ML20198S189
| ML20198S189 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/16/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20198S175 | List: |
| References | |
| 50-445-97-20, 50-446-97-20, NUDOCS 9801260102 | |
| Download: ML20198S189 (20) | |
See also: IR 05000445/1997020
Text
, ..
r, -
EtiGLOSURE 12 '
'
U.S. NUCLEAR REGULATORY COMMISSION -
REGION IV
Docket Nos.: 60-445
50-446
License Nos.: NPF-87
NPF 89
Report No.: 50-445/97-20
50-446/97-20
Licensee: TU Electrin
- - Facility
- Comanche Peak Steam Electric Station, Units 1 and 2
Location: FM-56
Glen R6se, Texas-
Dates: October 12 through November 22,1997
, inspectoes: Harry A. Freeman,- Acting Senior Resident inspector
Rebecca L Nease, Resident inspector
.
Approved By: Joseph I. Tapia, Chief Branch A
Division of Reactor Projects
Attachment: Supplemental Information
.
9901260102 980116
. PDR ADOCK 05000445
9 PM _
h
. ._
__ -.
- . . - , - - . - . . . - . - _ . - - _ .- - - -.- . - . ._
~
!
>
s
,
~
EXECUTIVE SUMMnRY
-7
I Comanche Peak Steam Electric Station, Units 1 and 2
- NRC Inspection Report 50-445/97-20; 50 446/97-20
-
,
Qgrations .
'
.. Operations personnel response to the Units 1 and 2 trips was prompt, appropriate, and
characterized by excellent three-way communications and good command and control . ,
L (Sections 01.2 and 01.3).
- Inadequate procedural guidance, complicated by a senior reactor operator's incorrect .
understanding of the system's operation, led to an inadvertent actuation of the low-;
temperature overpressure protection system during the Unit 2 cooldown.- This was a
violation of 10 CFR Part 50, Appendix B, Criterion V (Section 04.1).
- .. Woak procedural guidance, poor communications, and a lack of understanding of the
, operation of the personnel airlock doors resulted in a violation of Technical
,
Specifications related to ensuring containment integrity during core alterations -
(Section 04.2).
Operators performed core alterations prior to establishing direct communications with
'
.
- the control room when they installed lighting inside the core. This resulted in a noncited
'
.
violation of Technical Specifications (Section 04.3);
"
Maintenance
. Observed surveillances were well controlled and professional with, thorough prejob
,
briefings and excellent communications (Section M1.1).
. Poor control of work activities in the switchyard and personnel error resulted in an
automatic trip of the Unit 1 reactor from 100 percent power (Section M1.2).
. The licensee's retrieval of a damaged fuel assembly was performed in a deliberate and
l- 4 professional manner with a thorough prejob briefing. Good radiological; foreign
<
. material, and personnel safety practices were observed (Section M1.4).
__
.<- The licensee failed to repair all the structural gaps in the Unit 2 emergency core cooling
sumps that had been identified in 1994. This was a v:olation of 10 CFR Part 50,
Appendix _ B, Criterion XVI (Section M1.3). ,
"
- . A noncited violation was identified when maintenance workers modified bushings in as --
many as 79 valve actuators without review and documentation as required by -
procedure (Section M8.1).
,
_
. - , ' --
-
~
_.. _ _
g
g
_
d
A.- e-... ,s-, .%., - - . _ , c ,,y- .v..- - - ,- .,-m- +ry . r+- +e.- .- --
e
. - . . ,. - . . -- -. -. - . .._. - - . . . . . .-
.. .
!
.; , -
.
a
-2-'-
'
,
~
t
Engineering j
.. ; The inspectors found that the licensee's evaluation of an issue concoming control room;
. pressurization surveillance testing was weak in that it failed to encompass all potential
-vulnerabilities (Section E1.1).
_
[ 1. - . Engineering provided good support to the operation of the facility by providing thorough -- -
and conservative evaluations. This support was sometimes provided after the .
- maintenance actions had already been taken (Section E2.3).
i
Plant Support
'
-*- A noncited violation of Technical Specifications was identified when a radiation ;
protection technician failed to maintain constant physical control of a radiation area key
_ (Section R4.1).-
o
,
4
1
9
.-
t
c
_.
___
.
r
w
e -
M
ta
,l= 9 , w w-., aw a-,, um..va0 .m ,e w y n +
. . . -. -. . -
4
.
RenotLDetails
Summary of Plant Status
Unit.1
Unit 1 began the inspection period at 100 percent power, On October 27, the unit tripped due
to a generator output breaker fault which occurred during relay testing.
Unit 1 resumed power operations and, or. October 30, the unit reached full power and
remained at 100 percent power through the end of the report period.
Unit 2
- Unit 2 began the inspection period at 100 percent power. On October 24, during a downpower
in preparation for a refueling outage, the reactor was manually tripped from approximately
'10 percent power when a control rod malfunction esulted in four dropped control rods.
' The licensee commenced the third Unit 2 refueling outage on October 25. During plant
cooldown, the low-temperature overpressure protection system was inadvertently actuated.
- Unit 2 ended the inspection period in Mode 6 with the core being reloaded.
,
l. Operations
01 Conduct of Operations
01.1 General
The conduct of operations observed was characterized by good command, control, and
communications. Licensed operator responses to both the Units 1 and 2 trips were
professional and well controlled. Reduced inventory control and midloop operations
were good. However, several incidents occurred involving errors by experienced
personnel.
