ML20203L630
| ML20203L630 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 02/09/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203L618 | List: |
| References | |
| 50-413-97-15, 50-414-97-15, NUDOCS 9803060151 | |
| Download: ML20203L630 (50) | |
See also: IR 05000413/1997015
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
.
Docket Nos: 50-413, 50-414
Report Nos.: 50-413/97-15, 50-414/97-15
Licensee: Duke Energy Corporation
Facility: Catawba Nuclear Station. Units 1 and 2
Location: 422 South Church Street
Charlotte, NC 28242
Dates: November 23, 1997 - January 10, 1998
Inspectors: D. Roberts, Senior Resident Inspector
R. Franovich. Resident Inspector
M. Giles, Resident Inspector (In Training)
N. Economos, Reactor Inspector, Region II (RII) (Sections
M1.4 through M1.7)
-
D. Forbes. Radiation Specialist, RII (Sections R1.1, R1.2,
R1.3, R2.1, and RS.1)
R, Moore, Reactor Inspector. RII (Section 04.4 Section E8.1
through E8.8)
N. Stinson. Radiation Specialist. RII (Sections R1.1. R1.2.
R1.3. R2.1, and R5.1)
P. Tam. NRC Senior Project Manager. NRR (Section E3.2)
Approved by: C. Ogle, Chief
Reactor Projects Branch 1
Division of Reactor Projects
_ _ _
Enclosure 2
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G PDR
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EXECUTIVE-SUMMARY
1
' Catawba Nuclear Station. unts 1 and 2
,
NRC Inspection Report 50-413/97-15. 50-414/97-15
- This integrated inspection included aspects of licensee operations.
maintenance.- engineering, and plant support. The report covers-a seven-week
, period of resident inspection: in addition, it includes the results of
announced and reactive inspections by regional reactor safety inspectors.
<
radiation-specialists, and a project manager from the Office of Nuclear
! Reactor Regulation (NRR).
i Ooerations
s * In general, the conduct of routine operations, including plant shutdown
+
and startup activities associated with the Unit 1 refueling outage were
professional and safety conscious. (Section 01.1)
l
.
.
Operator performance during reactor and turbine startup was good as
- evidenced by proper procedure use, communications, and coordination.
(Section 01.2)
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Unit 1 refueling activities were performed without incident and in
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accordance with governing procedures. (Section 01.3)
Human performance weaknesses related to an inadvertent injection of
'
.
- safety injection system water into the reactor coolant system were
t identified as an unresolved item, (Section 04.2)-
$ .
Operators appropriately manually tri) ped the Unit I reactor (while it
,
was shutdown) in compliance with Tecinical Specifications following loss
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,
of indication for a shutdown bank control rod. (Section 04.3)
'
.
Operator response to plant conditions related to the December 30.1997.
Notice of Unusual-Event as a result of elevated reactor coolant system
t= -leakage was appropriate. (Section 04.4)
'
.
The inspectors concluded that flooding the Unit 1 refueling cavity with-
j- two inoperable charging pumps would have increased the margin to-boiling
E and would not have sufficiently diluted the reactor coolant system boron
concentration to erode the required shutdown margin. However, the
.
Technical Specification did not allow the licensee.to transfer water
-from the refueling water storage tank to the reactor-coolant system at-
- their respective boron concentrations without some exemption from the
- regulations. Hence. the Plant Operations Safety Committee's conclusion
that the operation did not constitute a positive reactivity change was
inappropriate. (Section 07.1)
,
, .
Maintenance _
-
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Surveillance activities were conducted well with proper use of
4 procedures and adequate communications batween personnel performing the
- tests. (Section M1.1)
.
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A natural circulation test performed on Unit 1 successfully demonstrated
'
the ability to cool the plant without forced reactor coolant system flow
following the replacement of the Unit 1 steam generators in 1996.
(Section M1.2)
.
Outage-related maintenance activities in general, were conducted with
good workmanship, proper radiological controls, and proper adherence to
procedures. (hection M1.3)
.
Sections of the licensee's second 10-year interval inservice inspection
program that were reviewed, complied with code requirements. Inservice
inspection examinations observed were performed in a satisfactory
manner. Technicians were well-trained and had good knowledge of plant
equipment and orocedural requirements. Inspection results were
evaluated and documented with accuracy and clarity. (Section M1.4)
.
The observed steam generator eddy current activity was weP managed and
executed in accordance with applicable procedures. Technical personnel
doing data acquisition were qualified to perform their assigned tasks.
The licensee took a proactive approach to resolve the problem of build-
up in steam generator tube inner surfaces. The eddy current inspection
plan for this outage met code and industry standards. (Section M1.5)
.
The licensee continued to demonstrate a weakness in the area of welding
certain production welds. Some welders lacked the necessary skills to
produce radiography quality welds as evidenced by the need for repeated
-
repairs during fabrication activities. Tne in-processing group had not
been able to satisfy the need for experienced welders in time for
training prior to the outage. (Section M1.6)
. A review of welding records associated with minor r.odification CE-8774/-
8778 on the service water lines of the 1A emergency diesel generator
disclosed that hold points were inspected as required, welders were
qualified to use the arocess s)ecified, the proper filler metal was
issued and used to fa)ricate tie aforementioned welds and that weld
fabrication and testing met applicable code requirements. (Section
M1.7)
.
An unresolved item was identified concerning anti-reverse rotation
devices not being installed on the Unit 10 reactor coolant pump motor
before it was installed during the December 1997 refueling outage.
(Section M7.1)
.
A non-cited violation was identified for failure to properly test
safety-related logic circuits for feedwater isolation and P-10 source
range block permissives. (Section M8.1)
_ .
,
3
Encineerina
Outage-related modifications for main steam isolath valve control
-
.
circuitry and low steam line pressure safety injection signals were
conducted appropriately. (Section El.1)
.
In general, engineering support of Unit 1 outage activities was good.
(Section E2.1)
.
A minor concern was identified concerning engineering documentation of
operability determinations. (Section E3.1)
.
The 1997 U) dated Final Safety Analysis Report revision was in compliance
with 10 CFR Part 50.71. A strength was noted concerning the
incorporation of pertinent changes to the revision, (Section E3.2)
.
A non-cited violation was identified related to failure to perform
adequate Technical Specification surveillance testing of emergency core
cooling system check valves due to an inadequate procedure. (Section
E8.3)
Plant Sucoort
.
The licensee was effectively maintaining controls for personnel
monitoring, control cf radioactive material, radiological postings, and
radiation area and high radiation area controls as required oy
10 CFR Part 20. (Section R1.1)
.
All personnel exposures as of December 1997 were below regulatory
limits. The licensee had established effective procedures for the use
of respiratory protection equipmert and was providing training for
personnel required to wear respiratory protection equipment.
(Section R1.2)
.
The licensee demonstrated strong management support in the area of As
low As Reasonably Achievable (ALARA) as indicated by source term
reduction efforts such as replacement of stellite valve seats, effective
chemical shutdown process for the current outage, and by establishing
challenging exposure goals. The inspectors viewed the overall ALARA
program as a strength. (Section R1.3)
. The resairatory protection program was being implemented as required by
10 CFR 3 art 20 Subpart H. Survey instrumentation had been adequately
maintained. (Section R2.1)
.
A violation was identified for failure to revise radiation work Jermits
.to_ reflect changes in dr.ess out specifications that arose from c1anging
radiological conditions. (Section R3.1)
. The radiation protection technicians had been provided an adequate level
of training to perform routine activities involving radiation and
control of radioactive material. (Section R5.1)
4
-
Emergency response activities were conducted well during the
' Notification of Unusual Event on December 30. 1997. Attention to detail
was warranted concerning the use of wide-range versus narrow-range plant
indication during events. (Section Pl.1)
.
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~ Reom-t Details
Summarv of Plant Status
.
-
Unit 11 began the inspection period with its end-of-life coast down in progress
"
at 98 percent power. A power reduction was initiated and the unit entered
Mode 3 on November 28, 1997, for refueling outage 1E0C10. Plant cooldown to
'
Mode 4 and Mode 5 was eccomplished on November 29. 1997. The unit entered
Mode 6 on December 3. 1997, and core off-load (No Mode) was completed on
December 8. 1997. Mode 6 was re entered on December 18, 1997, and after core
reload was completed. Mode 5 was entered on December 24. 1997. Heat up to
. Mode 4 and Mode 3 conditions occurred on December 28 and December 30, 1997
respectively. Reactor startup (Mode 2) commenced on January 4. 1998, with the
unit being placed on-line January 5. 1998. Power was increased to 100 percent
on January 9, 1998. The unit ended the inspection period at 100 percent
- power.
.
Unit 2 began the inspection period at 97 percent power. On November 23, 1997 #
a rapid power decrease was initiated because of an' air leak on main generator
power circuit breaker (PCB) 2B compressor skid. Power was stabilized at 49
percent at which time the pilot valve for 2B PCB was replaced. The pilot
valve had seat leakage because debris on the valve seat prevented full
closure. A power escalation commenced on November 23. 1997, and the unit was
returned to 100 percent power on November 24, 1997. 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
the applicable portions of the UFSAR that were related to the areas inspected.
- The inspectors verified that the UFSAR wording was consistent with the-
obser.ved plant practices, procedures, and parameters.
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
approved procedures. The inspectors attended operations shift turnovers
and site direction meetings to maintain awareness of overall plant
status and operations. Operator logs were reviewed to verify
Operational safety and compliance with Technical Specifications (TS).
Instrumentation computer indications, and safety system lineups were -
periodically reviewed, along with equipment removal and restoration
tagouts, to assess system availability. The inspectors conducted plant
tours to observe material condition and housekeeping. These tours
~
'iricluded visits to the containment building during the Unit I refueling
~
outage 1EOC10. Problem Identification Process (PIP) reports were
routinely reviewed to ensure that potential safety concerns and
equipment problems were resolved.
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Unit 1 shutdown activities for 1E0C10 were observed in accordance with
-
Procedure OP/1/A/6100/02. Revision 131. Controlling Procedure for Unit
Shutdown, in general, the conduct of operations was professional and
safety conscious.
01.2 Startuo Activities
a. 1DSoection Scone (71707)
The inspectors observed PT/0/A/4150/19. Revision 1, 1/M Aoproach to
Criticality. and OP/1/B/6300/001. Revision 62. Turbine Generator. These
procedures controlled approach to criticality and synchronization to the
grid on January 4.1998, and January 5.1998, respectively, following
the 1E0C10 refueling outage.
b. Observations and Findinas
The inspectors observed that operators were following procedures and
ensuring that plant equipment performed as expected. Reactor engineers
were present and provided assistance to operators for the required
reactivity plots. Reactor criticality was achieved within the allowable
tolerance band of the estimated criticality conditions.
Control room operators manually aligned the unit to the offsite
electrical grid after euto-synchronization was initially unsuccessful.
Auto-synchronization was unsuccessful because the alternating current
.
(AC) voltage regulator malfunctioned and subsequently tripped to the
manual regulator. A bent connector on the primary side of the Y-phase
potential transformer was found and repaired. Auto-synchronization to
the grid was later successfully accomplished.
The inspectors observed portions of PT/0/A/4150/11C. Revision 1. Dynamic
Rod Worth Measurement And Boron Endpoint. 0porations performance dering
this evolution was good. Rod movement was well coordinated and
communication between reactor engineering and control room operators was
clear and concise.
c. Conclusions
Operator performance during reactor and turbine startup was good as
evidenced by proper procedure use, communications, and coordination.
01.3 Unit 1 Refuelino Outaae Activities
a. Insoection Scoce (71707)
.The inspectors observed and assessed )erformance of various Unit 1
outage-related activities to ensure tlat procedures were followed, that
shutdown-risk controls were implemented. infrequently performed
activities were adequately prepared for and briefed by station
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e
personnel, and that foreign material exclusion controls were implemented
,
where applicable,
f
- b. Observations and fjndinas
! In general.- refuelin9 outage activities were i
and in accor6 nce with governing procedures. performed
Only withod incident
minor discrepancies: -
.
associated with equipment tag-outs and restorations were identified by '
a the inspectors: these discrepancies were discussed with the Shift Work
! Manager on duty for resolution.
Containment Cleanliness Walkdown
l The inspectors conducted a containment cleanlines1 tour of the reactor
t
building and pipe chase on December 27, 1997, before Unit 1 entered Mode
- 4. In general, the licensee's efforts to remove tools and debris and to
secure loose items were effective. The inspectors noted several minor ,
i
discre ancies and communicated them to the Shift Work Manager for
'
resolu 100,
i Unit Entry into Reduced Inventory and Midloco Doeration
i
! The resident inspectors reviewed the licensee's administrative controls
governing reduced reactor coolant system (RCS) inventory and midloop.
,
conditions.
.b At Catawba, a reduced inventory condition corresponded to 16 percent.RCS
[ level with fuel in the core. Midloop was defined as RCS water-level
- below the top of the flow area of the hot legs at the junction of the
[ hot legs to the reactor-vessel with fuel in the core. This corresponded-
g to.7.25 percent RCS level.
The outageofincluded
one period operationtwo periods ofAtoperation
in midloop. in reduced
the beginning inventory
of the outage. t and he
F
' unit was drained to just belov the reactor vessel flange (approxinately
25 percent RCS level) so the vessel head could be lifted. Once the core
-
was off-loaded, the system was drained again for steam generator (SG)
nozzle dam installation.
