ML17292B243
| ML17292B243 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 02/09/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17292B241 | List: |
| References | |
| 50-397-97-13, NUDOCS 9802170055 | |
| Download: ML17292B243 (81) | |
See also: IR 05000397/1997013
Text
E
CLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-397
50-397/97-13
Washington Public Power Supply System
Washington Nuclear Project-2
3000 George Washington Way
Richland, Washington
July 15 through August 2, 1997
T. Stetka, Senior Reactor Inspector, Engineering Branch
P. Goldberg, Reactor Inspector, Engineering Branch
M. Runyan, Reactor Inspector, Engineering Branch (IFI 9604-01)
Arthur T. Howell III, Director, Division of Reactor Safety
I
ATTACHMENT:
Supplemental Information
98021T0055
980209
ADQCK 05000397
-2-
EXE UTIVE SU
MARY
Washington Nuclear Project-2
NRC Inspection Report 50-397/97-1 3
During the period of July 15 through August 2, 1997, two NRC inspectors conducted an
inspection to followup issues previously identified in other inspection reports.
~Oe ra~in
While corrective actions to resolve the material buildup problem in Valves FDR V-3 and
FDR V-4 were effective, corrective actions to resolve a required reading problem were
not. Violation 50-397/9611-04 will be closed, however, an example of a new violation of
10 CFR Part 50, Appendix B, Criterion XVI,was identified for the failure to correct the
required reading issue (Section 08.1).
The new nuclear safety assurance
division procedure properly addressed
the technical
specification procedural requirements.
In addition, licensee conducted surveillances
were effective in assuring that other canceled procedure activities were properly
conducted.
However, there was a failure to update the Final Safety Analysis Report fire
protection sections (Section 08.2).
The root-cause analysis procedure was found to be properly applied.
Efforts were in
progress to improve the root-cause analysis program (Section 08.3).
The corrective actions to resolve continuing failures of the motor-to-pump coupling on the
ac standby lubricating oil pump were not fullyimplemented.
This was considered to be
an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (Section 08.4.1).
Corrective actions to correct and prevent recurring personnel error induced valve and
switch mispositioning errors were in progress (Section 08.4.2).
Actions were in progress to correct recurring personnel errors involving a lack of
equipment clearance/procedure
adherence
and the issuance of inadequate clearance
orders (Section 08.4.3).
Corrective actions to address the reversed termination of electrical equipment and wiring
=errors were appropriate to the cause (Section 08.4.4).
-3-
Actions to address the occurrence of shorting electrical terminals during the performance
of maintenance or surveillance activities were adequate and effective toward preventing
a recurrence of the events (Section 08.4.5).
The corrective actions that addressed
the inadvertent initiation of drywell to suppression
chamber bypass flowwere appropriate for the circumstances
and adequate to prevent a
recurrence of the events (Section 08.4.6).
There wa's a failure to issue a problem evaluation request that would have promptly
identified and provided corrective actions for the inadvertent start of a reactor
recirculation pump. This item was considered to be an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (Section 08.4.7).
Corrective actions to control a lack of documentation of issues in problem evaluation
requests and to resolve the inadequate labeling of radioactive materials were in progress
(Section 08.4.7).
~En
in erin
The reactor core isolation cooling system was downgraded from safety related to
nonsafety related.
While the system was found to be operable, it was also found to
be nonconforming.
The reclassiTication plan and schedule for returning the reactor
core isolation cooling system to safety related were thorough. As the result of these
downgrade activities, six reactor core isolation cooling valves were not being tested.
The failure to test these valves was considered to be an apparent violation of
10 CFR 50.55a(f). The failure to obtain NRC approval prior to downgrading the system
from safety related to nonsafety related was considered to be an apparent violation of
10 CFR 50.59 because
it apparently involved an unreviewed safety question
(Section E8.2).
An adequate evaluation of the March 3, 1996, residual heat removal system test results
was performed that demonstrated that the results were within the design basis
(Section E8.4).
Multiple examples of Final Safety Analysis Report inaccuracies were identified. While no
safety issues or operability issues were identified, these multiple examples were
indicative of a failure to update the Final Safety Analysis Report.
However, the ongoing
implementation of a Final Safety Analysis Report update program permitted the
exercising of enforcement discretion in accordance with the revised enforcement policy
(Section E8.5).
I
-4-
Appropriate actions to correct a new and previously unanalyized condition involving the
potential overpressurizing of the main steam safety relief valve actuators were being
taken. These actions indicated that the actuators were capable of withstanding the
additional pressure and that design documentation would be changed to reflect the new
design pressure ratings (Section E8.8).
The current design for the manual initiation of the automatic depressurization
system
was consistent with Regulatory Guide 1.62 as amended by the requirements of Three
Mile Island Action Item II.K.3.18 and no wiring error existed.
Functional Control
Diagram 731E788 was not consistent with the as-built plant configuration
(Section E8.10).
The lack of inclusion of the high pressure core spray service water loop in the corrosion
program was appropriate considering the type of failure that occurred.
In addition, the
inclusion of the high pressure core spray service water system in the wall thickness
measurement
program was considered to be a proactive approach toward eliminating
any future problems (Section E8.12).
While Engineering Directorate Manual 2.15 was properly implemented, actions were
being taken to further control the number of calculation modification records for plant
calculations. A self-assessment
performed by the licensee did not identify ifthe
outstanding calculation modification records potentially affected the technical content of
the calculations.
The NRC plans further review of this area during a future inspection
(Section E8.16).
-5-
e o
D
ils
To accomplish this inspection, the inspectors reviewed NRC Inspection Reports'50-397/96-11,
50-397/96-201, and 50-397/96-202.
The inspectors also reviewed the problem evaluation
requests identified in these reports and interviewed personnel.
In addition, the inspectors
reviewed the licensee's response to the violations documented in Letter GO2-96-201, dated
October 15, 1996, to NRC Inspection Report 50-397/96-11 and the NRC acknowledgment letter
dated November 14, 1996, the licensee's response to the open items documented in
Letter GO2-97-120, dated June 16, 1997, to NRC Inspection Report 50-397/96-201, and the
licensee's response documented
in Letter G02-97-228, dated December 23, 1997, to Task
Interface Agreement 96-TIA-005.
I. ~Oerattona
08
Miscellaneous Operations Issues
08.1
Closed
Viola ion
-397/9 11-: Failuretoimplementadequateandtimelycorrective
actions.
Bac
rou d
In NRC Inspection Report 50-397/96-11, the NRC identified a violation with three
examples where the licensee did not provide adequate and timely corrective actions.
The first example occurred on January 19, 1996, when the licensee found that Primary
Containment Isolation Valve FDR V-4 did not close due to foreign material on the valve
seating surfaces.
The licensee did not promptly correct the cause of the foreign material
and, as a result, from January 19 through July 6, 1996, Valve FDR V-4 had additional
closure failures and a redundant isolation valve, FDR V-3, also failed to close.
These
additional failures were also attributed to foreign material on the valve seating surfaces.
The second example involved a failure to correct a problem wherein the Corporate
Nuclear Safety Review Board was not receiving all of the 10 CFR 50.59 safety
evaluations for review. As a result it appeared that an additional 10 CFR 50.59 safety
evaluation (SE 95-095) was not reviewed by the Corporate Nuclear Safety Review
Board.
However, in their response to this violation example (Letter GO2-96-201 dated
October 15, 1996), the licensee stated that the Corporate Nuclear Safety Review Board
,= did.review Safety Evaluation SE 95-095 and that there was a typographical error in the
attachment to the Corporate Nuclear Safety Review Board meeting minutes for
Meeting 96-05 that made it appear that the safety evaluation was not reviewed.
'I
I
-6-
The third example involved the failure to complete the corrective actions taken to assure
that the fire protection water system would not be placed in an improper lineup. The
incomplete corrective action involved the requirement that all operators complete
required reading regarding the improper lineup of the fire protection water system.
Specifically, the licensee found that operators were using the fire protection water system
for nonflire protection activities white only a single source of water was available.
This
lineup configuration was contrary to the requirements of Procedure 1.3.10, which
prohibited the fire protection water system to be used for nonfire protection system
purposes unless both fire protection system water supplies were available.
This violation
was originally cited in NRC Inspection Report 50-397/95-18 in 1995 and was reviewed
for closure in NRC Inspection Report 50-397/96-11.
During Inspection 50-397/96-11
conducted in July 1996, the inspection team found that the required reading was only
completed by 50 of the 111 personnel required to do the reading.
In
ecor F llowu
F rei n Ma erial on Valve Sea in
Surface
The inspectors interviewed the system engineer and reviewed the modification package
for the modification installed to enable the licensee to flush the lines in which
Valves FDR V-3 and FDR V-4 were located.
In addition to a modification package
review, the inspectors walked down a portion of the modification that was accessible.
The inspectors also verified that the flushing was accomplished during the past refueling
outage and that the valves were stroked on a weekly basis to assure operability until the
modification was completed.
The licensee concluded that these flushing operations would remove foreign material
buildup in these lines and, therefore, prevent introduction of foreign material on the valve
seating surfaces.
The modification installed spectacle flanges and tees in these lines to
establish a flushing path.
To prevent recurrence of a foreign material buildup in these
valves the licensee also developed preventative maintenance tasks that will inspect and
clean these valves every 3 years and clean (de-sludge) the sumps every 2 years.
The
inspectors determined that these tasks combined with the quarterly valve stroking
procedures should assure that the valves remain operable.
Furthermore, the inspectors
noted that the licensee willconsider accelerated
pipe flushing ifforeign material buildup
was noted or ifvalve stroking indicated a degradation in the stroke time. The licensee
concluded that these activities willassure early detection of valve closure problems
based on an established history that demonstrated
that it took about 5 years for failures
to occur due to a foreign material buildup on the valve seating surfaces.
-7-
Co
ora e Safe
Revi w Bo rd Safe
Evalu
ion
view
The inspectors reviewed the documentation regarding the typographical error in the
attachment to the minutes of Corporate Nuclear Safety Review Board Meeting 96-05.
Review of these meeting minutes indicated that SCN 96-062 was reviewed.
