ML13312A713
| ML13312A713 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 08/24/1993 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML13312A711 | List: |
| References | |
| 50-206-93-19, 50-361-93-19, 50-362-93-19, NUDOCS 9309290179 | |
| Download: ML13312A713 (25) | |
See also: IR 05000206/1993019
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-206/93-19, 50-361/93-19, 50-362/93-19
Docket Nos.
50-206, 50-361, 50-362
License Nos.
Licensee:
Southern California Edison Company
Irvine Operations Center
23 Parker Street
Irvine, California 92718
Facility Name:
San Onofre Units 1, 2 and 3
Inspection At:
San Onofre, San Clemente, California
Inspection Conducted:
June 24 through July 28, 1993
Inspectors:
C. W. Caldwell, Senior Resident Inspector
J. J. Russell, Resident Inspector
-0. L. Solorio, Resident Inspector
C. M. Re an, NRR Intern
Approved By:
Wgne
.J. Won ,C ie
ign
Reactor Projects Se tion II
Inspecti onSumary
I Apc
i
on
on June
24 thrOuh
Jul 281 1993
(Report
Nos.
50-206/93_19.
019319
50-31
293a19
Areas
Insp
m:
Routine, announced, resident inspection of Units 1, 2 and 3
operations program including the following areas:
operational safety
verification, radiological protection, security, evaluation of plant trips and
events, bi-monthly surveillance activities, monthly maintenance activities
refueling activities, independent inspecti on, quality verification, design
changes, facility modifications, licensee self-assessment, fire protection
followup on items of noncompliance, corrective action programs, engineered
safety feature walkdown, maintenance program implementation, followup on items
of non compliance, licensee event report review, and followup of previously
identified items.
Inspection procedures 35702, 37700, 37701, 40500, 60705,
60710, 61726, 62700, 62703, 64704, 71500, 71707, 71710, 90712, 92700, 92701,
92702, 92720, and 93702 were covered.
Safety
Issues
Manag ient
ystem
(SIMSh- Itens:
None
9309290179 930826
PDR ADOCK 05000206
G
Resul ts:
General Conclusions and Specific Fidinls:
Strenpths:
Quality Assurance (QA)
surveillances on corrective action implementation
identified an inappropriate change to an abnormal operating instruction (AOl)
(Paragraph 9.a).
QA field observations continue to be a strength (Paragraph
9.b).
Weaknesses:
A weakness was identified concerning inadequate corrective actions for removal
of lagging from a main steam safety valve. In particular, the commitments
made in response to main steam safety valve inoperability in 1990, as
documented in a Licensee Event Report , were not implemented. In addition, a
root cause evaluation for the improper lagging removal from a Unit 2 main
steam safety valve in 1993 determined that the proposed corrective actions for
the 1990 event may not have been adequate even if they had been implemented.
Further, the NRC was concerned that the unlagged valve went unnoticed for
approximately four days (Paragraph 11.a).
A weakness was identified concerning inadequate control of changes to AOIs
(Paragraph 9.a).
The continuing issue associated with controleof sweld dfisler bmaterialrebyou
W
conractor personnel (Paragraph 9.b), with the issues described in previoous
inspection reports also related to contractor deficiencies, indicate that
additional management attention may be warranted in the control of
contractors.
Significant Safety Matters:
SummarY of Violations:
One violation of NRC requirements was identified within the scope of this
inspection for inadequate corrective actions related to the removal of lagging
from a main steam safety valve in Unit 2 on February 8, 1993 (Paragraph 11.a).
One non-cited violation of NRC requirements was identified for inadequate
control of Units 2 and 3 A0Is (Paragraph 9.a).
Open Items Summary:
During this report period, five new followup items were opened and 13 were
closed.
2
DETAILS
i
_Persons Contacted
Souhr
Clfri
Edson Co-many
H. Ray, S
enior Vice President, Power Systems
- R. Krieger, Vice President and Site Manager
R Rosenbium Vice President, Nuclear Engineering and Technical Support
JR Reilly, Manager, Nuclear Engineering & Construction
- B. Katz, Manager, Nuclear Oversight
K. Slagle, Deputy Station Manager
- R. Waldo, Operations Manager
- L. Cash, Maintenance Manager
- D. Breig, Manager, Station Technical
M. Short, Manager, Site Technical Services
M. Wharton, Manager, Nuclear Design Engineering
- P. Knapp, Manager, Health Physics
- W. Zintl, Manager, Emergency Preparedness
D. Herbst, Manager, Quality Assurance
C. Chiu, Manager, Quality Engineering
G . Moore, Plant Superintendent, Unit 1
V. Fisher, Plant Superintendent, Units 2/3
- G. Gibson, Supervisor$ Onsite Nuclear Licensing
. Reeder, manager, Nuclear Training
H. Newton, Manager, Site Support Services
- T. Rainsberry,
Plant Licensing Manager
- W. Marsh, Manager, Nuclear Regulatory Affairs
- T
n
Fee, Health Physics Assistant Manager
- E. Gatto, Health Physics Training Supervisor
- A. Thiel Manager, Electrical Systems Engineering
- R. Giroux, Engineer
Onsite Nuclear
icensing
- J
Darling, Engineer, Onsite Nuclear icening
- T. Frey, Engineerin g Aide, Onsite Nuclear Licensing
- Denotes those attending the exit meeting on August 2, 1993.
The inspectors also contacted other licensee employees during the course
of the inspection, including operations shift superintendents, control
room supervisors, control room operators, QA and O engineers,
compliance engineers, maintenance craftsmen, and health physics
engineers and technicians.
2.
Plant
Status
nt I
The Unit was permanently shutdown on November 30,
1992.
Primary and
secondary systems remained in a "SAFSTOR 1 condition throughout the
inspection report period.
Unit 2
The Unit began the inspection report period with all fuel offloaded to
the Unit 2 spent fuel pool for the Cycle VII refueling outage.
The ten
year reactor vessel inservice inspection was completed on July 12, 1993.
Core reload was completed July 18, 1993. The Unit was in Mode 5 at the
end of the inspection report period.
Unit 3
The Unit began the inspection report period at 100% power.
The Unit
experienced an automatic reactor trip and auxiliary feedwater (AFW)
injection on July 5, 1993, due to a main turbine trip. A gland sealing
steam spill valve failed open causing a loss of gland sealing steam and
a resultant loss of main condenser vacuum. This loss of vacuum caused
the main turbine trip. All safety systems functioned normally.
The
Unit was returned to 100% power on July 7, 1993.
On July 17, 1993, power was reduced to 80% for heat treatment of the
On July 18, 1993, the Unit resumed full power
operation and continued at 100% power for the remainder of the
inspection report period.
