscellaneous Engineering Issues E (Ocen) LER 50-413.414/97-003-00: Auxiliary Feedwater System Found Outside Design Basi (Ocen) URI 50-413.414/97-300-02: Catawba UFSAR Discrepancies a. Insoection Scooe (37551. 92700. 92903)

The inspectors reviewed the licensee's activities to address the potential design discreaancy associated with air entrainment caused by aligning the Auxiliary reedwater Condensate Storage Tank (CACST) to.the suction of the auxiliary feedwater (AFW) pumps in Units 1 and 2. The

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licensee had identified in LER 50-413/97-003 that the normal system alignment could potentially place each unit outside of its design basis, and that further engineering analysis from an outside contractor would be performed to confirm or refute the degraded condition. This issue was also raised as part of Unresolved Item 50-413.414/97-300-0 , .

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21 Observations and Findinas On May 15. 1997, the licensee identified a potential design deficiency associated with the normal configuration of aligning each AFW pump to the CACST (shared by both units) to provide condensate quality water at sufficient head to operate the pumps. The CACST was one of three nonsafety-related, condensate water sources tied to a common header feeding the aumps. The other two sources included each unit's upper surge tank (JST) and each unit's main condenser hotwell. All of these sources were normally aligned but capable of being isolated from the common header by motor-operated isolation valves: check valves were provided to prevent volume exchange between the three condensate quality water sources. Because of its elevation and the amount of suction head provided, the CACST would initially provide pump suction until its level decreased to a predetermined value at which time the UST would begin to supply the AFW pump The licensee determined that because of the nonsafety-grade tanks'

piping configurations, air could be introduced into the suction of all three of the AFW pumps during the transition from the CACST to the UST with a failure of the nonsafety-related 1(2)CA-6 to close on low leve This could potentially disable the pumps during a loss of offsite power (LOOP) event coincident with a steam line or feedwater line break prior to the transfer of AFW pump suction to its safety-related assured source, the non-condensate quality nuclear service water system. The licensee performed an initial operability determination given the above identified condition and determined that further engineering analysis would be required from a vendor. In the interim, the licensee closed the suction valves from the CACST (Valves ICA-6 and 2CA-6) to eliminate the potential for air entrainmen The inspectors learned that the valves were closed using the clearance

]rocess; specifically. Tagout 17-643 for Unit 1 and Tagout 27-1139 for Jnit 2. In addition to tagging the valves closed, the clearances (dated May 15. 1997) removed power from the valves by opening their breakers, and removed an Operator Aid Computer and control board annunciator alarm for "CA CST lo level" from service in each uni As a result of these actions, licensee personnel generated an Operations Technical Memorandum (#97-01) dated May 15, 1997, assigning " action items" to designated individuals ("normally a balance of plant licensed reactor operator")

until a permanent resolution of the AFW/CACST suction problem could be obtained. The technical memorandum stated that shutting the CACST suction valves would prevent the low level alarm from enunciating which normally prompted certain actions in abnormal operating procedur AP/1(2)/A/5500/06. Loss of S/G Feedwater. Revision 17. To compensate for the two CA-6 valve closures and the removal of the CACST low level alarms, the technical memorandum included actions to maintain the UST full, and to inform the control room SRO upon any AFW system automatic

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start to implement the abnormal procedure. The temporary melnorandum was given an expiration date of April 30, 199 The licensee performed a 10 CFR 50.59 screening (also on May 15, 1997)

of the technical memorandum in accordance with Nuclear System Directive (NSD) 209.10 CFR 50.59 Evaluations. Revision 6. to determine-if an unreviewed safety question determination would be required. The-screening determined that the activities described in the technical memorandum related to the implementation of the abnormal operating 3rocedure and did not change the facility as described in the [ Updated rinal) Safety Analysis Report (UFSAR). nor did it change procedure methods of operation, or alter a test or experiment as described in the UFSAR: and, therefore did not recuire a US0 determination. This screening did not specifically adcress the action to close the valve As of the end of this inspection aeriod, approximately nine months later, the clearance tags and tec1nical memorandum were still activ The inspectors reviewed the UFSAR. Section 10.4.9. Auxiliary Feedwater System, subsection 10.4.9.2. which described the suction sources for the AFW system. The UFSAR stated that "all of the preferred sources of condensate quality water are normally aligned to the CA pump suctions."