Since
SCN 96-062 encompassed
Safety Evaluation 95-95, this meant that this safety
evaluation was reviewed in that meeting.
Furthermore, the package of safety
evaluations distributed,to the 50.59 subcommittee for Corporate Nuclear Safety Review
Board Meeting 96-05 documented that SE 95-095 was reviewed.
Based on this review,
the inspectors concurred with the licensee's finding that the SE 95-095 was reviewed by
the Corporate Nuclear Safety Review Board and that the information in the attachment
provided to the NRC was incorrect due to the typographical error.
Im ro er Fire Pro ection Wate
S stem Lineu
The licensee modified their system to assure that all operators were reading the required
reading book by adding the required reading to the plant tracking log. The intent of this
action was to assure that the required reading was accomplished prior to closing out the
plant tracking system item. By listing in the plant tracking system log, the item would be
tracked to assure that the required reading was completed.
However, due to a
misinterpretation of the intent of the plant tracking system entry, personnel assumed that
. when the required reading topic was placed in the required reading book that the plant
tracking log item could be closed out. Therefore, the plant tracking item was closed out
even though the required reading was not completed.
To determine ifthis problem was corrected, the inspectors reviewed the required reading
book located in the control room. The inspectors determined that five required reading
items were still outstanding.
The inspectors also checked the plant tracking log to
determine ifall the outstanding required readings were entered into the log. The
inspectors found that only four of the five items were'ntered
into the log. The licensee
stated that the one item not logged was due to the loss of the person in charge of the
plant tracking log. While it appeared to the inspectors that the licensee had a system to
assure that the required readings were completed, the inspectors identified one operator
that still had not read the required material until July 22, 1997 (during this inspection).
In
addition, the inspectors noted that the licensee's process assumed that the opening of an
E-Mail messag
meant that the message'had
been read even though there was no
acknowledgment in the message
confirming that the message was read.
The inspectors
= interviewed five operators that had not acknowledged that they had read the E-Mail
message
and found that four of these five operators remembered completing the
required reading.
-8-
The inspectors considered the failure to complete the required reading to be an example
of a recurrent failure to complete corrective actions.
Criterion XVI, requires nonconformances
to be promptly corrected and action taken to
prevent recurrence of the nonconformance.
The recurrent failure to complete the
required reading for the fire protection water system lineup problem was considered to
be the first example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI
(50-397/9713-01).
nclusions
While corrective actions to resolve the material buildup problem in Valves FDR V-3 and
FDR V-4 were effective, corrective actions to resolve a required reading problem were
ineffective. Violation 50-397/9611-04 willbe closed, however, an example of a new
violation was opened for the failure to correct the required reading issue.
It was found
that Evaluation SE 95-095 was reviewed by the Corporate Nuclear Safety Review Board.
Closed
iola i n
-397/9611-05:
Failure to implement a nuclear safety assurance
division procedure.
~Bk ~run
NUREG-0737,Section I.B.1.2, "Independent Safety Engineering Group," required the
licensee to establish an onsite independent safety engineering group to perform
independent reviews of plant operations.
Technical Specification 6.2.3 was established
to address these requirements and the licensee established
a nuclear safety assurance
division. Furthermore, since Technical Specification 6.8.1.b requires written procedures
for the Nuclear Safety Assurance Division, the licensee developed Procedure PM 1.10.8,
"Nuclear Safety Assurance Assessments,"
to describe the responsibilities and functions
of this group.
However, Procedure PM 1.10.8 was canceled in 1993 because the
procedure was a restatement of the requirements located in Nuclear Operating
Standards 20, "Quality Assurance Evaluations." The licensee failed to recognize that the
deletion of Procedure 1.10.8 was contrary to the requirements of the technical
specifications because the information in Nuclear Operating Standards 20 did not have
the same review and approval requirements as procedures governed by the technical
specifications.
Ins e
or Followu
The licensee issued new Procedure SWP-ASU-01, "Evaluation of Programs, Processes,
and Suppliers," and trained quality services personnel to assure that future procedure
revisions consider all procedure requirements.
The inspectors reviewed the new
procedure and verified that it encompassed
the Nuclear Safety Assurance Division
activities as required by the technical specifications.
In addition, the inspectors reviewed
training records and interviewed personnel to verify that all quality services personnel
received the training.
-9-
During these reviews, the inspectors noted that the licensee also committed to perform a
surveillance to assure themselves that there were no other instances where procedures
were improperly canceled.
During a review of this activity, the inspectors noted that the
surveillance was only performed for the years of 1992, 1993, and 1996. When
questioned about the sampling selection, the licensee stated that these years were
chosen because
most procedure cancellations occurred during the 1992, 1993, and
1996 years.
Through further reviews, the inspectors found that a second surveillance
was performed that included 1995. To verify that no procedures were improperly
canceled, the inspectors reviewed the listing of procedures canceled in 1992, 1993, and
1996 and independently sampled 15 canceled procedures for these years.
In addition,
since the licensee did not check 1994, the inspectors reviewed a listing of procedures
canceled in 1994 and independently sampled procedure cancellations for that year. All
canceled procedures were found to be acceptable.
Since 1993, the time that this violation occurred, the licensee developed a data base
called the "Requirements Tracking System (RTS)." This system provided assurance
that
all requirements and commitments were properly incorporated into plant procedures.
The inspectors reviewed this data base and determined that the new process should
prevent recurrence of this violation.
During a review of the canceled procedures, the inspectors noted that canceled
Procedure 15.1.13, "Fire Suppression Systems Tamper Switch Operability," was
canceled based on the fact that tamper switches were not necessary ifthe valves
were locked open.
However, the inspectors also noted that Amendment 45 of the Final
Safety Analysis Report (FSAR), Appendix F, "Fire Protection Evaluation," Tables F.2-1
and F.3-1, specified a monthly checking requirement for control valves (F.2-1) and vent
and drain valves (F.3-1).
In addition, the inspectors noted that Amendment 51 to FSAR
Appendix F, Section F.5.2.3.1c, specified that manual, power operated, and automatic
valves in the flow paths be checked for the correct position once per quarter.
As the
result of procedure reviews and interviews, the inspectors determined that the control
valves were being checked on a quarterly basis in accordance with Procedure 15.1.18,
"Fire Suppression Systems Valve Alignment," and the vent and drain valves on a
refueling cycle basis in accordance with Procedure 3.1.1, "Master Startup Checklist," and
Procedure 2.8.7, "Fire Protection System."
Since the control valves included selected
manual, power operated, and automatic valves, the inspectors determined that
Amendment 51 was not adequate
in that it did not change FSAR Table F.2-1.
In
addition, since FSAR Table F.3-1 still specified monthly checking of vent and drain
valves and the licensee was only checking the valves every refueling outage (18
months), Amendment 51 failed to revise Table F.3-1 to reflect the new checking
frequency.
10 CFR 50.71(e) requires the FSAR update to include the latest material developed.
The failure to update FSAR Table F.2-1 to be consistent with Procedure 15.1.18
and FSAR Section F.5.2.3.1c and to update FSAR Table F.3-1 to be consistent
with Procedures
3.1.1 and 2.8.7 would be considered two examples of a violation of
I
-10-
However, due to a comprehensive
program that was underway to
update the FSAR, the NRC believes that these FSAR discrepancies
likelywould have
been identified through this program.
Therefore, the NRC is exercising discretion in
accordance with Section VII.B.3 of the Enforcement Policy.
ncl
i
The new nuclear safety assurance
division procedure properly addressed
the Technical
Specification procedural requirements.
In addition, licensee-conducted
surveillances
were effective in assuring that other canceled procedure activities were properly
conducted.
However; there was a failure to update the FSAR fire protection sections.
08.3
los
r s Ived
e
50-3
9 2 2-0: Two examples where significant problem
evaluation requests failed either to provide a root-cause analysis or to provide a
root-cause analysis of sufficient depth.
B;~ck
ourud
In NRC Inspection Report 50-397/96-202, the NRC identified two significant problem
evaluation requests that either did not have a root-cause analysis performed or had an
inadequate root cause analysis.
While the inspectors considered that the problem
evaluation requests were properly evaluated, they were concerned that the licensee did
not adhere to their root-cause analysis procedure.
The NRC reviewed Significant Problem Evaluation Request (SPER) 296-0519, which
documented an adverse trend offour problem evaluation requests written over a 4-week
period. The four problem evaluation requests documented errors in operating mode
changes and missed technical specification surveillance requirements.
The NRC
determined that SPER 296-0519 failed to followAdministrative Procedure 1;3.48, "Root
Cause Analysis," Revision 6.
The NRC reviewed SPER 296-0285, which documented an adverse trend in valve and
switch positioning. The NRC noted that the problem evaluation request did not have a
root-cause analysis performed, which the NRC considered to be a second example of a
failure to meet the requirements of the root-cause analysis procedure.
The inspectors reviewed Administrative Procedure 1.3.48, "Root Cause Analysis,"
Revision 6, and discussed the procedure with the licensee.
The licensee stated that this
procedure was intended to only provide guidance for performing a root-cause analysis.
Based on this review, the inspectors determined that Procedure 1.3.48 was properly
applied as a guidance procedure.
7
-1 1-
The inspectors discussed the root-cause analysis process with licensee personnel and
reviewed a paper that outlined the licensee's plans for root-cause analysis process
changes.
The licensee stated that a plant-wide initiative was being planned for additional
training on root-cause analysis to provide personnel with better skills. Based on
inspection findings, especially with respect to recurring events, the licensee
acknowledged that their root-cause analysis needed improvements.
The licensee stated
that their plan included identifying approximately 20 dedicated individuals to conduct
root-cause analyses; training this group in state-of-the-art root-cause analysis
techniques; and utilizing this group as team leaders for.root-cause analysis of significant
problem evaluation requests and other situations as required.
The licensee expected to
complete initial training by October 31, 1997.
~onli
o s
Root Cause Analysis Procedure 1.3.48 was found to be properly applied.
Efforts were in
process to improve the root-cause analysis program.