01.2 Unit 1 Reactor Trio
a. Insoection Scope (93702)
'At 10:44 a.m. on October 27, Unit 1 experienced an automatic trip from 100 percent
power.due to a loss of load and turbine trip. All safety systems functioned as designed.
Inspectors reported to the control room and observed the response to the event,
including operator monitoring of annunciators, supervisory control, and posttrip actions.
Operators exhibited good response to the event as exemplified by manually starting
auxiliary feedwater in anticipation of an automatic initiation. ' Following the trip, Source
Range N-31 energized as expected, but immediately failed downscale. This was the -
only material condition problem expenenced as a result of the trip.
.
.-y
1
l
-2-
b. Observations and Findinos
Operator response to the rtvent was pro 71pt and appropriate, operators used clear !
three-way communications, and the unit supervisor and shift manager demonstrated
good command and controlin directing the event response. Tha material condition of ;
the plant was very good and only min:,r problems were experienced as a result of the ;
trip.
01.3 Unit 2 Downoower and Reactor.Irlp
a. Scooe (71707. 93702)
On October 24 and 25, the inspectors observed control room op+rators ramp down
reactor power n preparation for a unit shutdown for Pefueling Outage 2RFO3 using the
following procedures:
IPO-003B, " Power Operations," Revision 4
IPO-0048, " Plant Shutdown from Minimum Load to Hot Standby," Revision 2
b. Observations and Findinos
During the downpower, with Unit 2 at 56 percent power, a rod control urgent failure
alarm occurred at approximately 11:40 p.m on October 25. The licensee immediately
began troubleshooting. At approximately 12:30 a.m., the licensee resumed ramping
down power by borating while troubleshooting en the rod centrol system continued. At
4:04 a.m., with the unit at approximately 10 percent power, three control rods dropped
approximately 20 steps and another dropped to the bottom, Operaus immediately
tripped the reactor and entered the emergency operating procedures. All equipment
operated as expected and there were no emergency safety features actuations.
The downpower was well controlled and performed in accordance with procedures.
The operators used excellent three-way communications throughout the routine
downpower. Operations personnel responded to the rod drop in a deliberate manner
without hesitation. The unit supervisor demonstrated excellent command and control,
calling out the steps in the emergency operating procedure clearly and metMJically.
The operators responded well.
04 Operator Knowledge and Performance
04.1 Low-Temoerature Overoressure Protection Actuation
a. Inseection Scoce (71707)
On October 25, the licensee inadvertently actuated the low-temperature overpressure
protection system during the Unit 2 cooldown. Both pressurizer power-operated relief
valves actuated. After verifying that the pressure was below the actuation setpoint,
.
.
-3-
operators closed the block valves to secure the depressurization. The inspector
reviewed the operating procedures, the alarm response procedures, and the technical
data manual procedure used during plant cooldown.
b. Observations and Findinos
The low temperature overpressure protection system is an automatic system that
protects the reactor vessel and pip'ng systems against pressure transients during low
temperature operation. The system continuously monitors reactor coolant temperature
and pressure. System temperature is converted into an allowable pressure and then
compared to the actual reactor coolant svstem (RCS) pressure. If oressure
approaches the Clowable pressure, a antrol board annunciator will sound. If pressure
exceeds allowable pressure, another control board annunciator w;;l sound and one or
both pressurizer power-operated relief valves will open if the RCS temperature is
s350*F.
Plant cooldown was conducted in accordance with Integrated Plant Operating
Procedure IPO-005B, " Plant Cooldown from Hot Standby to Cold Shutdown," Revision
2. The inspector noted that, in several locations throughout the procedure, a statement
cautioned that RCS pressure and temperature shoulci be maintained within the limits of
Ehnical Data Manual TDM-3018, *RCS Temperature & Pressure Limits," Revision 5.
TDM-301B contained a graph showing the pressurizer power-operated relief valve Ic'n-
temperature overpressure protection setpoints. Neither the TDM nor the integrated
plant operating procedure referenced that the system armed when reactor coolant
temperature was s350'F.
During the cooldown, operators slowed the pressure reduction to maintain pressure
between 850 and 900 psig while the safety injection accumulators were being isolated
but did not slow the rate of cooldown. The procedure required that the accumulators be
isolated prior to reducing pressure below 800 psig. During this time, operators received
Alarm 2 ALB-6D,"AT LO TEMP PORV 455A APPROACHING LMT PRESS." This
annunciator alarms when pressure is within 20 psig below the reference pressure.
Operators referenced the alarm response procedure which required that they refer to
TDM 301B in order to determine the RCS pressure and temperature limits. The
procedure did not requiro that pressure be immediately reduced to clear the r' arm.
Accumulator isolation was completed and operators recommenced the prestre
reduction. At approximately 350*F, the low-temperature overpressure protection
system actuated with pressure at approximately 735 psig. The power-operated relief
valves were shut when pressure dropped below the setpoint. Following the actuation,
the operators stated that they believed that the system armed at 320*F.
10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"
requires, in part that activities affecting quality shall be prescribed by instructions of a type
appropriate to the circumstances. ' Contrary to this requirement, Procedure IPO-005B,
Revision 2, was not appropriate to the circumstances in that the procedure did not require
that pressure be maintained below the RCS pressure and temperature limits as specified
.
.
-4-
in TDM 301B and, ar a consequence, both power-operated relief valves opened when
pressure was allowed to remain above the limit (50-446/9720-01).
