ML16342E115
| ML16342E115 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 06/03/1998 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342E113 | List: |
| References | |
| 50-275-98-08, 50-275-98-8, 50-323-98-08, 50-323-98-8, NUDOCS 9806090072 | |
| Download: ML16342E115 (50) | |
See also: IR 05000275/1998008
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORYCOMMISSION
. REGION IV
Docket Nos.:
License Nos.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-275
50-323
DPR-82
50-275/98-08
50-323/98-08
Pacific Gas and Electric Company
Diablo Canyon Nuclear Power Plant, Units 1 and 2
7 /~ miles NW of Avila Beach
Avila Beach, California
March 29 through May 9, 1998
David L. Proulx, Senior Resident Inspector
Donald B. Allen, Resident Inspector
James A. Sloan, Senior Resident Inspector, San Onofre
Dyle G. Acker, Senior Project Inspector
Steven D. Bloom, Project Manager, NRR
Howard J. Wong, Chief, Reactor Projects Branch E
Attachment:
Supplemental Information
'P806090072
980603
ADOCK 05000275
.
8
-2-
EXE UTIVE SUMMARY
Diablo Canyon Nuclear Power Plant, Units 1 and 2
NRC Inspection Report 50-275/98-08; 50-323/98-08
This inspection included aspects of licensee operations, maintenance,
engineering, and plant
support. The report covers a 6-week period of resident inspection.
~Ora ions
Control room operators and shift supervisors did not consistently meet management's
expectations in that thorough walkdowns of the control boards were not always
performed during shift turnover.
A Nuclear Quality Services audit identified similar
issues and management was taking action to address them (Section 01.1).
The inspectors identified an isolated instance of inattention to detail in the failure to
enter a limiting condition for operation.
The operators inappropriately designated the
inoperability of the reactor cavity sump level monitoring system as "information only,"
while entry into a 30-day limiting condition for operation was required.
Only two days of
the 30-day period had elapsed upon identification (Section 02.1).
During an engineered safety features walkdown of the safety injection (Sl) system, the
inspectors noted that the system was aligned properly, few leaks existed, and
housekeeping was excellent (Section 02.2).
~
An unresolved item was identified to review the licensee's determination in a Quality
Evaluation that personnel failed to comply with the clearance procedure while being fully
knowledgeable of the requirements (Section 04.1).
ain enance
Maintenance activities observed were performed well and in accordance with
procedures (Section M1.1).
During surveillance testing of a safety injection pump, an operator error was identified in
recording data from the wrong gauge, which was indicative of a lack familiaritywith the
procedure and a lack of knowledge of the basis for the measurement
being taken.
This
error was recognized by other licensee personnel independent of the
inspectors'bservation.
Otherwise, this and other surveillances observed were performed
satisfactorily (Section M1.2).
The licensee's justification for deferral of inservice testing for several post accident
sampling system valves during plant operation from quarterly to cold shutdowns was
inappropriate in that the basis for deferral failed to recognize that the applicable valves
were exercised during sampling during plant operations
(Section M3.1).
'!
-3-
~En
~irree~rin
Aviolation was identified for failure to perform a 10 CFR 50.59 evaluation for undersized
containment fan cooler unit (CFCU) motor leads and to have an incomplete and
inaccurate description of the plant Final Safety Analyses Report (FSAR) as required by
10 CFR 50.9(a). This was indicative of a failure to perform a thorough review of the
description in the Final Safety Analysis Report (FSAR) (Section E1.1).
ln the sample of 50.59 evaluations reviewed, a number of administrative errors were
identified in implementation of the 10 CFR 50.59 program, indicating a lack of attention
to detail. However, the licensee's implementation of its 10 CFR 50.59 program met the
program requirements.
Adequate safety evaluations were performed to support
conclusions (Section E1.2).
The determination that the lack of the proper seismic gap for the turbine pedestal
represented
a lack of conformance to the design and licensing basis was not timely.
This issue was identified October 1997, but the operability issues were not thoroughly
addressed
until May 1998. The conclusions of the operability evaluation and prompt
were reasonable
based on the information available.
(Section E2.1).
Aweakness was identified in initiallyimproperly classifying some conditio'ns, resulting in
explicit operability assessments
not being performed 2 of 12 issues.
The
implementation of the licensee's program for issues needing validation to determine
impact on operability was generally consistent with procedural guidance.
The timeliness
of the validation of all 12 issues reviewed was generally commensurate with the
potential safety significance (Section E2.2).
la
u
o
Security personnel failed to place temporary lighting under two portable trailers.
Security personnel took immediate compensatory measures.
Pending further NRC
review of the circumstances of the issue, this is an unresolved item (Section S1.1).
Re ort Details
Sum
of
I
tS gus
Unit 1 began this inspection period at 100 percent power. Unit 1 continued to operate at
essentially 100 percent power until the end of this inspection period.
Unit 2 began this inspection period at 30 percent power, with power ascension in progress.
Power ascension continued until 100 percent power was achieved on April2, 1998.
Unit 2
continued to operate at essentially 100 percent power until the end of this inspection period.
I. ~Oerattone
01
Conduct of Operations
01.1
e eralC
ens
7 70
The inspectors visited the control room and toured the plant on a frequent basis when
on site, including periodic backshift inspections.
Housekeeping was excellent
throughout safety-related areas.
In general, the performance of plant operators was
professional and reflected a focus on safety.
During this inspection period, the inspectors observed several shift turnovers.
The
inspectors noted that although no improper exchanges of information that could affect
plant safety were evident, improvement in the conduct of shift turnovers was warranted.
The inspectors noted that some control room operators did not perform thorough control
board walkdowns as required by Procedure OM12.DC1, "Relieving the Watch,"
Revision 7A.
These walkdowns consisted of a scan of the panels from the operator
console.
Although Procedure OM12.DC1 did not specifically describe what constituted
a sufficient control board walkdown, the licensee stated that a scan of the panels from
the operator console did not meet management's
expectations.