08.4
Closed
Unresolv
tem5 -397/962
-0: Failuretopreventtherecurrenceof
significant conditions that were adverse to quality.
08.4.1
S and
Circ
I
i
Lubri a in
il
um
Failur
/
~Ba lgqrourLd
The NRC identiTied multiple, recurrent failures of the ac standby circulating lubricating oil
pump motor-to-pump coupling. This safety-related pump, used to supply heated lube oil
to Emergency Diesel Generator DG2 for initial startup, failed on February 18, 1996. The
failure occurred in the motor-to-pump coupling. This failure resulted in a manual start
failure of Emergency Diesel Generator DG2 on February 20, 1996, during surveillance
testing.
While the motor-to-pump coupling was a contributor to this event, the starting of
the emergency diesel generator for mitigation of accident conditions was unaffected.
Review of this failure by the NRC identified that this coupling failed 2 months earlier and
that the motor-to-pump couplings also failed three times prior to 1991 and three
additional times since 1991 (not counting 1995 and 1996 failures). Following the 1991
failures, the licensee developed corrective actions that involved increased-frequency
of
alignment checks, the installation of flexible hoses, and replacing the coupling with a
different design coupling that was better suited to the operating conditions for the pump.
. The NRC found that these corrective actions, though considered effective to prevent
recurrence of the failures, were not properly implemented.
-1 2-
I s
c
rFoll wu
The inspectors reviewed Significant Problem Identification Report 296-0119 and
interviewed licensee personnel regarding the ac standby circulating lubricating oil pump
failures. The inspectors determined that the findings identified in NRC Inspection
Report 50-397/96-202 demonstrated that while the root cause and proposed corrective
actions were appropriate, the licensee failed to implement the corrective actions resulting
in additional failures of the motor-to-pump coupling. Specifically, while the licensee
initiallyperformed increased frequency alignment checks over a 3-year period (after
1991), these alignment checks were subsequently stopped.
In addition, the flexible
hoses, which were intended to reduce induced piping stresses
on the pump motor
assemblies,
were never installed apparently due to budget considerations.
Furthermore,
while the licensee investigated and identified new couplings that were more robust for
the pump operating conditions, the couplings were not purchased
and the in-stock
couplings continued to be used.
The inspectors determined that the licensee's corrective
actions were not fullyimplemented.
The inspectors considered the failure to fully implement the corrective actions for the
motor-to-pump coupling to be the cause of repeated coupling failures.
Appendix B, Criterion XVI, requires nonconformances
to be promptly corrected.. The
failure to promptly correct the coupling failures was considered to be the second example,
of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-397/9713-01).
g~nc
i~s'he
corrective actions to resolve continuing failures of the motor-to-pump coupling on the
ac standby lubricating oil pump were not fully implemented.
This was considered to be
an example of a violation of 10 CFR Part 50, Appendix B.
08.4.2 Valve and Swi ch Posi ionin
Error
~Back round
The NRC found that valve and switch positioning errors were identified as a significant
issue in Problem Evaluation Request 296-0285. This problem evaluation request
identified an adverse trend with valve and switch positioning errors that had occurred
since 1995. The NRC was concerned that four recent problem evaluation requests and
~ three gold cards indicated that these mispositioning errors were still occurring and that
the'licensee's
actions to correct these errors were ineffective.
The inspectors noted that the licensee issued Significant Problem Evaluation
Request 296-0285 on April 19, 1996, to identify an adverse trend. This problem
evaluation request identified 26 instances of valve and switch mispositioning errors that
-1 3-
occurred in 1995 due to personnel error. To determine the effectiveness of the
corrective actions from this problem evaluation request, the inspectors requested
a listing
from the plant tracking log of all valve and switch mispositioning errors since January 1,
1997.
The licensee provided the inspectors a listing of ten problem evaluation requests
covering the time period of January 28 through July 18, 1997, and a gold card, dated
December 13, 1996, that identified mispositioning errors. The inspectors reviewed these
problem evaluation requests and determined that nine of these requests and the gold
card represented
additional examples of valve and switch mispositioning errors that were
caused by personnel error. Furthermore, the inspectors noted that the licensee issued a
second significant problem evaluation request (297-0072) on March 20, 1997, which
again identified an adverse trend in human performance that involved mispositioning
errors.
The inspectors determined that the licensee was taking appropriate actions to
resolve this personnel error problem.
Conclusions
Corrective actions to correct and prevent recurring personnel error induced valve and
switch mispositioning errors were in progress.
The continuing personnel errors were
being appropriately identified and trended by the licensee for corrective action.
08.4.3
Cl ar nce 0 der an
Procedure
P oblem
B;~kr~un
The NRC found that clearance order and procedure problems were identified in
Significant Problem Evaluation Request 296-0308 dated April29, 1996. This problem
evaluation request identified an adverse trend relative to 12 problem evaluation requests
associated with clearance orders and procedures.
The NRC reviewed a sample of
problem evaluation requests to determine the extent of the issue and to determine ifit
was resolved.
As the result of this review, the NRC identified 15 additional problem
evaluation requests that appeared
to involve clearance order or procedure problems that
occurred since Significant Problem Evaluation Request 296-0308 was issued.
The
clearance order and procedure problems involved inadequate clearance orders and
failures to follow clearance orders procedures.
Ins e
or Followu
Since the issuance of Problem Evaluation Request 296-0308, the inspectors determined
that 12 problem evaluation requests identified instances of personnel errors involving a
failure to followclearance orders or plant procedures and a failure to issue adequate
clearance orders.
Four of these problem evaluation requests were considered to be
significant. The inspectors noted that the licensee issued Significant Problem Evaluation
Request 297-0116 on March 28, 1997, that identified the continuing trend regarding
inadequate clearance orders.
k
-14-
The inspectors noted that seven problem evaluation requests (296-0364, 296-0415,
296-0428, 296-0497, 296-0650, 296-0832, and 297-0072) involved the failure to adhere
to clearance orders or plant procedures and five problem evaluation requests (296-0351,
296-0537, 296-0775, 297-0073, 297-0016) involved inadequate clearance orders.
The
inspectors determined that the licensee identified the problem (i.e., issued Significant
Problem Evaluation Request 296-0308), and had corrective actions in progress.
(~nulligs
Actions were in progress to correct recurring personnel errors involving a lack of
equipment clearance procedure adherence
and the issuance of inadequate clearance
orders.
The recurring personnel errors were being appropriately identified and trended
by the licensee for corrective actions.
08.4.4
El c r'cal Wirin and Termi a i n Error
~Back round
E
The NRC found that wiring and termination errors were identified in Significant Problem
Evaluation Report 296-0693 dated September 23, 1996. This problem evaluation
~ request identified an adverse trend relative to five problem evaluation requests
associated with reversed terminations.
The NRC reviewed the five problem evaluation
requests and determined that it appeared that the licensee's efforts failed to prevent
recurrence of these errors.
The NRC based their conclusion on the fact that the licensee
limited their analysis to work specifics (i.e., only addressed
each speciTic issue and did
not address the underlying cause).
ns ec or Followu
The inspectors reviewed the problem evaluation requests that documented these wiring
and termination errors. The inspectors also reviewed a listing of problem evaluation
requests involving wiring errors for the last year. This listing identified 16 problem
evaluation requests that involved wiring errors.
The inspectors selected 6 problem
evaluation requests from this list for further review. As the result of this review, the
inspectors identified 2 Nonsignificant Problem Evaluation Requests 297-0157 and
297-0414 involved wiring errors that were due to human error. The remaining wiring
error issues involved either drawing errors from original construction or unrelated design
- errors.
Furthermore, the inspectors were informed that during the period of 1989 through
June 1, 1996, there were only 11 wiring errors that involved human performance errors.
When combined with the 2 personnel errors identified by the inspectors, this meant that
there were 13 wiring errors attributed to personnel errors since 1989. As the result of this
review, the inspectors concluded that the wiring and termination issues did not represent
a degrading personnel error issue in this area.
However, it also indicated that wiring
errors had existed in the plant.
Discussions with licensee personnel indicated that while
electricians and instrumentation and control technicians are trained and required to
-15-
check for wiring errors during their work activities. The inspectors also noted, however,
due to the development of problem evaluation requests that identified wiring errors and
the lowered threshold for writing such problem evaluation requests, the licensee was
continuing to identify and correct such issues.
@on~el i~ion
Corrective actions to address the reversed termination of electrical equipment and wiring
errors were appropriate to the cause.
08.4.5
Sho
i
ofElecricalT rmin Is
~Back rc
n
The NRC found three shorted terminal events that were identified in Problem Evaluation
Requests 296-0222, 296-0692, and 297-0039.
These events involved: the incorrect
connection of test equipment during equipment troubleshooting causing an average
power range monitor to be shorted to ground (296-0222 dated March 27, 1996); the
inadvertent shorting of terminals with test leads while attempting to take voltage
measurements
during a calibration (296-0692 dated September 23, 1996); and the
shorting and subsequent failure of a rod block monitor power supply caused by dropping
a screwdriver into the panel during a calibration (297-0039 dated January 13, 1997).
The NRC also noted that while two additional problem evaluation requests (296-0227
and 296-0293), which were referenced in Problem Evaluation Request 296-0692,
identified similar events, they did not involve the taking of voltage measurements.
Based
on their review of these three events, the NRC concluded that the licensee did not
broaden their corrective action efforts to solve the problem. As a result, the'NRC
concluded that shorted terminal events due'to personnel errors continued to occur.
Ins ec or Followu
As documented in NRC Inspection Report 50-397/96-202, the inspectors noted that the
three events involved different causes.
In addition, the. inspectors noted that Problem
Evaluation Requests 296-0227 and 296-0293 involved circuit trips that occurred due
opening of a panel and the removal of a panel and, therefore, did not involve shorted
terminals.
The inspectors noted that the initiators of these events were diverse and that the only
common cause was personnel errors.
Based on these reviews and interviews, the
inspectors determined that the licensee's corrective actions were appropriate.
These
included: suppling personnel with insulated tools; developing a written policy to require
the use of insulated tools; insuring that new power supplies have terminal covers; and
individual counseling regarding the use of proper tools for the job.