In Special Report 2-SR-97-001 to the NRC Region IV Regional Administrator (licensee
letter TXX 97250, dated November 24), the liansee committed to the following:
(a) assess if the misconception of the arming temperature is a general knowledge
deficiency and conduct appropriate training if deemed necessary, (b) revise Alarm
Procedures ALM-0064A and -B to include the arming setpoint, and (c) revise Integrated
Pirnt Operating Procedures IPO-005A and -B to add appropriate provisions ;o establish
temperature and pressure cor.ditions during cooldown which will not unnecessarily
challenge low ternperature overpressure protection system actuation.
c. Conclust203
Inadequate guidance in both the integrated plant operating procedure and in the alarm
response procedure contributed to an inadvertent actuation of the low-temperature
overpressure protection system. Additionally, incorrect knowledge of system operation
by a senior reactor operator contributed to the event.
04.2 Confiauration Control of Containmem Inteority Durina Core Alteratiomi
a. Scoco W707)
In following the licensee's investigation and corrective actions conceming recent
challenges to maintaining containment integrity during core alteration, the inspectors
reviewed the following licensee documents:
Operations Notification and Evaluation Form 971384
Operutions Notification and Evaluation Form 97-1397
Plant incident Report 97-1378
Procedure SOP-9078, " Containment Personnel Airlocks," Revision 3
Procedure OPT-4088, " Refueling Containment integrity Verification,"
Revision 2.
b. Findinas and Conclusions
Loss of Containment intearity; On November 10, the licensee was performing core
alterations with both PAL doors open and de-energized. Technical Specification 3.9.4
requires, in part, that during core alterations, at least one of the two PAL doors be
capable of being closed and that each penetration providing direct access from the
containment atmosphere to the outside atmosphere shall be closed. A plant equipment
operator responsible for ensuring closure of the PAL noted that several hoses
associated with the PAL hydraulic system were disconnected to support maintenance
activities. The equipment operator questiened if this configuration would affect his
ability to close the inner door. At the tir.ie, the licensee was relying on the capability to
- _. .
.
5
i
raanually close the inner PAL door for meeting Technical Specification 3.9.4.
Operations immediately suspended fuel movement.
The PAL system engineer determined that the inner door could not be considered
r operable because its pressure equalizing valve, considered part of the PAL door, was
open. The open equalizing valve provided a direct containment atmosphere to outside
atmosphere pathway that would not ham isolated when the inner door was manually
closed. A miscommunication between oporations personnel and the system engineer
resulted in the outer door being declared operable and core alterations were resumed.
Upon r: loser inspection, the system engineer found that the pressure equalizing valve
for the outer door was also partially open, rendering the outer door inoperable. Again,
fuel movement was suspended. Operators re energized the outer door and closed its
associated pressure equalizing valve, ensured that the outer door was capable of being
closed, and then resumed core alterations. Coaducting core alterations with the PAL
doors being incqpable of being closed is a violat,on of Technical Specification 3.9.4 (50-
446/9720-02).
Procedures OPT-408B, ' Refueling Containmont Integrity Verification,' and SOP 9078,
' Containment Personnel Airtocks," were weak in that they did not provide clear
instructions concerning manual operation of the PAL doors and associated pressure
equalizing .vm The licensee revised both procedures to provide precautions and
instruction cr operating the PAL doors manually to establish containment integrity, in
addition, several other a teknssses were ;dentified. The plant equipment operator
responsible for PAL door closure was not aware that the PAL doors were de energized
and would have to be clased manua"y. The licensee determined that few operators
fully understood the operational status of the airlock and pressure equalizing valves
when the PAL doors were required to be manually operated. Core alterations were
resumed prior to verification of the operability of the outer door due to a
miscommunication between operations and the system engineer.
NeaLMtst On November 11, with core alterations in progress, the nuclear steam supply
system work wintaow manager recognized a potential containment integrity breach when he
discovered that the hand hole covers in SG 2 04 had been removed. Another concurrently
scheduled work activity, to remove and replace a feedwater instrument isolation valve,
would have completed an open pathway through the hand holes, Steam Generator 2 04,
and the feedwater instrument isolation line to the outside atmosphere. Upon discovery, the
licensee immediately suspended core off load and initiated an investigation which verified
that the valve had been welded in placa prior to the time when tb i hand hole covers had
been removed during core alterations. Technical Specification 3.9.4 had not been violated.
The inspectrls reviewed this near miss and found that, during the outage, the licensee
relied on sequencing work to ensure containment integrity during core alterations.
Specifically, when work on containment penetrations inside containment had been
completed. fuse penetrations were closed, and work packages were issued to allow
work on reratrations outside containment. Eddy current work in Steam Generator 2-04
had been cornpleted and the steam generator hand hole covers were ins'alled.
._ - = . - _- - _ _ - ___ __- - _
.
6-
However, since the work package was not closed and the clearance was still in effect, a
technician removed the hand hole covers for some followup eddy current investigation.
Operations personnel did not authorize the hand hole cover removal and were unaware !
that the containment boundary had been opened. During this time frame, the work
order for removing and replacing the feedwater instrument isolation valve had been i
authorized. Had both jobs been conducted at the same time, an air to-air breach of !
containment would have occurred during core alterations and would have been a I
violation of Technical Specification 3.9.4. The inspectors concluded that controls for
maintaining containment integrity were weak and, in this case, would not have
prevented a breach in containment integrity during core alterations.