1
After the core was reloaded into the-reactor vessel. the unit entered
i reduced inventory early on December 23, 1997, for reactor vessel head
"
replacement and B steam generator nozzle dam removal (which provided for
a large vent path in accordance with the administrative controls
governing shutdown risk). Reactor coolant system level was increased to
20-percent for A-train engineered safety fGture (ESF) testing.
Following ESF testing late on December 23. 1997. RCS level was reduced
. _
_again to 8 percent for. the removal of the other SG nozzle dams and
miscellaneous valve work. The unit remained at 8 percent level until
December 25, 1997, when RCS vacuum refill was performed.
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The inspectors reviewed NRC and industry guidance and the licensee's
- '
' procedures including Nuclear System Site Directive (NSD) 3.1.30- Unit ,
Shutdown Configuration Control and procedures for draining the RCS. The
i inspectors also reviewed the Technical Specification Action Item Log-to
verify that essential equipment was available. The inspectors verified
that the licensee had reviewed their controls and administrative
.
procedures governing shutdown risk.
~
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The licensee conducted pre-job briefings with the operations shifts
scheduled to perform RCS jraining to reduced inventory conditions. The
briefing package provided a description of the evolution. TS
implications,. NSD 3.1.30 implications, success criteria, roles and
responsibilities, termination criteria, and contingency. plans.
4
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Information pertaining to shutdown risk management was updated and
reviewed during the entire outage, not just during reduced inventory
operations, on a daily basis. The status of boration flow paths, core
fill flow paths, reactivity instrumentation, residual heat removal (RHR)
and spent fuel sool cooling, power availability to the 4160 volt (V)
+
. essential switc1 gear, RCS level, boron concentrations, and RCS thernal
- margin (time to boil) was reviewed daily at the outage management
meetings. The inspectors considered the routine monitoring and
-
L continuous-licensee awareness of system and equipment status and risk-
l informative parameters a strength in maintaining a focus on defense in
depth.
- Control room operators were observed prior to and during the drain down-
l. to reduced inventory and midloop to verify that:
1
L 1) Containment closure was maintained with fewer-than ten exceptions
4
during reduced inventory, as required by NSD 3.1.30. No
j- . exceptions to containment closure were allowed by the licensee.
l while the RCS was at midloop.
2) A member of the operations shift was assicaed as the Containment
. Closure Coordinator and was responsible for maintaining the status
- of all penetrations.
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3) Redundant core exit temperature indications were available.
'
4)- Two independent trains of RCS level instrumentation were
- maintained during reduced inventory and midloop. The wide-range
i. and mid-range (differential pressure) RCS level indications, as
- well as level sight glass, were available during reduced -
inventory. Narrow-range (ultrasonic) level indications were
available during mid-loop.
~
'5)~ RCS level disturba'nces were minimized. ~ Site Directive 3.1.30,
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included guidance regarding the need to minimize RCS level -
3
disturbances such as ESF flow balancing during-reduced inventory
and midloop operations. The A-train ESF testing was performed
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with RCS level at 20 percent between entries into reduced
,
inventory on December 23. 1997.
6) Two independent makeup paths of borated water were available in
accordance with NSD 3.1.30. The licensee's Abnormal Operating-
Procedure'AP/1/A/5500/19. Loss of RHR. 3rovided for aligning the -
degrags and gravity feed flowpaths slould-RHR be lost or
7) The B SC cold-side primary manway provided a large vent path-for
reflux cooling after the reactor vessel head was set, Once the
other SG nozzle dams were removed and all SG manways and
diaphragms were installed, two upper head injection isolation
valves (INC-198 and 1NC-199) were opened to provide a large vent-
path.
8) Two ofn tte and two onsite AC power sources were available during
reduced inventory and midloop operation. To minimize the.
possibility of a loss of power to the required busses access to
these areas was restricted and work activities:affecting
associated switchyard equi) ment was controlled in accordance with
OP/1/A/6150/06. Draining tie Reactor Coolant System.-Enclosure
4.12,. Reduced Inventory Posting Requirements.
-The inspector also noted that control room operators exhibited a
questioning attitude and sensitivity to shutdown risk orior to ESF
-
testing by requesting engineering and regulatory compiiance sup) ort to
resolve a concern regarding the operability of A-train RHR in tie ESF
test alignment.
c. Conclusions
The licensee conducted outage activities safely with appropriate . .
-
sensitivity to shutdown risk and the availability of attendant plant
equipment. Only minor housekeeping items were identified during the.
inspectors * containment cleanliness-walkdown. Control-room operators
exhibited a-good questionino attitude-and-sensitivity to shutdown risk
~
prior to ESF testing.
' 04 Operator Knowledge and Performance
04.1 - Promot Onsite Resoonse to Events _-lqsal Comments (93702)
The licensee reported three separate events to the NRC Headouarters
Operations Officer Yia the Emergency _ Notification System in accordance
with 10 CFR 50.72. These events occurred within 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />s-of each other
, . . .near;the end of the_ Unit.1 refueling outage. _ The inspectors responded
to the site and reviewed the licensee's activities related to the
,
_ events. Each event is described separately-in sections 04.2. 04.3. and
04.4 below. The events were all reported appropriately by licensee
staff with-sufficient information provided and in accordance with
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' regulations. The event notification for the manual safety. injection
-
'
' discussed in section 04.2 was rescinded on January 8,1998, after the
- ~ licensee revisiteo further the requirements-of 10 CFR 50.72. The
inspectors identified no violations in this area.
04.2 Inadvertent safety Iniection Pumo Discharae to RCS
l a. Insoection Scone (93702)
. The inspectors responded to the site and reviewed the circumstances
n
surrounding an inadvertent injection of safety injection system water
.
into the Unit 1 RCS and a subsequent pressurizer heatup transient on
?- December 29,1997. . The inspectors assessed operator performance in
L stabilizing the plant, the root cause of the transient, and the-
[ licensee's initial correctiu actions.
j b. Observations and Findinas
Seauence of Events
,
i On December
- 29, 1997,
performing Procedure at app /6200/009.roximately
OP/1/A 12:17 Operation,
Cold leg Accumulator a.m., operators were
! Revision 61, to fill the Unit I cold leg accumulators in preparation for
F
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unit startup from the refueling outage. The_ plant was in Mode 4 with
RCS temperature and pressure at approximately 330 Fahrenheit ('F) and-
'--
550 pounds per square inch gauge (psig), respectively. Pressurizer
i- surge line temperature was approximately 488 F. Low tem)erature over-
.
'
pressure protection for the primary system was not operaale, nor was it
required with reactor coolant system temperature above 285'F. The
operator at the control board was performing steps in Section 2 of the
] procedure to align the safety injection system for accumulator fill.
6 Section 2.3 required using safety injection (NI) pump 1A. The operator
! read through the procedure prior to initiating the fill and marked those
-steps not to be used "N/A": skipping those steps that would be used.
[ During the performance of the procedure, Step 2.3.3, which directed the
-
operator to close valve 1NI-118A, NI Pump 1A Cold leg Injection
- - Isolation was inadvertently missed. Tho operator stated his intention
to wait and return to this step just prior to initiating the fill in
order to minimize out-of-service time for the safety injection flowpath
, to the RCS, Homents later, an operator who had been directed to locally
! check the status of NI pump 1A -informed the operator at the controls -
! that the pump was ready. The operator at the controls forgot that step
!
2.3.3 to isolate the RCS cold leg injection header had not been
- performed earlier, and started the pump.
RCS pressurizer level and pressure immediately started rising while the
t . . . temperature drop)ed as a result of the. colder _ safety injection system
, water entering t1e RCS. Operators stated that they immediately noticed
j that pressurizer level was rising but did not initially attribute the
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rise to the start of the NI pump because of ongoing routine heatup
'
operations and the associated Expansion of water in the system. The
pressurizer level deviation annunciator was already illuminated as a
result of earlier normal heatup activities. Within 3 minutes, operators
realized that the additional level increase was due to the safety
injection pump start: they secured the pump and monitored plant
parameters.
Pressurizer surge line temperature dropped from 480'F to approximately
330'F as a result of the insurge of colder RCS water. After the safety
injection pump was stopped, the temperature began to recover. increasing
about 80 degrees in less than 15 minutes. Control room operators,
attempting to prevent the heatu) from exceeding TS 3.4.9.2 limits.
initiated pressurizer spray. T1e spray initiation resulted in an
outsurge of warmer pressurizer water through the surge line into the
RCS: causing surge line temperature to jcnn to approximately 470*F. The
change from 330*F to 470*F in less than 20 minutes exceeded the
-
pressurizer heatup TS limit (100 degrees in any 1-hour period).
Operators eventually stabilized pressurizer surge line temperature at
approximately 460'F. . As a result of the out-of-limit condition, an
engineering evaluation was performed (see section E3.1 of this report)
as required by the TS and the pressurizer was determined to be
acceptable for continued operation.
'
Doerator Performance and Reaulatory Sianificance
-
The inspectors interviewed plant personnel and determined that this
event was caused by human error and failure to follow procedures. The
control room operator intended to follow the procedure, but made an
error in forgettina to return to the requisite step before starting the
safety injection pump. The failure to follow Procedure OP/1/A/6200/009
was contrary to requirements in TS 6.8.1.a and Regulatory Guide 1.33.
Revision 2. Appendix A. Section 3.d. which stated that written
procedures shall be established and implemented covering operation of
the ECCS (cold leg accumulators).
Late in the inspection period, the inspectors recalled a previous event
during a Unit 2 shutdown in December 1996 where human error lead to an
inadvertent injection of water from the cold leg accumulators into the
RCS. This event was reported in Licensee Event Report (LER) 50-414/96-
007 on January 14, 1997. The inspectors considered that the two events,
while having low safety consequences, were significant, in that there
,
'
may have been common themes present between the 1936 event and the
December 29. 1997, event. Consequently, pending further review, the
inspectors will track the human aerformance issues associated with the
two events as Unresolved Item (URI) 50-413.414/97-15-01: Failure to
. Follow Procedures Resulting in Inadvertent Injections of ECCS Fluid Into
the RCS,
Regarding the pressurizer heatup in excess of TS limits, the inspectors
were concerned that the control room operators at the time were either
__ _ __ _ _ ~ . _ _ _ - __
8
unaware of or unfamiliar with pressurizer outsurge phenomena arior to
initiating pressurizer spray. The inspectors questioned w'1etier
initiating sprays was appropriate in view of the outsurge phenonenon, or
would it have been more prudent to allow temperatures to coast upward,
minimizing the thermal stresses to the pressurizer even if TS limits
were inevitably exceeded as a result of the initiating safety injection
event. This concern was expressed to plant management who was reviewing
the circumstances and training issues surrounding operator aerformance
during the recovery operation. The inspectors will track t11s issue
along with the procedure adherence issue under the Unresolved Item.
As stated in paragraph 04.1. operators initiclly reported this event via
the emergency notification system per 10 CFR 50.72. There was initially
some question as to whether or not the inadvertent injection was
reportable. Upon further review of related regulatory guidance, the
licensee determined that the event did not meet reportability criteria
specified in 10 CFR 50.72 and the eve.it notificatior, was rescinded on
January 8. 1998. The inspectors considered the operators' initial
decision to notify the NRC while considering the question on
reportability, to be conservative,
c. Conclusions
Operator performance errors lead to an inadvertent injection of safety
injection water into the reactor coolant system. During recovery from
the safety injection, operator actions contributed to the pressurizer
heatup rate exceeding Technical Specification limits. The pressurizer
was evaluated to be structurally acceptable for continued operation. An
unresolved item was identified related to the human performance issues.
04.3 Manual Reactor Trio While in Mode 4
a. Insoection.Scoce (93702)
The inspectors reviewed the circumstances surrounding a manual reactor trip initiation for Unit 1 on December 29. 1997. The inspectors
reviewed post-trip data. including control room data. Operator Aid
Computer trends, and printouts from the Sequence of Events Recorder.
4
The inspectors attended the Plant Operations Review Committee (PORC)
meeting authorizing the unit startup, and reviewed the PORC meeting
minutes,
b. Observations and Findinas
With Unit 1 shutdown in Mode 4 and RCS temperature and pressure at
approximately 336 F and 420 psig respectively, operators were
withdrawing control rod shutdown banks.A and.B in accordance with
o)erating procedures to provide shutdown capability. While withdrawing
slutdown bank B operators noticed that the digital rod position
indication (DRPI) for rod J-3 in that bank would not advance past 48
steps withdrawn, while the other rod positions in the bank advanced
,
. __ _ _ _ _ _ _ __ - _____-__ . _ _ - --
- __
<
i
,
9
i towards the 60 step indication. Operators drove bank B back to 42-
F -
-steps, as indicated by DRPI. and rod J-3 indicated approariately.
Operators then consulted engineering who recommended wit 1 drawing the
'
bank again towards 60 steps. With the rods at 58 steps, operators
received a DRPI Urgent Failure alarm. Rod J-3 general warning and rod
bottom indications were received, and operators manually tripped the
reactor as required by TS 3.1.3.3 and entered Abnormal Procedure
'
] AP/1/A/5500/05. Reactor Trip or Inadvertent Safety' Injection Below P 10.
l Revision 16.