In addition, the
inspectors noted that the shift supervisors did not consistently perform control board
walkdowns during shift turnover. Although this was not required by procedure, this also
~
did not meet management's
expectations.
The inspector's reviewed Nuclear Quality Services most recent audit of the operations
department.
The inspectors noted that this audit identified similar issues with respect to
shift turnovers, and that licensee management was taking action to correct the
performance issues.
The licensee initiated a standing order to all of the crews that
clearly defined management's
expectation of a complete control board panel walkdown,
in'response to the inspectors concerns.
-2-
02
Operational Status of Facilities and Equipment
02.1
aiu e to En
echn'cal S ec'ation
TS Ac io
atemen
a.
Ins ec ion Sco
e
1707
On a daily basis, the inspectors reviewed the licensee's compliance with limiting
conditions for operation to ensure that the licensee complied with the TS.
b.
Observa ions and
i din s
The inspectors noted that, in general, operators effectively implemented the TS.
However, on April28, 1998, the inspectors noted an isolated instance in which a limiting
condition for operation was improperly implemented.
On April 27, the licensee identified
that Instrument LI-62, the Unit 1 reactor cavity sump level indicator was acting
erratically. Operators declared this equipment inoperable.
Operators then erroneously
initiated a TS tracking sheet that designated
Instrument LI-62 inoperability as
"information only" for Unit 1. However, TS 3.4.6.1 states that with the reactor cavity
sump level monitor inoperable, operation may continue for up to 30 days, after which the
licensee must place the Unit in hot standby in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The inspectors informed the shift supervisor of this discrepancy in TS tracking and the
shift supervisor corrected this error. Instrument LI-62 was repaired, retested and
declared operable on April29, two days into the TS action statement.
The inspectors
noted that although this issue had little safety significance because the instrument was
inoperable for far less time than the TS allowed, the failure to enter the proper TS action-
statement was an example of inattention to detail.
c.
~Co
us'ons
The inspectors identified an isolated instance of inattention to detail in the failure to
enter a limiting condition for operation.
The operators inappropriately designated the
inoperability of the reactor cavity sump level monitoring system as "information only,"
while entry into a 30-day limiting condition for operation shutdown action statement was
required.
Only two days of the 30-day period had elapsed upon identification.
02.2
En in ered Safe
ea ure Walkdown
Sl
s em
a.
Ins ection Sco
e 71707
The inspectors examined the design bases, operational status, valve and breaker
alignment and housekeeping
associated
with the Sl system.
-3-
b.
Observa ions an
Find'
The inspectors noted that all applicable valves and breakers were in their proper
positions.
The materiel condition of the system was good in that few leaks were noted
and those that existed were identified and tracked in the licensee's corrective action
system.
Housekeeping was excellent in the Sl pump rooms.
Conclusions
The operational status and material condition of the Sl system was noted to be
excellent.
04
Operator Knowledge and Performance
04.1
Po ential Clear
c
o
du e Viola io
a.
ns ec ion Sco
70
9 901
The inspectors reviewed the licensee's response to AR A0449239 and Quality
Evaluation Q0011991, that identified a potential violation of the clearance procedure.
b.
Observa ions a
i din s
On December 15, 1997, the licensee identified that a shift foreman (with the
concurrence of the shift supervisor) authorized work isolation without using the
clearance procedure.
Instead, an operator was sent to the area and maintenance
caution tags were used for work isolation, in order to address heat stress and high
radiation area concerns.
Procedures
OP2.ID1 "Clearances and Administrative
Tag-outs," Revision 9, and OP2.ID2, "DCPP Tagging Procedures," did not permit work
to be done under this type of isolation. Licensee review of the action request resulted in
the action request being elevated to a "Quality Evaluation," for a condition adverse to
quality.
The inspectors noted that the Quality Evaluation determined that the shift foreman and
shift supervisor were knowledgeable that their actions were not in accordance with
established procedures,
but proceeded nonetheless.
This issue warrants further NRC
review and will be treated as an unresolved item (URI 50-275;323/98008-01).
This
issue will be discussed
in NRC Special Inspection Report 50-275;323/98011).
c.
Conclusions
An unresolved item was identified to review the licensee's determination in a Quality
Evaluation that personnel failed to comply with the clearance procedure while being fully
knowledgeable of the requirements.
08
4
Miscellaneous Operations Issues (92700, 92901)
08.1
osed
'ce see
ven
Re
LER 50-323/96-001:
TS 3.4.6.1 Not Met with the
Reactor Coolant System Leakage Detection Systems Inoperable Due to Personnel
Error. This LER discussed
an event in which operators allowed the reactor cavity sump
level monitoring system to be inoperable coincident with inoperability of the containment
atmosphere
particulate radioactivity monitoring system.
This configuration placed Unit 2
in TS 3.0.3 for a time period in excess of that allowed. Operators failed to declare the
reactor cavity sump monitoring system inoperable when blockage was indicated.
For
corrective actions, the licensee:
(1) counseled the operators involved on making
conservative operability calls, (2) discussed the event with all shift supervisors to
communicate management's
expectations,
(3) increased the diameter of the sump level
system bubbling tube to prevent the buildup of contaminants, and (4) revised the
applicable surveillance test procedure (STP) to ensure that a minimum water level would
be present in the sumps.
The inspectors reviewed the licensee's corrective actions and
determined them to be satisfactory.
This issue was discussed
in NRC Inspection
Report 50-275;323/95-18.
This item is closed.
IN1
Conduct of lNaintenance
M1.1
a'n ena
c
Ob erva io s
a.
s ec ion
co e 62707
The inspectors observed portions of the following work activities:
MP E-57.10B, Generic Motor Preventative Maintenance, Revision 9
MP E-57.14A, High Voltage Testing of Electrical Equipment, Revision 6
ROI62847 Sl Pump Preventative Maintenance
MPE53.10A Refurbish Valve Sl-1-8923
Observations and F'ndin s
On April30, the inspectors observed portions of the polarization index test performed in
accordance with Procedure MP E-57.14A, "High Voltage Testing of Electrical
Equipment," at the 4160 volt breaker for the Sl Pump 1-1. The technicians had the work
package at the job site and were performing the steps as written. The test equipment
was calibrated within its required frequency.