3.
Operational SafetY Verification (62700,
71707)
The inspectors performed several plant tours and verified the operabi
lity of selected emergency systems, reviewed the tag out-log and
verified proper return to service of affected components. Particular
attention was given to housekeeping, examination for potential fire
hazards, fluid leaks, excessive vibration, and verification that
maintenance requests had been initiated for equipment in need of
maintenance.
The inspectors also observed selected activities by
licensee radiological protection and security personnel to confirm
proper implementation of and conformance with facility policies and
procedures in these areas..
a.
Units 2 and 3 Seismic Observations (62700, 71707)
During this inspection period the inspector observed ten instances
in which control of equipment in safety-related areas was not in
accordance with the licensee's program as outlined in station
procedure S0123-1-20, "Seismic Controls -
Seismic Controls During
Maintenance, Testing and Inspection."
Although these individual
observations were of low safety significance, the inspector was
concerned that the corrective actions for this problem may need to
be expanded to involve other organizations.
Control of components in safety-related areas was previously
identified in previous NRC Inspection Report 50-206/93-11.
Corrective actions taken in response to this identificati 'on were
to refamiliarize station and contract maintenance personnel with
the requirements of seismic procedures.
However, the inspector
5
2
considered that many of the instances observed during this
inspection period indicated that personnel outside the maintenance
organizations may also need to be made aware of these
requirements.
In conclusion, the inspector considered that this
issue still warrants management attention.
During the exit meeting the Maintenance Manager indicated that in
selected areas of the maintenance organization a re-trainling
program for 50123-1-1.20 would be initiated.
The Vice President,
Nuclear Generation, acknowledged that further management attention
was required and that a plan was being implemented to address the
seismic restraint issue. Additionally, the Maintenance Manager
indicated that efforts undertaken as a result of findings during
the previous inspection period had resulted in improvements within
the maintenance organizations. The inspectors will review the
effectiveness of these actions in future inspections.
b.
Unit 2 Reactor Coolant Sstem Drain Down
to
idlooJ (71707)
On July 23,
1993, the inspector observed the Unit 2 reactor
coolant system (CS) draindown to approximately 17 inches above
the bottom of the RCS hot leg, in accordance with operating
instruction S023-3-1.8, "Draining The Reactor Coolant System."
The drain down was observed from both the control room and the
containment spray pump room (used to drain down the RCS).
The
drain down was conducted in accordance with proceduresand in a
controlled and professional manner.
No deficiencies were
identified.
No violations or deviations were identified.
4.
Evaluation of
Plant
Trips
andi Events (93702)
a.
Partial Loss of Ann unciators
-
Units
2 and
3
On July 4, 1993, annunciator ground alarms activated on both Units
and on the common boards in the control room.
At this time Unit 2
was defueled and Unit 3 was in Mode 1. The operators then noted
abnormal annunciator operation for annunciators that indicated the
status of electrical systems and plant services for both Units and
reactor services for Unit 3. The-following annunciator boards
were affected: 3UA0063A,B,C; 2/3UA0063D,E; 2UA0063A,B,C;
2/3UAO61AB; and 3U0A56B. This abnormal operation included, at
various times, spurious alarms, alarms that would not reset,
improper audible indication, and audible indication that would not
reset.
The operators entered S023-13-22,
"Loss of Control Room
Annunciators," and increased monitoring of safety-related
parameters.
Maintenance personnel performed troubleshooting and
restored the annunciators to operable status on July 5, 1993.
Maintenance personnel replaced various circuit modules that
3
controlled power to groups of annunciators (AN 1128 modules) and
circuit modules that controlled individual annunciator function
(AN 1123 and AN 1127 modules) in order to correct the problem.
The licensee was evaluating the root cause for the failure of
these circuit modules and had not completed this evaluation at the
end of this report period.
The inspector will review the results
of this root cause analysis as inspector followup item (IFI 50
361/93-19-01).
b.
internals i
nd in Reactor Vessel -
mnit
2
On June 30, 1993, the licensee found two safety injection cold leg
nozzle thermal sleeves in the area of the Unit 2 reactor vessel
flow skirt.
This condition was documented in nonconformance
report (NCR) 93060175. The sleeves were subs Iequently removed.
The licensee was performing a ten year inservice inspection (ISI)
of the Unit 2 reactor vessel at the time. The reactor vessel
internals, including the core support barrel, had been removed in
preparation for the ISI. The licensee documented in the NCR that
there was no operability impact to reactor internal components
which may have been contacted as the sleeves moved from the cold
leg nozzles to the flow skirt. Additionally, the licensee
concluded that the two remaining sleeves would not impact
operability of reactor vessel internals should they become
dislodged.
On July 13,
1993, the licensee found a metallic object lodged
between the Unit 2 reactor vessel and the vessel flow skirt.
The
licensee was using an ultrasonic probe to inspect the vessel when
the metallic object was noted.
Based on visual observations, the
licensee concluded that the object was a steam generator tube
plug.
The licensee concluded that this was one of two tube plugs
that had been discovered missing from their installed tube
locations during a Unit 2 outage in 1988.
The plugs were
Combustion Engineering mechanical tube plugs fabricated from
Inconel 690, and were five inches long with a nominal outside
diameter of 0.650 inches.
The licensee attemptea to dislodge the tube plug using remote
mechanical equipment, but was unsuccessful.
It appeared that the
plug was firmly lodged in its position between the reactor vessel
and the core-flow distribution skirt.
The licensee performed
a
safety analysis when the plugs were first discovered missing in
1988.
On July 13, 1993, a conference call was held with NRC
Region V management and licensee management concerning the
advisability of leaving the plug in place.
The inspector reviewed the safety analysis which had been
submitted to the NRC in 1988.
The inspector concluded that the
safety analysis was adequate in that it demonstrated minimal
safety significance in leaving the plug in place.
The inspector
concluded that the analysis adequately addressed any possible
0
4
damage to the RCS, the fuel, or interconnected systems should the
plug become dislodged from its current position during power
operation.
Based on the conference call and the safety analysis
mentioned above the inspector had no more concerns in this area.
On July 14,
1993, the Unit 2 core barrel was reinstalled with the
plug left lodged as described above.
No violations or deviations were identified.
5.
Bi-MonthlY Surveillance Activities (61726)
During this report period, the inspectors observed or conducted
inspection of the following surveillance activities:
a.
Observation
of Routine Surveillance Activities (Unit
2
S023-II-9.207,
"Bently Nevada Speed Sensor Model 300 HA
and Model TD 80 Tach Driver/Pulse
Transmi tter Cal i brati on."