The licensee implemented the following intermediate corrective actions to prevent
recurrence during fuel reload: (1) no work was permitted on containmeat boundary
equipment during core alterations and all open work order packages wee retrieved;
(2) the NSSS work window manager was assigned the primary responsibility for
containment integnty; and (3) workers were not permitted to sign back on a clearance
until the work order had been re reviewed by operations.
c. CQDclusions
The inspectors concluded that the licensee's controls for ensuring containment integrity
during core alterations were weak. Weak procedures for operating the PAL doors
resulted in the failure to meet the Technical Specification requirement of being capable
of closing the PAL door during core alterations. Contributing factors to this included
poor communications and operator knowledge deficiencies. Finally, relying on the
sequencing of work activities in the outage schedule would not have prevented work
activities from occurring concurrently and could have resulted in a breach of
containment integnty during core alterations.
O4.3 Core Alterations Without Communications
a. lDipection Scopp (71707)
On November 8, the licensee inserted on underwater light into the reactor vessel in
preparation for fuel off-load prior to establishing direct communications between the
control room and the refueling station. The inspector reviewed the cause of the event
and the licensee's immediate and planned corrective actions.
b. Obietyations and Findin95
Technical Specifications define core alterations as the movement or manipulation of
any component within the reactor pressure vessel with the vessel head removed and
fuelin the vessel. Technical Specification 3.9.5 requires that direct communications be
maintained boNveen the control room and personnel at the refueling station during core
alterations. Contrary to these requirements, the licensee placed an underwater light
- _
-- _. ._ _ . .- . _ _ - - _ - - - - . -_ _ - _ . - _ _ _ . _ -
.
'
,
-
7
,
ir. side the reactor ve:,sel prior to establishing direct communications between the i
control room and the refueling station.
After the light had been placed into the vessel, the fuel handling supervisor was alerted
to the fact that this constituted a core alteration. The fuel handling supervisor halted
,
further fuel handling activities. As part of their corrective actions, the licensee issued a
lessons learned report on the event, established signs on the refueling bridge to remind
personnel of what constrtuted a core alteration, and conducted refresher training to all
' fuel handling supervisors and contractor personnelinvolved with the refueling. The
licensee issued a ONE form which will be dispositioned as a plant incident report.
Placing an underwater light into the reactor vessel above the fuel had negligible effect on
core reactivity, in the improved standard h chnical Specifications, not yet approved for
the licensee, cote alter: tion has been redefined to be the inovement of any fuel, sources,
or reactivity control components within the reactor vessel with the vessel , sad removed
and fuelin the vessel. The inspector concluded that the event had little actual significance
and that the licensee's corrective actions were apprepriate. This nonrepetitive,
licensee identified, and corrected violation is being treated as a noncited violation,
consistent with Ssction Vll.B.1 of the NRC Enforcement Policy (50-446/9720-03),
c. Conclusions
A noncited violation of Technical Specifications was identified related to performing
core alterations prior to establishing direct communications with the control rocM when
operators installed lighting inside the core.
08 Miscellaneous Operations issues (92901)
08.1 (Closed) Violation 50 445f4461/9706-01: f ailure to establish procedures to ensure
that alllicensed operators that have their licenses conditioned to wear corrective
lensos for the eye, always have available appropriate lenses qualified for a self-
contained breathing apparatus, in the enclosed Notice to NRC Inspection Report 50
445(446)!97-06, the NRC concluded that the information regarding the reason for the
violation and the corrective actions taken and planned were already adequately
addressed on the docket and that a response was not necessary unless the licensee
concluded that the descriptions or corrective actions did not accurately reflect their
position. The licensee did not respond and this item is closed.
- , . - . -- - . . - - .
- -- - - - ,
-
F
.
8-
lL Maintenance
M1 Conduct of Maintsnance
M1.1 General Comments
in general, maintenance and surveillance activities were characterized by
knowledgeable individuals and professional performance. Although the planning and
preparation prior to the start of the Unit 2 outage was thorough, numerous problems
occurred during the outage. This included damaged equipment, work stoppages, and
personnelinjury Several of these issues involved mistakes by experienced personnel.
a. Inanection Scone (61728. 82707)
The inspectors observed all or portions of the following work activities:
Turbine-driven Auxiliary Feedwater Pump design modifications
Diesel Generator 2-01 maintenance
OPT 214A, * Diesel Generator Operability Test,' Revision 10
OPT-467A, "Trair, A Safeguards Slave Relay K609 Actuation Test," Revision 3
b. Observations and Findinas
The inspectors found the work performed under the above activities to be well
controlled and professional. Prework briefings were timely and thorough. Excellent
three-way communications were observed throughout the performance of the work.
Individual work groups reviewed the work steps and discussed the potential
,
consequences and appropriate responses. Operators performing the work read the
'
steps aloud before performing them.
- M1.2 Unit 1 Reactor Trio Review
a. Scope
in followup to the October 27 reactor trip, the inspectors reviewed the licensee's
immediate and interim actions for controlling work activities in the switchyard. - The
inspectors also reviewed the Interface Responsibilities Memorandum, dated July 2,
1997, which described the licensee's process for controlling work in the switchyard.
b. Observations and Findinas
On October U, Unit i experienced an automatic trip from 100 percent power due to a
loss of load and turbine trip (Section 01.2) Unit 2 was in a refueling outage, and the
Unit 1 generator was supplying the grid through fireaker 8010 to the west bus of the
345kV switchyard; The east bus of the 345kV sv'itchyard was isolated to support
- lightning protection modifications. At the time of the trip, Glen Rose Transmission
r =
' " J.,5., -
_ _ - - _ . - - . . . - _ _ .
.
.