The technicians were knowledgeable about
the test equipment and its application. The test results were within the expected range.
-5-
The inspectors observed portions of the preventative maintenance,
and subsequent
post maintenance testing and inspection, of the Sl Pump 1-1. The maintenance
personnel had the work package at the job site, were knowledgeable and proficient.
~Conclus'ons
The maintenance activities observed were performed in accordance with procedures.
The clearances were properly hung and were adequate to protect the work.
M1.2
Survei ance Observations
Ins ec ion Sco
e 61726
Selected surveillance tests required to be performed by the TS were reviewed on a
sampling basis to verify that:
(1) the surveillance tests were correctly included on the
facility schedule; (2) a technically adequate procedure existed for the performance of the
surveillance tests; (3) the surveillance tests had been performed at a frequency
specified in the TS; and (4) test results satisfied acceptance
criteria or were properly
dispositioned.
The inspectors observed all or portions of the following surveillances:
L
STP V-3L2A
Exercising Valve SI-8821A, Sl Pump Discharge To
Reactor Coolant System (RCS) Cold Legs, Revision 0
STP V-2H
Miscellaneous AuxiliaryBuilding Valves, Revision 11
STP V-3L10A
Exercising Valve SI-8923A, Sl Pump
1 Suction Valve,
Revision 0
STP P-SIP-11
STP P-AFW-23
Routine Surveillance Test of SI Pump 1-1, Revision 7
Routine Surveillance Test of Motor-Driven Auxiliary
Feedwater Pump 2-3, Revision 3
b.
Observa
i
s a d F'ndin s
On April 30, the inspectors observed the performance of STP P-SIP-11, "Routine
Surveillance Test of SI Pump 1-1," Revision 7. This test demonstrated
the pump
performance while operating on recirculation, and satisfied the requirements of the
Inservice Test Program.
The inspectors observed the pretest briefing, installation of test
equipment, and the inspection of the pump and recording of pump parameters during
the test. The inspectors observed that the operator had recorded the data from the
temporary gauge monitoring the differential pressure across the pump instead of the
differential pressure across the flow orifice, and as a result, obtained flow values, which
were incorrectly recorded as out of tolerance.
The operator requested Technical
-6-
Maintenance personnel to vent and troubleshoot the temporary gauge.
The inspector
identified the error to the operator, and the surveillance was reperformed.
The final data
was properly recorded with satisfactory test results.
Subsequently, the inspectors
learned that Technical Maintenance personnel had concurrently recognized the
operator's error upon arrival at the job site and had notified the shift supervisor.
The inspectors discussed this issue with the operator involved. The inspectors noted
that the operator was not sufficiently familiar with Procedure STP P-SIP-11 or the
concept that the flow measurements
required were to be obtained from differential
pressure across the flow orifice and not across the pump.
On April30, the inspectors observed the performance of: STP V -2H, "Miscellaneous
AuxiliaryBuilding Valves," Revision 11, for Valve Sl-'8923A; STP V-3L2A, "Exercising
Valve SI-8821A, Sl Pump Discharge To RCS Cold Legs," Revision 0; and STP V-
3L10A, "Exercising Valve SI-8923A, Sl Pump
1 Suction Valve," Revision 0. These tests
measured the valves stroke times using the valve control switch actuated electronic
timer and position indicating lights per STP G-15B, "Determination of Valve Stroke
Times with Electronic Timers," Revision 3, and satisfied the requirements of the
Inservice Test Program. The electronic timer was within its calibration frequency.
The
tests were performed as written. The operators performing the tests were
knowledgeable of the test and test equipment, and the test results satisfied the
acceptance
criteria of the surveillances.
~conclus'ons
During surveillance testing of a Sl pump, an operator error was identified in recording
data from the wrong gauge, which was indicative of a lack of familiaritywith the
procedure and a lack of knowledge of the basis for the measurement
being taken.
This
error was recognized by other licensee personnel independent of the
inspectors'bservation.
Otherwise, this and other surveillances observed were performed
satisfactorily.
Maintenance Procedures and Documentation
~STR view
Ins ection Sco
e 61726
The inspectors reviewed selected sections of the licensee's IST plan as part of the
inspection associated with the surveillance observations discussed
in Section M1.2 of
this inspection report.
-7-
0 serva ions and Fi din s
The inspectors noted that the IST plan directed the appropriate testing and frequencies
for the surveillances observed.
In addition, the inspectors reviewed the licensee's
justifications to defer testing of certain components during cold shutdown.
The licensee's second 10-year interval of the IST program committed to Operations and
Maintenance Code ASME OMA-1988 Part 10, "Inservice Testing of Valves in
Light-Water Reactor Power Plants," for inservice testing of safety-related valves.
Section 4.2.1 of this document requires the all active'valves to be stroke tested
quarterly.
Section 4.2.1.2(c) further states that ifexercising the valve is not practicable
during plant operation, the testing may be limited to cold shutdowns.
Section 6.2
requires the licensee to maintain a record of test plans that include justification for
deferral of stroke time testing.
The inspectors noted that the licensee's IST plan contained a number of "cold shutdown
justifications" (CSJs) that deferred testing of certain safety-related valves. The
inspectors noted that Justification CSJ V-CS25 deferred 17 valves to cold shutdown on
the basis that the valves could only be opened under administrative controls.
Most of
these valves were a part of the post accident sampling system (PASS).
However, the
basis for Justification CS J V-CS25 failed to recognize that these PASS valves were
routinely exercised during plant operations monthly by chemistry personnel to draw
samples.
Therefore, the inspectors concluded that the stated basis for deferral was
inappropriate in that it w~s practicable to exercise these valves on a quarterly basis
. during plant operation.
The licensee initiated AR A0460656 to evaluate the inspectors'oncern.