S023-II-9.501,
"Surveillance Requirement Reactor Coolant
Pump Shaft Speed Sensor to Core Protection
Calculator Calibration."
5023-3-3.12 ISS2, "Integrated System Refueling Test."
b.
Observation of Routine Surveillance Activities (Unit 31
S023-II-9.2071
"Bently Nevada Speed Sensor Model 300 HA
and Model TD 80 Tach Driver/Pulse
Transmitter Calibration."
S023-II-9.501,
"Surveillance Requirement Reactor Coolant
Pump Shaft Speed Sensor to Core Protection
Calculator Calibration."
No violations or deviations were identified.
6.
Monthly Maintenance Activities (62703)
During this report period, the inspectors observed or conducted
inspection of the following maintenance activities:
a.
Observation of Routine Maintenance Activities (Unit 2)
MO93030993001,
"Installation of Seismic Braces to Unit 2
Class 1E Transformer 2B04X."
M093071352000,
"Installation of Seismic Braces to Unit 2
Class 1E Transformer 2B06X."
5
M09307102 7000,
"Flush Water From Unit 2 Emergency Diesel
Generator 2G002 Oil System."
M093031141 000,
"Handwheel is Missing and The Declutch
Lever is Loose,
CCW Valve 2HV6552."
MO921101 55000,
"Disassemble Reactor, Perform Fuel
Movement Activities, and Reassemble the
Reactor."
b.
Observation of Routine Maintenance Activities (Unit 3)
M092092743 000,
"Re-align Cold Leg Temperature Indicator
No violations or deviations were identified.
7. Engineered Safety
eature System Walkdown - Unit 3 (71710)
The inspector reviewed Auxiliary Feedwater P&IDs against station
operating procedures S023-2-4, "Auxiliary Feedwater System
Operation," and S023-0-17, "Locking of Safety Related Critical
Valves and Breakers."
The inspector also walked down portions of
the system. Inspection activities were ongoing at the end of the
inspection period.
No violations or deviations were identified.
8.
Plant Modification
and Refueling Activities (37700,
37701, 60705,
60710)
a.
Unit 2 Core Reload (60710)
The inspector observed portions of the Unit 2, Cycle VII core
reload activities from the control room and from the reactor
cavity. The inspector concluded that, with the exception
discussed below, core reload activities were conducted in a
controlled and deliberate manner, and that personnel were
cognizant of their duties and responsibilities.
On July 14, 1993, the inspector observed a reactor operator (RD)
performing the duties of the 1/M monitor in accordance with S023
X-7, "Nuclear Fuel Movement for Refueling Cycles."
The inspector
noted that although the RO monitored the 1/M chart recorder, the
RO did not notify the control room engineer (ORE) that the 1/M
chart recorder was trending appropriately (not trending in a
nonconservative manner to ensure there were no criticality
excursions) before the fuel assembly was ungrappled in the core.
The inspector subsequently verified that the CRE had verified that
the 1M chart recorder trended in an appropriate manner before he
notified the refueling machine operator to ungrapple the fuel
assembly in its designated core reload position.
The inspector
6
noted that procedure S023-X-7, also specified the CRE to monitor
the 1/M chart recorder. Thus, there was no safety significance
associated with this incident.
The inspector determined that the reason theul/M monitor did not
inform the CRE before the fuel assembly was ungrappled was because
he had not reviewed the section in S023-X-7 outlining the duties
of the 1/M monitor prior to assuming the position. Although there
was no safety consequence of this observation, the inspector noted
that it was an Operations management expectation that operators be
sufficiently familiar with a procedure such that they can perform
in accordance with the procedure.
The inspector discussed this observation with
a
Operations
management who indicated that as a result improvements would be
made in the training ROs and refueling engineers receive on S023
X-7. Additionally, the licensee indicated that a sign-off step
would be added to S023-X-7 to assure that ROs review the
requirements for the position of the 1/M monitor prior to assuming
the position. The inspector considered these actions adequate.
b.
Design Changes and Modifications (37700, 37701)
The inspector reviewed portions of the following design changes.
These Design Change Packages (DCPs)
were not submitted to the NRC
for approval prior to implementation, as allowed in 10 CFR Part
50.59(b):
o
DCP 2-6605.08,
"Control Room Human Factors
Modifications
0
DCP 2-6827.00,
"Primary Plant Protection System
Circuit Test and Engineered Safety
Features Alarm Modifications"
o
DCP 2-6863.00,
"Shutdown Cooling and Containment
Spray Crossconnect"
o
DCP 2-6974.00,
"Replace 1000/1500 KVA Transformers"
0
DCP 2-6863.01,
"Pressurizer Vent"
The inspector verified that the portions of these DCPs reviewed
were in accordance with the licensee's Technical Specifications
(TS), that the DCPs were controlled by adequate procedures, and
that the DCPs were properly tested before being declared operable.
The inspector verified that procedures had been changed as
necessary and that operators had received adequate training on the
DCPs. The inspector verified that appropriate changes had been
made, or were planned, to applicable drawings, documents, and the
licensee's Updated Final Safety Analysis report. The inspector
walked down portions of these design changes as they were being
7
implemented in Unit 2. The inspector verified that the licensee
planned on reporting these design changes to the NRC as required
in 10 CFR 50.59(b).
Overall, the inspector concluded that these
design changes were accomplished adequately, with one exception.
This exception involved aspects of DCP 2-6974.00 which will be
reviewed in a future inspection as described below. The inspector
also had one minor concern with the training provided for DCP 2
6863.00 as described below.
DCP 2-6974.00. "Replace 1000/1500 KVA Transformers'
This modification controlled the replacement of fourteen 1500 KVA
and fourteen 1000KVA transformers in Units 2 and 3. The licensee
began this replacement with the Class-1E transformers 2BO4X and
286X that provided vital 480 VAC power to Unit 2. Those two
transformers were initially installed, declared operable, and
energized without vendor recommended seismic supports. The
replaced 2BO4X transformer was energized on July 16, 1993,
and the
replaced 2B06X transformer was energized on June 23, 1993. On
July 19, 1993, the licensee discovered that these seismic supports
were not in place, during an unrelated inspectionaand declared
both transformers inoperable.
On July 19,
1993, and July 20,
1993, the licensee installed the seismic supports to these
transformers, declared the transformers operable, and reenergized
them.
The licensee was conducting an analysis to determine the
necessity of these supports and was conducting an investigation
into why they were not installed originally.
These activities
were ongoing at the end of this inspection report period.
The
inspector will review the results of the analysis and the
investigation as unresolved item (URI 50-361/93-19-02).