.c.
protection and control technicians were testing Breaker 8000 on the east bus of the
345kV switchyard. Glen Rose Transmission is a separate division within the TU
Electric Company. In preparation for testing, technicians had closed Breaker 8h 0 and
opened the two air switches on either side. When Breaker 8000 received the test trip
signal to open, an unexpected pole disagreement delayed the opening enough to allow
the protecjve lockout function timer to start and time out. This resulted in a protective
lockout relay actuation which opened Breaker 8010, causing a loss of load and
subsequent Unit 1 turbine and reactor trips. All work in the switchyard was immediately
- suspended and was permitted to resume only after licensee management was fully
briefed on the scope and potentialimpact. The licensee determined that the cause of
the trip was failure of Glen Rose Transmission technicians to defeat the protective
lockout feature on Breaker 8000.
.The inspectors reviewed the licensee's process for controlling work in the switchyard
and found it to be a nbiguous and lacking formality. The Interface Responsibilities
Memorandum, dated July 2,1997, provided little guidance concerning review, approval,
or coordination of switchyard work. The interface agreement did not require switchyard
work to be reviewed by Comanche Peak personnel. Switchyard work was controlled
through the work control scheduling process. Typically, only work thought to have a
potential for impacting plant operation was shown on the schedule and not all
cwitchyard work was scheduled.
The licensee's investigation revealed several weaknesses associated with control of
work in the switchyard. Since few Glen Rose Transmission technicians had site
access, the technicians actually performing the work were not necessarily those that
attended the prejob briefing. Contrary to the Interface Responsibilities Memorandum, a
single point of contact between Operations and Glen Rose Transmission had not been
designated. Switchyard breaker testing was performed without procedures, relying on
skill of the craft and electrical diagrams. Only that work which was scheduled received
Comanche Peak review for impact to the plant. The testing of Breaker 8000 was not
scheduled and as a result did not receive Comanche Peak review for impact to the
plant.
The licensee has established a task team to develop long term corrective actions. In
the interim, all switchyard work is described on a written plan, reviewed by Comanche
Peak management, and briefed by Glen Rose Transmission technicians.
c. Conclusions
The inspectors concluded that the trip was caused by personnel error because Glen
Rose Transmission protection and control technicians did not fully understand or review
the impact that the breaker testing on the east bus could have on the west bus. In
addition, the licensee lacked a formal process for effectively controlling activities in the
. ., . _. ._ -- -
__.
.
10-
W 3 fppQpQu f Corrective Actions on Containment Sumps
section Scooe (62707. 92902)
On November 8, the licensee identified 16 gaps in the emergency core cooling system l
,
structural support members that were larger than the fine mesh openings. Following
completion of the repairs to the Unit 2 sumps, the inspectors visually confirmed that the
gaps identified by engineering had been repaired. The inspectors reviewed t%e work
orders originally used to repair the gaps in 1994.
b. Observations and Findinas
in 1994. Violation 50-445(446)/9423-03 was issued which stated that the licensee's
design control measures did not adequately verify that the Units 1 and 2 containment
sump trash racks met design requirements. Structural gaps in each of the emergency
core cooling system containment sumps were larger than the fine mesh openings and
did not meet design basis requirements. The licensee repaired the Unit 2 gaps under
Work Orders 194 078046-00 and 194 078047-00. On November 8,1997, the
licensee identified nine gaps in the Train A sump and seven gaps in the Train B sump
which did not meet the design basis requirements. The gaps were approximately
0.625 inches long and the two widest were between 0.250 inches and 0.375 inches
wide. Of these 16 gaps,8 had been previously identified in 1994, but had not been ;
!
adequately corrected. When the sump gao issue was originally identified in 1994, the
licensee contracted with Westinghouse to perform an engineering evaluation to :
consider what affect the ingestion of debris into the containment sumps could have on
containment spray and emergency core cooling. That evaluation concluded that the
gaps did not affect the operability of these safety systems. The inspector verified that .
'
the recently identified gaps were bounded by the 1994 evaluation and that the
operability of the systems was again not affected.
The inspector reviewed the work orders used in 1994 to repair the Unit 2 sump
structures. Neither work order specified the locations of the gaps to be repaired.
Instead, the work orders directed the work group to use stainless steel plates to cover
openings and reduce the gaps to no more than 0.115 inches. The work orders required
that a quality control inspector inspect the structure for holes or gaps, which exceeded
the criteria specified in the design change. The design change directed that any hole or
gap with a side dimension or diameter greater than 0.115 inches that would allow
debris to flow into the sump be repaired. The quality control inspecticas had been
documented as being satisfactory.
FSAR Section 6.2.2.2.7 stated that the fine screen had a 0.115 inch opening to ensure
that the spray nozzle orifices and grid assemblies in the reactor core do not clog and
that trash racks and screens are provided to preclude clogging of the recirculation lines
and any of the system's components. The section stated that the design of the
containment spray recirculation sumps satisfied the requirements of NRC Regulatory
Guide 1.82, " Sumps for Emergency Core Cooling and Containment Spray Systems,"
. l
4
11-
I
dated June 1974. Regulatory Guide 1.82 states that the size of the openings in the
fine screen should be based on the minimum restrictions found in systems served by l
'
the sump.
The original ONE form which documented the deficiencies in 1994 did not specify the j
locations of gaps but instead stated that there were approximately 48 gans in the Unit 2 !
sumps. The ONE form wording was not clear as to whether there were 48 gaps in l
each sump or 48 gaps total. Weld data record sheets in the work orders indicated that
71 repairs were made in the Train A sump and that 81 repairs were made in the Train B
sump.