The licensee's
evaluation agreed that Justification CSJ-CS25 was flawed because the valves were
routinely exercised during plant operation.
However, the licensee determined that
missed surveillances did not occur. The licensee noted that because the PASS valves
were normally shut valves, they could be considered passive valves because they were
only opened momentarily to draw samples.
Therefore, the licensee concluded that
stroke timing of these valves was unnecessary.
The licensee used NRC guidance
document NUREG-1482, "Guidelines for Inservice Testing at Nuclear Power Plants," to
justify this conclusion.
NUREG-1482, Section 2.4.2 stated that a valve need not be
considered active ifit is removed from its safety function for a short period of time, such
as manually opening a sample valve to take a sample.
However,
Section 2.4.2 further stated that if a valve is routinely repositioned during plant
operations it is an active valve. The licensee stated that NUREG-1482, Section 2.4.2,
supported their position that the PASS containment isolation valves were passive valves
and need not be stroke time tested.
However, the inspector noted that Section 4.4.2 stated that the IST program applies to
PASS valves that are required to perform a containment isolation function. Such
containment isolation valves are required to be included in the IST program and be
tested except where relief has been granted.
The inspector concluded that
-8-
Section 4.4.2 supported the position that PASS valves were required to be stroke time
tested.
The inspectors determined that further review was required to determine the adequacy
of the licensee's position. Therefore, removal of the PASS containment isolation valves
'rom stroke time testing requirements
is considered an unresolved item pending further
NRC review (URI 50-275;323/98008-02).
C.
Conclusions
The licensee's justification for deferral of inservice testing for several post accident
sampling system valves during plant operation from quarterly to cold shutdowns was
inappropriate in that the basis for deferral failed to recognize that the applicable valves
were exercised during sampling during plant operations.
An unresolved item was
identified to further review the licensee's position that the PASS containment isolation
valves are passive valves and not subject to stroke time testing requirements.
E1
Conduct of Engineering
.
c
a.
Ins ecionSc
e 3 551
9290
The inspectors evaluated the licensee's response to AR A0454060 that identiTied that
during repair of a CFCU motor, that incorrect insulation was installed on the motor
Observa ions an
'nd'n s
On February 23, 1998, a licensee vendor identified that the motor leads for CFCU 2-5
were qualified for 600 volt service.
The licensee's environmental qualification files were
based on insulation rated to 2300 volts. The licensee initiated an AR to place this item
into the corrective action program.
C
Because of the underrated insulation of the CFCU, the licensee contacted the vendor to
evaluate the as-found condition from an operability perspective.
The vendor's
evaluation demonstrated that the CFCU motors were capable of performing their
intended safety function, and thus were operable.
The inspectors reviewed the vendor's
analysis and had no concerns.
The licensee determined that the environmental
qualifications of the CFCU motors were still valid based on the vendor's analysis.
The
licensee revised the environmental qualification files to reflect the use of insulation rated
to 600 volts for the motor leads.
The licensee dispositioned the apparently discrepant
condition as "use-as-is" based on these evaluations.
-9-
However, on April 10, 1998, following the licensee's resolution of the issue, the
inspectors reviewed the FSAR Update and noted that Section 6.2.2.3.3.2 stated that the
CFCUs had motor leads rated to 2300 volts and that the leads were rated to a voltage
that met or exceeded that of the CFCU motors (2300 volts). Because the licensee
determined that the existing 600 volt leads were acceptable, this was a defacto change
to the facility as described in the FSAR. However, the licensee had not recognized that
their resolution of the issue was not consistent with the FSAR and did not perform a
10 CFR 50.59 safety evaluation for this configuration. The inspectors also noted that the
CFCU 2-5 motor leads had been rated to 600 volts since initial plant licensing in 1985.
Therefore, the FSAR submitted with the initial license application was not complete
and
accurate in all material respects.
The failure to perform a safety evaluation for a defacto
change to the facilityas described in the FSAR and the failure to submit and maintain a
complete and accurate FSAR is a violation of 10 CFR 50.59(b)1 and 50.9(a) (VIO 50-
275;323/98008-03).
Subsequently,
based on the inspectors'bservation,
the licensee performed a safety
evaluation of the CFCU motor leads rated to 600 volts. The licensee did not identify any
unreviewed safety questions.
The inspectors reviewed the safety evaluation and agreed
with the licensee's assessment.
However, the inspectors noted inattention to detail in the justifications as to why no
unreviewed safety questions existed.
'Question 3 asked ifthere was an increase in the
probability of malfunction of safety-related equipment.
However, the licensee's answer
justified why no new unanalyzed condition existed.
Question 6 of the justification asked
ifa malfunction of a different type existed, but the answer did not discuss potential new
failure modes.
These oversights did not affect the outcome of the safety evaluation, but
were an examples of inattention to detail.
~Con lusio s
A violation was identified for failure to perform a 10 CFR 50.59 evaluation for undersized
CFCU motor leads and to have an incomplete and inaccurate description of the plant
Final Safety Analyses Report (FSAR} as required by 10 CFR 50.9(a).
This was
indicative of a failure to perform a thorough review of the description in the FSAR. The
safety evaluation performed subsequent
to the inspectors'dentification of this issue
did'ot
determine that an unreviewed safety question existed.
eview of 10
F
50 59 Evaluations
37001
Ins ec ion Sco
e
The inspector reviewed the licensee's program guidance and assessed
the licensee's
performance implementing its 10 CFR 50.59 safety evaluation program.
Specifically,
the inspector reviewed a sample of 10 CFR 50.59 screenings and associated
unreviewed safety question determinations.
-10-
0 servations and Find'
From November 17-21, 1997, the inspectors conducted a review of 10 CFR 50.59
packages prepared by the licensee for Units 1 and 2. The effort included discussions
with licensee staff familiar with the licensee's training, procedures and preparation of
10 CFR 50.59 packages,
as well as review of the licensee's
10 CFR 50.59 design
change review program procedures and completed packages.