DCP 2-6863.00, "Shutdown Cooling and Containment
Spray
Crossconnect'
This modification involved a change that connected the containment
spray and spent fuel pool cooling systems and allows the licensee
to use the containment spray (CS) pumps to provide SFP cooling and
to provide shutdown cooling (SC) for the RCS.
The inspector
noted that training had been provided to the licensed Operators by
the licensee'
training staff during the months of March and
April, 1993. The inspector also noted that the two principal
functions of this design change, using CS pumps to provide SFP
cooling and SDC, were used during the Unit 2 Cycle VII refueling
outage. The design change was completed during this outage. The
inspector interviewed licensed Senior Reactor Operators .(SROs) and
ROs who were actively involved in using the CS pumps to provide
The inspector received comments that the
training could be improved.
The inspector noted that pre
evolution briefs had been conducted which enabled the operators to
operate Unit 2 safely, and that no mis-operations of the controls
resulted.
The inspector contacted licensee training staff and
learned that further training was scheduled for the month of
- II
8
August 1993. The inspector conclsuded that this additionaltI
training was appropriate, but was concerned that complete training
had not been provided to the operators prior to declaring the
design change operable.
The inspector will monitor this
additional training during the course of normal inspection
activities.
This was considered of minor safety significance
since some training had been provided Iadequate pre-evolution
briefs were conducted, and the operators did not mis-operate the
controls.
In summary, the inspector concluded that the portions of the DCPs
inspected were adequate with the exception of DCP 2-6974.00 which will
be further reviewed.
No violations or deviations were identified.
9.
Independent Inpe2tion (35702,
40500, 92720)
a.
eactor CoolantPm
Abnormal
Operatina Insrucion_
age (35702,
40500, 92720)
In January 1993, the licensee's Quality Assurance (QA)
organization identified that AON
o023-13-6,
"Reactor Coolant Pump
(RCP) Seal Failure," Temporary Change Notice (TCN)
o -
(issued in
July 1991),
was inappropriately changed toallow operators to
institute an orderly plant shutdown following a loss of controlled
bleedoff (CBO) flow to the RCP seals.
Specifically, QA personnel
found that there was no documented basis for changing the AOl
The information used to provide the justification for changing the
AOI, was a vendor pump test which documented that the RCPs could
run without component cooling water cooling to the CBO flow.
However, Station Technical personnel misinterpreted the vendor
test and concluded that the RCPs could run without 080 flow
(rather than without CCW cooling).
Immediately after this
discovery the AOI was corrected to require a reactor trip upon
loss of CBO flow. The inspector considered that this observation
by the licensee's QA organization was an example of a well-planned
and well-performed QA surveillance.
The root cause for the inappropriate change to the A01 was
identified to be the failure of an engineering supervisor to
independently verify the accuracy of information provided to the
operations department.
Corrective actions taken included the
development of formal requirements for transmitting information
from Station Technical to Operations. The inspector considered
the licensee's corrective actions adequate.
The inspector noted that during the time TCN 0-7 was in effect
there were no instances where operators used S023-13 6 to
institute an orderly plant shutdown as a result of losing 080 flow
to the RCP seals, therefore there was no safety significance of
the inappropriate TCN.
9
The inspector considered that the TCN 0-7 to S023-13-6 was an
example of inadequate control of a procedural change in that there
was no independent verification of information used to issue a TCN
against the procedure. However, this violation is not being cited
since it was licensee identified, appropriate actions were taken
as a result of the inspector's concerns, there was no safety
significance, and the requirements of Section V.B of the
Enforcement Policy were satisfied, non-cited violation (NCV 50
361/93-19-03).
b.
Welding Filler Material Control (92720)
On July 5, 1993, the site QA organization found uncontrolled
welding filler material during a walk down of the Unit 2 Auxiliary
Feedwater pump turbine work. The material was issued to a
contract welder who had not attended SCE welder training, but had
been provided reading material by his employer which discussed
filler material control.
The inspector noted that this was the
third instance in which QA found uncontrolled welding filler
material during the Unit 2 Cycle VII outage (two involved
contractor employees and one involved SCE personnel).
The
inspector will review the licensee's corrective actions in a
future inspection.
The inspector noted that these observations were examples of an
aggressive QA organization. However, the inspector was concerned
with the number of recent issues involving weaknesses in the
control of contractors.
Specifically, a large number of seismic
concerns were attributed to contractors (identified in NRC
Inspection Report 50-206/93-11),
and contractor attention-to
detail issues (involving the identification of degraded
radiological control barriers, improper placement of a self
reading dosimeter, and inadvertent damage to equipment) were
described in NRC Inspection Report 50-206/93-09, Paragraph 3.b.
Therefore, the inspector concluded that control of contractors,
particularly-during outages, appeared to warrant additional
management attention.
C.
Status of Units 2 and 3 When Defueled (92720)
The inspector reviewed licensee actions for core reload of Unit 2
on July 14, 1993. All of the fuel in the core had been offloaded
to the Unit 2 SFP earlier in the outage. When the licensee was
making preparations to commence the core reload, the inspector
observed that the Control Room Emergency Air Cleanup System
(CREACUS)
was not fully operational.
This was a Limiting
Condition for Operation (LCO) of Unit 2 while in Mode 6.
The
licensee and inspector noted that the Mode status of Unit 2, as
relates to Technical Specifications (TS)
was not well defined with
all fuel removed from the reactor vessel.
When the licensee was ready to commence core reload of Unit 2, the
10
Unit was in a TS Action statement for CREACUS (TS 3.7.5) due to
electrical work being done on one train of CREACUS.
With Unit 3
in Mode 1, the licensee was complying with the applicable TS
ACTION, to restore the inoperable train of CREACUS to operable
status within 7 days or place Unit 3 in Hot Standby.
The licensee interpreted the Unit 2 status as not in Mode 6 for TS
purposes, except for TS 3.7.5. The inspector observed that this
interpretation was stated in a special order issued by the Vice
President, Nuclear Generation,
onl July 14,
1993, to the Operations
department. The inspector also observed that the licensee
commenced core reload with one train of CREACUS inoperable. The
inspector noted that if the Unit was not in Mode 6 then this could
have been considered a Mode change to Mode 6 when core reload was
commenced. The inspector noted that this Mode change would have
been into a Mode for which the LCO for TS 3.7.5 was n
ot met, which
would have been contrary to TS 3.0.4.
The inspector noted that if
Unit 2 had not offloaded the fuel assemblies, the applicable
ACTION would have remained unchanged .
Unit 3 would still have had
to shut down in 7 days regardless of Unit 2 status due to the
wording of this particular TS.