10 CFR Part 50, Appendix B, Criterion XVI, ' Corrective Actions,' requires, in part, that
conditions adverse to quality and nonconformances be promptly identified and
corrected. Contrary to this requirement,16 gaps greater than the maximum allowable
gap were not promptly identified and corrected. On November 8,1997, eight previously
identified and eight addit!onal structural gaps, that exceeded the Final Safety Analysis
Report description of 0.115 inches, were identified in the Unit 2 emergency core cooling
sumps. This is a violation (50-446/9720-04).
c. Conclusions
The licensee fJiled to promptly identify and correct the gaps in the Unit 2 emergency
core cooling system containment sumps. The original work orders were poorly written
because they did not specify the locations of the gaps to be repaired but instead relied
on the work groups to locate and repair the gaps. Several gaps which did not meet the
design basis requirements had been identified in 1994.
M1.4 New Fuel Assembiv Damage
a. lnspection SconeJ62707. 93702)
The inspector responded to the site in response to a fuel handling event in order to
verify that the fuel assembly was in a safe condition and did not represent a potential
radiological hazard to stored spent fuel. The inspector reviewed the cause of the
damage, the licensee's actions to secure the damaged assembly, and the actions
taken to prevent future damage.
b. QbicIyations and Findin95
While lowering a new fuel assembly into the high density storage racks in Spent Fuel
Pool X-02 in high speed, the fuel handler observed a sudden decrease in load cell
reading concurrent with unexpected movement of the long handled tool attached to the
assembly. The operator immediately raised the assembly. The operator and fuel
handling senior reactor operator observed that the assembly appeared to be damaged.
All fuel movement was secured while the licensee conducted an investigation. The
. _ _ , - . . _. -_ __ _ _ . . _ . - --
.
I
-
12
licensee suspended placing any more assemblies into the high-density fuel racks until
procedural, personnel, and/or equipment weaknesses could be resolved.
Ths inspector verified that the damaged fuel assembly did not represent a hazard to
any spent fuel assembly. The inspector noted that the licensee had stationed a
refueling senior reactor operator in the spent fuel pool area to monitor any potential
changes to the assembly since it was being held by the long-handled tool and to
prevent any unauthorized individual from approaching the refueling bridge. Because
the fuel assembly was being held by only 4 of the 25 guide tubes, the licensee secured
the assembly to the hoist by using two loops of aircraft cable slung around the lower
nozzle. The licensee believed that any lateral movement through the pool could
damage the remaining guide tubes, so a temporery design change was implemented to
allow the use of the cable prior to removing the assembly from the pool.
The fuel assembly was damaged when an edge of the lower nozzle contacted the edge
of the fuel rack during lowering. As the weight of the assembly shifted from the long-
handled tool to the fuel rack, the fuel assembly began to lean. A postevent review by
the fuel vendor concluded that a 3 degree lean angle could damage the fuel assembly.
The vendor also stated that moving the fuel would not be advisable unless seven or
eight of the guide tubes remained intact.
The fuel handler was required by procedure to lower the fuel assembly into the high
density racks in slow speed until 10 inches had been inserted into the rack. The
assembly could then be lowered in high speed. The fuel handler had one hand on the
pendent controlling the hoist and the other hand on the long-handled tool to help guide
the assembly into the rack. The handler was required to monitor a load celllocated on
the hoist, guide the assembly into the rack, observe when 10 inches had been inserted,
and then shift to fast speed in a smooth motion. Although the fuel handler was a
contractor that had a significant amount of experience in fuel movement, he failed to
correctly perform this evolution because he did not wait until the assembly was inserted
at least 10 inches into the rack before lowering it in high speed.
The licensee's prejob briefing for the retrieval of the damaged fuel assembly was
thorough and appropriately focused on personnel, radiological, and equipment safety.
Self checking and verification techniques were stressed. Access to the refueling area
was tightly controlled to avoid confusion. Throughout the evolution, the licensee
demonstrated proper radiological safety and foreign material exclusion practices. The
inspectors concluded that all aspects of this difficult evolution were well controlled and
perforrned in a deliberate and professional manner.
c. Conclusions
The inspector concluded that the damaged fuel assembly was damaged due to
operator error. The inspector concluded that the damaged fuel assembly was carefully
controlled and moved and that the licensee's plans to suspend further use of the high-
density fuel racks until the issue could be resolved was appropriate.
4
i
1
,
13-
l
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Unresolved item 50-445(446)/9717-03: modifications made to Fisher-Type
667 air-operated valve actuator bushings without the required review. As previously
desenbed in NRC Inspection Report 50-445(446)/9717, this unresolved item was
opened for the inspectors to: (1) evaluate the extent and impact of modifications to the
actuator bushings, (2) determine if the appropriate postmaintenance tests were
performed on the affected steam generator atmospheric relief valves (ARVs), (3) verify
that the licensee corrected the Master Equipment List, and (4) evaluate any generic
aspects of the issue.
The licensee completed its investigation and did not identify any additional
modifications to actuator bushings, bringing the maximum number of unreviewed
modifications to 70, most of which were not safety related. The licensee concluded that
the modifications were acceptable because the small holes drilled in the actuator
bushings did not affect their functionalintegrity. The inspectors agreed with this
evaluation. The licensee also determined that the steam generator ARVs had been
postmaintenance tested after the elastomers were replaced. The inspectors reviewed
the Master Equipment List entries for the ARVs and found that they had been
corrected. After conducting interviews with maintenance personnel and management
and after reviewing the licensee's investigation report, the inspectors did not identify
any generic concem related to the issue.