The licensee considered the program to conform to the Nuclear Safety Analysis Center-
125, "Guidelines for 10 CFR 50.59 Safety Evaluations," which was referenced and
partially included in Procedure TS3.ID2, "Licensing Basis Impact Evaluations,"
Revision 3. The inspector also reviewed Procedure CF4.ID3, "Design Change Package
Implementation," Revision 7, and Procedure CF3.ID9, "Design Change Package
Development," Revision 6.
Allindividuals who prepared or were independent technical reviewers had received the
licensee's
10 CFR 50.59 training. The training is followed by an examination.
The
computer training was based on Nuclear Safety Analysis Center - 125 guidance on how
to write safety evaluations.
This training was the prerequisite to a one-day training held
twice a year to instruct writers and reviewers on the process to fillout Licensing Basis
Impact Evaluations (LBIE). The inspector noted that there was no refresher training to
ensure that the reviewers were kept up-to-date.
vie
of
0 C
50.5
Ev
o ra
cka esa
dDe
i n
ac
e
Numerous instances of using outdated LBIE forms and a lack of attention to detail in
fillingout the LBIE forms existed.
Procedure TS3.ID2, Revision 3, was revised on
June 11, 1997, and pages 2 and 3 of some of the packages reviewed were still using
the old form and, therefore, did not answer a new question added in Revision 3, about
whether the activity or change, test or experiment relied on a vendor safety evaluation,
which had not been reviewed by the Plant Staff Review Committee (PSRC).
The
licensee issued AR A044362044362 September
11, 1997, to document this issue.
The
inspector found numerous inconsistencies
in which the licensee updated either the
FSAR or the Design Criteria Memorandum (DCM) depending on the level of detail of the
modification as it related to the level of detail in the FSAR or DCM. These documents
'onstituted the design'basis of the plant and the inspector noted that some details of the
modification were not incorporated.
The inspector also noted that due to the fact that
part of the engineering department was onsite and part offsite, some of the packages
were hard to followsince parts of the documentation were in both places.
The inspector
noted for example that paperwork in the final package did not have signatures on all
paperwork indicating completion because the signed copy was offsite. There were also
numerous copies of safety evaluations, which did not have signatures indicating
approval by the PSRC.
When brought to the attention of the licensee, they were able to
produce PSRC meeting minutes, which indicated that the packages without signatures
were presented to the PSRC and were approved.
0
-11-
The following is a summary of the 10 CFR 50.59 packages reviewed.
Design Change Package (DCP) P-05037'l, Revision 0- This DCP addressed the
drilling of holes in ball valves in the Unit 2 liquid radwaste system and adding
rupture disks in the piping lines. This modification was to prevent
overpressurization of the containment penetration piping during post accident
conditions. The DCP does not discuss updating the DCM T-16 or the FSAR to
incorporate the containment penetration overpressure
devices installed. The
licensee issued AR A0414348, dated February 26, 1997, which stated that
DCM T-16 should be updated as necessary for containment overpressure,
and,
then on September
11, 1997, explicitly states to include in the DCM, P-050371,
however, the inspector did not find any evidence that the update had been
incorporated into the DCM. The inspector also found that an outdated LBIE
screening form was used and that this was identified by the licensee in
AR A0443620. The independent technical reviewer was the process sponsor
who did not realize that the outdated form was being used.
DCP N-050286, Revision 0 - This package addressed
modifications to the
charging and Sl lines of the emergency core cooling system.
A pressure
reducing orifice assembly and trimming orifice were installed. The orifices were
installed to prevent erosion of the throttle valves, which existed prior to the
modification. The LBIE screening form was outdated and the independent
technical reviewer was the process sponsor.
The modification in this DCP
removed the throttle valves and'flow orifices, which were shown on Figure 3.2-9
of the FSAR, but the DCP did not mention updating the drawings in the design
package.
DCP J-50298, Revision 0- This DCP addressed
adding a "GO" push-button for
the steam generator main feedwater supply valves. These buttons would be
used to test the closure times of the main feedwater supply and bypass valves.
This would allow testing without disturbing normal plant operation.
The LBIE
screening was performed on an outdated form. FSAR Section 6.2.1.3.8 listed on
the form as a reference did not exist in the FSAR. The package discusses
an
FSAR update which would be incorporated but there was no discussion of an
update to the DCM.
DCP M-050366, Revision 0- This package addressed
a modification to relocate
the diesel generator carbon dioxide manual actuation switches.
The LBlE
screening was performed on the outdated form. The reference document on the
cover page for the screening lists this package as DCP M-05366, rather than
DCP M-050366. The inspectors also noted that Question 8 of the 50.59
evaluation asks about a change to the Fire Protection Program (FPP). The
question was answered "yes," however, there was no copy of the FPP with the
package.
The licensee stated that there was an electronic version of the FPP
and that subsequent
to the inspection a hard copy would be placed in the DCP to
ensure that the FPP is microfiched with the DCP.
-12-
~
DCP M-049222, Revision 0 - This package revised FSAR Chapter 6 and
DCM S-3B to incorporate the new design bases from the Westinghouse analysis
for the minimum required auxiliary feedwater flow rates.
A previous 50.59 and
letter to the NRC revised the TS Bases for Section 3/4.7.1.2 and FSAR Chapter
15. Quality Evaluation Q0011838 documents the fact that the bases were
changed and new calculations were performed to develop new surveillance test
program acceptance
criteria without updating the licensing basis, documented in
FSAR Chapter 6 and DCM S-3B. There were no signatures on the screening
form because,
during the time period this was approved, electronic signatures
were allowed.
DCP A-050330, Revision 0- This DCP addressed
restoring a fire barrier above
the shift foreman's office between fire area 4-B and 4-B-2. On the screening
form, there was no answer to question 5 of the evaluation, although there was a
justification writeup that indicated that the answer should have been "no."
DCP A-050070, Revision 0 - This DCP addressed
the removal of Thermo-lag
and the installation of 3M Firepro. There was no answer on the screening form
for the question "Is the Reference Document a procedure?"