.
The plant responded appropriately to the trip signal, with all rods
indicating at bottom. To avoid an unnecessary secondary plant
. transient. operators bypassed the feedwater isolation signal upon
.
I
tripping the reactor and bypassed the step in the AP to manually-
initiate the feedwatar isolation. Operators expressed that the
auxiliary feedwater system had not been fully tested in preparation for
- entering Mode 3 and two steps later in the procedure operators were
F directed to restore normal feedwater. Plant management reviewed the
i issue of whether or not ap3ropriate procedural guidance was provided for
,- feedwater isolation. The 30RC addressed this issue and initiated PIP 1-
t
'
C97-4391. No action was specified in the PIP to address deviation from
the AP. The inspectors were concerned about the deviation from the AP.
- This issue is characterized as Unresolved Item 50-413/97-15-02.
A)propriateness of Operator Actions During Rod Testing, pending further
>
NRC review. ,
,
U The cause of the J 3 rod's. indication 3roblem was a failed detector-
! encoder card in the A data cabinet. T1e failed card was replaced and
L the shutdown banks were withdrawn without further incident.
L
l .During a review of the licensee's reactor trip evaluation contained in
-
Procedure PT/0/A/4150/02, Transient Investigation, the inspector noted
that the engineer completing the attachments incorrectly listed pre.
<
transient RCS pressure as 1687 psig. The correct: pressure was 420 psig.
- _ The engineer had obtained the erroneous value from an operator who~
i referred to the narrow range pressure instruments in the control room.
- which go off scale low below approximately 1700 psig. The correct
- - pressure for the Mode 4 plant configuration should have been obtained
from a wide range pressure instrument. The inspector had a similar
observation this period during the event discussed in section Pl.1 and
noted that more attention to detail was warranted concerning the correct
instrumentation to reference during response to plant transients.
!
. - c. . Conclusions
1
l Operator actions to initiate a manual reactor trip following a
.
^
. . . mal. function-in the DRPi . system were appropriate. Follow-up actions to
bypass a feedwater isolation were under further review by the inspector.
-More attention to detail was warranted regarding the correct
instrumentation to reference during events.
!
!
l
'
_ _ _ _ . _ ,___ , _ _ , _ _ _ . _ _ _ _ _ _ __ _~
__ _ _ _ _ ._. . _ _ _ _ _ .- _ _ _
f
10
04.4 Excess Reactor Coolant (NC) System Leak Rate Durina Unit 1 Mode 3 Heat
.
N
a. Insnection Scone (71707)
The inspectors reviewed the circumstances associated with the
Notification of Unusual Event (NOUE) that occurred on Unit 1 during Mode
3 heat up on December 30, 1997.
b. Observations and Findinas
Initial Unit 1 conditions were Mode 3 and heat up to normal operating
temperature and pressure had been completed for approximately ten
minutes. Approximately 17 licensee personnel were in containment
performing system integrity and post-maintenance functional checks. At
5:35 p.m.. an alarm was received on reactor vessei (RV) leak-off high
,
temperature. At approximateij 5:40 p.m. the control room received
'
reactor coolant drain tank (NCDT) alarms indicating excess NC system
leakage. At 5:55 p.m. . the abnormal procedure for loss of NC was
entered, a second charging pump was started and the containment was
evacuated. A leak rate of approximately 40 gallons per minute (gpm) was
- determined. The Technical Support Center (TSC) and Operations Support
Center (OSC) were manned and a NOUE was declared at 7:22 p.m. due to
exceeding TS leak rate criteria and im Plant
cool down was initiated at 7:50 p.m.. pending
The NRCplant cool down,
was notified at 8:06 p.m,
4
At 8:30 p.m. the WRC was notified of the second charging pump start
(four-hour notification). Cool down was secured at 10:08 p.m. with NC
conditions at 1300 psig and 466 degrees F. At 1:06 a.m. on December 31.
1997, a containment entry team identified NC loop drain valves INC-13
and 1NC-106 crxked open and terminated the event with closure of the
valves. The NRC was notified of the event termination at 1:42 a.m.
The initial review by the inspectors indicated that the operator actions
'
were appropriate iur plant conditions. Actions to initiate cool down.
stabilize the plant conditions, and activate the TSC and OSC were timely
'
-
and conservative. NRC notifications were consistent with regulatory
requirements. Appropriate investigations were initiated to determine
the root cause, review the event and evaluate equipment performance and
impact. In ) articular the NCDT system was inspected and evaluated with
4
respect to tie over pressurization it experienced because of this event.
Degraded equipment was inspected and .~efurbished. The investigation to
determine the cause for the drain valves being slightly open was
ongoing. This investigation was documented in PIP 1-C97-4406. A
special report was being prepared to address Unit 1 start up events
w1ich includes the NC system high leak rate NOUE.
. . . .
.
i
_ _ _-.
_ . -_ .__ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ _
'
11
- c. Conclusion
-
j The licensee's response to the NOUE due to high-NC system leakage was
appropriate. Operator response was good and appropriate investigations
were initiated to review event response, root cause, and plant equipment
performance.
l
07 Quality Assurance in Operations
j 07.1 Plant Doerations Review Committee (PORC) Meetina
i a. Insoection Scone-(71707)
)
F On December 4 a PORC convened to discuss activities related to filling
! the refueling canal for core off-load to the spent fuel pool and TS
L
'
3.1.2.3..whichstatedthatonecharg)ingpum)
flow path (required by a se)arate TS shall 3einoperable the boron andinjection
capable of ,
being powered from an operaale emergency power source. The inspectors
'
attended the PORC meeting, reviewed the TS and TS Basis, and discussed
associated regulatory compliance and safety issues with NRC and plant
management,
i
'
b. Observations and Conclusions
.
At the time-of the PORC meeting, the reactor vessel head had been ' lifted
s
and the RCS was in a " loops not filled" condition. The licensee was
-
preparing to flood the refueling canal'to begin core alterations. - The
t
thermal margin was 15 minutes (high decay heat condition) to core boil
--
-(upor loss of the RHR system), and the minimum RCS boron concentration
-
required for shutdown margin was 2475 ppm. The IB charging pump was
-
inoperable because-of lube oil system equipment problems (see section
M2.1), and the 1A emergency diesel generator was inoperable for outage-
i related mr 1tenance. As a result. TS 3.1.2.3 required that all-
operations avolving positive reactivity changes be sus [ 2nded.
.
l The-licensee's objective was to flood the re#ueling cavity by 4
L transferring water from the refueling water storage tank-(FWST) and
thereby increase the thermal nargin for time to boil.- The. function of
the PORC was to determine if .he transfer of water from the FWST. which
j. was at a boron concentration of approximately 2800 ppm to the RCS at
, epproximately 3100 ppm. constituted a positive reactivity addition
prohibited by TS 3.1.2.3. The PORC concluded that the transfer of FWST
water to the RCS would constitute a ' boron adjustment" and not a
- positive reactivity addition. The PORC unanimously endorsed proposed
i actions to flood the refueling canal with clarification that no core
l alterations would be permitted. Following some discussion with the
4 . . . _ inspectors concerning the term " positive reactivity addition." the
L licensee decided to postpone flooding the refueling canal until some
.
other resolution could be obtained. The 1B charging pump was returned
s
to service on Decercber 5.1997, and refueling cavity fill was initiated
- - shortly thereafter.
$N
'
, _ , _- _,__ _
_.. - _ , _ _ . . - - _ _ - _ - . _ _
. _ - _ _ __ ._ _ ._ .
12
c. Conclusions
The inspectors concluded that flooding the refueling cavity would have
increased the thermal margin to safety and would not have sufficiently
diluted the RCS boron concentration to erode the required shutdown
mergin. However, the TS did not allow the licensee to transfer water
from the FWST to the RCS at their respective boron concentrations
without some exemation from the regulations. Hence, the FORC's
conclusion that t11s was a reactivity adjustment was inappropriate,
08 Hiscellaneous Op rations Issues (92901)
08.1 (Closed) LER 50-414/94-02-01- Reactor Trip Breakers Opened Due To
Component Failure
The event described in this LER occurred on June 15, 1994, due to an
intermittent rod control system firing cara failure. The circumstances
surrounding the event and the licensee's corrective actions associated
with the original LER were discussed in NRC Inspection Report 50-400/96-
05. The LER was supplemented on November 7,1996, to clarify that
Procedure OP/1.2/A/6150 Rod Control: not Procedure PT/0/A/4150/19.
Approach to Criticality, was revised to include provisions for checking
selected rod light indication at the rod control cabinets prior to
withdrawing control rods.
During the review of this LER, the inspector noted that a low power
.
Jhysit. test. Procedure PT/0/A/4150/118. Control Rod Worth Measurement
)y Rod Swa), was also revised to include the status check at the rod
control ca)inets. The inspector recalled that the rod swap procedure
was not used during the recently completed Unit I refueling outage and
that a new method contained in Procedure PT/0/A/4150/11C. Dynamic Rod
Worth Measurement and Boron Endpoint. Revision 0 was used instead.
This procedure was not in existence at the time of the LER and therefore
- did not include the provisions for checking control rod status at the
rod control cabinets. The inspector considered that the dynamic rod
,
worth measurement method contained the same inherent risks as the
procedures referenced in the LER and that it should include the same
provisions. This was discussed with regulatory affairs personnel who
indicated they would address the newer procedure and review the process
for incorporating previous corrective actions into new procedures. This
LER upplement is closed.
II. Maintenance
M1 Conduct of Maintenance
.
M1.1 _ General Comments Surveillance (61726)
The inspectors observed portions of the following surveillances and
inspection activities:
13
.
PT/0/A/4150/11C. Revision 1. Dynamic Rod Orth Measurement And
-
Boron Endpoint
.
PT/0/A/4150/01, Revision 17. Controlling Procedure for Startup
Physics Testing
.
PT/0/A/4150/19. Revision 1, 1/M Approach to Criticality
.
TT/1/A/9200/11. Revision 0. Natural Circulation Verification Test
.
PT/1/A/4200/09. Revision 153. Engineered Safety Features Actuation
Periodic lest
.
IP/0/A/3710/019. Revision 24, 125 Volts Direct Current (VDC) Vital
Instrumentation and Control Power System Battery Capacity Test
During these activities, the inspectors noted proper use of procedures
and adequate communication between personnel performing the tests. No
vialations were identified.
M1.2 Natural Circulation Verification Test
a. Insoection Scope
The inspectors observed licensee performance of TT/1/A/9200/11. Revision
,
'
0. Natural Circulation Verification Test on November 29, 1997. The
natural circulation verification test was performed to demonstrate the
ability of the nuclear steam supply system (NSSS) to remove heat via
natural circulation of the primary coolant and allow fine-tuning of the
on-site simulator for natural circulation conditions for the new steam
generators. The inspector reviewed the test procedure in advance, and
p observed licensee performance during the test to verify compliance.
b. Observations and Findinas
This test was controlled by system engineers who collected the data,
utilizing the operator aid computer (OAC), and determined test
acceatability. The inspector attended the pre-test briefing, ccaducted
by t1e RCS lead engineer. The briefing was conducted in an 0;derly
manner. with emphasis placed on acceptance criteria, termination
criteria, and expected plant response.
The test corsisted of tripping all four reactor coolant pumps
simultaneousty while the plant was in Mode 3. with RCS temperature and
pressure at 557'F and 2235 psig, respectively. Adequate decay heat was
available to drive natural circulation. Establishment of natural
circulation was verified by observing wide range RCS loop temperatures
as well as core exit therroccuples. In addition to tnese Jarameters,
pressurizer and steam generator levels and pressures, and RCS subcooling
were monitored. Stable natural circulation was maintained while data
was gathered for acceptance criteria determination. The test was
. terminated based on decr. easing steam pressure of 931 psig that
approached a termination test criteria for steam pressure of 900 psig.
In addition to acceptance criteria, review criteria were also
established. Review criteria provided additional restrictions on plant
conditions during the evolution. Plant conditions required during the
.-. __. . ._ ..
14
test for three different review c"iteria were not met but were evaluated
~
to be acceptable. The evaluation performed by engineering concluded
that the test was completed satisfactorily. The inspectors' review of
the test results lead to the same conclusion.
c. Conclusions
The natural circulation test was conducted in a controlled manner with
good emphasis placed on monitoring critical plant parameters to detect
abnormal plant trends if present. The test demonstrated that natural
circulation could be achieved on Unit 1 following the loss of forced
circulation. Additionally, the inspectors considered the engineering
evaluation of recorded plant data to be adequate.
M1.3 General Comments Maintenance (62707)
The inspectors observed performance of and reviewed documentation
associated with the following outage related maintenance detivities:
.
MP/C/A/7400/044, Revision 11. Diesel Engine Crankshaft Alignment
and Thrust Clearance Measurement
- MP/0/A/7150/057A, Revision 0, Residual Heat Removal Pump with
Cartridge Seal Removal and Replacement and Corrective Maintenance
.
MP/0/A/7150/039. Revision 29, Reactor Coolant Pump Seal Removal
and Replacement
-
During these activities, the inspectors noted proper use of procedures,
appropriate radiological controls, and good workmanship from personnel
performing the maintenance. No violations were identified.