The inspector considered the safety significance of this issue to
be low, but noted that this issue highlighted the problem with TS
which do not specifically recognize defueled conditions. The
Region V staff had discussions with NRR personnel and requested
0
that NRR evaluate the Mode status of the unit when the reactor is
defueled.
The inspectors will assess the licensee's actions in
this instance upon receipt of NRR's evaluation as inspector
followup item (IFI 50-361/93-19-04).
d.
Balance of Plant Inspection - Unit 2 (71500)
During the Cycle VII refueling outage, the inspector conducted
walkdowns of the Unit 2 turbine building .
The inspector observed
activities associated with the turbine overhaul, main feedwater
pumps, and the condenser., The inspector identified no
deficiencies during these walkdowns.
No violations or deviations were identified.
10.
Review of Licensee Event Reports (90712, 92700)
Through direct observations, discussion with licensee personnel, or
review of the records, the following Licensee Event Reports (LERs)
were
closed by onsite review:
Unit 2
93-02, Revision 0,
125 VDC Battery Chargers 2B1 and 2B2 Inoperable
Due To Incorrect 10 CFR Part 21 Evaluation."
0
11
This item indicated that on February 25, 1993, the licensee determined
that battery chargers 2B1 and 2B2 were inoperable following replacement
of the reactor balance circuit cards.
This LER was reviewed previously
by the inspector and the results were documented in. NRC Inspection
Report 50-206/93-09. In that report, the inspector indicated that the
item would remain open since several corrective actions had not been
completed. In particular, the maintenance procedure governing battery
testing, 5023-l-9.14, "Battery Charger Inspection, Cleaning and
Testing," had not been revised to include post-installation verification
and adjustment of current limiter settings.
In addition, the original
10 CFR Part 21 report from the vendor was to be reevaluated for
additional corrective actions and procedure enhancements as deemed
appropriate.
The licensee has completed their reevaluation of the 10 CFR Part 21
report from the vendor, C&D Batteries. The licensee's reassessment
resulted in several actions. These actions included a revision to the
controlling procedures to require recording the "as-found" current limit
setting prior to making the setpoint adjustment.
If the "as-found"
setting should be found less than the TS requirement, then an NCR would
be generated and the appropriate personnel would be notified.
The
licensee also indicated that they would incorporate the new calibration
information received from the vendor into the appropriate maintenance
procedure for current limit setpoint adjustment after it is received
from the vendor. The inspector considered that the licensee's actions
both proposed and implemented were appropriate. This item is closed.
No violations or deviations were identified.
Follow-Up of Previously Identified
Items (64704, 92701)
a.
(Closed)
Unresolved
Item
(50-361/93-02-03).
"Cnfigiration
Control
Issues
In Units 2 and 3."
This item discussed several problems involving improper
configuration control that were identified by the licensee and by
the NRC as follows:
1)
On February 8, 1993, Station Technical personnel identified
that the lagging for Unit 2 main steam
safety valve (MSSV)
2PSV8411 had been removed.
With the lagging removed, the
setpoint was indeterminate and the valve was declared
The lagging had apparently been removed by
Maintenance personnel four days prior. For followup action,
the lagging was replaced, the valve was declared operable,
and NCR 93020012 was issued. As a result of this problem,
the inspector was concerned that work activities on the
valve were not adequate to ensure that configuration control
was maintained, and that it took approximately four days to
identify the discrepancy.
Since this item was identified, the licensee issued LER
12
361/93-001 to report the problem to the NRC and performed a
root cause evaluation of the event.
The evaluation report,
ROE 93-005, was issued on April 13 , 1993, which identified
that the root cause was due to insufficient barriers in the
work planning process to identify that removal of insulation
from the MSSVs would render them inoperable.
The RCE also
indicated that there were several contributing causes
including lack of effective corrective actions from a prior
event involving the MSSVs.
In July 1990, the licensee identified that MSSV setpoints
changed depending if the lagging was on or off. This was
due to changes in the temperature profile of the valve which
affected the spring constant and the lift
setpoint of the
valve.
The licensee issued LER 361/90-008 which indicated that
several corrective actions would be implemented.
One action
in particular was to revise the general maintenance order
(MO)
to require an engineering review prior to removal of
any lagging installed on the MSSVs.
The licensee also
indicated that these Planned actions would ensure that
operability of the MSSVs was properly addressed prior to the
removal of lagging.
However, upon review of the corrective actions implemented,
the inspector noted that the licensee did not revise the
general MO to include an engineering rEtview of the MSSVs.
Instead, the general MO was revised such that insulation
removal from the MSSVs required a separate MO.
In fact,
Engineering review of lagging removal on the MSSVs was not
addressed at all.
The inspector noted that the licensee attributed this
discrepancy to the fact that in 1990, a number of personnel
were responsible for closure actions to regulatory
commitments.
In this specific case, the person who closed
the item took a liberal interpretation of how the corrective
actions identified in the LER could be implemented.
In
addition, the inspector questioned whether the proposed
action to have an engineering review of MSSV lagging removal
would have prevented further problems.
Specifically, the
licensee's RCE noted that not all engineers were aware that
removal of lagging could change the valve setpoint.
After the February 1993 event, the licensee implemented or
proposed corrective actions to0 include, reinstalling the
lagging, installing signs at each MSSV warning about the
implications of lagging removal, and changing the program to
ensure that a warning is included in the computerized
maintenance management system to alert personnel that a MSSV
must be declared inoperable if the valve body insulation is
13
removed. The licensee believed that the changes to the
maintenance management system should prevent this from
reoccurring. The inspector considered that the licensee s
actions both proposed and implemented subsequent to the
February 1993 inoperable MSSV were adequate.
10 CFR Part 50, Appendix B, Criterion XVI, requires that for
significant conditions adverse to quality, measures shall
assure that the cause of the condition is determined and
that corrective actions are taken to preclude repetition.
However, the licensee's corrective actions for the July 1990
event involving inoperability of the Unit 3 MSSVs were not
adequate to prevent the inoperability of MSSV 2PSV8411 in
February 1993.
This inadequate corrective action is
identified as violation (VIO 50-361/93-19-05).
2)
This unresolved-item also identified that on February 1,
1993, the licensee found that the pressure instrument root
valves were open for both Unit 3 containment spray pumps.
This was in conflict with their required position.
The
licensee closed the valves and then performed a walkdown of
all similar root valves in both Units 2 and 3. During the
walkdown, a number of other valves were found open,
including instrument valves for a high pressure safety
injection pump in Unit 2 and eight root valves for the boric
acid makeup systems in Units 2 and 3.
The main concern with
the valve misalignment was that the tubing downstream of
these root valves was not seismically qualified.