Also, the form did
not have actual signatures,
but only the names put onto the form electronically of
the individuals who reviewed the screening and the evaluation.
DCP N-049317, Revision 0 - This package dealt with replacing of the
containment recirculation sump screen for Unit 1. The licensee's screening and
50.59 evaluation appeared to be acceptable.
DCP M<9282, Revision 0- This DCP addressed
the evaluation FHARE No. 114,
in which the nonrated penetration seals are located within the fire areas of the
Auxiliarysaltwater pump rooms.
The evaluation determined that nonrated
penetration seals would not reduce the effectiveness of fire area
boundary and
would not affect the ability to safely shutdown the plant. The screening,
evaluation, and conclusions appe'ared thorough.
Maintenance Work Order (MWO) C0150947 - The maintenance work order
addressed
the disassembly of Valve FCV-41 actuators for the main steam
isolation valve. The main steam isolation valve would not meet the TS required
closing time during a surveillance test.
The safety evaluation and associated
technical evaluation appeared to be acceptable.
DCP N-47861, Revision 0 - This package addressed
the new refueling cavity
seal design for use during refueling outages, to seal the gap between the reactor
vessel flange and the refueling cavity floor during flood-up of the cavity. The
LBIE screening and 50.59 evaluation appeared to be acceptable.
-13-
DCP H-43663, Revision
1 - This DCP deleted the moisture separators
and filters
from the CFCUs. The LBIE screening and evaluation appeared to be thorough.
The evaluation included an evaluation performed by Westinghouse
related to this
DCP.
Procedure OP2.ID2, Revision 6 - "DCPP Tagging Requirements."
The revision
to the procedure modified the requirements for hanging red tags when
performing work under a sub-clearance.
Block 13 of the Procedure History
Sheet did not have an answer as to how the present practices would be changed
and who would be affected.
~
Procedure CF4.ID7, Revision 5- "Temporary Modifications, Plant Jumpers and
MBTE." The revision to the procedure added steps to the Jumper Log for
hanging and removal of information tags and independent verification of those
activities. Also, there was a clarification of the mechanical jumpers.
For both of the procedure changes, Procedure OP2.ID2 and Procedure CF4.ID7,
Block 12 - PSRC Review indicated the meeting number and date of either the approval
or rejection.
However, unlike the DCP forms of Procedure TS3.ID2, there was no place
for a signature indicating that approval or rejection from the PSRC for the procedure
history sheets of Procedure AD1.ID2.
The inspectors noted that although a number of minor administrative errors existed in
the licensee's implementation of 10 CFR 50.59, no safety issues were identiTied in the
inspectors sample.
The inspectors concluded that the overall program was satisfactory.
~Ccli~sion
In the sample of 50.59 evaluations reviewed, a number of administrative errors were
identified in implementation of the 10 CFR 50.59 program, indicating a lack of attention
to detail.
However, the licensee's implementation of its 10 CFR 50.59 program met the
program requirements.
Adequate safety evaluations were performed to support
conclusions.
E2
Engineering Support of Facilities and Equipment
E2.1
Lac of Seism c Ga
B
een
he
rbi e Pedestal an
he Turbine Build'n
a.
ns ection Sco
e 37551
The inspectors reviewed Nonconformance Report N0002058, and AR A0446082
documenting the discrepancy between the FSAR Section 3.8 describing seismic gap
separation requirements and the measurements
determined during a baseline walkdown
performed by the civil engineering department in support of the implementation of the
maintenance
rule. The inspectors discussed the status of this issue with the Support
Engineering Director.
~
~
Obse
a ions a d F ndin s
-14-
On October 21, 1997, AR A0446082 was initiated to document the lack of the required
seismic gap between the turbine pedestal and the turbine building. This action request
(AR) documented the maximum calculated horizontal displacement as follows:
Elevation 119 feet: 1.S9 inches east-west and 1.34 inches south-north.
Table 3.8-27A
of the FSAR specified the maximum calculated displacement and the minimum
separation at Elevation 140 feet. The minimum separation specified was 2.88 inches on
the east, 3.00 inches on the west, 1.25 inches on the north, and 1.31 inches on the
south. The seismic gaps were required to assure that during an earthquake, the
massive turbine pedestal would not impact the turbine building and cause damage to
safety-related equipment contained within it. The emergency diesel generators,
the
component cooling water heat exchangers,
and the 4160 volt vital switchgear are some
of the safety-related equipment located in the turbine building.
The actual measurements,
determined during walkdowns for the implementation of the
maintenance
rule, were as follows: at the south end of Unit 2 turbine pedestal, the
seismic gaps between the pedestal and the flanges of the steel columns were 1/8 inch
and 5/8 inch. The gaps on both sides of the column were
1 1/4 inches.
The gap on the
east side was
1 3/16 inches, and the gap on the west was generally
1 N inches with one
point where the gap was 3/4 inch. Additional discrepancies were noted, such as
styrofoam and plywood within the gap.
On March 11, 1S98, Nonconformance Report N0002058 was initiated documenting
more than 200 ARs generated to document insufficient seismic gaps in various plant
buildings, including the containments and both turbine buildings. Additional
nonconforming conditions included commodities (piping, conduit, tubing, platforms, etc.)
and supports either spanning the gap or within the gap.
On April 10, 1998, the
Technical Review Group for this nonconformance determined that a prompt operability
assessment
was required.
The prompt operability assessment
which specifically
addressed
the gap between the pedestal and the turbine building was initiated and
approved on that date and concluded that the safety-related equipment located in the
turbine building was operable.
Operability Evaluation 98-'09, Revision 0, was approved on April 17, 1998, and
confirmed the assessment
performed in the prompt operability assessment.
On
May 12, 1998, additional information was provided, to be incorporated into the
operability evaluation to address the items and supports that spanned the seismic gap
or are located in the gap. The conclusions were the same, that the safety-related
equipment in the turbine building continued to be operable.
However, more analysis
and calculations were to be performed to support this resolution to the
nonconformances.