M1.4 Inservice Insoection (ISI) of Safe ; d e, lated Welds and
Comoonents (Unit 1)
a. Insoection Scone (73753)
The inspector verified by observation and document review that
nondestructive examinations of safety-related welds were performed in
accordance with the licensee's implementing procedures and applicable
code requirements. The controlling code for Catawba's ISI act vities
was the American Society for Mechanical Engineers (ASME) Code Section
XI, 1989 Edition with no 6ddenda, (Code). Procedures used for
examinations observed were as follows:
NDE-630 Revision 2 Ultrasonic Examination of Similar
Metal Welds in Wrought Ferretic
Steel
'~
~
NDE-35. Revision l'6 Liquid Penetrant Examination
. _ _ . _ _ _ _ .. .. _ ._.._. _ _ _ - - . _ . _ _ . _ .. _ .. _ _ _. _ _ _
l
!
15-
(b. Observations and Findinos
-
L The inspector reviewed activities conducted during a scheduled refueling
outage, designated as End Of Cycle 10 (E0C 10) outage. This outage wa:;
L
i
the second outage of the second 10 year interval. Examinations.
performed on safety-related welds were identified in thelicensee's ISI
Database Management System. The inspector selected at random several
- ISI examination categories and verified by review that the number of l
. welds selected by the licensee for examination during this outage were
, consistent with Tables IWB-2412-1 and IWB and C 2500-1 of the code,
"
Examination categories selected for this review were as follows:
L
B-A Pressure Retaining Welds in Reactor Vessei
t B-D Full Penetration Welds of Nozzles in Vessels ,
B J- Pressure Retaining Welds in Piping-Nominal Pipe Size less
!- than 4-inch and greater than 4-inch, branch connections and
i socket welds.
'
C-F Class B Pressure Retaining Welds in Nominal Pipe Size less
than 4-inch and greater than 4 inch and brahu connections
and longitudinal welds.
- - In addition, to this work effort the inspector observed ISI
- examinations performed on the following welds.
4
ltem Weld Examination
i
C01.010.008 IELDHX-SH-FLG Ultrasonic (UT)
^
.
C01,020.002- 1ELDHX-SH-HD UT
C01.020.003 1ELDHX-HD-FLG UT
j- C05.030.011. IN1206-2 Liquid Penetrant (PT)
L C05.030.012 IN1206-3 PT
.
'
- By work observation and associated record review, the inspector
determined that the above welds were adequately examined and that the
- code required information and examination results were documented and'
-
evaluated satisfactorily. Examiners were adequately trained and
knowledgeable, and performed their assigned tasks with attention to
- detail and code recuirements. Equipment and caterials used were
'
properly identifiec and traceable to certification documents, and *.
et,uipment used was in calibration.
- _ ; , ._ .. -
l-
y
[-
b'
,
d
< ,u,,,-w-.- ,..--e. --.- ..a.. . . - , . . , , -.---n- , , - - e--- - - ---n--n, - - - , - r, a
.. _ __ . . _ . _ . _ . _ _ _ _ _ _ _ . . _ _ _ _ . _ _ _ _ . _ ._ ._
t
16
c. Conclusion
Sections of the licensee's second 10 year interval 151 program that were
reviewed, complied with code requirements. ISI examinatior. observed
were performed in a satisfactory manner. Technicians were well trained
and had good knowledge of plant equipment and procedural requirements.
Inspection results were evaluated and documented with accuracy and
clarity.
M1.5 [ddy Current Examination of Steam Generator (SG) Tubes (Unit 1)
,
a. Insoection Scoce (73753)
By work observation and review of applicable procedures, the inspector
i determined the adequacy of the data acquisition phase of the SG tubes
eddy current testing (ET) program. This ET inspection was being
performed in accordance with the requirements of plant Technical
Specifications, the ASME Code Section XI,1989 Edition with no addenda
"
and included provisions of Code Case N 401-1 Digital Equipmcat. NRC
Regulatory Guide 1.83. Revision 1 was applicable by reference. Other
governir.g documents and prosedures associated with data collection and
analysis were as follows:
NDE-701. Revision 3 Multifrequency Eddy Current Examination of SG
Tubing at Catawba Nuclear Station
NDE 703. Revision 5 Evaluation of ET dcta for SG Tubing
iddy Current Guidelines. Catawba Nuclear Station. Unit 1. E0C 10
b. Observations and Findinas
The inspector observed data acquisition in progress on December 19.
1997 This work eff'rt included puisition, verification of probe
location, in line system calibration, personnel qualification, and
equipment calibration. Examination: Were being performed with the MlZ-
30 8 acquisition systeni with digital and multifrequency eddy current
techniques. Differential bobbin coils 0.560 and 0.540 inches in
diameter were being used for this examination. The ET plan called for
examination of all active tubes with bobbin coil probes in each of the
four SGs. Motorized rotating pancake coil (MRPC) examinations were
being performed to characterize indications identified by the bobbin
coil with respect to area, orientation and morphology. Approximately
60-70 tubes were examined by MRPC. During the bobbin coil examination,
the licensee determined that a deposit build-up existed on the inside
diameter (10), e ' surface of tubes in the hot and cold legs of all
.four SGs. Tk .eposits were having a negative impact on [T data
acquisit * because they hindered probe movement through the tubes
to the euen: at each tube had to be tested twice to assure full
length covers increased probe wear rates resulted in more frequent
change outs : contributed to the slowdown. The inspector met with the
- . . _ _ _ - - .- - - _ _
- _ - - _- - - . . . _ _ - - - _ - - - - _ .-- . . - -
l
17
licensee's responsible engineer and determined that immediate corrective
'
actions taken to alleviate the problem included: changing the planned
" full pull" of each tube to a two step a)proach to avoid having to push
3 robes through the full length of the tu]es and using smaller diameter
)obbin probes 0.540 versus 0.560 inch for the examination. Results of a
radioisotope and scanning electron microscope (SEM) analyses, revealed
the presence of Co 58 due to activation and decay of Nickel. Cr 51 due
to inconel and Stainless material: Co 60 due to activation of Co 59 and
Fe 59 due to stainless steel material. The SEM analysis showed that
iron chrome, nickel and large amounts of fluorine and carbon were also
present. The latter two elements were determined to be associated with
materials used in ET probe construction. The aforementioned problem was
documented in PIP-1 C97-4111. Additional planned actions included
4
aggressive cleanup of metal oxides during startup. monitoring for solids
- and nickel and a determination of boron concentration levels.
The inspector observed ET of SG tubes in SG A. reviewed applicable
procedures. calibration records, and personnel qualification
certifications for completeness and accuracy. At the close of this
inspection, the licensee had examined approximately 85 percent of the
total number of tubes in the four SGs and no rejectable tube indications
were identified.
c. Conclusion
The observed activity was well managed and executed in accordance with
applicable procedures. Technical personnel doing data acquisition were
qualified to perform their assigned tasks. The licensee took a
proactive ap3 roach to resolve the problem of build up in SG tube 10
surfaces. T1e ET inspection plan for this outage met code and industry
standards,
M1.6 Minor Modification to Reolace Sections of 18-inch Primary Fcedwater 751
Picina Between Containment isolation Valves In Doahouse (Unit 1)
a. Insoection Scoce (62700/55050)
The inspector determined Dy work observation and document review the
adequacy of work activities in reoards to replacement of piping material
between certain CF containment isclation valves in the Unit 1 doghouse.
The governing code for this activity was the ASME Section 111 1974
Edition through Summer 1974 Addenda. The piping involved in this
modification was classified as Duke Class B. The modification was
identified as minor modification CNCE 8965. Applicable work orders
included 97044910. 97044911. and 97044916.
b. 0bservations and Findinos
By review of the modification package the inspector ascertained that
-the design of Tilting Disk Swing Check Valves ICF31.1CF49 and 1CF58
ind caused severe localized erosion in the associated 18 inch diameter
- - -. - - - - . - . - - - . - - ._.. - -
18
carbon steel pipe immediately downstream of the check valves. The
'
replacement piping was made of 18 inch schedule 80 Stainless Steel SA
376/TP304 material. On December 18, 1997, the inspector observed field
welds in progress and undergoing re) airs in response to rejectable
indications identified by radiograp1y or ultrasonic examination. Welds
involved in this work effort were as follows:
Weld No. 512e Drawina Coments
(inches)
1CF24-1 18 x 0.938 1CF24 Repaired three times for code
rejectableindications
ICF24 3 18 x 0.938 1CF24 Repaired four times for code
rejectableindications.
1CF29-1 18 x 0.938 1CF29 Repaired three times for code
rejectableindication.
1CF29 3 18 x 0.938 1CF29 Repaired three times for code
rejectcble indications.
In addition to the above work effort, on January 8 9.1998, the
inspector reviewed completed weld process control forms to verify that
required quality control (0C) hold points had been performed and
initialed by OC weld inspectors as required, and that filler metal
material had been documented as required by the responsible welder and
reviewed by the welding OC inspector. Within these areas, the inspector
noted that fabrication of production welds under field conditions
continued to be a challenge for the licensee as evidenced by the
rejection of five out of six.18-inch weld joints by radiography due to
fabrication type defects. The licensee's PIP written to investigate
this problem indicated that vendor welders provided to work on this
modification did not have the proper skills to perform radiography
quality welds. To resolve this problem, site welding technical support
recommended that a group of welders should be identified and trained to
perform quality welds in a consistent manner, that welders needed for
outage work be identified well in advance of the outage to allow for
additional training, and that if an adequate number of welders cannot be
secured, then welding services should be contracted. For the near term,
the licensee planned to allow the site welding technical sup) ort lead to
evaluate the weld jobs and select specific in house welders )ased on
their experience and expertise or have a qualified welding contractor to
satisfy the welding needs of the nuclear station. The inspector
expressed his concern over the inability to obtain, train, and maintain
a group of welders with demonstrated ability to produce quality work at
.the licensee't nuclear. sites. In addition. the inspector ex)ressed a
concern over the licensee's continuing inability to secure tie services
of_ an ex)erienced and qualified welding engineer to assume the
responsi)ility and to provide direction to the welding program. The
continuing inability to produce quality welds and the lack of commitment
-
- - . - _ - - -_- --. - - _ - . - - _ - - . _ . . - . . -
19
to a strong welding organization was identified as a weakness. The
'
licensee was continuing to pursue the hiring of a qualified welding
engineer.
c. Conclusion
The licensee continued to demonstrate a weakness in the area of welding
certain production welds. Some welders lacked the necessary skills to
4
produce radiography quality welds as evidenced by the need for repeated
repairs during fabrication activities. The in processing group had not
been able to satisfy the need for experienced welders in time for
l training prior to the outage.
M1.7 Deletina Certain Drain Valves and Small Bore Lines Off Emeroency Diesel
Generator Return Headers. (Unit 1)
a. Insoection Scone (62700/55050)
The inspectors determined by review of selected work orders whether the
tasks performed and the documents generated complied with governing
procedures and code requirements,
b. Observations and Findinas
J
Corrective Minor Modifications CE 8774 and CE 8778 were issued to
eliminate small bore service water (RN) piping which is susceptible to
'
-
corrosion and pinhole leaks. Jrain valves 1RN-74. 890. -912. 913.
-945, and -961 and associated small bore piping were deleted. Also
- abandoned one inch 31 ping off the diesel generator RN return header was
cut and plugged. T1e described work was performed under work orders
(W0s). 97045405 01, 9704112Z-01 and 97041124 01. All work associated
with these W0s was performed under Procedure SM/0/A/ 8140/001. Welding
of 0A Piping and Valves. This procedure specified OC welding hold
points, required that all personnel including welders and )ipe fitters
doing work enter their signature on the weld record, and tlat filler 4
metal used be documented.
All new field welds were classified as ASME Class C. Duke Class G. Weld
process control and OC inspections required were applicable to 0A
Condition 1 welds. Welds fabricated under this classification and QA
condition have specific OC hold points including cleanliness, fit up,
and ) reheat, all of which were required by the Governing Procedure OAL.
16. Rev.17, Inspection of ASME Section XI Field Piping Welds.
Completed process control records of welds fabricated under these work
orders were reviewed to verify that specified bold points were checked
by QC as required, that welding filler material used complied with the
. applicable field weld data sheet (FWDS). L-250. Rev.17. and that the
filler metal had been issued to and used by welders qualified under the
i.forementioned FWDS requirements.
umwe.wm
'R
9
20
Welds whose fabrication records were reviewed were as follows:
Weld. Size Drawing Work Order.
16 2" sch. 40 1RN240 97041122 01
socket
19 2" sch. 40 1RN240 97041124 01
socket
31, 32 1" sch. 40 1RN238 970t.5405 01
socket
Based on this review and discussions with QC personnel, the inspector
determined that these welds were fabricated and ins)ected in accordance
with applicable procedures and code recuirements, tlat the information
recorded was complete and accurate, anc that filler metal, at the issue
station, was properly stored, segregated, and issued in accordance with
applicable procedures,
c. Conclusion
This record review of welding required by minor modification CE 8774/.
.
' 8778 on the service water lines of the 1A EDG disclosed that hold points
were inspected as required, welds were fabricated using the designated
4dld process, the proper filler metal was issued and used to fabricate
the aforementioned welds and that weld fascication and testing met
applicable code requirements.