Furthermore, the
inspectors considered these corrective actions to be adequate
and effective toward
reducing the potential for personnel errors during such maintenance activities.
-1 6-
~Co clusions
Actions to address the occurrence of shorting electrical terminals during the performance
of maintenance or surveillance activities were adequate and effective toward preventing
a recurrence of the events.
08.4.6
Con ainmen Amo
h ric
onrolDesi nD ficie
~Bckc~oI
Significant Problem Evaluation Request 297-0020 documented exceeding the technical
specification limitfor bypass flow from the drywell to the suppression chamber while
operating containment isolation valves in the containment atmosphere control system to
restore a nitrogen blanket in containment.
This event occurred following an
enhancement
to the operating procedure to improve the operator's ability to repressurize
the containment atmosphere control system using valve test switches.
During their
review of this problem evaluation request, the NRC found that two apparently similar
events occurred in the past.
The first event, which occurred in 1992 and was
documented
in Nonconformance Report (NCR) 292-0231 dated March 20, 1992,
involved the removal of a valve test push button from the control circuitry to remove a
single failure vulnerability. A new test switch was subsequently installed that was single
failure proof. The second event, which occurred in 1993 and was documented
in
Problem Evaluation Request 293-0346 dated March 31, 1993, involved the discovery
that performance of a periodic instrument surveillance test caused drywell to suppression
chamber bypass flowto exceed technical specification limits. As the result of these
reviews, the NRC concluded that the inadvertent introduction of a new initiator for the
event through enhancement of the nitrogen blanket operating procedure was not
something that could have been reasonably prevented through the problem evaluation
request investigation that was conducted in 1993. The NRC also concluded, however,
that these events were apparently caused by an uncorrected design problem.
The inspectors noted that the first event (Problem Evaluation Request 292-0231) did not
involve an actuation of the containment atmospheric control system nor the initiation of
drywell to suppression chamber bypass flow. Th'e first event only postulated the
potential for a single failure of the valve test push button. As a result, the licensee took
, actions to modify the test switch to assure that the single failure vulnerability was
mitigated. While the second event did result in the initiation of a bypass flow condition, it
involved a problem with the surveillance procedures.
Since this surveillance was
normally conducted during refueling conditions, it had not been a problem in the past.
However, when the surveillance was performed during plant operations in an attempt to
shorten outage times, it caused
a bypass flow condition. The inspectors noted that the
technical specification limits were not exceeded during this event.
The third event
involved a revision to an operating procedure to simplify operator actions during the
-1 7-
nitrogen phase of containment atmospheric control system operation.
The procedure
revision was inadequate,
in that, when it permitted the use of the test switch to activate
the required containment isolation valves, it did not assure that power was removed
from those valves that could cause a bypass flow condition to occur. Though a bypass
flow did occur, this flowwas immediately terminated and the technical specification
limiting condition for operation was not exceeded.
Based on this review, the inspectors
determined that only two of these events involved an actual bypass flow to occur, that
these bypass fiows did not exceed the technical specification limiting condition for
operation,'that these events were not the result of a design error, and that the events
were caused by human errors pertaining to surveillance scheduling and the procedure
revision process.
The inspectors further determined that the corrective actions taken by
the licensee were appropriate for the circumstances
and adequate to prevent a
recurrence of the events.
These included:
revisions to Procedures
PPM 2.3.3.A and
2.3.3.B; a review of all procedures that involved the use of the test switch to assure that
the required valves were disabled; counseling of involved personnel; the conduct of a
"lessons learned" training for system engineers; and the addition of test switch operation
precautions in the operator training program.
C n lusion
The corrective actions that addressed
the inadvertent initiation of drywell to suppression
chamber bypass flowwere appropriate for the circumstances
and adequate to prevent a
recurrence of the events.
08.4.7 Timel Iniia ion of Proble
valua ion
e ue
s
BaakraBrou
d
The NRC identified two instances where problem evaluation requests were not written to
identify plant problems.
The first instance involved a failure to initiate a problem evaluation request by operations
personnel when a quality assurance
audit identified anomalous plant equipment
operation.
This instance was documented in Problem Evaluation Request 296-0489.
While the problem evaluation request described three anomalous equipment operation
instances, the NRC considered one to be the subject for a problem evaluation request.
This instance involved the inadvertent start of the reactor recirculation pump during
"testing activities on June 10, 1996. The NRC concluded that the reactor recirculation
pump start resulted in an unplanned entry into a technical specification limiting condition
for operation and that this condition met the threshold for the initiation of a problem
evaluation request.
The second instance, involving radiation protection department personnel, identified the
use of gold cards in lieu of problem evaluation requests to identify plant problems an'd a
continuing failure to correct an inadequate radioactive material labeling problem. The
0
-18-
use of the gold cards was documented
in Problem Evaluation Request 296-0357 dated
May 1996. The NRC noted that the licensee's corrective actions for this problem were
not effective as evidenced by the issuance of Problem Evaluation Request 296-0839
dated December 1996. This second problem evaluation request again identified that
gold cards were being used to identify problems and, in particular, documented that gold
cards were used to identify the inadequate labeling of radioactive materials.
The NRC
noted that this problem evaluation request did not determine why previous corrective
action from seven problem evaluation requests concerning inadequate labeling of
radioactive materials was not identified as an adverse trend by the radiation protection
staff through its independent review of the gold cards.
The NRC concluded that the
licensee's corrective actions were ineffective toward correcting the use of gold cards and
the inadequate labeling issues.
Ins ec
r Followu
An m
I
I n
ui m n
r i: The inspectors noted that operations personnel
concluded that a problem evaluation request was not necessary for the inadvertent
reactor recirculation pump start because the problem evaluation request threshold was
not reached.
However, the inspectors'eview of Technical Specification 3.4.1.4/4.4.1.4
indicated that temperature differentials were required to be taken within 15 minutes prior
to startup of an idle recirculation loop. Therefore, the inspectors determined that the
event did result in the inadvertent entry into a technical specification limiting condition for
operation and that the required temperature measurement
surveillance was not
performed prior to pump start.
Furthermore, the inspectors noted that the lack of a
problem evaluation request resulted in a failure to develop corrective actions that
addressed
such areas as: the initial failure to note the unplanned entry into a technical
specification action statement; the failure of the testing circuit; whether similar testing
needed to be performed for other system maintenance or modifications; and test
procedure revision. The inspector's review of Procedure 1.3.12, "Problem Evaluation
Request," Revision 24, indicated that the guidelines for initiation of a problem evaluation
request stated, in part, that a problem evaluation request be issued for unexpected
operating events and for deficiencies involving the technical specifications.
ad'o
o ec io
S a
b e s'he inspectors reviewed Problem Evaluation
Request 297-0485, issued for the improper storage and labeling of radioactive material
containers.
The inspectors found that Significant Problem Evaluation Request 297-0537
was written to document an adverse trend in the radiological protection program.
Based
on,these reviews, the inspectors determined that the licensee was not fullyeffective at
improving the radiation protection staffs knowledge of the gold card program and its
relation to the problem evaluation requests.
In addition, the inspectors noted that the
licensee identified problems with correcting the inadequate radioactive material labeling
problems.
The inspectors were informed that the licensee hired a contractor to assist in
the development of a root cause analysis for Problem Evaluation Request 297-0537.
To
control the labeling issues, the inspectors noted that the licensee initiated daily plant
-1 9-
walkdowns to identify inadequate labeling conditions until the root cause analysis and
corrective actions for this problem could be developed and implemented;
The inspectors considered the failure to provide adequate corrective actions to
identify the inadvertent start of the reactor recirculation pump to be contrary to
the requirements of 10 CFR Part 50, Appendix B, Criterion XVI. 10 CFR Part 50,
Appendix B, Criterion XVI, requires nonconformances
to be promptly identified and
corrected.
The failure to promptly identify and correct a nonconformance was
considered to be the third example of a violation of 10 CFR Part 50, Appendix B,
Criterion XVI (50-397/9713-01).
Conclusi ns
There was a failure to issue a problem evaluation request that would have promptly
identified and provided corrective actions for the inadvertent start of the reactor
recirculation pump. This item was considered to be an example of a violation of
10 CFR Part 50, Appendix B. Corrective actions to control a lack of documentation of
issues in problem evaluation requests and to resolve the inadequate labeling of
radioactive materials were in progress.
C
se
I s e
i
Followu
I
m
0- 97/
-: Correctiveaction program
timeliness goals not met.
~B:kcCrourrd
As documented in NRC Inspection Report 50-397/96-202, the NRC noted that several
problem evaluation requests were initiated to identify untimely resolution of problem
evaluation requests and their associated
corrective actions.
Problem Evaluation
Requests 295-0915 (August 1995), 296-0272 (April 1996), and 296-0735 (October 1996)
were initiated to determine why several problem evaluation requests were not
dispositioned within 30 days.
Problem Evaluation Request 296-0709 (October 1996)
was initiated to determine why significant problem evaluation requests were not
dispositioned within 14 days.
In addition, Problem Evaluation Requests 297-0027 and
297-0043 (both January 1997) were initiated to determine,why corrective actions were
not properly dispositioned or implemented when required.
s ec or Followu
The inspectors reviewed the reports that the licensee was using to track problem
evaluation request resolutions and corrective action dispositions.
The existence of these
tracking reports was evidence that the licensee was aware of their problem evaluation
request timeliness problems and was taking actions to correct the problems.
The
inspectors noted that the licensee issued weekly reports to all management
personnel
that designated the number of late problem evaluation requests and provided information
regarding the problem evaluation requests that would be coming due during the next
-20-
week.
The inspectors reviewed these reports for the weeks of July 7, 14, and 24, 1997,
and noted that late reports and reports coming due during the next week were being
dispositioned.
The inspectors determined that this reporting system was effective at
addressing and assuring that late problem evaluation requests were being resolved.
The
inspectors also reviewed the process that addressed
overdue corrective action issues.
The inspectors found that the licensee was tracking the overdue corrective actions
through the use of a monthly trending report and departmental "annunciator panel"
reports.