Technical Specification 6.8.1 requires, in part, that the licensee establish, implement,
and maintain procedures covering the activities referenced in Appendix A of Regulatory
Guide 1.33, Revision 2, February 1978. Appendix A, Secticn 9, requires procedures for
performing maintenance. Licensee Procedure STA 206, " Review of Vendor
Documents and Vendor Technical Manuals," Revision 19, stated that vendor
documents or correspondence that will be used for design, testing, or other input for
CPSES activities shall receive review and approval on a vendor document review
traveler or be incorporated into an applicable vendor technical manual prior to final
acceptance and approval of the activity, inspectors concluded that the licensee
violated Technical Specification 6.8.1 in that maintenance personnel failed to follow
procedure when they modified as many as 79 Fisher-Type 667 valve actuator bushings
(some of which were associated with safety related valves) without proper
documentation or review. This nonrepetitive, licensee-identified, and corrected
violation is being treated as a noncited violation consistent with Section Vil.B.1 of the
NRC Enforcement Policy (50-445(446)/9720-05).
_ _ _ _ _ _ _ _
.
.
14
I
Ill. Engineerlag
E1 Conduct of Engineering
E1.1 Control Room Pressurization Unit Surveillance Plant incident Evaluation l
a. Insoection Scooe (37551)
The inspector reviewed Plant incident Evaluation 97 934 which addressed control room
pressurization unit surveillance test acceptance criteria inconsistencies. The evaluation
was initiated following questions raised by the inspector as documented in NRC
Inspection Reports 50-445(446)/9717 and 50-445(446)/9718. The inspector reviewed
the evaluation to assess the thoroughness and quality of the self assessment.
b. Observations and Findincs
The inspector found that the evaluation did not include any type of formal charter
documenting the purpose or scope of the evaluation. Consequently, the inspector was
unable to assess whether the evaluation fully met the licensee's expectation that all of
the issues that should have been addressed be resolved. Nevertheless, the evaluation
thoroughly reviewed the issue of leaving the as-left values of pressurization flow above
the design basis value.
The inspector reviewed the data provided in the evaluation and noted that there
appeared to be a correlation between the measured flow rates and the dates that the
test was performed. Tests conducted during the surnmer months were generally
measured at higher flow than tests conducted during the winter. Additionally, the l
inspector noted that the licensee was committed to ANSI /ASME N510-1980, " Testing of
Nuclear Air Cleaning Systems," which stated that the number of readings taken to
determine flow through the duct should not be less than 16, The inspector noted that
the procedure only required 12 readings. The licensee issued another ONE form to
address both the adequacy of the evaluation and why only 12 readings were required.
c. ConclusioD1
The inspector concluded that, while the evaluation was conducted by qualified
personnel who thoroughly reviewed the specific issue of exceeding the design basis, it
did not encompass all potential weaknesses in testing the pressurization units. The
licensee initiated additional ONE forms to address the additional questions raised by
- the inspector.
. .- - .__ - .
.
?
15-
E2 Engineering Support of Facilities and Equipment
.
E2.1 Qual Train comoonent Coolina Water System Outmoe
a. Insoection Scoon (37551) ,
,
The inspector reviewed 10 CFR 50.59 Evaluation SE 97-81 which concerned a dual
train component cooling water system outage cjuring the Unit 2 refueling outage
following the reactor core offload.
3
b. Obsgyations and Findinas
Prior to the Unit 2 refueling outage, the inspector questioned the nuclear steam supply
system work window manager regarding the safety evaluation prepared for conducting a
dual train outage. The work window manager was not aware of any evaluation. Within the
next few days, the licensee informed the inspector that D. C. Cook had made a 10 CFR
50.72(b) notification for being outside design basis for conducting a dual train component
cooling water system outage. The licensee informed the inspector that they had pulled
their planned dual train outage out of the schedule until they had a chance to complete
their safety evaluation. ,
The inspector reviewed the licensee's safety evaluation. The licensee concluded that
the planned dual train component cooling water system outage with the reactor core
fully offloaded did not represent an unreviewed safety question. The inspector found
that the licensee's evaluation was thorough and technically correct.
c
E8 Miscellaneous Engineering issues (92902)
EB1 (Closed) Insoection Followuo item 50-445(446)/9718-02: seismic qualification of
integrated leak rate test rig. This item was left open to review the licensee's evaluation
of the connection. In ONE Form 97-1103, the licensee concluded that, during a design
basis earthquake, the rig could potentially have an undesirable interaction with one
source range nuclear instrument cable. Although the licensee concluded that a
i
damaged source range nuclear instrument cable would not have prevented the safe
shutdown of the reactor, the licensee determined that the connection should be
.
modified to assure conservatism for future operations. The inspector concluded that
the licensee's evaluation was thorough and that the proposed modification was
conservative.
l_V. Plant Sunnort -
R1 Radiological Protection and Chemistry Controls
The inspectors observed good radiological practices being implemented by all plant
personnel. Workers were familiar with their radiological work permit requirements. On
>
,_
.. _ . _ _
.
.
16
one occasion, the inspectors observed a crane operator swinging potentially
contaminated reactor vessel studs outside of the controlled area boundary to avoid
hazards to personnel inside the area. After the inspector pointed out that the studs
had to be surveyed p*. t to passing outside of the boundary, the crane operator
ensured that the studs remained inside the boundary during the movement.