H2 Maintenance and Material Condition of Facilities and Equipment
M2.1 Charaina Pumo 1B Inocerability and Unolanned Entry into TS
a. Insoection Stone (62703)
On December 3, the licensee noticed that the IB charging pump's
auxiliary oil pump was running when it was expected to be idle.
Maintenance technicians determined that the lube oil system was unable
to maintain pressure. The 18 charging pump was declared inoperable.
The 1A emergency diesel generator was inoperable for outage maintenance,
and Unit 1 entered TS 3.1.2.3, which required that all operations
involving core alterations or positive reactivity changes be suspended.
Troubleshooting revealed a failed lube oil system relief valve and two
reversed motor leads that caused the auxiliary lube oil pump to operate
in the reverse direction, unable to pump oil,
b 0bservations and Findinos
The auxiliary oil pump is designed to run for two minutes before the
charging pump is started to prime the lube oil system. When the
charging pump starts and comes to full speed, the shaft-driven main lube
-
-
___
--
21
oil pump starts delivering oil to the lube system. System pressure will
'
increase when the main lube oil pum) starts. This will cause a pressure
switch to shut off the auxiliary lu)e oil pump when lube oil pressure
reaches a set value.
The licensee detarmined that the motor leads had been reversed since
September 1996. The inspector reviewed various documents to determine
the impact of the auxiliary oil aump's loss of function on charging pump
operability. No discussion of tie auxiliary lube oil pump was located
in the UFSAR. Accordin
auxiliary lube oil pum)gautomatically
to the designstarts
basisto
documentation,
brin the
pressure to 8 psig. T1e vendor manual. CNM 1201.05 g lubricating oil
0203 001. Operating
! and Maintenance Instructions for Pacific Pumps. Manual No. 2700.
I provides a start-up procedure step to turn on the auxiliary lube oil
aump before starting the charging pump. However, neither the design
) asis document nor the pump vendor manual indicated that auxiliary lube
I oil pump operation was critical to charging pump operation. The
) inspector discussed the function of the auxiliary oil pump with a
'
station engineer, who indicated that the > ump's function is to minimize
bearing wear by lubricating the bearings aefore the charging pump is
started. The engineer also indicated that the auxiliary lobe oil pump
was not needed for the charging pump to start and perform its safety
function and essentially performed an equipment service life function.
The inspector noted that the charging pump had passed its quarterly TS
performance test requirements since the motor leads had been installed
reversed in September 1996,
c. Conclusions
The licensee exhibited conservative decision making by declaring the IB
charging pump inoperable until troubleshooting activities could reveal
the cause of the low lobe oil system pressure condition. The condition
of the auxiliary lube oil pump, with the motor leads reversed, did not
adversely affect the ability of the IB charging pump to perform its
safety function.
M7 Quality Assurance in Maintenance Activities
M7.1 Reactor Coolant Pumo 1D Anti-Reverse Rotation Device Not Installed
a, Insoection Scooe (62707)
The inspector reviewed circumstances surrounding anti reverse rotation
devices not being installed on the 10 reactor coolant pump motor when it
was installed during the Unit 1 refueling outage.
.
b. Observations and Findinos
On December 28, 1997, with Unit 1 shutdown in Mode 5. plant personnel
noticed the 10 reactor coolant pump rotating backwards while Jerforming
checks on the pump. The pump was not operating at the time: lowever.
I
i
22
other pumps in the reactor coolant system were, causing loop :
- differential pressure which tended to spin non operating pumps in the
reverse direction. Operations personnel secured the operating IC pump,
which allowed the 10 pump to come to a stop. Personnel at the pum)
successfully attempted to hand rotate the motor (un coupled from t1e
pump) in both directions and identified that anti-reverse "Dawls" had ,
not been installed in the motor. The pawls (five of them) are attached
to the pump flywheel and are levers that ride along a serrated, more
stationary ratchet plate in the motor frame. During normal operations.
the flywheel spins in the clockwise direction, and the pawls are angled ;
such that they do not engage the ratchet slate, allowing continued
operation. When the pumps are secured, tie flywheel allows the pump to
coast down, and the pawls eventually engage the ratchet plate as the
pump tends to rotate backwards. Shock absorbers aid in preventing anti-
reverse rotation.
The inspector learned that a spare pump motor had been installed during
the Unit I refueling outage in December 1997, and that the pawls had .
been removed from that motor in 1983. The licensee was able to locate
the 1983 work order and find the pawls, which had been placed in a
storage box. The
operated normally.Licensee pawls were
)ersonnel later later
installed
performed in thea motor,
motor current and the pump
signature analysis and a breacaway torque measurement (reviewed by the
inspectors) to determine that the pump motor was not damaged.
Plant personnel initiated station PIP 1 C97-4360 to documant this item.
4
At the end of the inspection period, the PIP was still open as licensee
personnel investigated what controls were or should have been in place
to identify the missing pawls when the spare motor was installed in
December. Theinspectorswereconcernedthatqualitycontrolmeasures
for warehouse activities should be reviewed. While not specifically $
discussed in the Chapter 15 of the UFSAR as an accident mitigating
device, the pawls were discussed in Chapter 5 for equipment protection ,
aurposes. Pending further inspector review, this item is identified as '
Jnresolved item (URI) 50 413/97-15 03: Anti-Reverse Rotation Devices not
Installed in the 10 Reactor Coolant Pump,
c, Conclusions
An unresolved item was opened related to circumstar.ces surrounding anti-
reverse devices not being installed in the 10 reactor c0olant pump
during the refueling outage.
M8 Miscellaneous Maintenance Issues (92902) ,
M8.1 (Closed) LER 50-413/97-008: Inadequate Solid State Protection System
,_
. Surveillance (SSPS) Testing .
This LER described a deficiency during surveillance testing of SSPS
universal logic boards in a memory configuration, that would not allow
detection of an internal card subcomponent failure. The potential card
.
4
'wg,,,---,,imev---g- r w ww- ,r -v,y ---rp wn -..r m <pr,,, , _p,--
- - -e , w-,-- y-~,--,- -,.y--,.m--,-.v-,,-erreg,-r.--ww--e -- ' , , - ,-
____. ____ _ _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .
i
23
failure scenario could affect three circuits associated with feedwater
~
isolation on *H1 Hi~ steam generator level, feedwater isolation on a
safety injection signal, and the P 10 yower range permissive interlock.
which allows manual reinstatement of tie source range circuits when
reactor power is below 10 percent. These functions were described and
test requirements were delineated in TS 3/4.3.1 and TS 3/4.3.2. The
licensee implemented the surveillance requirements every two months by
using a semi-automatic testing feature provided within the SSPS logic l
cabinet by the vendor. The licensee identified the test deficiency in '
the method provided by the vendor during a review of the circuitry on
November 11, 1997. Following identification, licensee 3ersonnel
communicated the information to nuclear plants both wit 11n and external
to the Duke Energy system. The test design was also discussed with the
vendor, which later issued a technical bulletin communicating the
generic aspects of this deficiency to the nuclear industry and
, recommending changes to testing methods.
The licensee revised its test procedures, specifically
IP/1(2)/A/3200/002A, SSPS Train A Periodic Testing: and
IP/1(2)/A/3200/0028. SSPS Train B Periodic Testing: to correct the
deficiency. The inspectors reviewed the procedure revisions, and
observed successful performance on Unit 1 B-train on November 11. 1997.
The inspectors also verified the adequacy of the revision by comparing
it to station and vendor drawings.
The safety significance of the test deficiency was reduced by the fact
that the circuits passed the revised test, and the feedwater isolation
circuits have been successfully tested during refueling outages. For
the P 10 permissive its function to allow manual reinstatement of
source range trips was backed up by an automatic function. The licensee
prom)tly communicated the deficiency through the operating events
data)ase which allowed other licensees to correct similar test problems
at their facilities. Failure to have adequate SSPS test design and
procedures for testing the feedwater isolation and P 10 permissive
circuits was contrary to TS 3.3.1. and TS 3.3.2. However, this non-
repetitive, licensee identified and corrected violation is being treated
as a Non Cited Violation (NCV). consistent with Section Vll.B.1 of the
'
Enforcement Policy and is identified as NCV 50-413.414/97 15-04:
Failure to Have Adequate Test Procedures for SSPS Logic Associated With
Feedwater Isolation and P-10 Permissive Circuits. This LER is closed.
III. Engineerina
El Conduct of Engineering
E1,1 Outaae Modifications
~
a. 'Insoection Scone (37551i
During the Unit I refueling outage, the licensee implemented
modifications to the main steam isolation valve (MSIV) control circuitry
. - -
.. - - _ - _ _ _ . -_ ,
___ ____ -_ _._ _ _ _ _.___ _ _
,
!
l 24 i
! .
and to the safety in;ection logic.
.
i- The inspector reviewed work packages -
'
associated with modifications, watened Jortions of the modification work'
in the field, and reviewed the TS and U:SAR to ensure that these
!
documents accurately reflected the associated changes to the plant. :
j
b. Observations and Findinas '
Nuclear Station Modification CN 11377 was implemented to eliminate the
safety injection signal on low steam line_ pressure. The modification
i was performed to reduce the number of unnecessary safety injections,
'
- such as one that occurred during a Unit 2 loss of offsite power event on '
February 6,1996, and complicated the plant response to the event. On i
i January 3, 1997, the licensee requested a TS revision to eliminate the
2
'
low steam line pressure safety injection signal. On April 3.1997, the
TS revision was approved as Li e nse Amendment Nos. 158 and 150 for Units
,
1 and 2. respectively. The inspector reviewed the TS and UFSAR to
ensure that revisions reflected the change. The inspector identified a '
- UFSAR discrepancy whereby information had not been updated to reflect
a
the change. The inspector brought the discrepancy to the attention of
- regulatory compliance personnel, and verified that it and other '
discrepancies associated with the modification had been identified
previously b
correction. y The the licensee and had
TS revisions documented
been completed in variation notices
for Unit 2 andfor
were in
- the process oT being incorporated for Unit 1.
'
The licensee also implemented Nuclear Station Modification CN 11373.
? This modification was designed to eliminate a single failure
l vulnerability to the HSIVs. Since 1995, three unit trips had been .
- _ attributed to digital optical isolator (001) failures in the MSIV
'
control circuitry that caused the valves to close while the unit wes at ,
n 100 percent power. The modification involved the control board push.
4
button circuitry, which had controlled a single relay that would in turn
actuate a solenoid valve to cause the MSIV to close. The modification
i changed the push-button circuitry such that a pafr of relays actuate the
solenoid valve: the. modification also reduced the number of D01s in the
- control circuitry as well as the number of normally energized components
1 (D0!s and relays) required for the HSIVs-to remain open. The
modification did not im)act the HSIVs' ability-to close on a main steam
isolation signal from tie SSPS.
l-
c. Conclusions
i The inspector concluded that the modifications were implemented in
i accordance with governing procedures. The inspectors identified a UFSAR
1
discrepancy that the licensee had independently identified, in addition
to others, and had documented them in variation notices for resolution,
r . -
- .
.
m
k
E
1
_, ._ _ _ - _ , - , _ . _ _ _ . , _ , , . _ _ _ _ _ - - - , _ - _ . - . - . -
(
25
E2 Engineering Support of facilities and Equipment
E2.1 General Comments (37551)
In eneral, engineering support of plant operations, facilities, and
equ pment was good. This included engineering support during the RCS
lea and NOUE on December 30 1997. During and following the event.
engineers thoroughly researched several design aspects of the RCS loop
drain valves and compared them against plant event data to
systematically consider and eliminate postulated failure scenarios.
Other activities for which good engineering support was noted included
reactor startup and low power physics testing.
E3 Engineering Procedures and Documentation
E3.1 General Comments (37551).
An area of minor concern to the inspectors was identified related to
engineering documentation in operability evaluations. Two operability
determinations reviewed this month included the pressurizer evaluation
following the December 29. 1997, safety injection event: and the
evaluation of increased flow to the steam generators following the loss
of control pnwer to the steam driven auxiliary feedwater pump trip and-
throttle valve identified in November, 1997 (NRC Inspection Re) ort 50-
413.414/97-14). Both evaluations used general terms in descri)ing the
acceptability of affected equipment without providing specific
-
background or supporting information related to acceptance criteria that
engineers considered.
In the case of the pressurizer evaluation, engineers stated that the
calculated hoop stress caused by the sudden increase in pressurizer
pressure on December 29, 1997, was acceptable because it was
significantly lower than any thermal stresses. No further discussion of
the thermal stresses (specific values, assumptions, calculations.
acceptance criteria) was provided. The associated engineer later
performed a calculation of the assumed thermal stress values with the
inspector present, and demonstrated that the stresses were within code
allowable limits. For the turbine driven pump auxiliary feedwater flow
evaluation. the acceptability of higher flow rates was based on an
. electronic mail message from a corporate engineer stating that the
higher flows were bounded by accident analysis calculations. The
inspector concluded that further NRC review of those calculations (which
were not provided in the documentation) was warranted before the
associated unresolved item (URI 413/97-14-01) could be closed.
The inspectors discussed the documentation concern with licensee
. .. . . management who indicated that a further review of engineering philosophy
.in this area may be warranted.
.
.--
!
!