As a
result, it was possible that there could be a diversion of
some safety injection flow after a seismic event.
As an immediate corrective action, the licensee restored all
the valves to their intended closed position. In addition,
the licensee performed an Operations Division Experience
Report (ODER) 3-93-06, to determine the cause of the event.
Although, the licensee could not determine exactly how the
valves became mispositioned, they considered that the valves
were not fully closed the last time they were operated to
support in-service testing (IST).
The licensee determined
that the root cause was inadequate interface among
organizations during the use of IST procedures.
The ODER
indicated that the common cause appeared to be the process
of operation by implication.
In particular, the ODER
pointed out that liberal interpretations of the procedures
may have been taken by making some assumptions on the part
of personnel that were incorrect.
For followup to the valve mispositioning occurrences, the
licensee initiated several additional corrective actions.
These included issuance of a policy statement reemphasizing
that valves, switches, and breakers cannot be operated
without a controlling document specifically stating to
- I
14
A
operate the component.
The licensee indicated that if steps
0
are not specifically identified, then a procedure revision
is required that would require an SRO review of the
operation to help ensure that the as-left condition matches
the system alignment requirements. In addition, the
licensee also evaluated the Station Technical Division1S
procedures that pertain to engineered safety feature (ESF)
pumps to determine if they comply with Operations procedure
requirements. Changes were recommended as necessary. The
inspector considered that the licensee's actions for this
problem were adequate.
The inspector considered that the
licensee's actions were approriate.
This portion of the
unresolved item is closed.
3)
This unresolved item also involved a number of errors that
were identified by the NRC on piping and instrument diagrams
(P&IDs)
41097A and 40197B, "Auxiliary Building Emergency
Chilled Water System Loop A." These errors included a
temperature instrument that was missing, root valves and
temperature instruments reversed on the PlD from their
installed configuration, and drain valves located in places
other than shown on the drawing. The inspector considered
that the most significant error-was a temperature instrument
(TI), 2TI987D, that was moved on the drawing during a recent
drawing change, DCN-3, in October 1992. The drawing change
resulted from a system walkdown in April 1992 to support a
0
system hydrotest. A
number of changes were recommended for
the drawing and were verified by a second individual. A
site problem report (SPR) was generated to initiate the
drawing change. However, the verifier incorrectly
identified that the TI was in the wrong place and modified
the SPR to get it relocated on the drawing.
The licensee assessed this problem in a Nuclear Engineering
and Design Organization (NEDO) Division
investigation
Report, DIR-NEDO-93-0 02.
The licensee determined that the
error with 2TI987D was one of only a few errors with drawing
changes. In this case, the verifier made the change and
introduced the error.
The error that was made was not
identified since there was no Quality Control check of the
recommended change that was made by the verifier. The
licensee also indicated that the current error rate of
drawing changes was less than three percent, which was
within NEDO expectations.
As corrective action, the licensee counseled the individual
who made the error, focusing on attention to detail and
self-checking techniques.
As additional corrective action,
the licensee indicated in the DIR that a procedural
requirement for a quality control check of any new
description of the as-built configuration would be made
prior to revising drawings to ensure that the new
15
description was correct.
The inspector considered that the
licensee's corrective actions were appropriate.
This
portion of the unresolved item is closed.
4)
This unresolved item also involved inaccurate drawings for
the Unit 2 salt water cooling (SWC)
system.
On December 30,
1992, prior to an IST on the Unit 2 SEC pump 2P112 seal
water supply piping valves, the Unit 2 Control Room
Supervisor (CRS)
discussed with the NRC inspector drawing
discrepancies on P&ID 40126A, "Component Cooling Water
System (Salt Water Pumps)."
In particular, the P&ID showed
wrong valve numbers for the seal water supply inlet rhpck
valve 048,' and ball valve 032 for SWC pump 2P113B.
The
drawing deficiencies were determined to be associated with
the valves as labeled on the drawing and not on plant
equipment tags. The CRS indicated that the previous
revision of the drawing was correct and that somehow the
errors were introduced in the latest revision of the drawing
at the time. The CRS also indicated that an SPR would be
initiated to correct the drawing discrepancy. However, on
February 10, 1993, the inspector noted that the control room
drawing had not been changed and found that the SPR
coordinator had not received a request to revise the P&ID.
As a result, the inspector was concerned that there could be
other uncorrected drawing errors.
As a followup to the inspectors concern, NEDO performed an
investigation, NEDO-93-001,
and found that the error was
introduced by a designer who was using the computer assisted
drafted (CAD) program called CATIA.
The problem resulted
when the copy function on CATIA was used to create a
configuration change from one train of SWC to the other.
The designer forgot to revise the valve tag numbers as
appropriate. In addition, a checker only reviewed the
revised portion of the drawing and did not check to see if
the original valves on the drawing had their valve tag
numbers updated.
This was also true for the design
supervisor, who did not detect the error.
The licensee performed an assessment of a number of drawing
changes that were made by the same individuals for a one
month period.
The licensee found that of the 2290 changes
that were made, there were only three minor typographical
errors.
An audit consisting of a review of a random sample
of 20 electrical drawings, consisting of approximately 3700
changes, was performed that found only six minor drafting
errors.
As a result of this evaluation, the licensee
concluded that there was a very small error rate for drawing
changes and that the ones identified were very minor in
nature with the exception of this example, which was
considered to be an isolated error.
As a followup to this problem, the licensee implemented a
16
-I
number of corrective actions including coaching of all
designers on the concept of "self-checking," revising the
procedure for design change notice incorporation and
checking to emphasize attention to detail and the concept of
self-checking, and periodic monitoring of the effectiveness
of self-checking process.
The inspector considered that the
licensee's actions were appropriate.
This portion of the
unresolved item is closed.
The inspector considered that the licensee's actions an
d
evaluations for the misaligned root valves, emergency chilled
water P&IDsf and the salt water cool ing system P&I problems were
appropriate.
The generic issue concerning configuration control
was addressed in NRC Inspection Report 50-206/93-11. In that
report, the inspector identified a violation with several examples
and four non-cited violations for failure to follow procedures.
Most of these procedural adherence problems resulted in
configuration control problems in the Units.
The inspector will
evaluate the licensee's actions on this matter by reviewing the
licensee's response to the Notice of Violation in NRC Inspection
Report 50-206/93-11.
b.
(Closed) Followup Item
50-3611913-0201)_ "Nonrotation of
Operators - Followup of Operator Li sLg Banch
Evaati on.
This item involved the rotation of licensed operators during
licensee-administered requalification examinations. The licensee
evaluated crews using two scenarios run on the plant-referenced
simulator.