As an example of this tracking activity, the inspectors found that Problem
Evaluation'Request
297-0046, issued on January 15, 1997, identified a trend in late
corrective actions that was attributed to engineering.
Review of these reports by the inspectors indicated that the late report trend and the
overdue corrective action trends were leveling offwith some evidence of a
decreasing trend. This was notable considering that the number of problem evaluation
requests were increasing.
To further improve their process, the licensee stated that
they were implementing the use of electronic problem evaluation request resolutions
The use of this system would provide quicker response,
a user friendly system, and
provide an effective tracking system.
In addition, they were considering revising
Procedure PPM 1.3.12A, "Processing of Problem Evaluation Requests," to change the
problem evaluation request disposition times from 14 days to a more realistic 30 days.
NI8
Miscellaneous INaintenance Issues
M8.1
Clos d V'ola 'o
0- 9
96 1-: Failure to followmodification and scaffolding
procedures.
Ba~-kcCk~u
The NRC found three examples where plant modifications were performed using the
technical evaluation process instead of the project modification record or minor
modification processes
as required by procedure.
The NRC reviewed Plant Procedure
Manual
1 4.1, "Plant Modifications," Revision 22, which was the governing procedure for
the implementation of permanent plant modifications. The procedure allowed the use of
a technical evaluation request to perform certain permanent plant modifications, which
were considered to be equivalent changes.
The NRC reviewed Technical Services
- Instruction Tl 1.2, "Equivalent Change Evaluations," and determined that the equivalent
change process was not to be used for complex plant modifications or when formal
calculations were significantly impacted.
Based on these procedures, the three
examples were considered to be violations.
In addition, the NRC identified a violation where the licensee failed to followthe plant
scaffolding procedure for unsecured scaffolding stored in safety-related plant areas.
The
I,
i
-21-
NRC reviewed Maintenance Programs and Procedure 10.2.53, "Seismic Requirements
for Scaffolding, Ladders, Man-Lifts, Tool Gang Boxes, Hoists, and Metal Storage
Cabinets," Revision 14. The NRC determined that the procedure required that all
scaffolding be left in an acceptable seismic configuration and, ifit did not meet
procedural requirements, that an engineering evaluation be performed.
There were no
engineering evaluations performed for the unsecured scaffolding identified by the NRC.
In
rFol w
The inspectors determined that the violations occurred due to procedure weaknesses,
which were identified by the licensee as the root-cause for the violations. The inspectors
reviewed Plant Procedure Manual 1.4.1, "Plant Modifications," Revision 23, which the
licensee revised to clarify when an equivalent change could be used in place of the
modification procedure.
The inspectors found that the revised procedure contained
checklists and guidelines to aid in determining when an equivalent change could be
used.
In addition, the inspectors found that a 10 CFR 50.59 screening was required for
each equivalent change.
The inspectors determined that the procedure was adequate to
preclude repetition of the violations.
The inspectors reviewed Maintenance Program and Procedure 10.2.53, "Seismic
Requirements for Scaffolding, Ladders, Man-Lifts, Tool Gang Boxes, Hoists, and Metal
Storage Cabinets," Revision 6, which the licensee revised to clarify scaffolding storage
requirements.
The inspectors found that the procedure contained the requirement to
contact engineering ifstorage of scaffold components was found piled in safety-related
areas of the plant. The procedure also required that engineering evaluate the condition
and provide a 10 CFR 50.59 review for each request.
In addition, discussions with the
NRC resident inspector indicated that no additional scaffolding problems were identified
during their plant tours.
The inspectors determined that the revised modification procedure was adequate to
preclude repetition of this example of the violation. In addition, the inspectors determined
that the revised scaffolding procedure provided clarification that would preclude repetition
of this example of the violation.
-22-
Miscellaneous Engineering Issues
E8.1
Cl
e
ns ec ion Followu
I em 397/ 604-0:
Use of Generic Letter 89-10 valve
factors for operability determinations.
~Bck round
During closure of the Generic Letter 89-10 motor-operated valve program, the NRC
noted that the licensee had occasionally used less conservative valve factors than those
justified under Generic Letter 89-10 to demonstrate the operability of a marginal valve.
None of these examples were considered to constitute an immediate operability problem.
However, the NRC was concerned that use of the lower valve factors was not adequately
supported by test data and may under predict the thrust required to operate the valve
under design basis conditions.
In general, the licensee's motor-operated valve program
did not specify minimum criteria (valve factors or other parameters)
to be used when
assessing
operability.
Ins ec or
ollowu
The licensee revised Procedure MES-10, "Motor-Operated Valve Sizing and Switch
Settings," Revision 0, via Temporary Change Notice 96-192, to include a definitive guide
for evaluating motor-operated valve operability. The new operability criteria stipulated
how valve factors, stem factor degradation, packing loads, rate of loading, and degraded
voltage factors should be selected in the assessment
of operability. The inspectors
reviewed the revised criteria and considered the new operability criteria to be consistent
with Generic Letter 89-10 and good engineering practice.
E8.2
CI
ed
Unre
Ived
m 5 -39
961
-02: Determination of the safety-related status of
the reactor core isolation cooling system, which was downgraded from safety related to
nonsafety related in 1985.
Bac
rou d
The NRC identified that the reactor core isolation cooling system was downgraded from
a safety-related to a nonsafety-related
status in 1985, which changed the seismic
qualification of the system from seismic Category
I to nonseismic.
This downgrade was
performed due to a modification to the automatic depressurization
system, which allowed
the safety function of the reactor core isolation cooling system to be enveloped by this
system.
The NRC noted that Chapters 3, 5, and 7 of the FSAR specified that the reactor
core isolation cooling system components were still considered seismic Category
I and
Table 3.2-1 of the FSAR specified that the reactor core isolation system was quality
Class
I and Seismic Class I. After discussions with the licensee, the NRC.noted that this
downgrade was not approved.
This issue was referred to the NRC program office as
-23-
Task Interface Agreement 96-TIA-005 to determine whether the licensee's downgrade
effort was appropriate.
Ins ec or
ollowu
The licensee submitted Safety Analysis Report Change Notice SCN 85-195, dated
October 4, 1985, to the NRC to revise the FSAR and technical specifications to reflect
the reactor core isolation cooling system downgrade from safety related to nonsafety
related.
The inspectors reviewed this submittal and found that the 10 CFR 50.59 safety
evaluation, dated June 28, 1985, determined that there was no unreviewed safety
questions associated with the downgrade.
The submittal stated that the automatic
depressurization
system combined with the low pressure injection systems provided the
same function previously accomplished by the reactor core isolation cooling system.
The
inspectors also noted that the plan was to delete the reactor core isolation cooling
system from the technical specifications and Chapter 15 of the FSAR, where it was
specified as the backup system to the high pressure core spray system.
The inspectors
reviewed the May 2, 1989, letter from the NRC to the licensee and found that the NRC
denied the application for a technical specification amendment submitted in Change
Notice SCN 85-195.
On January 31, 1997, in response to Task Interface Agreement 96-TIA-005, the NRC
program office concluded that the downgrading of the reactor core isolation cooling
system was unacceptable.
This response stated that the reactor core isolation cooling
system was a replacement for the high pressure core spray system during limited times
when the high pressure core spray system was inoperable.
Therefore, during this
limiting condition for operation, as specified in Technical Specification 3.7.3, the reactor
core isolation system was considered part of the emergency core cooling system
replacing the high pressure core spray system.
In addition, the reactor core isolation
system was originally assumed
to mitigate the consequences
of the loss of all feedwater
accidents in Section 15.2.7 of the FSAR and was con'sidered to be a coping system for a
station blackout event.
Finally, the staff concluded that the safety-related function of the
reactor core isolation cooling system was not enveloped by the automatic
depressurization
system since the automatic depressurization
system was considered as
a last resort system because of the transient effects associated
with its actuation.
Based on the NRC determination that the reactor core isolation cooling system was
safety related, the licensee prepared Problem Evaluation Request 297-0491, dated
May 29, 1997, to determine the operability of the system and reclassify the system as
safety related.
The inspectors reviewed Revision
1 of the followup assessment
of
operability, which was part of the problem evaluation request.
The followup assessment
of operability determined that the system %as operable but nonconforming.
The system
was determined to be nonconforming because the system was safety related and the
-24-
activities implemented following the reclassification in 1985 (e.g., modifications) were not
in conformance with the original license requirements.
The inspectors noted, however,
that the licensee had maintained the technical specification requirements for the reactor
core isolation cooling system, which included periodic testing. The inspectors also noted
that Chapter 7 and Appendix 15A of the FSAR indicated that the reactor core isolation
cooling system was used to mitigate the consequences
of the control rod drop accident.
The inspectors noted that the followup assessment
of operability contained an
assessment
of the changes that were made to the system components after the
downgrade.
The inspectors determined that the portions of the reactor core isolation
cooling system required to maintain the integrity of the reactor coolant pressure
boundary and to provide containment isolation remained safety related and that their
classification was not changed.
The remaining equipment was reclassified as
nonsafety related.
Documentation to support the seismic qualification of equipment
that was designated as nonsafety related was not required nor maintained.
The
components reclassified to nonsafety related were not maintained to the requirements
of a 10 CFR Part 50, Appendix B, quality program, but instead to an augmented quality
program.
The augmented quality program allowed parts and components to be
purchased commercially (i.e., from a non-Appendix B supplier) and were not required to
be dedicated.
The inspectors reviewed the insewice test program for the reactor core isolation cooling
system to determine ifany changes were made due to the downgrade.