,
26
l E3,2 1997 Revision to the UFSAR !
i
-
l a. Insoection Secoe (37551) l
"
By letter dated September 25, 1997. the licensee submitted the 1997
revision to the UFSAR in accordance with 10 CFR 50.71. This regulation !
requ1_res that:
i This submittal shall contain all the changes necessary to reflect !
information and analyses submitted to the Commission by the ,
licensee or prepared by the licensee >ursuant to Commission !
- requirement since the submission of t1e original FSAR or, as
[ eppropriate, the last updated FSAR.
'
2
'
10 CFR 50.71 states that the updated FSAR shall be revised to include the
effects of:
1
1. "All changes made in the facility or procedures as described in
the FSAR"
2. " Safety evaluations performed by the licensee either in support of
4
requested license amendments...." - Since this category clearly-
involves NRC staff approval of licensin
changes that the staff approved (e.g., g basis changes, othertopical rep i
- American Society of Mechanical Engineers (ASME) Code sections.
!
'
exemptions, etc.) but were not conveyed as amendments are also
.
implied, '
i -
"
.... or in support of conclusions that changes did not involve an
unreviewed safety question" These are evaluations performed by
the licensee in accordance with the provisions of 10 CFR 50.59.
!
'
3. "All analyses of new safety issues
the licensee at Commission request" performed
Examples by or
include on behalf of
licensee
t
-actions as a result of generic letters, bulletins, etc.
,
The inspector reviewed the 1997 revision of the Catawba UFSAR in office
and onsite, and met with licensee personnel on November 13, 1997, to-
compare with-requirements and discuss various issues,
b. Observations and Findinas ,
'
On June 10, 1997, the staff issued an exemption to the license. This
-
exemption authorized the licensee to schedule UFSAR revisions to once per
fuel cycle based only upon Unit 2 refueling outages. Since the last Unit <
2 refuelina outage was completed in early May 1997, the inspector found
~ ~
that the 1997 UFSAR update was submitted in accordance with the schedule
} specified by the June 10. 1997. exemption.
The regulation does not require the staff to review and approve the
- changes in the UFSAR. since the changes are presumably previously
_
m
_ - _ . . _ _ _ . . _ - _ . . ._ _ . _ _ . _ _ _ , . _ _ . . _ . - . _ . . _ _ . _ - _ _ _ - _ _ . _ .._ - _.--_ _ _ _
___. . __ . _ _ _ _ _ _ . _ _ . _ _ . _ _
i
i 27
4
approved. or do not require approval. Accordingly, the purpose of the
review was to confirm that the changes made in the 1997 revision comply
1 with the provisions of 10 CFR 50.71.
I
' The inspector traced the changes in the 1997 UFSAR revision to documents ,
in the official NRC records (amendments to the operating license, staff i
letters transmitting safety evaluations, annual 10 CFR 50.59 reports
- submitted by the licensee. NRC inspection reports, licensee letters,
etc.). The inspector confirmed that changes conveyed by the 1997
, revision complied with the change scope specified by 10 CFR 50.71.
By license Amendments 153 (for Unit 1) and 145 (for Unit 2) the NRC !
staff imposed a license condition. The condition stipulated that:
,
- "Accordingly, the license is hereby amended to authorize ,
revision of the Updated Final Safety Analysis Report
i
-(UFSAR) as set forth in the application for amendment by
Duke Power Com>any dated September 21, 1996. The licensee
shall submit t1e revised description authorized by this
'
.
amendment with the next update of the UFSAR in accordance
t
with 10 CFR 50.71(e)."
l The inspector reviewed sections in Chapter 8 of the UFSAR and found that
the licensee had fully revised those sections (regarding miscoordinated
circuit breakers) in accordance with the approval in the Safety
Evaluation associated with Amendments 153 and 145. The inspectors
-
therefore concluded that the licensee had fulfilled the requirement
! imposed by the license condition conveyed by Amendments 153 and 145.
i By Amendments 159 (Unit 1) and 151 (Unit 2) the staff im)osed another
license condition (the first condition of Appendix 0 to tie operating
l licenses), which stipulated:
,
"This amendment requires the licensee to incorporate in the
1
- U) dated Final Safety Analysis Report (UFSAR) certain
clange's to the description of the facility. Implementation
,
' of this amendment is the incorporation of these changes in
the licensee's application dated March 7. 1997, as
supplemented by letters dated April 2. 10, 16, 22. and 28.
L 1997. and evaluated in the staff's Safety Evaluation dated
April 29, 1997."
I The inspector reviewed Sections 15.6.3.15.6.3.1 and 15.6.3.2 of the
. UFSAR and found that the licensee had substantially revised those
, sections (regarding the number of steam generator 3ressure operated
- - relief valves required operable) in accordance wit 1 the a
Safety Evaluation associated with Amendments 159 and 151.pproval in the
~
The inspectors
- therefore concluded that the licensee had fulfilled the requirement
imposed by the cited license condition conveyed by Amendments 159 and
,
151,
i
.
4
i
'
,_- _ _ _ _ _ ,_._,m_.,__ _ _ _ , __.____;__..______.-- . _
- . - . _ _ . . . _ _ _ . _ , . - -
28
The licensee's current process to incorporate all pertinent changes into
-
the 1997 revision, ensuring that it remained a living licensing basis
document, was noted as a strength. The most significant example is the
incorporation of the analysis of the weir gate drop accident in Chapter
15. This analysis had been missing from the UFSAR since the units were
licensed to operate in the mid 1980s. The NRC staff's review result had
been published in the form of a footnote to TS 3.9.7. even though the
staff did not publish the associated safety evaluation or point out that
the analysis was missing. The licensee's incorporation of this analysis
in the UFSAR has prompted the staff to take remedial actions on this
issue,
c. Conclusions
The inspector concluded that the 1997 revision of the Catawba UFSAR was
in compliance with the requirements of 10 CFR 50.71. The inspector also
concluded that the licensee has fulfilled the requirements of two license
conditions reviewed for each unit. The licensee's current process to
incorporate all pertinent changes into the 1997 revision, ensuring that
it remained a living licensing basis document, was noted as a strength.
E8 Hiscellaneous Engineering Issues (92903)
E8.1 (Closed) VIO 50 413.414/96-10-01: Failure to Follow Procedure for
Equipment failure Analysis
This item addressed the licensee's failure to follow procedure SD 3.3.6.
Failure Analysis and Trending (FATS) revision 2 which required
notification of engineering when as-found instrument conditions exceeded
s)ecified out-of wierance (00T) criteria. The licensee's response to
tie violation, dated September 19, 1996, stated the corrective actions to
resolve this issue. These included training, an assessment of the FATS
program and 00T reporting, and procedural guidance enhancement to ensure
reporting of 00T instrument conditions. The inspector verified
performance of the corrective actions which were documented in PIP 0 C96-
1761 and completed on November 24, 1997. A sample review of work
documentation identified no additional examples of inadequate
notificatinn of 00T instruments.
E8.2 (Closed) VIO 50-413.414/97-03-01: Failure to Follow Procedure for ,
Receipt, Inspection, and Handling of Replacement Parts 1
This item addressed failure to follow procedures for receipt, ins)ection,
and handling of parts from the spare diesel. The diesel was purciased in
1987 to provide replacement parts for the station emergency diesel
generators (EDGs). The receipt inspection documentation stated that it
would be placed on QC hold status and salvaged parts were to be evaluated
against Duke s)ecifications prior to use. The diesel was not stored in a
designated OC lold area and although many parts were missing. there was
no documentation to verify the required evaluations were performed.
Periodic testing and maintenance of the EDGs indicated that EDG
.- - - - - - . . - . - -- - - - - . . _ . _. - - - .
M
d
23
.
performance was not degraded by the installation of parts from the spare
l ,
diesel.
The licensee's corrective actions were specified in the violation
response dated April 15, 1997. These actions included upgrade of the
saare diesel storage building to Level B OC storage criteria, review of
t7e spare diesel specifications against Duke specifications, review of
the spare parts upgrade process, and evaluation of parts used from the
s)are diesel. The inspector reviewed the completed corrective actions
w11ch were documented in PIP 0 C97 0322 and closed on May 13, 1997.
E8.3 (Closed) URI 50 413.414/97-10 01: Review Corrective Action for IST Check
Valves
-
(Closed) LER 50 413/97 005: Failure to Perform TS Surveillance
These items addressed inadequate inservice testing (IST) surveillance of
ECCS check valves. The valves were not tested for reverse flow as
1
required by the IST 3rogram specified by the TS 4.0.5. The issue was
<
unresolved pending tie completion of the licensee's extent of condition
investigation, This investigation was completed on June 23, 1997, as
documented in PIP 0 C97-2050. The licensee identified this deficiency
during system review in preparation for an NRC inspection. The cause was
determined to be an inadequate IST surseillance procedure which did not
include the IST program requirements and criteria for re! arse flow
testing of ECCS valves INI 813. 2NI 813, 1NI 142, and 2N1 342. The
-
valves were reverse flow tested at the first available opportunity and
met the IST criteria. The surveillance procedures were revised to
include the required test requirements. An extensiveness review was
performed to determine if other check valves were not appropriately
-
tested. The failure to reverse flow test the check valves as required by
the TS and IST program is a violation of regulatory requirements. This
non repetitive, licensee identified and corrected violation is identified
<
as a non-cited violation, consistent with section Vll.B.1 of the NRC
Enforcement Policy, and is identified as NCV 50 413.414/97-15 05: Failure
to Perform TS Surveillance Due To Inadequate IST Surveillance Procedure.
E8.4 (Closed) U 0 50 413.414/97 09-04: Failure to follow Procedure Two '
Examples
Example o' addressed 10 CFR 50.59 screening evaluations for changes to
Emergency ^ ocedures which did not include adecuate detail of the basis
'
for response to screening questions as requirec by the applicable
procedure. Corrective actions specified by the licensee's response to
the violation, dated Se)tember 15, 1997, included training and interim
measures to assess 10 C:R 50.59 screening performance by the operations
. procedures group. Corrective action completion was documented in PIP 0-
C97 1925, which was closed on October 19, 1997. The inspector reviewed
the training guidance and a sample of procedure change 10 CFR 50.59
screening evaluations performed after the training. Adequate detailed
justifications were documented for the sample reviewed.
_
- . .- ._ - , . . . .
. ..
.
.
30
Example two addressed oyen items and deficiencies identified during th6
-
licensee's Design Base )ocument (DBD) development which were not entered
into the PIP tracking system as required by procedure EDM 170, Design
Specifications, Revision 5. The licensee's response to the violation,
dated September 15, 1997, stated that the DBD open items would be entered
into the PIP trackin
updated on June 10,1997,
g system.
whichThe
listedinspector reviewed
and addressed thePIP
DBD0-C97-1918.
discrepancies previously not entered into the PIP process.
E8.5fClosed) IFI 50 413.414/97 10 03: Resolution of FWST Set Point
inconsistencies
l This item addressed inconsistencies in FWST level set point calculation
!
CNC 1552.08 00 0264. Revision 0, related to flow va kes and valve
operation times. The licensee resolved the incomstencies in Revision 1
of the calculation. The calculation conclusion, which stated that the
containment sump swap over would occur prior to reaching the FWST
critical height for vortexing, remained valid.
E8.6 (Closed) IFl 50 413.414/97 10 04: Inaccuracies Caused by Using DEPLET
Code on Different Computer Models
This item addressed a discrepancy in flow values derived from the DEPLET
code when used on different com>uters, i.e. IBM RISC 6000 versus the IBM
mainframe computer. Although t1e discrepancy did not impact the results
of the FWST level set point calculation, it was unclear if other
calculation applications of the DEPLET code had been evaluated. The
issue was documented in PIP 0 C97 2417 and stated that the McGuire and
Catawba FWST level set point calculations were the only ap)lications of
the DEPLET code. The discrepancies were evaluated for eac1 of these
applications.
E8.7 IClosed) VIO 50 413.414/96 05 02 (EA 97-179): Inadequate 10 CFR 50.59
Evaluation for Changes to Auxiliary Feedwater (CA) Piping Temperature
This item adcressed an inadequate 10 CFR 50.59 screening review for the
design temperature change of the CA piping. The screening evaluation
incorrectly concluded that a 10 CFR 50.59 safety evaluation was not
required for this design change. The licensee's violation response,
dated June 16, 1997, identified the root cause and specified corrective
actions to resolve this issue. The cause was determined to be the
inappropriate use of an interim operability evaluation to make a
permanent design change to the plant. Corrective actions included
clarification and enhancement of the design change and 10 CFR 50.59
process, improved guidance in 10 CFR 50.59 screening, and training on
these programs. Additionally. permanent design changes were made on the
. CA piping design temperature which included 10= CFR 50.59 evaluations.
The corrective actions were being tracked on PIP 0 C97-1926 The ,
remaining training on the revised 10 CFR 50.59 process and guidance was
scheduled for the first quarter of 1998. Based on the completed and
.
J
._. _____ _ _ _ _ _ _ ____ -- ____ ______ ____ . _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ .
1
31
scheduled corrective actions, the inspector concluded this item was
,
adequately addressed.