The inspector noted that the licensee was not rotating
the positions held by the SROs so that an individual SRO would be
the CRS during one scenario and the Shift Superintendent (SS)
during the other scenario. The inspector was concerned that this
was a change in the methods previously used by the licensee, and
that this was less comprehensive than having the operators rotate
positions. The inspector requested NRC's Operator Licensing
Branch (OLB) provide an evaluation of this issue.
The inspector received OLB's evaluation.
The evaluation stated
"the NRC's expectation is that facility licensees train and
examine their operators in the same crew configurations with which
they normally operate the plant. As a result, crew.members should
rotate between positions in the manner identical to the facility's
rotation practices for both control room operation and crew
evaluations (as specified in the facility's requalification
program). However, it should also be noted that ES-t04, D.1.G (of
the "Examiner Standards", NUREG 1021, Rev.7) states that SROs must
be evaluated in at least one scenario in an SRO licensed crew
position to fulfill their license requirement."
The inspector concluded that the licensee was examining their
operators in the same crew configurations that they used to
operate the plant. The inspector concluded that the nonrotation
17
A
d.
of SROs observed was in accordance with NRC expectations.
This
item is closed.
C.
(Clo
)Folowu
I
Item (50-206/92-12-).
'Missed Iitenal
Commitment -
RE:
Evaluation Of Performing An E ualizin_ Charge On
Unit 1 Vital BatterY
umer
149 Volts.
This item identified that the licensee had apparently not
performed an evaluation of the conditions that led to the
performance of an equalizing charge on Unit 1 vital battery number
2 at 149 volts instead of the nominal 139 volts.
This was an
internal commitment made in the nonconformance report (NCR)
documenting the problem.
The inspector was concerned that the
licensee missed completing this evaluation even though it was a
factor in deciding that an NCV was appropriat e for the original
i ssue-(See NRC Inspection Report 50-206/90-28) .
Subsequent investigation determined that the licensee never
completed the root cause case study, nor was it tracked on the
licensee's regulatory commitment tracking system (RCTS). In
addition, the inspector was concerned the licensee's NCR program
did not include any provisions to track internal commitments made
in NCRs.
Thus, since there was nothing that linked completion of
an NCR to a specific commitment date, it was possible that actions
committed to in any NCR would not be completed in a timely manner
such as this one.
The licensee evaluated the inspector's concern and determined that
they had performed a review of the condition within two months of
the initiation of NCR 90080031.
The evaluation was completed and
the results were included in the logic of the disposition.
However,'because there were no provisions for tracking the due
date of this item, it was not obvious that the issue was resolved.
The licensee also performed an assessment of the tracking
capability of internal commitments and decided to make a software
change to provide capability to track forecast dates for closure
of NCR dispositions. The licensee had expected this to be
completed by January 31,
1993.
The inspector considered that the
licensee's actions, both proposed and implemented, should prevent
recurrence of this problem.
Therefore, this item is closed.
d.
(Closed)
Unresolved Item
( 362/93-11-01). "Control Of E
uipment
In A Seismic Exclusion
Zone
In Unit
3"
On June 23,
1993, the inspector observed that a contractor
tractor-trailer was parked very close to the seismic exclusion
zone (SEZ)
near Unit 3. The SEZ is used to store fire tanker
trucks.
The inspector observed that the tractor-trailer was
parked more than 15 feet from the tanker seismic restraints, as
required.
However,
the tractor-trailer appeared to be parked
within the "two times the height" distance requirement specified
on a nearby sign.
18
The inspector discussed this concern with the licensee who
assessed the situation further. In particular a roving fire
watch was tasked with determining if this was an isolated case or
if there was a more generic problem. The licensee determined that
there were two instances shortly after the June 23 observation in
which equipment exceeded the height limitation specified.
However, in neither case was the fifteen foot restriction
challenged.
For followup action to this concern, the licensee either
implemented or planned to imp lement the following actions:
o
A briefing was conducted with site Security personnel to
ensure that they understood the height limitations.
o
The licensee was assessing the need for a letter to all site
personnel describing the need to keep the SEZ free from
potential hazards.
o
A roving fire watch will be assigned to check that the SEZ
is not challenged during the early portions of the Unit 3
refueling outage.
a
New signage will be installed to better delineate management
expectations for storing equipment near the SEZ.
The inspector considered that the licensee's actions both planned
and implemented were adequate. This item is closed.
e.
(Closed)
nreolved
Item
(5 36193-O2-o2)
"ousekeepifln
Concerns
In
Units
2 and 3"
This item discussed several housekeeping problems that appeared to
cause potential fire or seismic hazards to safety-related
equipment.
These problems included inadequate control of carts in
the spent fuel pool buildings, items stored on top of the Unit 3
diesel generator fuel oil storage vault, and potential fire
hazards found in Units 2 and 3.
The inspector continued monitoring housekeeping conditions since
this problem was first identified.
Subsequent to these issues,
additional problems were noted. In NRC Inspection Report 93-11,
the NRC issued the licensee a Notice of Violation with several
examples and four non-cited violations for failure to follow
procedures.
Most of these procedural adherence problems resulted
in configuration control problems in the Units.
The inspector
will evaluate the licensee's actions on this matter by reviewing
the licensee's response to the Notice of Violation in NRC
Inspection Report 50-206/93-11.
This item is closed.
19
(Closed) Unresolved Item (50-361/93-05-06). 'DIR Issued To Address
Accuracy Of Future LERs."
LER 2-91-007, Revision 0, discussed the shutdown of Unit 2 due to
the loss of CBO flow (seal flow) to an RCP.
'The LER discussed the
licensee's corrective. actions which included changing the RCP AOI
to allow an orderly shutdown following loss of CBO flow to a RCP
(discussed in Paragraph 9.a of this inspection report), and that
Unit 2 RCPs had been reassembled using a special bolt preloading
technique.
During a corrective actions audit the above statements in the LER
were determined to be inaccurate by the licensee's QA group. QA
found that there was no basis for changing the RCP AOI to allow an
orderly plant shutdown, and that documentation of using the
special bolt preloading technique was not complete for two RCPs.
The inspector-noted that the RCPs were
areassembled during the Unit
2 Cycle VII outage using the special bolt preloading technique.
As a result, the licensee indicated that the LER would be revised.
Additionally, a DIR would be initiated to determine the. cause for
the inaccuracies identified by QA, addressing the inspector's
concerns with regard to the accuracy-of future submittal s.