The inspectors
found that the licensee revised the inservice test program in December 1994 when the
program was upgraded for the second 10-year interval to the 1989 Edition of ASME
Section XI. At this time, the licensee took advantage of the downgraded reactor core
isolation cooling system and changed the program by deleting valves that were
considered a part of the downgrade effort. The valves excluded from the inservice test
program included Check Valve RCIC-V-11, a suction valve in line from the condensate
storage system; Check Valve RCIC-V-086, a suction'valve for the RCIC water leg pump;
Check Valve RCIC-V-21, a miniflowvalve from the main pump; and Motor-Operated
Valve RCIC-V-59, a discharge valve from the RCIC pump. The inspectors reviewed
testing for these valves and determined that while the valves were deleted from the
program, they remained operable because they were being tested as a part of other
surveillance testing activities. The inspectors also noted that containment isolation valve"
test requirements for some reactor core isolation cooling valves were modified to
measure the close only function to ensure containment integrity, where previously their
function had been to both close for containment integrity and open for reactor core
isolation cooling injection. The inspectors reviewed the test procedures for testing the
containment isolation valves and found that in 1985, Procedure 7.4.7.3.3, "Plant
Operability Test," Revision 4, required that the containment isolation valves be stroked in
both the open and closed direction to assure that stroke times were within the specified
acceptance
criteria as required by the ASME code.
The inspectors noted that current
Procedure OSP-RCIC/IST/Q702, "RCIC Valve Operability Test," Revision 1, required that
the valves be stroked in both the open and closed direction, but only specified an
-25-
acceptance
criterion for the closing direction. The inspectors found that there were six
containment isolation valves that did not have an acceptance
criteria for opening
stroke-time testing. These valves included RCIC-V-13, head spray isolation valve;
RCIC-V-19, minimum-flow to suppression
pool isolation valve; RCIC-V-28, auxiliary
cooling to suppression
pool isolation valve; RCIC-V-31, suppression
pool to RCIC
suction; RCIC-V-40, turbine exhaust to suppression
pool isolation valve; and RCIC-V-66,
head spray isolation valve. The inspectors also noted that Valve RCIC-V-45, the turbine
steam supply isolation valve, was no longer tested for either opening or closing stroke
times.
10 CFR 50.55a(f) requires inservice tests of valves required for safety to assure that the
valves comply with the requirements of Section XI of the ASME code.
Section XI of the
ASME Code requires that acceptance
criteria be developed for valve stroking tests so
that stroke-time degradation can be identified. The failure to develop appropriate
acceptance
criteria for the opening stroke-time testing for six reactor core isolation
cooling system valves and the failure to test the stroke times for Valve RCIC-V-45 is
considered to be an apparent violation (50-397/9713-02).
The inspectors reviewed the corrective actions required to reclassify the previously
downgraded reactor core isolation cooling system components to safety related.
The
corrective actions were documented
in Problem Evaluation Request 297-0491.
The
problem evaluation request identified 23 tasks that included establishing seismic
qualification; establishing environmental qualification; evaluating previous procurements,
substitutions, maintenance,
equivalent changes,
and plant modifications; and evaluating
and revising the inservice test program.
In addition, the inspectors reviewed the draft
reclassiflication plan and the schedule for completion.
The inspectors determined that
the licensee planned to complete the reclassiflication by the end of 1997. The inspectors
also determined that the reclassification plan was thorough.
The licensee stated that they were in the process of performing commercial grade
dedication on 130 components or parts that had been purchased corn'mercially and not
through a 10 CFR Part 50, Appendix B, supplier.
The inspectors reviewed five
commercial grade dedication packages that the licensee had recently prepared.
The
inspectors concluded that the five packages were adequate.
The inspectors reviewed
eight modification packages that were prepared between 1984 and 1996. The
inspectors found that for the modifications1o the safety-related parts of the system, the
components were purchased as safety-related components with seismic qualification.
The inspectors found one modification, which was in the downgraded portion of the
system.
Modification 92-161 added a pressure tap to the lube oil pressure switch on the
turbine skid. The inspectors found that there was no seismic analysis for this change in
the modification package.
-26-
The inspectors questioned the risk significance of the reactor core isolation cooling
- system and how it was categorized in the Maintenance Rule program.
The licensee
stated that they considered the reactor core isolation cooling system to be a risk-
significant standby system.
On December 23, 1997, the licensee responded to Task Interface
Agreement 96-TIA-005 and provided additional information relative to the use.of the
reactor core isolation cooling system.
This additional information indicated that the
reactor core isolation cooling system was not a safety-related backup for the loss-of-
feedwater event, was not an emergency core cooling system, and was not a coping
system for the station blackout event.
In addition, modifications to the automatic
depressurization
system allowed the system to envelop the functions of the reactor core
isolation cooling system and provide controlled reactor depressurization.
Therefore, the
licensee concluded that the automatic depressurization
system was not a last resort
system.
The NRC reviewed this response
and agreed with the licensee's positions
regarding these events.
However, the NRC also noted that the licensee's response
stated that the reactor core isolation cooling system should not have been downgraded
without NRC approval because
it was a backup to the high pressure core spray system
for the control rod drop accident.
The licensee also stated in this response that approval
of the reactor core isolation cooling system classification downgrade was not docketed
by the NRC.
10 CFR 50.59, "Changes, Tests, and Experiments," permits the licensee to make
changes to the facility and to procedures as described in the safety analysis report
without prior Commission approval, provided the change does not involve an unreviewed
safety question.
A proposed change shall be deemed to involve an unreviewed safety
question ifthe probability of a malfunction of equipment important to safety may be
increased.
The reactor core isolation cooling system was downg'raded from safety related to
nonsafety related without NRC approval.
Since this system was a backup to the high
pressure core spray system for mitigation of a control rod drop accident and applicable
testing and quality standards were not maintained, the downgrade may have increased
the probability of a malfunction of equipment important to safety.
Therefore, this
downgrade involved an unreviewed safety question and is considered to be an apparent
violation of 10 CFR 50.59 (50-397/9713-03).
CConcI IsIons
The reactor core isolation cooling system was downgraded from safety related to
nonsafety related.
While the system was found to be operable, it was also found to be
nonconforming.
The reclassification plan and schedule for returning the reactor core
isolation cooling system to safety related were thorough and timely. As the result of
I
-27-
these downgrade activities, six reactor core isolation cooling valves were not being
tested.
The failure to test these valves was considered to be an apparent violation of
Downgrading the system from safety related to nonsafety-related
apparently increased the probability of a malfunction of equipment important to safety
and was considered to be an unreviewed safety question.
This was considered to be an
apparent violation of 10 CFR 50.59.
lo
d Vio
i
-
7/ 11-: Failure to maintain plant design basis.
~Bck rou d
The NRC identified one example of a violation where plant configuration control was not
being maintained and two examples of the violation where the licensee failed to have
design analyses for the installed plant configuration. The first example was identified
when the NRC reviewed Technical Evaluation Request 96-0125.
This technical
evaluation request documented a modification to increase the clearances
at the lever
arm pivot for a valve operator by removing one of two washers.
The licensee had not
determined whether the new clearance met the vendor's clearance requirements.
The
two other examples of the violation were identified when the NRC reviewed calculations.
Calculation CMR-96-0128 analyzed a welded connection for a standby liquid control
system piping hanger but not the installed bolted connection.
Calculation CMR-95-0292
covered an all carbon steel and an all stainless steel piping configuration, but did not
cover the installed carbon/stainless
steel piping configuration..
In
o
ol owu
The inspectors determined that the licensee revised Calculation CMR-96-0128 to
reflect the actual bolted field installation.
In addition, the licensee revised
Calculation CMR-95-0292 to reflect the as-built carbon/stainless
steel pipe configuration.
The inspectors also determined that the valve vendor concurred with the washer removal
specified in Technical Evaluation Request 96-0125 and stated that, ifthe alignment at
the lever arm pivot could not be corrected, it was acceptable to use only one thrust
washer: The inspe'ctors concluded that the licensee had performed adequate corrective
actions for the three examples identified in the violation.
The licensee identified that the drawings were not revised to reflect the modified pipe
hanger configuration identified in the violation and acknowledged that this was a
weakness
in the design process.
To correct this weakness, the licensee revised
Technical Services Instruction Tl 1.2 to require tracking of document changes to ensure
drawings were revised promptly to reflect plant modifications. The inspectors noted that
Procedure EDP2.15, "Preparation Verification and Approval of Calculations," and
EDP2.11, "Field Changes," were revised to require that whenever calculations were
used to justify as-built configurations, sufficient information had to be provided to
describe how the calculation applied to the field configuration and to justify that the
calculation was still valid. Procedures
EI2.8, "Generating Facility Design Change
-28-
Process," and EDP2.50, "Generating Facility Minor Design Change Process," were
r'evised to require that whenever vendor information was used as a design input, the
vendor information should be taken from published vendor documents or obtained in
writing from the vendor.
The inspectors also reviewed the records of training for design
and system engineers that emphasized the importance of documenting the basis for
design changes and vendor concurrence.
E8.4
Clo
d Un
s
ved
I e
5 - 9 /9 201-0:
Discrepancies betweenresidual
heat
removal heat exchanger test analysis data and the FSAR.
B c
round
The NRC identified that the thermal performance monitoring test results for Residual
Heat Removal Heat Exchanger 1B, conducted on March 3, 1996, indicated that, the
standby service water system gained 60 percent more heat than the residual heat
removal system lost. Since the licensee determined that the maximum heat transfer rate
was 11 percent, the 60 percent heat transfer rate mismatch was unacceptable.
In
'addition, the NRC found that the licensee's evaluation used the standby service water
system's higher heat transfer rate, which was nonconservative,
and did not justify this
use.
The licensee attributed the error in heat transfer rates to defective instrumentation.
Based on the use of the higher heat transfer rate, the NRC concluded that the licensee
had not evaluated the test results to assure that the test requirements were met.
In
addition, the NRC believed that the instrumentation used to measure temperature and
flow data was suspected
to be inaccurate prior to the performance of the test.
The inspectors discussed the results of the March 3rd test with licensee personnel and
found that the test engineer suspected
a problem with the ultrasonic flowmeter used to
measure residual heat removal flow rate through the heat exchanger after the test had
been performed. After the test, the licensee inspected the installation of the ultrasonic
flow meter and determined that the instrument had.not been installed properly to ensure
coupling. of the transducer to the pipe. Since the standby service water side of the heat
exchanger used an accurate installed flow element, the licensee decided to use the less
conservative standby service water heat transfer rate to complete the evaluation.