E8.0 (Closed) LER 50-413/95 003. 50-413/95 003 1: Failure to Perform TS i
Surveillance Due to Unanticipated Interaction of Systems
'
This item addressed component cooling (KC) containment boundary valves
which could adversely impact containment integrity during certain
accident conditions because these valves did not meet TS isolation
requirements. A containment integrity team was formed to review station
containment integrity and surveillance test procedures to assure
appropriate testing of containment boundary valves. An extensiveness
review identified additional valves which did not meet General Design
Criteria (GDC) requirements for containment integrity. The licensee's
corrective actions were tracked in PIPS 0 C95 1120. C96 0043. C96 0044,
C96 0045, and C96 0046. The review team developed ten positions
regarding related containment integrity issues. These were submitted to
the NRC for review. The NRC review identified a noncompliance with GDC 57 associated with the containment penetration for the steam turbine CA
pump (CAPT) steam supply. The remaining isolation valves discrepancies
were addressed by surveillance procedure changes.
The CAPT penetration isolation valves did not meet GDC 57 in that the
isolation valves were not locked closed, nor capable of being remotely
closed either automatically or manually. This was an original design
condition. The licensee submitted an exemption request on September 2.
-
1997, for these aenetrations based on the importance of assuring a steam
su) ply to the CA)Ts during certain accident conditions. Although this
LER will be closed, this GDC 57 noncompliance issue was identified as an
unresolved item associated with dual function isolation valves in a
previous inspection NRC report as URI-413.414/97-14-03.
The inspector reviewed the licensee periodic test procedures and verified
that the KC boundary valves were being appropriately tested. The NRC
review of the exemption request was ongoing.
IV. Plant Succort
R1 Radiological Protection and Chemistry Controls
R1.1 Tour of Radioloaical Protected Areas
a. Insoection Scone (83750)
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program as required by 10 Code of Federal
Regulations (CFR) Parts 20.1501, 1502. 1601, 1802. 1902, and 1904. The
review included observation of radiological protection activities
including personnel monitoring controls, control of radioactive material,
radiological surveys and postings, and radiation area and high radiation
area controls.
.
7-_ _
, , , - .
_
- _ _ _ _ ___. ___ _ ___ __
32
b. Observations and Findinas
During tours of the auxiliary building and radioactive waste storage and
handling facilities, the inspectors reviewed survey data and performed
selected independent radiation and contamination surveys to verify aree
postings. Observations and survey results determined the licensee was
effectively controlling and storing radioactive material.
During plant tours, the inspectors observed that extra high radiation
areas (locked high radiation areas) were locked as recuired by licensee
procedures and all other high radiation areas observec were appropriately
controlled as required by licensee procedures. The ins)ectors also
inventoried the licensee's extra high radiation area (EiRA) and very high
radiation area (VHRA) key control boxes maintained by radiological
control and determined that at the time of the inspection, all keys
assigned to radiological control for locked EHRAs and VHRAs were
l
accounted for. Dosimetry controls for the EHRAs and VHRAs observed were
established in radiation work permits (RWPs) and special radiation work
permits (SRWPs) as required by licensee procedures.
1
The licensee's records showed that the licensee was maintaining
approximately 152.360 square feet of floor space as a radiologically
controlled area tRCA). During the current outage period, the licensee
was maintaining approximately 12.500 square feet as recoverable
contaminated area. Records reviewed also showed the licensee maintained
less than one percent of the RCA as contaminated area during non outage
periods.
The inspectors reviewed personnel contamination event (PCE) reports
I
prepared by the licensee to track, trend, determine root cause, and
determine any necessary follow up actions. The licensee had continued
efforts in 1997 to reduce personnel contaminations. Approximately 144
PCEs had occurred to date in 1997 which included 16 contamination events
that occurred through December 12 during the Unit 1 outage. The
inspectors reviewed and observed licensee efforts to reduce personnel
contaminations which included decontamination of areas and components,
use of contamination control enclosures, use of personnel contamination
clothing, and portable work site ventilation systems. During tours of
the facility, the inspectors discussed RWP and SRWP requirements with
workers and found those workers interviewed understood their RWP and SRWP
rec uirements. The inspectors observed workers in the auxiliary building
anc reactor containment building generally adhering to the requirements
for properly wearing dosimetry and ]ersonnel contamination clothing as
specified on the RWPs and SRWPs. T1e inspectors also observed
radiological housekeeping in the facilities to be good,
c. Conclusions . _
Based on observations and procedural reviews, the inspectors determined
the licensee was, except as noted later in section R3.1. effectively
maintaining controls for personnel monitoring, control of radioactive
- - .. . _-- - - - _ - . _---- - - . - - _.
.
2
I
33
material, radiological postings, and radiation area and high radiation
,
area controls as required by 10 CFR Part 20.
i
R1.2 Total Effective Dose Ecuivalent (TEDE) Controls ,
a. Ininett1Dn, Scone (83760)
This area was reviewed to determine the adequacy of the licensee's use of
!
process and engineering controls to limit exoosures to airborne
-
radioactivity, adequacy of respiratory arotection program, licensee's
administrative controls for assessing tie TE0E in radiation and airborne
!
radioactive material areas, assessments of individual intakes of
radioactive material and records of internal exposure measurements and
assessments as required by 10 CFR 20.1101, 1201, and 1502. Title 10 CFR
20.1703(a)(3) requires the licensee to maintain and to implement a
respiratory protection program,
b. Observations and Findinas
4
'
The inspectors reviewed and df Jed with licensee representatives TEDE
exposures for plant and contract personnel for 1997. Through review of
selected dose records and discussions with licensee representatives, the
inspectors confirmed that all TEDE exposures assigned during the period
were below 10 CFR Part 20 regulatory limits.
The use of process and engineering controls to limit airborne
-
radioactivity concentrations in the plant were discussed with licensee
- representatives, and the use of such controls were observed during tours
of the plant. These controls included decontamination of areas, covering
contaminated areas. use of worksite ventilation, and other methods used
,
in minimizing worker time in contaminated and airborr.e areas. The
licensee was tracking and trending respirator usage for each RWP to
determine the effectiveness of the resairatory protection program. The
inspectors reviewed licensee reports tlat indicated reductions in the use
of respirators during recent refueling outages resulting from increased
use of engineering controls.
The inspectors reviewed and discussed the licensee's program for
monitoring internal dose and reviewed the results of assessments for
, personnel having indications of positive intakes of radioactive material.
>
The licensee incurred two positive uptakes in 1997 which were still being
evaluated by plant personnel for dose assessment. A preliminary review
showed the doses were wc1! below regulatory limits.
,
The inspectors reviewed records for eight employees who had recently worn
respiratory protection equipment. The inspectors verified that for the
records reviewed, each worker had successfully. completed respiratory
protection training, was medically qualified, and was fit-tested for the
specific respirator type used in accordance with licensee procedural
requiretrents, lhe insp3ctors also reviewed air sampling results for
,
, _ . _ . - - - . - _ _ - - , - - - ,,,o-, ....y, _ ,,,,,.. 7 , - , , , , _ , , , , . - , , - , ,
- _ _ _ _ _ - _ - _ _ _ _ __ - _ _ _ _ _ __ _ _-_ _ _ ___ - ___
34
several work evolutions and reviewed worker bioassay results which showed
,
doses were being assigned as required.
The inspectors conducted an in office review of the licensee's procedure
Radiation Protection Directive No. 11 1, Radiation Area Access and
Monitoring Devices," for conducting Body Burden Analysis (BBA). The
procedure required a body burden analysis be performed for radiation ;
workers terminating employment. However, the procedure stated this
requirement may be waived in writing by the Station Radiation Protection
Manager or his designee. The inspectors determined the licensee had
)erformed BBAs for radiation worcers terminating employment between
)ecember 1 and December 15, 1997 or had documentation reflecting why a
l The
BBAwasnotperformedonsomeindividualsterminatingemhoyment.
inspectors reviewed BBA information for approximately ll individuals who
had been authorized to work in radiation areas ar.d terminated employment
during this period. For those records reviewed, the inspectors
determined tie licensee had performed termination BBAs or documented why
termination BBAs were not performed as required by licensee procedures,
c. Conclusions
All personnel exposures to date were below regulatory limits. The
licensee had established effective procedures for the use of respiratory
protection equipment and was providing training for personnel required to
wear respiratory protection equipment.
'
-
R1.3 As Low As Reasonably Achievable (R M B).
a. Insoection Stone (83750)
The inspectors reviewed the licensee's implementation of 10 CFR
20.1101(b) which requires that the licensee shall use, to the extent
practicable, procedures and engineering controls based upon sound
radiation protection principles to achieve occupational doses and doses
to members of the public that are ALARA.
b. Observations and Findinas
The inspectors interviewed licensee personnel and reviewed records of
ALARA program results and activities. The 1997 site exposure goal was
approximately 286 person-rem and included two refueling outages. The
licensee was effectively tracking and trending dose rate reduction
efforts in 1997 for outage and non outage tasks.
At the time of the inspection, the licensee accumulated approximately 192
)erson rem year to-date which was consistent with year to date estimates.
?ose estimates for the three most significant . dose contributor work
evolutions during the outage included: steam generator ins)ection at 21
person rem, mechanical valve work at 9.5 person-rem, and slielding
installation and removal at 8.5 person-rem. Planning for these '
evolutions was reviewed and discussed with ALARA personnel. The
\
. _ . . - - _. ,_ _ - , . . - . - -
. -_ - -- __ - . . - - - - - -
35
inspectors concluded the ALARA activities for these evolutions were well
planned. The inspectors also reviewed documentation which showed that
the licensee had installed non stellite hard facing on 52 valves to
'
reduce source term activity in both units. The licensee had )lanned
similar work on seven other valves with non stellite during tie current
outage.
During tours of the facility the inspectors observed radiation protection
(RP) technicians controlling access to work areas. in addition to
observing RP technicians briefing workers in the work areas as
radiological c6nditions changed during the outage. The inspectors
observed good use of .11elding, teledosimetry, remote cameras and
, wireless communications systems for controlling personnel exposures
- during outage evolutions.
. The licensee had recently installed a new remote radiation monitoring
system consisting of 80 radiation detectors in the auxiliary building.
Final implementation of the remote monitoring system will support up to
300 detectors. This detect'on system provided live time general area
survey data without having to enter the areas to perform surveys,
c. Conclusiorn
The licensee demonstrated strong management support in the area of ALARA
as indicated by source term reduction efforts such as replacement of
stellite valve seats, effective chemical shutdown process for the current
-
outage, and by establishing challenging exposure g'als. o The inspectors
viewed the overall ALARA program as a strength.
R2 Status of Radiation Protection and Chemistry Facilities and Equipment
'
R2.1 Breathina Air and Resoirator Review
a. Insoection Scone (83750)
caseous breathing air .eet
Title 30 CFRminimum
the applicable 11.121 grade
requires that compressed,
requirements for Grade D or higher quality.
Title 10 CFR Part 20 Subpart H provides requirements for respiratory
protection programs. Title 10 CFR 20.1501 requires licensees ensure
instruments and equipment used for quantitative radiation measurements
are calibrated,
b. Observations and Findinas
The inspectors reviewed and discussed with the licensee representatives
the program for testing and qualifying breathing air as Grade D. The
inspectors examined breat.hing air manifolds for physical integrity and
current calibration of gauges, in addition, the inspectors further noted
that the supplied air hoods and hoses available for use were compatible
per manufacturer's instructions as were air supplied respirators and
]
s
l
__. _ _ , . . _ . _ -_ _ ,__
36
hoses All respiratory protection equipment observed during facility
,
tours was being maintained in a satisfactory condition.
During facility tours, the inspectors noted that survey instrumentation
and continuous air monitors observed in use within the RCA were operable
and currently calibrated. The inspectors toured the instrument
calibration room and discussed the portable instrument program with
cognizant personnel. The inspectors determined the licensee had an
adequate number of survey instruments available for use during the outage
and the instruments were being calibrated and source checked as required
by licensee procedures,
c. Conclusions
Review of breathing air testing records verified that the licensee was
calibrating breathing air compressor equipment and sampling in use
breathing air systems for certification in accordance with procedural
requirements. For the tests reviewed. breathing air met Grade D or
better quality requirements. The res)iratory protection program was
being implemented as required by 10 C:R Part 20 Subpart H. Survey
instrumentation had been adequately maintained.
R3 Radiation Protection and Chemistry Procedures and Documentation
R3.1 RWP Discreoancies
-
a. Insoection Scooe (71750)
On December 19. 1997, the inspector received a briefing from RP
technicians in preparation for inspection activities in the IB RHR puma
room, a contaminated area. The inspectors detected a discrepancy in tie
dress requirement listed in the RWP and questioned the RP technicians. ,
who indicated that an error had been made. The inspectors reviewed the
RWPs governing work in the RHR pump room RP briefing slips, procedures
governing the use of RWPs. surveys of contaminated areas, and station PIP
0-C97-4262.
b. Observations and Findinas
On December 15 and 16. 1997, the inspectors received RP briefings in
preparation for entering the IB RHR pump room to inspect maintenance
activities. During both of these briefings, the inspectors were informed
that the "J" dress category, consisting of full dress plus extra pairs of
gloves and shoe covers or booties, was required: this information was
provided on an Auxiliary Building Job Form. Form 405025. On December 19.
the inspectors received an RP briefing to return to the IB RHR pump room
to. inspect the pump. The inspectors were informed that the "H" dress
category consisting of full dress without the extra gloves and booties,
was required. The inspectors asked wh
indicated on December 15 and 16, 1997.y theRP
The dress was notindicated
technician 'J' category
that as
- J" dress category was not listed on the RWP and referred to a survey or
_____
.?7
map of the room and saw that access to the R4R pum) room involved two
'
step off pads. .The RP technician indicated that t1e ins
correct and corrected the Form 405025 to reflect the *J"pectors were
dress category
requirement.