The inspectors concluded that the licensee's resolution to this issue appeared to be
reasonable technically;,however, the licensee's evaluation was not timely. The
degraded seismic gaps of the turbine pedestal, representing nonconformance to the
-15-
design and licensing basis, were identified in October 1997, but the licensee did not
perform a thorough operability evaluation until May 1998.
c.
Conclusions
The determination that the lack of the proper seismic gap for the turbine pedestal
represented
a lack of conformance to the design and licensing basis was not timely.
This issue was identified October 1997, but the operability issues were not thoroughly
addressed
until May 1998. The conclusions of the operability evaluation and prompt
were reasonable
based on the information available.
E2.2
0 erabili
Assess
e
s
a.
s ection Sco
e 3755
and71707
The inspectors reviewed Inter-Departmental Administrative Procedure OM7.ID5, "Issues
Needing Validation to Determine Impact on Operability (INVDIO),"Revision 0, and
reviewed the followingARs that documented all usage of Procedure OM7.ID between
January
1 and April20, 1998:
A0449723
A0451004
A0451 459
A0452094
A0452896
A0453967
A0455956
A0456727
A0459053'0459822
A0459989
A0460020
b.
The inspectors also attended the April22, 1998, emerging issues meeting and the
April23, 1998, AR review team meeting.
Observa ions and Fi din s
Procedure OM7.ID5 provided guidelines and instructions for determining ifan identified
concern "is in fact a degraded condition which has an impact on the operability of
equipment."
INVDIOwas defined in the procedure as "a hardware or
documentation-related
issue which requires validation before questioning whether the
affected equipment can perform its intended safety function. Validation determines
whether a degraded condition actually exists." The procedure specified responsibilities
and provided guidelines to ensure that information necessary to support an operability
determination was obtained in a timely manner.
Step 5.3 of the procedure also required
that, "if, at any time during the investigation, it is decided that a degraded condition
exists" the licensee must perform a pro'mpt operability assessment,
a confirmatory
and/or an operability evaluation.
Management
review of the
ARs and operability determinations were performed via the Daily AR Review team.
ARs A0451459, A0452094, A0452896, A0459822, and A0459989 documented issues
which clearly met the definition of INVDIOwhen initiallyidentified. For example,
AR A0459822 identified that some spare parts installed in systems used only for training
had been modified without documentation, and that parts from training were sometimes
later taken and installed in the units. Before an operability determination could be
I
I
~
~
-16-
made, the licensee needed to determine ifparts that had been modified had actually
been installed in the plant, and ifthe parts had been properly dedicated.
Afterthe
licensee determined that a part had been installed in the plant without dedication, a
prompt operability assessment
was initiated.
Two of the ARs did not provide all relevant known information. After discussing the
issues with licensee personnel, the inspectors determined that the ARs were properly
processed.
For instance, AR A0453967 described a failed Raychem splice on an
operating containment fan cooler motor. As a known degraded condition, the failure did
not satisfy the definition of INVDIO. The AR did not state that the fan was not required
to be operable in the existing operational mode. The INVDIOstatus was actually to
confirm that the motor lead splices in the other unit were not degraded.
AR A0451004, initiated on January 14, 1998, described a potential generic
environmental qualification problem that could have rendered all the containment
emergency sumps inoperable.
Min-Kinsulation had been found to behave differently in
a post-accident environment, during laboratory testing for a boiling water reactor
licensee.
In the, testing, the insulation turned to sludge and resulted in restricting flow to
drywell suction strainers.
Before the licensee could determine the operability of systems
at Diablo Canyon, it needed to better understand the test conditions so that the
vulnerability of Min-Kin the containment conditions expected following a loss of coolant
accident at a pressurized water reactor could be assessed.
The AR did not clearly
document how much information was initiallyknown about the test conditions, and the
inspectors at first determined that enough information was known to provide a
reasonable doubt that the Min-Kat Diablo Canyon was fully,qualified, and that a prompt
operability. assessment
should have been performed.
However, after discussing the
issue with the Assistant Engineering Manager, the inspectors agreed that the licensee's
assessment
was acceptable.
After the test report was received by the licensee, the
issue was removed from INVDIOstatus and a prompt operability assessment
was
performed on January 22, 1998. The inspectors determined that the licensee's
resolution of the issue was timely.
AR A0449723 documented another INVDIOissue that resulted in a degraded condition
being validated. The licensee's evaluation and corrective actions for that condition were
timely.
AR A0460020 described a condition in which the loads on the letdown heat exchanger
outlet nozzle had changed as the result of several minor increases
in the design
temperatures for the component cooling water system in post accident conditions. The
licensee performed piping analyses and determined that seismic loads had decreased,
but that thermal loads had increased above the previous levels qualified by
The inspectors determined that the thermal loads being greater than the
qualiTied levels represented
a degraded condition, as defined by Procedure OM7.ID5.
The procedure defined degraded conditions to included deficiencies in design, analysis,
licensing, or qualification. Therefore, this issue did not meet the definition of INVDIO,
and a prompt operability assessment
was required.
However, the AR clearly stated that
'I
-17-
the sum of the loads was acceptable, which in essence was an operability assessment.
AR A0459053, initiated on April2, 1998, documented that the as-left fullclosed air
pressure for the air operator of a steam generator inlet line flow control valve was lower
than the functional limit. This issue was initiallyclassified as INVDIO, although it clearly
identified a degraded condition and required a prompt operability assessment.
However, the initiator documented the elements of a prompt operability assessment
in
the AR along with the initial description of the issue.
The Assistant Engineering
Manager agreed that this should have been initiallyclassified as requiring a prompt
and that he had recognized this and discussed it with the
initiator.
AR A0456727, initiated on March 13, 1998, was not classified as INVDIOuntil April 8,
1997. The issue involved a potential concern of whether a FSAR statement from
another facilitythat was found to be invalid applied to Diablo Canyon.
This AR had not
been classified as INVDIOon initial identification. This classification was incorrect., This
issue was still being evaluated by the licensee.