The inspector reviewed the licensee's DIR and noted that the root
cause for the change to the RCP AOI was information provided from
a engineering supervisor to the LER writer which was not
independently verified. Corrective actions included the
development of formal guidance for transmitting information from
Station Technical to Operations which was incorporated into the
Station Technical System Engineer's Roles and Responsibilities
document. The inspector considered the licensee's actions
appropriate. This item is closed.
9.
(Closed) Followup Item (50-361/93-05-05).
"DIR Procedures
Lack
Provisions To Handle Interim CARs."
During a review of DIR report procedural requirements for Nuclear
Oversight, Station Technical, Operations, Maintenance, Health
Physics and Chemistry, the inspector noted that the various
divisions' procedures did not Include provisions for handling the
implementation of interim corrective actions. It was also noted
that time requirements for issuing reports, and extensions for
reports which could not be completed within the recommended time
frame, varied among the divisions. The licensee indicated that
they would initiate efforts to provide more formality in their DIR
procedures throughout the nuclear organization.
The inspector reviewed the nuclear organization procedure S0123
XV-50.39.1, PCN 0-2, "Preparation, Review, And Approval Of
Division Investigation Reports," and noted the licensee had
incorporated guidance to provide for handling the implementation
of interim corrective actions, timeliness of DIRs, and the methods
20
to approve extensions. Additionally
the licensee indicated that
individual division DIR procedures would also be changed to model
the guidance as written in S0123-XV-50.39.1. The inspector
considered the licensee s actions adequate. This item is closed.
Within this area inspected, one violation concerning inadequate
corrective action was identified.
12.
Followi
On tems Of Nncomliance (92702)
a.
(Closed)
Violation
(50-361/92-26-_01.
"Failure To Identify M&TE n
Trav el er s"
This violation identified that personnel were not consistently
implementing the requirement to complete a traveler when measuring
and test equipment (M&TE) was used in the plant. This was
contrary to the requirements established in Section 6.2.4 of
procedure So123-Ir.2, TCN 1-4, "Preparation And Responsibility
Of The M&TE Traveler."
The traveler was used to track the use of
the M&TE so that an evaluation of the uses could be performed
should the M&TE fail a subsequent calibration.
In the December 21,
1992, Reply to a Notice of Violation, the
licensee indicated that corrective actions including formal
training of M&TE users on proper usage and an audit of the M&TE
usage database were performed to identify and resolve all M&TE
usage discrepancies.
These actions were completed on December 1,
1992, when all M&TE uses associated with unreviewed calibration
failures due to deficiencies in the database were evaluated.
Subsequent to the evaluation, NCRs were initiated, evaluating the
potential impact of M&TE calibration failures on plant equipment.
In addition, the licensee instituted monthly monitoring of the
database and other recommendations of a Quality Action Team as a
result of program deficiencies that were identified.
Monthly
tracking of M&TE database was considered as a means for management
to monitor the accuracy of the M&TE traveler database. The
inspector reviewed a monthly monitoring report and considered that
the licensee's actions were appropriate. This item is closed.
b.
(Coe)
Voain
(50361922606). "Failure
To Perform
Proper
Evaluations
n Failed
M&TE."
This violation identified that the cognizant department
supervisors were not consistently documenting the specific reasons
that retests or recalibrations were not required if M&TE failed
its calibration as required in Sections 6.2.4 and 6.2.5 of
procedure S0123-I-1.5 , TCN 1-4, "Evaluation Of Calibrated Items
After M&TE Failure."
In their December 21, 1992, Reply to a Notice of Violation, the
licensee reviewed the six calibration failure notifications (CFN)
21
in question and revised them in accordance with the procedures.
This was accomplished by December 18, 1992 and the licensee
further determined that the original conclusions documented in the
original CFN evaluations had not changed.
In addition, in order to prevent reoccurrence, the licensee
provided periodic retraining for CFN evaluators and developed a
checklist to enhance the CFN evaluation process.
The inspector
reviewed the checklist and considered that the licensee's actions
were appropriate. Therefore, this item is closed.
C.
(Closed) Violation (50-361/92-26-07)
"QA Failure To Assure
Effective Corrective Actions
on
Failed M&TE."
This violation concerned a QA audit of the licensee's M&TE program
in June 1990.
The audit identified instances in which M&TE uses
were not being properly documented on M&TE travelers in accordance
with station procedure S0123-II-1.2, "Preparation And
Responsibility Of The M&TE Traveler."
However, the licensee did
not take adequate actions to correct the deficiencies found in the
1990 QA audit, as evidenced by the number of instances in 1991 in
which M&TE usage was not documented in travelers as required by
procedure.
In their December 21, 1992, Reply to a Notice of Violation, the
licensee stated that corrective actions included a comparison
between the two applicable databases to determine if the M&TE uses
associated with unreviewed calibration failures were evaluated and
corrected as required.
In August 1992, anew procedure for Maintenance division root
cause evaluations was issued.
Procedure S0123-I-1.42
"Maintenance Division Experience Reports (MDERs) u was issued to
require formal RCE training for personnel performing RCEs.
Formal
training in the conduct of root cause evaluations for Maintenance
personnel performing MDERs was conducted from June 1992 through
October 1992.
In addition to the corrective actions mentioned above, the
licensee evaluated* their sampling techniques used when performing
audits to determine why the problems noted by the inspector had
not been identified during the audit. Action was taken to provide
more balanced samples*. This was accomplished by providing
additional training to all QA Auditors based on the results of the
evaluation.
This item is closed.
d.
(Cl osed)
Vi ol ati on
(50-36192-3402).
Fail re
o Adhere
o REP
Reg ui
rements."I
On December 17, 1992, the inspector observed performance of a
quarterly 1ST test on Unit 2 high pressure safety injection pump
2P017.
The inspector noted that the engineer and his supervisor
22
crossed radiological boundaries by reaching into, and touching,
objects within a contaminated area. Neither individual was
wearing the required protective clothing. These actions were
contrary to station procedure S0123-VII-9.9,
TCN 11-3, "Radiation
Exposure Permit (REP) Program."
The licensee's corrective actions included a commitment to develop
specific guidance for engineers working with components within
contaminated areas.
REP 502, "Minor Maintenance Inservice Test
Support," was developed to allow system encineers authorization to
reach into contaminated areas while perforring pump ISTs.
The
inspector verified that all affected personnel had been trained on
REP 502. This item is closed.
13.
Exit Meeting
On August 2, 1993, an exit meeting was conducted with the licensee
representatives identified in Paragraph 1. The inspectors summarized
the inspection scope and findings as described in the Results section of
this report.
The licensee acknowledged the inspection findings and noted that
appropriate corrective actions would be implemented where warranted.
The licensee did not identify as proprietary any of the information
provided to or.reviewed by the inspectors during this inspection.
23