Also,
the inspectors found that the licensee performed an additional performance evaluation of
" the. heat exchanger using the conservative heat transfer rate from the residual heat
removal side. The purpose of this evaluation was to compare the projected test results
to the minimum required heat removal rates.
The lower residual heat removal side heat
transfer rate and the design conditions contained in the FSAR were used to'determine
the most limiting design operating mode. The evaluation showed that the residual heat
removal heat exchanger was capable of handling the design and licensing basis heat
loads.
Based on the evaluation, the licensee concluded that the heat exchanger was
-29-
The inspectors reviewed Operating and Engineering Test Procedure 8.4.42, "Thermal
Performance Monitoring of RHR-HX-1Aand RHR-HX-1B," Revision 5, and noted a
number of procedural improvements.
The licensee revised the procedure to specifically
define acceptance
criteria, to require a functional test of the equipment prior to the start
of the test, and to provide direction on performing the evaluation using the most limiting
design conditions.
The inspectors noted that the licensee expanded the test acceptance
criteria to include a statement that the percent difference in the energy balance across
the heat exchanger should be less than 10 percent or within the accuracy of the test
instrumentation.
In addition, the inspectors noted that the revised procedure required the
analysis of the test results be compared with the design conditions, and have an
independent engineering review. The inspectors also reviewed the test results of the
March 28, 1997 performance tests and noted that differences in the heat transfer rates
between the standby service water side and the residual heat removal side were within
the acceptance
criteria.
Conc~i
The licensee performed an adequate evaluation of the March 3, 1996, residual heat
removal system test results and demonstrated that the results were within the design
basis.
E8.5
C osed
U
e olved
e
50-39 /96201-02'ailure to periodically update the FSAR as
required by 10 CFR 50.71(e).
~Bggfoi~d
The NRC identified five examples where the licensee failed to update the FSAR.
The first example involved the use of.design condition values for calculating the heat
removal capacity of the residual heat removal heat exchangers.
The calculation used a
standby service water flowvalue of 6900 gpm, whereas, FSAR Table 9.2-5 listed a flow
value of 7400 gpm.
While the licensee justified the adequacy of the 6900 gpm flow
value, the NRC determined that the licensee failed to update the FSAR to reflect the new
flow value.
The second example involved the inclusion of an incorrect figure in the FSAR.
Figure 7.3-10c, "Nuclear Boiler.System FCD (Functional Control Diagram)," was
. inconsistent. with General Electric Elementary Diagram 807E180TC.
Figure 7.3-.10c
contained control logic seal-ins and permissives that did not exist in the elementary
diagram.
The NRC determined that the actual as-built plant logic wiring was consistent
with the elementary diagram and not the FSAR functional control diagram.
-30-
The third example involved the in-place deactivation of the standby service water keep
full system.
This system was deactivated
in October 1993, however, the NRC
determined that FSAR, Section 9.2.7, was not updated to reflect this in-place deactivated
status.
The fourth example involved inconsistencies
between the flow values used in flow
balance test procedures and the values listed in FSAR, Table 9.2-5. Specifically, Flow
Balance Test Procedures 7.4.7.1.1.1, 7.4.7.1.1.2, and 7.4.7.1.1.3 used flow rates that
were less than those listed in the FSAR for five components cooled by the standby
service water system.
While the licensee justified in their calculations that, the flow
values used in the test procedures were adequate,
the NRC determined that the licensee
failed to update the FSAR to reflect the actual flow values used.
The fifthexample involved discrepancies
between the FSAR electrical system
description and electrical system calculations.
Specifically, emergency diesel generator
loads and direct current system (station battery) loads listed in the FSAR were
inconsistent with the loads used in various design calculations.
While the licensee
justified in their calculations that the load value discrepancies
did not affect system
operability or reliability, the NRC determined that the licensee failed to update the FSAR
to reflect the loading conditions for the emergency diesel generators and the direct
current sy'tem.
n
c rF liow
andb
rvic W
r
s e
ow o
e Residu
I
a
emoval Heat Exch
n
rs
The inspectors interviewed personnel and reviewed Problem Evaluation
Request 297-0042 to determine the reason that the FSAR and the plant procedures were
not in agreement with respect to the standby service water flow to the residual heat
removal system heat exchangers.
The inspectors also reviewed completed Flow Test
Procedures 7.4.7.1.1.1 and 7.4.7.1.1.2, Request For Technical Services 97-01-008, and
a draft version of Licensing Document Change Notice Form (LDCN) FSAR-97-008.
This
review was conducted to determine ifthe values used in the flow test procedures were
appropriate, ifthey involved any safety issues, and the corrective actions taken by the
licensee.
The inspectors noted that while FSAR, Table 9.2-5, documented
a flow of
7400 gpm, the procedures provided an acceptable flow range of 6900 to 7400 gpm. This
meant that a flow rate of 6900 gpm, which was less than the flow rate specified in the
FSAR, could be considered acceptable.
Further review by the inspectors indicated that
from about 1986 to 1990 the FSAR listed a flow of 6900 gpm. However, as the result of
a licensee conducted safety system functional audit on the standby service water system
in 1990, the FSAR was revised to increase the flow to 7400 gpm. This increase was
based on initial plant assumptions,
which stated that the standby service water inlet
temperatures from the spray pond was 95'.
However, further review by the inspectors
indicated that the worst-case design basis accident condition inlet temperature from the
spray pond was 88.7'.
Based on Calculation ME-02-92-245, the licensee
demonstrated that a 6900 gpm flow rate was adequate for an inlet temperature of90'.
I0
-31-
However, the inspectors also determined that this draft version of LDCN FSAR 97-008
did not clarify the confusion that was noted by the NRC team with respect to the
multiplicityof design temperature values.
As a result of the inspectors'bservation,
the
licensee considered revising the licensing document change notice. The inspectors
considered this to be an example of a lack of attention to detail when incorporating
changes into the FSAR in that while one section of the FSAR was revised, another
applicable section of the FSAR was not revised at the same time. Specifically, FSAR,
Section 9.2.7.2, referred to a note in FSAR, Table 9.2-5, that was deleted in 1990. While
the inspectors determined that the 6900 gpm flowwas properly justified,,they considered
the failure to update the FSAR to be contrary to the requirements of 10 CFR 50'.71(e).
Incorr
FS ': The inspectors reviewed the automatic depressurization
system
logic diagram and the clem'entary diagram.
As the result of this review, the inspectors
noted that Drawing 02B22-04, 23, 3, Sheet 3 of 6, "Nuclear Boiler System FCD," was
identical to Figure 7.3-10c in Amendment 51 of the FSAR. The inspectors also noted
that these diagrams included logic figures for "SEAL-IN 105 SEC AFTER INITIATIONOF
TDS (Timing Device)," "SEAL IN LOGIC 'C'," and "PERMISSIVE UNLESS LOGIC A 8 C
RESET SWITCH IS IN 'RESET'OSITION." Through discussions with licensee
personnel the inspectors noted that these logic functions did not exist on the plant
elementary diagram and that the plant was properly wired in accordance with the
elementary diagrams and not in accordance with the functional control diagrams.
The
inspectors determined that while the plant was properly wired in accordance with the
plant elementary diagram, the failure to update the figure in the FSAR was contrary to
the requirements of 10 CFR 50.71(e).
ea
iva ion of he
ndb
S rviceW erKee
Fu
S sem:
The licensee informedthe
inspectors that while the standby service water keep full system was deactivated
in 1993,
they did not implement a FSAR change until November 11, 1996. This was confirmed by
the inspector's review of LDCN FSAR-96-092.
The inspectors determined that the failure
to revise the FSAR within 24 months was contrary to the requirements of
S andb
ervice Wa er S s em Flow 8
I n es: The inspectors reviewed the Flow
Balance Test Procedures 7.4.7.1.1.1 and?.4.7.1.1.2
and noted the discrepancies
between the procedures and Table 9.2-5 of the FSAR. The components that had
incorrect flow rates were the low pressure core spray pump motor bearings, residual heat
removal pump seal coolers, and the high pressure core spray diesel generator, diesel
" generator room coolers, and pump room cooler. The inspectors also noted that while the
licensee's calculations supported the lower flows to these components, the failure to
update FSAR Table 9.2-5 to reflect these lower flow rates was contrary to the
requirements of 10 CFR 50.71(e).
-32-
Discr
anci
s B
een
he
nd Elec ric
I S ste
Calc
a i n: The inspectors
interviewed personnel and reviewed draft LDCN 97-000, LDCN FSAR-97-019, and
LDCN FSAR-97-035 to verify that the FSAR discrepancies
did not represent safety
issues.
The inspectors found that LDCN 97-000 made administrative FSAR changes,
which included an update to FSAR, Table 8.3-15; LDCN FSAR-97-019 provided a
FSAR correction to Table 8.3-18 to reflect the loading change from Distribution
Panel E-DP-S1/1D to E-DP-S1/1F; and LDCN FSAR-97-035 revised FSAR
Tables 8.3-4a, 8.3-4b, 8.3-5, 8.3-6, and 8.3-7 to be consistent with the battery loading
profile that was updated in Calculation 02.05.01.
The inspectors also found that the
changes made by LDCN 97-000 represented
another example of a lack of attention to
detail when incorporating changes to the FSAR, in that while one section of the FSAR
was revised and another section was not at the time.
In this case, the text section of the
FSAR documented
a voltage range up to 242 kV, whereas, Table 8.3-15 still reflected a
voltage range up to 240 kV.
These LDCNs represented
issues in which the acceptance
criteria in the surveillance
procedures was inconsistent with the data presented
in the FSAR and changes made to
the FSAR were inadequate
in that the changes did not correct all affected sections of the
FSAR. The inspectors determined that the FSAR discrepancies
did not involve any
safety or operability issues and that the failure to update the FSAR were further
examples'of a 10 CFR 50.71(e) violation (the first two examples involved fire protection
as discussed
in Section 08.2 of this report).
The inspectors were informed that the licensee initiated a FSAR upgrade project. The
licensee stated that development of this project was initiated in 1996 when the licensee
identified problems with the accuracy of the FSAR through the performance of eight
safety system functional audits during the 1988 to 1992 time period and through NRC
inspection findings. The licensee further stated that the completion date for this project
was August 1997.