The CACST was listed first among the three condensate-quality source It further stated "to maintain steam generator water chemistry, especially for such fast recovery events as [ station) blackout, loss of

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normal feedwater. or main steam system malfunction. the AFW pumps should be normally aligned to condensate quality water. All necessary means to prevent inadvertent injection of out-of-chemistry nuclear service water to the steam generators must be employed."

The inspectors evaluated the licensee *s actions against the UFSAR comments and determined that the licensee incorrectly concluded on May 15. 1997, that shutting the valves and issuing additional instructions to operators regarding the implementation of Procedure AP/1(2)/A/5500/06, did not involve a change to the facility or its procedures as described in the UFSAR As a result, the licensee failed to meet the 10 CFR 50.59 requirement to perform an evaluation determining whether or not shutting the valves resulted in a US0. The inspectors discussed this issue with licensee personnel who indicated that the following factors influenced its decision not to pursue a safety evaluation for closing the valves:

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The clearance process and not the temporary or permanent modification process, was used to implement the change. The-temporary modification process was ruled out as a method to implement the valve closure, because of its expected short duratio _

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The inspectors questioned whether or not the clearances had been reviewed and dispositioned per the licensee's quarterly clearance review program outlined in Procedure PT/0/B/4700/058. Operations Quarterly Safety Tag Audit. Plant personnel indicated that the clearances had been identified as requiring further evaluation due to their age, but it was decided that the ongoing engineering analysis would be due soon and that the clearances should remain in place pending its completio The ins)ectors noted that the licensee had identified several times tiroughout the nine-month period that the ongoing engineering analysis would not be due until late winter 1998, including a CA-6 engineering update documented for a November 1 Site Direction Meeting. During that meeting, plant management was informed that preliminary results of the detailed analysis verified the problem of AFW pump air entrainment and that the isolation of the CACST was an appropriate decision. The inspectors also noted that the clearance extended beyond a refueling outage for Unit 1. The inspectors concluded that the temporary or permanent modification process would have been the appropriate vehicle to implement this chang No procedures were physically changed to implement the valve closure or the actions described in the Operations Technical

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Memorandum. The licensee considered the specific operator actions described in the memorandum as typical actions that would have been performed anyway (except for the action to enter AP-06 on any AFW actuation). The inspectors contended that the disabling of the low level alarm affected performance of emergency and abnormal o)erating procedures which allowed certain actions despite the a)sence of the alar .

The licensee did not consider the actions to close the valves as compensatory actions (described in NRC Generic Letter 91-1 Revision 1. and its implementing program. NSD-203. Operabilit Revision 9).

10 CFR 50.59 states that the licensee may make changes to the facility as described in the safety analysis report, or make changes in the procedures as described in the safety analysis report without prior Commission approval unless the )roposed change involves a change in the technical specifications or an JSQ. It also requires that the licensee  ;

maintain records of changes in the facility and of changes in procedures '

made pursuant to this section, to the extent that these changes constitute changes in the facility as described in the safety analysis report (or the procedures as described therein). The records must  !

include a written safety evaluation which provides the bases for the J determination that the change does not involve a US0. The licensee's

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failure to perform a USQ determination for the above compensatory actions affecting the normal source of suction for the AFW system as described in the UFSAR (and hence the failure to maintain associated records of such determination) was contrary to 10 CFR 50.59 and is identified as Violation 50-413.414/98-01-05: Failure to Conduct 10 CFR 50.59 Safety Evaluation for Operable but Degraded Condition and Related Changes Involving the Normal AFW Pump Suction Sourc At the end of the inspection period. licensee management stated that it recognized the weaknesses in its program implementation resulting in the violation and intended to correct those in the near term since preliminary results from the offsite engineering analysis confirm the outside design basis condition with valves 1CA-6 and 2CA-6 open to the AFW pumps' suction heade The LER will remain open pending the licensee's permanent resolution of the AFW design basis conditio c. ' Conclusions One violation of 10 CFR 50.59 was identified regarding the failure to perform a safety evaluation with an unreviewed safety question determination for compensatory actions associated with the realignment of the auxiliary feedwater system pumps' normal suction sources. This issue also involved poor decision making in the licensee's implementation of the clearance process instead of the temporary modification proces IV. Plant Sucoort R1 Radiological Protection RI.1 General Comments (71750)

As noted in Section M2.2 above. the inspectors found minor discrepancies between radiological postings on scaffolding containers located behind the auxiliary building and the actual contamination levels on equipment contained therein. The results of inspector-initiated smear analyses demonstrated that contaminated levels were well below NRC regulatory requirements for posting contaminated radioactive material: however, the inspectors concluded that the minor discrepancies between postings and actual contaminant levels warranted additional attention from site managemen Other radiation protection activities were determined by the inspectors to be adequate. No violations or deviations were identified.