The AR documented continuous
progress toward obtaining the information necessary to resolve the potential operability
issue, and the inspectors determined that the initial misclassification of the issue did not
result in significant delays in obtaining the information required to determine ifan
operability issue existed.
c.
~Co cI s'o
s
Aweakness was identified in initiallyimproperly classifying some conditions, resulting in
explicit operability assessments
not being performed 2 of 12 issues. The implementation
of the licensee's program for issues needing validation to determine impact on
operability was generally consistent with procedural guidance.
The timeliness of the
validation of all 12 issues reviewed was generally commensurate with their potential
safety significance.
R1
Radiological Protection and Chemistry Controls
R1.1
General Co
en s 71750
The inspectors evaluated radiation protection practices during plant tours and work
observation.
The inspectors determined that personnel donned protective clothing and
dosimetry properly, and that radiological barriers were properly posted.
S1
Conduct of Security and Safeguards Activities
S1.1
General Commen s 71750
During routine tours, the inspectors noted that the security officers were alert at their
-18-
posts, security boundaries were being maintained properly, and screening processes
at
the Primary Access Point were performed well. During backshift inspections, the
inspectors examined protected area illumination, especially in areas where temporary
equipment was brought in. The inspectors noted two areas in which compensatory
actions were warranted.
A trash bin and a temporary power trailer had shadows cast
under them that made it difficultto see under. The security watch officer added these to
items to the half hour security compensatory tours.
Pending further inspector review of
this issue, this is an unresolved item (URI 50-275;323/98008-04).
F1
Control of Fire Protection Activities
F1.1
Com ensato
Measures
ns
c ion Sco
e 71750
The inspectors reviewed the licensee's compensatory measures
used to ensure that
these compensatory measures were commensurate
with NRC requirements.
bserva ions and F'ndin s
The licensee's fire protection plan was located in FSAR Section 9.5.1 and was
implemented by License Condition 2.C.(4) of the facility's operating license.
Fire
protection TS were relocated to the licensee's Equipment Control Guidelines (ECGs),
which were licensee controlled specifications not requiring NRC approval to amend.
ECG 18.7 provided the actions necessary to compensate for inoperable fire barriers
such as fire doors, fire rated assemblies,
fire seals, or fire dampers.
This ECG required
that ifa fire rated assembly was inoperable to establish an hourly fire patrol as long as
the automatic detection or suppression systems were verified as operable.
Ifthe
detection and suppression systems are inoperable, ECG 18.7 required a continuous fire
watch for inoperable fire rated assemblies.
However, the licensee revised ECG 18.7
and the fire protection plan in FSAR section 9.5.1 to define a continuous fire watch as
follows: "Afire watch is considered continuous ifthe patrol can monitor the immediate
vicinity on the nonfunctional fire rated assembly at least once per 15 minutes."
The inspectors interviewed several shift supervisors who stated that they had used this
definition of continuous fire watches so that more than one fire area could be covered by
a single person.
The inspectors questioned the validity of this definition. A continuous fire watch
appeared to be a substitution of manual operation (a fire watch with a fire extinguisher)
for automatic operation.
However, a 15 minute patrol did not appear to be an adequate
substitute for automatic operation of the detection and suppression systems because
action taken by the patrol could be delayed up to 15 minutes rather than immediate.
Pending further NRC review of the adequacy of the licensee's definition of a continuous
fire watch, this is an unresolved item (URI 50-275;323/98008-05).
-19-
c.
~Co cIusions
An unresolved item was identified to review the licensee's determination that a
15 minute fire tour was sufficient for a continuous fire watch as a compensatory
measure for inoperable fire protection equipment.
V. Mana
e
ent Meet n s
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
at the
conclusion of the inspection on May 17, 1998. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary.
No proprietary information was identified.
Licensee
ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIALLIST OF PERSONS CONTACTED
W. M. Crockett, Manager, Nuclear Quality Services
R. D. Gray, Director, Radiation Protection
T. L. Grebel, Director, Regulatory Services
D. M. Miklush, Manager, Engineering Services
J. R. Molden, Manager, Operations Services
D. R. Oatley, Manager, Maintenance Services
R. P. Powers, Vice President and Plant Manager
L. F. Womack, Vice President, Nuclear Technical Services
INSPECTION PROCEDURES (IP) USED
IP 37551
IP 62707
IP 71750
IP 92903
10 CFR 50.59 Safety Evaluation Program
Onsite Engineering
Surveillance Observations
Maintenance Observation
Plant Operations
Plant Support Activities
Followup - Operations
. Followup - Engineering
-2-
ITEMS OPENED AND CLOSED
~Oened
50-275;323/
98008-'01
50-275;323/
98008-02
50-275;323/
98008-03
50-275;323/
98008-04
50-275;323/
98008-05
~Clo ed
Removal of PASS containment isolation valves from stroke
test requirements (Section M3.1)
Failure to perform 10 CFR 50.59 evaluation for change to
size of CFCU motor leads and an inaccurate and incomplete
FSAR description of the motor leads (Section E1.1)
Failure to provide temporary lighting under portable trailers
(Section S1.1)
Performance of 15 minute fire tours for continuous fire
watches (Section F1.1)
Potential violation of the clearance procedure (Section 04.1)
50-323/96-001
LER
Failure to Implement TS 3.4.6.1 for Reactor Coolant
Leakage Detection Systems (Section 08.1)
-3-
LIST OF ACRONYMS USED
CFCU
ECG
INVIDO
IP
LBIE
PSRC
TS
Action Request
American Society of Mechanical Engineers
Containment Fan Cooler Unit
Design Criteria Memorandum
Design Change Package
Diablo Canyon Power Plant
Equipment Control Guideline
Final Safety Analysis Report
Issues Needing Validation to Determine Impact on Operability
Inspection Procedure
Licensing Basis Impact Evaluation
Noncited Violation
Post Accident Sampling System
Public Document Room
Plant Staff Review Committee
Safety Injection
Surveillance Test Procedure
Technical Specification
Unresolved Item
Violation
ql