R4 Staff Knowledge and Performance
R4.1 Locked Hiah Radiation Area Key Control
a. laspection Scooe (71750)
On November 8, the licensee discovered that positive control of a locked high radiation
area key had not been maintained. After contacting the individual who signed for the
key, the licensee located the key in a bag at the steam generator platform. The
inspector reviewed the circumstances and corrective actions surrounding the control of
the locked high radiation area key.
b. QbigIYatipas and Findinas
Technical Specification 6.12.2, *High Radiation Area," requires, in part, that areas
accessible to individuals with radiation levels greater than 1000 mrem /h at 30 cm shall
be provided with locked doors to prevent unauthorized entry and that the keys shall be
maintained under the administrative control of the shift manager on duty and/or
radiation protection supervision.
Radiation Protection Instruction RPI 110, * Radiation Protection Shift Activities,'
Revision 6, provided administrative instructions on the control of keys to locked high
radiation areas. Section 6.5.1.4 required that radiation area keys only be issued to the
security shift lieutenar't, the shift manager, or a radiation protection quahfied individual.
Section 6.5.1.3 required that the individual, to whom the key is issued, maintain
constant physical possession of the key.
Contrary to the requirements of RPI 110, a radiation protection technician to whom the
key was issued failed to maintain constant physical possession of the key when the key
was given to a contractor to unlock a cover on a steam generator manway. When the
oncoming crew conducted a key inventory, they discovered that the key was missing.
When contacted, the technician to whom the key was issued informed the lead
technician that he had directed that the key be left in a bag on the steam generator
platform, where it was subsequently found.
The inspector found that the area where the key was located was controlled by
radiation protection and that the key was not used by an indnndual to gain unauthorized
access to a locked high-radiation area. As a corrective measure, the radiation
protection manager reiterated the requirements of the procedure and his expectations
- __ _
.
.
17
that the procedures be followed. Training was conducted with all radiation protection -
personnel.
c. Conclusl0D1
Failure of the radiation protection technician to maintain constant physical control of the
radiation area key was a violation of Technical Specification 6.12.2. This nonrepetitive,
licensee-identified, and corrected violation is being treated as a noncited violation
consistent with Section Vll.B.1 of the NRC Enforcement Policy (50 445(446)/9720-M).
81- Co :due* of Security and Safeguards Activities
Throughout the inspection period, the inspectors observed alert security officers
appropriately manning their assigned posts. On one moming, the inspectors noted that
fog had significantly reduced visibility. The inspectors verified that security had
appropriately responded as required by the security plan.
V. Management Meetinas
X1 Exit Meeting Summary
The inspectors presented the results of the inspection to members of licensee manaqement at
the conclusion of the inspection on November 25. The licensee stated that they had not yet
completed their investigation into the emergency core cooling system sump gap issue. The
inspectors asked the licensee whether any materials examined during the inspection should be
considered proprietary No proprietary information was identified.
..
-.. -- . .. . - . . - . -. ..
.
!
- ;
ATTACHMENT ;
SUPPLEMENTAL INFORMATION ,
PARTIAL LIST OF PER?.ONS CONTACTED
l
Licensee
M. R. Blevins, Plant Manager
J. R. Curtis, Radiation Protection Manager
D. L. Davis, Nuclear Overview Manager .
J. J. Kelley, Vice President, Nuclear Engineering and Support
M. L. Lucas, Maintenance Manager .
D. R. Moore, Operations Manager
C. L. Terry, Group Vice President, Nuclear Production
.
INSPECTION PROCEDURES USED
37551 Onsite Engineering
61726 Surveillance Observations
'
62707 Maintenance Observations t
71707 Plant Operations
71750 Plant Support Activities
92901 Followup' Plant Operations
92902 Followup Maintenance
92903 Followup Engineering
93702 Prompt Onsite Response To Events At Operating Power Reactors
P
ITEMS OPENED AND CLOSED
Opened
50-446/9720-01 VIO Inadequate procedure resulted in both power-operated
relief valves opening who pressure was allowed to
remain above the low-temrature overpressure
protection system limit- Mtion 04.1).
50-446/9720 02 VIO Conducting core alterations with the personnel airlock
doors incapable of being closed (Section 04.2).
.. - . . . .. . . . . . . - .
_ - _ . _ _ _ _ _ _ _ __ . _ _ _ _ . _ _._ __._ .
,
'
.
2
50-446/9720-03 NCV Failure to establish communications prior to placing an
underwater light in the reactor vessel (Section 04.3).
50-446/9720-04 VIO Failure to promptly identify and correct
16 nonconformances in the ECCS sumps including eight
previously identified structural gaps (Section M1.3).
50-445(446)/9720-05 NCV Failure to follow procedure when mod,fying Fisher Type
667 valve actuator bushings without proper
documentation or review (Section M8.1).
50-446/9720-06 NCV Failure of the radiation protection technician to maintain
constant physical control of the radiation area key was a
violation (Section R4.1).
Closed
-50-446/9720-03 NCV Failure to establish communications prior to placing an
underwater light in the reactor vessel (Section 04.3).
50-445(446)/9720-05 NCV Failure to follow procedure when modifying Fisher Type
667 valve actuator bushings withost proper
' documentation or review (Section M8.1).
50-446/9720-06 NCV Failure of the radiation protection technician to maintain
constant physical control of the radiation area key was a
violation (Section R4.1).
50 445(446)/9706 01 VIO Failure to establish procedures to ensure that alllicensed
operators that have their licenses conditioned to wear
corrective lenses for the eye, always have available
appropriate lenses qualified for a self-contained breathing
apparatus (Section 08.1).
50-445(446)/9717 03 URI Review scope of accumulator bushing modification and
generic aspects of maintenance modifications
(Section M8.1).
c
'
,
50-445(446)/9718-02 IFl Review of seismic qualification of integrated leak rate test
rig (Section E2.1).
-