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F2 Status of Fire Protection Facilities and Equipment F2.1. Malfunction of Fire Detection Comouter Insoection Scone (71750)

The inspectors reviewed an issue involving the failure of the fire detection system to monitor a series of alarm points (i.e., fire zones).

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): Procedore RP/0/B/5000/013. NRC Notification Requirements. Revision 21: Operations Management Procedure 2-2 Attachment 7. Non-Licensed Operator Turnover Sheet. Revision 48: the Unit 1 Facility Operating License: UFSAR Selected License Commitments (SLC) Section 16.9. Auxiliary Systems - Fire Protection Systems:

Procedure IP/0/A/3350 003. Fire Detection System (EFA) Channel Operational Test Procedure Revision 4: and the fire panel All Points Log. The inspectors discussed with operations supervision the expectations and training of the fire protection console operators (FPCO) responsible for monitoring the fire alarm compute Observations and Findinas On February 4. 1998, during troubleshooting of the fire detection system the licensee determined that a series of alarm points were not functioning properly. Alarms from the affected detectors would not have

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been received in the main control room. The fire detectors were declared inoperable and fire watches were established for the affected zones in accordance with the fire protection program requirements. A total of 36 zones were affected. Subsecuent to the discovery. the licensee replaced three power supply anc computer logic cards associated with the fire Janel and verified that all zones were being monitored properly. On rebruary 7. 1998, a separate, unrelated card failure resulted in the loss of fire zone monitoring. Appropriate compensatory measures were established and the panel repaire Following the February 4 incident, licensee personriel identified that the fire panel computer previously had not been monitoring all fire zones based on a review of an All Points Log printout. During this

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review, the licensee identified that specific series alarm zones had not been monitoring since January 21, 1998. Further, some single zone alarms committed to as part of the UFSAR, Chapter 16. Selected License Conditions (SLC). Section 16.9. were not being monitored since December 24, 1997. Licensee personnel determined that compensatory fire watches had not been posted within one hour for the affected fire zones during the above dates. which was contrary to Facility Operating License Condition 2.C.(8) for Unit 1. and 2.C.(6)- for Unit 2: along with commitments contained in UFSAR SLC, Section 16.9-6, Fire Detection

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Instrumentatio SLC Remedial action 16.9-6.a stipulated with any, but not more than one-half the total in any fire zone Function A fire detection instruments shown in Table 16.9-3 ino>erable, restore the inoperable instrument (s) to operable status witlin 14 days or within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> establish a fire watch patrol to inspect the zone (s) with the ino)erable instrument at least once per hour...". The licensee made a 24-lour notification to the NRC for the non-compliances per License Condition 2F (both Units) and 10 CFR 50.7 .The inspectors' inde)endent review of the All Points Log printout indicated that on Fe)ruary 4,1998, the 300 and 700-series fire detector points were the zones involved, which affected various zones included in Table 16.9-3. Fire Detection Instruments. A review of the non-licensed operator turnover logs indicated that operators were reviewing and turning over the res)onsibility to monitor the fire panel to subsequent I operating shifts wit 1out recognizing that the series and single fire zone alarms had been disabled since December 24, 199 The inspectors * review of operator logs, procedural guidance for fire j alarm panel operation, and training lesson plans, found that there were no written instructions or guidance for the operators to compare the All Points Log printout to fire zones designated to be monitored. The 3 inspectors considered that this was a weakness and a significant contributor to the problems with the fire detection panels not being

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identified earlie Plant personnel documented these problems in PIPS 0-C98-0474 and 0-C98-0499, which included proposed corrective actions to provide the FPC0 with better guidance on incorporating a review of the All Points Log once per shift. Increased surveillance of the alarm panels was provided until confidence in the system's performance could be regaine The failure to identify.the deleted fire zones before February 4.1998, and failure to establish compensatory fire watch )atrols within one hour (after 14 days had expired) was contrary to Catawaa Facility Operating LMense condition 2.C.(8). Technical Specification 6.8.1.1, and commitments contained in SLC. Section 16.9 (of the UFSAR). This failure affected single zones dating back to December 24, 1997, and the entire 300 and 700 series alarms deleted as far back as January 21, 1998. In