Several days later, the NRC inquired about the discrepancy and determined
that the licensee had initiated PIP 0 C97 4262 to document the results of
an investigation they had initiated. The inspector also discussed the
issue with an RP supervisor, who indicated that a review had been
'
performed revealing additional examples of inaccurate RWPs, and that
immediate steps had been taken to correct the discrepant RWPs. The
inspector considered the initiation of_the review, as well as actions-
L taken to correct other identified discrepancies, responsive and proactive
l
to address the discrepancy once it had been identified.
The licensee's review indicated that Procedure SH/0/B/2000/003. "Use of
the Radiation Work Permit Revision 00" had not been followed. Step
4.4.1 of the procedure stated that initiating temporary changes to RWPs
is permissible under certain conditions: (1) personnel affected by the-
change are informed: (2) changes are documented in an appropriate logbook
l or
shifton a survey: Step 4.4.2 stated " initiate a permanent revision whenand (3) the
change,
radiological conditions warrant permanent changes in protective clothing,
equipment, or s)ecial instructions." The licensee's review revealed
I
incidents where)y changes in RWPs to minimize the spread of contamination
during SG eddy current testing were not logged: in addition, associated
changes in dress requirements were not incorporated into a permanent
revision of the RWP when the changes extended beyond one shift. The
licensee did not identify instances whereby the personnel affected by the
change were not informed of the updated information.
The 18 RHR pump room, at the 522 foot elevation of the auxiliary
building, was located in a contaminated area. Access to the contaminated
area was located on the 543-foot elevation of the auxiliary building.
The contaminated area on the 543 foot elevation provided access to the
emergency core cooling pumps and a spiral staircase down to the RHR pump
rooms, A step off pad was provided at the access to the contaminated
area on the 543 foot elevation. The licensee indicated that maintenance
activity in the 1B RHR pump room involved extensive work in the pump bowl l
and that a second step off pad was placed at the sump room doorway to
minimize-the spread of contamination outside of tie pump room. The
inspector asked when the second step off pad was placed: the licensee
could not furnish a record of when it was em)loyed or the specific
radiological conditions that prompted it. T1e inspector considered this
lack of documentation an example of poor record keeping practices.
. .
To. independently verify that the inspectors' observation was the only
example whereby old information was provided during the RP briefing, the
inspectors reviewed records associated with the IB RHR pump maintenance.
Numerous additional examples were identified whereby "H dress was
specified for maintenance and inspection activities instead of "J" dress.
_
___. _ _ _ _ _ __ _ _ _ _ _ _ _ __ _ _ _
i !
.
i
t
j 38 !
indicating the personnel affected by the change were not informed of the ;
,
change in dress category. '
I
Although the inspectors did not identify any clean area or personnel l
. contamination events as a result of workers using "H" dress rather than .
1
"J" dress, there were multiple instances whereby workers received
obsolete information because the RWP governing work in the IB RHR pump :
room was not revised to reflect changes in radiological conditions and ,
-
associated use of the "J" dress category. These occurrences indicated a '
4
problem with procedural adherence and constitute a violation of the
i licensee's administrative procedure regarding the use of RWPs, -
characterized as Violation 50 413/97 15 06: Failure to Revise RWPs to !
! Reflect Changes in Dress Requirements As a Result of Changing !
- Radiological Conditions.
c. Conclusions
,
j, The inspector considered the lack of documentation associated with the *
, placement of a second step off pad in the IB RHR pump room an example of
.
poor record keeping practices. A violation was identified for failure to :
revise an RWP to reflect permanent changes in radiological conditions, 1
- The licensee's initiation of a review to identify similar discrepancies,
- as well as actions taken to correct them, was responsive in addressing
l the problem. y
<.
!- R5 Staff Training and Qualification in Radiation Protection and Chemistry
4-
R5.1 Trainina of RP Technicians
i ;
,
a. Insoection Scone (83750)
- The ins)ectors reviewed training of RP Technicians to determine whether
the tecinicians had been provided adequate training in procedures to ,
minimize radiation exposures and control radioactive material as required -
] b. Observations and Findinas t
The inspectors reviewed training requirements and records for the RP
i
technicians. The inspectors also reviewed h e continuing training i
curriculum for the period January 1,1997, through December 10, 1997, '
! which included topics to minimize radiation exposure. During facility ;
l tours the inspectors interviewed RP personnel and observed work practices
to determine the effectiveness of radiation protection training.
.
'
c Conclusions
. . .
- L
Based on the training activities reviewed and interviews, the inspectors
-determined the radiation protection technicians had been provided an
adequate level of training to perform routine activities involving
radiation and control of radioactive material.
!
! ,
.yy_ _ _ - - - , . . r ,m., y - . . . ~ . . . , ._r.._,_ - __...,,--..,_,,;m_, _
--.. __._ . . -
- . _ _ - . - - . , , - - - _ , , .
. _- _ . - .-. - - . - - - - - _ - - . - ---__-
J
39
P1 Conduct of EP Activities
Pl.1 Notification of Unusual Event (NOUE) on December 30. 1997
a. s tion Scone (71750)
The inspector observed emergency response activities during the NOVE on
December 30 - 31, 1997. This emergency action
following an excessive RCS leak on Unit 1 which, levelawas
required plantdeclared
cooldown.
b. Observationc and Findinas
The TSC and OSC were both manned beginning at i:20 p.m. on December 30,
1997, following indications of excessive RCS leakage (approximately 40
gallons per minute) on Unit 1. The inspecturs were onsite at the time of
initiation and observed the emergency response activities from both the
control room and the TSC. OSC activities were observed via a video
conference monitor provided in the TSC. The TSC became operational at
7:30 p.m. after it was fully manned: emergency coordination was then
transferred there from the control room. The inspectors considered that
70 minutes seemed long for TSC activation following initial notice to
staff it. This was discussed with the TSC Site Emergency Coordinator
(SEC) after the event who indicated that the TSC was fully manned before
7:30 p.m., but control was not transferred earlier because a decision had
not been made as to which of the qualified SEC 3ersonnel would take over.
The inspector noted that the 70 minutes was wit 11n 75 minute criteria
established in licensee procedures and NRC guidance.
Good command and control was noted throughout TSC operation, and plant
status update briefings were effective. The various TSC activities were
conducted professionally, including technical support activities and NRC.
State, and county notifications. The video conferencing capability
between the TSC and OSC was efftective. Radiological protection
activities were also conducted appropriately,
In general, correct information regarding plant status was effectively
communicated and logged in the TSC. One exception was noted concerning
pressurizer pressure when RCS cooldown and depressurization activities
were placed on hold. TSC personnel incorrectly communicated the pressure
as 1695 psig and this value was entered in the computer 109 As a
result, this incorrect information was communicated by the inspector to
offsite NRC personnel. Lat6r discussions with TSC personnel indicated
that the actual value was 1300 psig, and the incorrect value was taken
from a narrow range pressure indication when a wide range instrument
should have been referenced. This error had minor significance at the
. _ time but could create confusion and cause inappropriate res)onse given a
different set of circumstances. The inspector noted that t11s error was
similar to a mistake made during a post trip review associated with Unit
1 a day earlier (discussed in Section 04.3). More licensee attention to
detail was warranted in this area.
1
80
c. Conclusions
Emergency response activities were conducted well during the Notification
of Unusual Event on December 30 31, 1997. More attention to detail was
warranted concerning the use of wide range versus narrow range plant
indication during and following events.
V. Manaoement Heatlngs
X1 Exit Meeting Summary
The inspector presented the inspection results to members of licensee
management at the conclusion of the inspection on January 14, 1998. The
licensee acknowledged the findings presented. No proprietary information
was identified.
._ .
- - . . _
__ . - . . - . - - - . - . . .
,
41
,
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
K, Nicholson, Compliance Specialist
M, Kitlan, Regulatory Compliance Manager
2
G. Peterson. Catawba Site Vice President
R. Propst, Chemistry Manager
EC
N. Economos
D. Forbes
, R Moore
N. Stinson
INSPECTION PROCEDURES USED
IP 37551: Unsite Engineering
IP 55050: Nuclear Welding General Inspection
'
IP 61726: Surveillance
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support Activities
,
'
IP 73753: Inservice Ins 3ection
IP 83750: Occupational Exposure
IP 92901: Followup - Operations
IP 92903: Followup Engineering
IP 92902: Follevap Maintenance
IP 93702: Prompt Onsite Response to Events
,
. ,ou e
r -r+ y+e
1
42
.
ITEMS OPENE0, CLOSED, AND DISCUSSED
Doened
50-413.414/97 15 01 URI Failure to Fol:ow Procedures
Resulting in Inadvertent Injections
of ECCS Fluid into the RCS (Section
04.2)
50 413/97 15 02 URI Appropriateness of Operator Actions
During Rod Testing (Section 04.3)
50 413/97 15 03 URI Anti Reverse Rotation Devices Not
Installed in the ID Reactor Coolant
Pump (Section M7.1)
50 413.414/97-15 04 NCV Failure to Have Adequate Test
Procedures for SSPS Logic Associated
With feedwater Isolation and P-10
Permissive Circuits (Section M8,1)
50 413,414/97-15 05 NCV Failure to Perform TS Surveillance
Due to inadequate IST Surveillance
.
Procedure (Section E8.3)
50-413/97 15 06 V10 Failure to Revise Radiation Work
Permits to Reflect Changes in Dress
Requirements As a Result of Changing
Plant Conditions (Section R3.1)
Closed
50 414/94 002 01 LER Reactor Trip Breakers Opened Due to
Component Failure (Section 08.1)
50 413/97-008 LER Inadequate Solid State Protection
System Surveillance Testing (Section
M8.1)
50-413.414/96-10-01 VIO Failure to Follow Procedure for
Equipment failure Analysis (Section
E8.1)
. .
.
, -- - ,e ,
m
-
-== ,
.- _ _ - __. _. .. . _ .- . _
43
50 413.414/97 03 01 VIO Failure to follow Procedure for
-
Receipt. Inspection, and Handling of
Replacement Parts (Section E8.2)
50 413.414/97 10 01 UR! Review Corrective Action for IST
Check Valves (Section E8.3)
50 413/97 005 LER Failure to Perform TS Surveillance
(Section E8.3)
50 413.414/97 09 04 VIO Failure to follow Procedure. Two
Examples (Section EB.4)
50 413.414/97 10 03 IFI Resolution of FWST Set Point
inconsistencies (Section E8.5)
50 413.414/97 10 04 IFl Inaccuracies Caused by Using DEPLET
Code on Different Computer Models
(Section EB.6)
50 413.414/06 05 02 VIO Inadequate 50.59 Fvaluation (EA 97-
179) for Changes to Auxiliary
Feedwater (CA) Piping Temperature
(Section E8.7)
50 413/95 003 and LER Failure to Perform TS Surveillance
-
50 413/95 003-1 Due to Unanticipated Interaction of
Systems (Section E8.8)
LIST OF ACRONYMS USED
1E0C10 Unit 1 Refueling Outage
AC Alternating Current
ALARA As Low AS Reasonably Achievable
AP Abnormal Procedure
ASME American Society of Mechanical Engineers
BBA Body Burden Analysis
CAPT Steam Tt.rbine CA Pump
CFR Code of Federal Regulations
CGA Compressed Gas Association
DBD Design Basis Document
D01 Digital Optical Isolator
DRPI Digital Rod Position Indication
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generators
EHRA . Extra High Radiation Area
ESF Engineered Safety Feature
'F Degrees Fahrenheit
FATS Failure Analysis and Trending
_ -___ _ _
,
44
FSAR Final Safety Analysis Report
FWDS Field Weld Data Sheets
FWST Refueling Water Storage Tank
GDC -General Design Criteria
GPM Gallons Per Minute
IST Inservice Testing
KC Component Cooling
LER- Licensee Event Report
MS!V Main Steam-Isolation Valve
-NCV Non Cited Violation
NC Reactor-Coolant
NCOT Reactor Coolant Drain Tanker
NI Safety Injection
NOUE Notification of Unusual Event
'
NRC Nuclear Regulatory Commission
'
NRR Office of Nuclear Reactor Regulation
NSD Nuclear System Directive
NSSS Nuclear Steam Supply System
'
OAC Operator Aid Computer
00T Out of Tolerance
OSC Operations Support Center
PCB Power Circuit Breaker
PCE Personnel Contamination Event
PIP Problem Investigation Report
PORC Plant Operations Safety Committee
PPM Parts Per Million
.
PSIG Pounds Per Square-Inch Gage
OC- Quality Control
RCA- Radiologically Controlled Area
RHR -Residual Heat Removal
RII -NRC Region 2 Office
RP Radiation Protection
RWP Radiation Work Permit
RV Reactor vessel
-SG Steam Generator
.SRWP Special Radiation Work Permit
SSPS Solid State Protection System
TEDE Total Effective Dose Equivalent
TS Technical Specification
-TSC- Technical Support Center
=UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
V Volts
VDC Volts - Direct Current
. VHRA _ . Very High-Radiation Area .
VIO Violation
WO Work Order
__--- o