ML20217G566
| ML20217G566 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 03/23/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20217G543 | List: |
| References | |
| 50-413-98-01, 50-413-98-1, 50-414-98-01, 50-414-98-1, NUDOCS 9804020423 | |
| Download: ML20217G566 (33) | |
See also: IR 05000413/1998001
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-413. 50-414
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
,. . PDR ADOCK 05000413
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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
inspector.
Doerations.
- -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 leak. (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 .
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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 accurate. (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 weakness. (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
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requirements of Title 29 Code of Federal Regulations Part (CFR) 1926.
Safety Standards for Scaffolds Used in the Construction: Final Rule.
With the exception of a discrepancy identified between actual internal
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contamination levels and the amount posted radiological handling and
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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.
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. 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 them.
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, 1998.
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-ring.
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 period.
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 period.
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 inspected.
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 E8.1.
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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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 resolved.
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 sources.
. 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 alignment. 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-C98-0476.
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 ) asis.
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 flowpath.
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 unit.
located in the auiliary building, had )een o)ened.during the .
maintenance activity. - At the completion of t1e maintenance activities.
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 minutes.
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 minutes.
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 door.
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 leak.
01;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 report.
04 Operator Knowledge and Performance
04.1 Containment Chill Water Pumo Trio
a. 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 issue.
b. 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 incident.
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 valve. 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 tripped.
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 affected.
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 Procedures.
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 service.
07 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 adequately.
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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 leak.
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-ring.
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 alarm.
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 path.
The inspectors observed that the PORC exhibited good questioning
attitude concerning the various aspects of this issue.
-c. 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-ring.
08 Miscellaneous Operations Issues (92700. 92901)
08.1 (Closed) Licensee Event Reoort (LER) 50-414/96-07: Cold Leg Accumulator
Discharge.
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 Procedures.
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 filling.
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 Testing.
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, 1997. 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 transient.
Following the reactor trip. Abnormal Operating Procedure AP/1/A/5500/05.
' Reactor Trip or Inadvertent Safety Injection Below P-10. Revision 16.
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 Procedures.
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 operators.
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 usable.
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 SRO.
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 out. No reference to
the appropriateness of MF isolation could be gleaned.
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 OMP.
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 50-413.
414/98-01-02: Failure to Follow Plant Operating and Administrative
Procedures.
II. Maintenance
M1 Conduct of Maintenance
M1.1 Comoonent Coolina Water (KC) 2B Heat Exchance (HX) Tube Cleanina
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(Unit 2)
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 97111777-01. 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 5.
b. 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 system. 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 HX.
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 tubesheet. l
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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
documentation. Weld appearance was satisfactory and the documents and
records were complete and accurate.
c. 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 followed.
tests were performed and records were complete and accurate.
M1.2 Reolacement of Certain Isolation Valves on the Nuclear Service Water ;
(RN) System. Associated with the Control Room Air Chillers (Unit 1) l
a. 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. -94.
-95. -96. -97, and -99. l
b. Observation and Findinas
At the time of this inspection, sections of the RN piping were
undergoing modification to facilitate installation of the replacement
valves. 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 dimensions.
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 40.
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
. fabrication and others which had been completed. Through this work
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11
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
Catawba. 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
job.
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 required.
c. Conclusions
Replacement of certain isolation valves on the RN system used on the
control room air chillers was consistent with applicable code.
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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M2 .Haintenance and Haterial Condition of Facilities and Equipment.
M2.1 Seal Water Valve Iniection Inservice Testina
a. Insoection Scone (61726)
On; January 28, 1998. troubleshooting activities were performed.to
determine the cause of indication problems associated with 2NW-190A.
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
personnel.
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. Specifically.
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 only.
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
valve. The valve was removed from the system and bench tested. 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 signal.
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-bound.
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 first.
The licensee indicated that PT/2/A/4200/027, NW Valve Inservice Test.
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-190A.
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-190A.
M2.2 Scaffoldina Proaram And Handlina Of Scaffoldina Material
a. 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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areas. Discussions were conducted with health physics and
scaffolding crew personnel.
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 contamination.
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
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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 label.
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 20.
c. 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 Rule.
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
adequate.
M2.3 Main Feedwater Reaulatino Valve 1CF-37 Problems
a. 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,
b. 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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16
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 movement.
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 cavity.
below 5 graphite and rope packing rings) was unapproved for this. valve.
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
operation.
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 replacement. 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 procedure.
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 spacer.
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-37.
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c. Conclusions
~
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.
III. Enaineerina
E3 Engineering Procedures and Documentation
E3.1 Calculation of Accentable Emeraency Core Coolina System (ECCS)
Leakaae Outside Containment
a. 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).
b. 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 secured.
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 determination.
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 100.
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 monitored.
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 UFSAR.
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 licensee.
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 Containment.
c. Conclusions
An Inspector Followup Item was identified to assess the licensee's
dose analysis calculation for ECCS leakage outside containment.
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 procedures.
b. 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 environment.
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
pressure.
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 injection.
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 inleakage.
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' observation.
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 7.
Within their corrective action program, the licensee is considering
several alternatives to address the design deficiency for long-term
resolution.
c. Conclusions
The licensee's identification of the design deficiency was commendable.
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 appropriate.
E8 Miscellaneous Engineering Issues
E8.1 (Ocen) LER 50-413.414/97-003-00: Auxiliary Feedwater System Found
Outside Design Basis.
(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 50-413.414/97-300-02.
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b. 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 pumps.
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 level.
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 entrainment.
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 unit. 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 procedure.
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, 1998.
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 procedures.
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 valves.
As of the end of this inspection aeriod, approximately nine months
later, the clearance tags and tec1nical memorandum were still active.
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 sources.
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:
.
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
duration.
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23
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 completion.
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 10.
1997 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 change.
- No procedures were physically changed to implement the valve
closure or the actions described in the Operations Technical
-
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 alarm.
.
The licensee did not consider the actions to close the valves as
compensatory actions (described in NRC Generic Letter 91-18.
Revision 1. and its implementing program. NSD-203. Operability.
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
1
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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 Source.
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
The LER will remain open pending the licensee's permanent resolution of
the AFW design basis condition.
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 process.
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
management.
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
a. 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 2-22.
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 computer.
b. 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
'
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 repaired.
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
'
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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Instrumentation. 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
hour 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 50.72.
.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, 1997.
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
-
identified earlier.
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 regained.
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
-
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 Detectors.
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i
c. 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, 1998. l
The licensee acknowledged the~ findings presented. No proprietary
information was identified.
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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
ODEDe.d
50-413.414/98-01-01 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 04.1.
08.1. 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-190A.
(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
(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 -
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