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addition, during that time the operators inadequately performed their turnovers without recognizing the non-functioning fire panel alarm points. Licensee management has appropriately addressed the factors-that caused the above non-compliances in its corrective actions as described-in PIP 0-C98-0499. 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 50-413,414/98-01-06. Failure to Establish Fire Watch Patrol Within 1 Hour for Non-Functioning Fire-Zone Detector _-_ _ __-___ - _ _

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i Cont'_.sions One non-cited violation was identified for failure to establish l compensatory fire watches after several fire detection zone alarms i malfunctioned for greater than 14 days. The inspectors identified a weakness concerning the lack of written guidance to operators on how to effectively monitor the fire detection panel alarms, i V. Mananamant Meetinas i l

X1 Exit.Heeting Summary j The inspectors ) resented the ins ection results to members of licensee management at t1e conclusion of he inspection on February 25, 199 l The licensee acknowledged the~ findings presented. No proprietary information was identifie .

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PARTIAL LIST OF PERSONS CONTACTED Licensee M. Birch, Safety Assurance Manager M. Boyle. Radiation Protection Manager R.: Glover.. Operations Superintendent-J. Forbes.' Engineering Manager R. Jones. Station Manager-M. Kitlan. Regulatory Compliance Manager G. Peterson. Catawba Site Vice-President R. Propst. Chemistry Manager INSPECTION PROCEDURES USED IP 37550: Engineering IP.37551: Onsite Engineering IP 55050: ASME Welding IP 61726: Surveillance Observation IP 62700: Maintenance

'IP 62707: Maintenance Observation -]

l IP 71707: Plant Operations 1 IP 71750: Plant Sup) ort Activities IP 92700: Licensee Event Reports l IP 92901: Followup - Operations IP 92903: Followup - Engineering IP 40500: Effectiveness of Licensee Controls in Identifying and Preventing Problems ITEMS OPENED. CLOSED. AND DISCUSSED ODED .414/98-01-01 URI Basis For Five-Minute Period of VC System Inoperability with Compensatory Action (Section 01.2)

50-413.414/98-01-02 VIO Failure to Follow Plant Operating and Administrative Procedures (Sections 0 .1. 08.2. and 08.3)

50-413/98-01-03 NCV -ailure to Install Correct N king Spacer in Feedwater

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Regulating Valve ICF-37 (Section M2.3)

50-413.414/98-01-04 IFI Assess the Licensee's Dose Analysis Calculation for ECCS Leakage Outside Containment (Section E3.1)

50-413.414/98-01-05 VIO Failure to Conduct 10 CFR 50.59 Safety Evaluation for Operable but Degraded Condition and Releted Changes Involving the Normal AFW Pump Suction Source (Section E8.1)

- 50-413.414/98-01-06 NCV Failure to Establish Fire Watch Patrol Within 1 Hour for Non-Functioning Fire Zone Detectors (Section F2.1)

50-414/98-01-07 URI Operability of Valve 2NW-190 (Section M1.2)

Closed 50-414/96-07 LER Cold Leg Accumulator Discharge (Section 08.1)

50-413.414/97-15-01 URI Failure to Follow Procedures Resulting in Inadvertent Injections of ECCS Fluid into the Reactor Coolant System (Section 08.2)

50-413/97-15-02 URI Appropriateness of Operator Actions During Control Rod Testing (Section 08.3)

Discussed 50-413.414/97-003-00 LER Auxiliary Feedwater System Found Outside Design Basis (Section E8.1)

50-413,414/97-300-02 URI Catawba UFSAR Discrepancies-(Section E8.1)

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LIST OF ACRONYMS USED AHU - Air Handling Unit AP .- Abnormal Procedure CFR -

Code of Federal Regulations CLA -

Cold Leg Accumulator DBD -

Design Basis Documentation EFA -

Fire Detection System ESF -

Engineered Safety Feature FPCD -

Fire Protection Console Operators IFI -

Inspector Followup Item LER -

Licensee Event Report NCV -

Non-Cited Violation OMP -

Operations Management Procedure PIP -

Problem Investigation Report PDR -

Public Document Room RCS -

Reactor Coolant System RWST -

Refueling Water Storage Tank SLC -

Selected Licensee Commitments UFSAR - Updated Final Safety Analysis Review ,

URI -

Unresolved Item VC - Control Room Ventilation System VIO -

Violation WO -

Work Order YV -

Containment Chilled Water