However, the licensee later determined that more time was needed to
perform this upgrade and revised their estimates.
This project was finally initiated on
April 7, 1997, and had a projected completion date of March 6, 1998.
Review of the
schedules and milestones for this project by the inspectors indicate that it was about
20 percent complete and was being performed by contracting personnel.
The inspectors
also noted that this project willencompass
a review of all FSAR chapters.
Based on a
review of this program, it appeared that the program will be effective and would have
identified the issues identified by the NRC: The licensee has docketed this program in
their response to the NRC's request for additional information pursuant to
10.CFR 50.54(f) dated February 7, 1997, and to the open items identified in NRC
Inspection Report 50-397/96-202 dated June 16, 1997. Therefore, in accordance with
Section VII.B.3 of the Enforcement Policy, the NRC is exercising discretion and is not
taking formal enforcement action on these findings.
-33-
Q<~nlu.~ins
Multiple examples of FSAR inaccuracies were identified. White no safety issues or
operability issues were identified, these multiple examples were indicative of a failure to
update the FSAR. However, the implementation of a FSAR update program permitted
the exercising of enforcement discretion in accordance with the revised enforcement
policy.
E8.6
Closed
Ins ec 'on
oil wu
I ems
50-397/
2 1-03'0-397/96
01-
joOE::g
B
~
d
p
~Bc ~rd
The NRC identified errors between design requirement documents and the actual system
design configurations.
These errors included an omission regarding the backup power
source for the residual heat removal pumps, an incorrect description of the function of
the standby service water keep full pumps, which were abandoned
in-place, but were still
listed in the design basis document as an operable system (50-397/96201-03),
a lack of
detail regarding instrumentation and control requirements for the residual heat removal
pumps (50-397/96201-05), and incorrect listing of the automatic depressurization
system
valves that were actuated from the remote shutdown panel (50-397/96201-09).
Ins eco
Followu
The inspectors reviewed records pertaining to the design requirement document
program. The inspectors found that, as the result of the NRC findings, the licensee
issued Problem Evaluation Request 297-0044 to address the specific issues.
In addition,
the licensee recently initiated a design requirements document upgrade program.
The
inspectors noted that this program plan was to review all 21 system level design
requirement documents, which encompassed
29 nonsafety-related
and 19 safety-related
systems, and 6 topical level design requirement documents, which encompassed
11
safety-significant areas.
Each system engineer was provided packages of design
requirement documents for their assigned systems and the activity was being tracked by
the licensee's plant tracking log.
In the response to the open items identified in NRC
Inspection Report 50-396/96-201, the licensee committed to complete this program by
December 31, 1998.
0
-34-
E8.7
lo ed
n
c ion Followu
I e
50-397/96201-0:
Plant procedure did not reflect the
plant response to an under voltage condition.
~Back
ro
d
The NRC determined that Plant Procedure Manual (PPM) 4.7.1.9, "Loss of Power to
SM-8," did not describe the actual plant response to the tripping of Residual Heat
Removal Pumps 2B and 2C during an under voltage condition. The NRC also
determined that plant operators were knowledgeable of actual plant response and that
the licensee planned to revise the procedure to correct this omission.
ns
cto
F
II wu
E8.8
The inspectors verified that the licensee revised Plant Procedure PPM 4.7.1.9 by adding
Residual Heat Removal Pumps 2B and 2C to the list of breakers and equipment that
trip on a SM-8 under voltage.
In addition, the inspectors verified that Plant
Procedure PPM 4.7.1.8, "Loss of Power to SM-7," was also revised by adding Residual
Heat Removal Pump 2A and the low pressure core spray pump to the list of circuit
breakers and equipment that trip on a SM-7 under voltage. Through personnel
inter'views, the inspector's also verified that the residual heat removal pumps and the low
pressure core spray pump would automatically restart when power was restored to the.,
busses ifan initiation signal (e.g., an emergency core cooling system initiation signal)
occurred.
In addition, the inspectors concluded that since these pumps are usually not
operating during normal plant operations, the absence of these pumps on the
procedure's "Automatic Actions" listing did not have any effect on the operator's ability to
cope with the loss-of-power conditions.
I
nr
olv
m
-
7/
1- 7: Inadequate analysis of design pressure for
the automatic depressurization
system actuators
Backcaround
The automatic depressurization
system was designed such that nitrogen was supplied to
accumulators to keep the main steam safety relief valve actuators pressurized to
186 psig. The NRC found that the accumulators and main steam safety relief valve
actuators had no pressure relieving device. Therefore, as the drywell temperature
increased during accident conditions, the pressure within the accumulators and actuators
. would also increase and the overpressurizing of these components was possible.
Under
such accident conditions, the NRC postulated that the drywell temperature could reach
285'F and the pressure
in the accumulators and actuators would increase from 186 psig
to greater than 260 psig. The NRC also determined that even with the elevated pressure
and temperature
in the drywell, the pressure
in the accumulators/actuators
would remain
within the design pressure of the equipment.
However, the NRC also postulated that if
operators actuated containment spray, pressure
in the drywell would drop causing the
temperature induced higher pressure
in the accumulators/actuators
to exceed the main
0
-35-
steam safety relief valve actuator design pressure of 250 psig. The NRC noted that this
low drywell pressure condition was not recognized in the accident analysis.
In addition,
the NRC noted that Calculation 5.46.05, "Maximum and Minimum CIA (Containment
Instrument Air) System Pressure," evaluated the minimum and maximum pressures to
which the accumulators/actuators
were subjected.
While the calculation took credit for
the high drywell pressure that reduced the pressure differential between the
accumulators/actuators
and the drywell, it did not address the low drywell pressure
condition.
Ins ec or Followu
The inspectors found that based upon the NRC concern, the licensee performed a
preliminary calculation which determined that under worst-case differential pressure
conditions (i.e., the containment pressure would depressurize
to 0 psig and the. actuator
would have an increased pressure due to the increased temperature affects) the actuator
would be subjected to a maximum pressure of 277 psig. The licensee also determined
that the accumulator and piping design pressure was 300 psig and the main steam
safety relief valve actuator design pressure was 250 psig. Therefore, the actuator could
be subjected to pressures that were in excess of the design pressure.
However, the
licensee determined that more precise calculations would probably show that since the
temperature
in the drywell was decreasing due to the containment spray, the
temperature
in the actuators would also be decreasing and that the 277 psig pressure
would not be reached.
The inspectors reviewed documentation from Crosby Valve, Inc.,
the manufacturer of the main steam safety relief valve actuators.
The inspectors noted
that the valve manufacturer was in the process of changing the actuator design pressure
rating from 250 to 300 psig and that no changes to the actuator were required to meet
this new pressure rating. The licensee stated that appropriate changes to design
documentation would be made following completion of the design change evaluation.
The, inspectors noted that the licensee was in process of rerating the actuator design
pressure to satisfy the NRC concern.
The licensee stated that the scheduled completion
date for the actuator rerate was October 15, 1997.
Conclusions
h
Appropriate actions to correct a new and previously unanalyized condition involving the
potential overpressurizing of the main steam safety relief valve actuators were being
taken.
These actions indicated that the actuators were capable of withstanding the
- additional pressure and that design documentation would be changed to reflect the new
design pressure ratings.
~
~
-36-
E8.9
lo ed
Ins
e
i
ollowu
I em 50-3 7/96201-0:
Incomplete data forthe main
steam safety relief valve quencher and tail pipe support design.
Backcaround
The NRC identified incomplete documentation to support the operating stresses for the
main steam safety relief valve quencher supports and tail pipe supports.
The NRC
requested the source of the design stresses
used for the quencher and tail pipe
supports, however, the licensee was unable to retrieVe this information.
Calculation NE-02-89-18, Revision 2, established the maximum safety relief valve tail
pipe stress level limit and the minimum safety relief valve reopening pressure.
The NRC
considered that while the methodology used in the calculation was adequate,
it lacked
design stress documentation.
ns ec or Followu
The inspectors reviewed three draft calculation modification records, which'the licensee
developed in order to reassess
structural design margins since they were unable to
retrieve the source data used in Calculation NE-02-89-18.
The licensee determined the
piping-to-quencher support load using a detailed piping support model. The inspectors
reviewed Request For Te'chnical Services 96-12-012, dated December 17, 1996, which
the licensee developed to update Calculation NE-02-89-18 and incorporate the revised
design margins for the main steam safety relief valve quencher supports and the tail pipe
supports.
The inspectors noted that this information, in the form of preliminary
calculations, indicated that the design margins for the supports increased from the
original 3 to 13 percent.
The licensee stated that the final calculations would be
completed by September
17, 1997.
E8.10
los d Unresolved Item 5 - 9 /9 201-10'ailure to implement the requirements of
Regulatory Guide 1.62 for automatic depressurization
system initiation.
~Back round
Through review of the General Electric Functional Control Diagram (FCD) 731E788, the
NRC determined that the FCD did not agree with the as-built configuration for the manual
initiation of the automatic depressurization
system because the original design was
inadvertently altered.
The NRC postulated that a design error was introduced in 1985 as
.part of a modification to install an inhibit switch to prevent automatic actuation of the
automatic depressurization
system following a reactor vessel low water level condition.
In addition, the NRC noted that operators were tiained to activate this inhibit switch upon
entry into the emergency operating procedures for a reactor vessel low water level
condition. The NRC determined that the inhibit switch defeated the manual-initiate
function shown on the FCD.
-37-
The NRC further postulated that this modified manual initiation was inconsistent with the
manual-initiate operation described in Regulatory Guide 1.62, "Manual Initiation of
Protective Functions." The NRC determined that three of the five guidelines listed in
Regulatory Guide 1.62 were not met when the inhibit switch was initiated. Specifically,
the operation now required more than the minimum number of operator actions, the
group opening of the valves (i.e., 4 valves and then three valves together), as intended in
the original design, was altered, and the seven valves now had to be opened individually
in a sequential manner.
The NRC concluded that since Appendix C of the FSAR included Regulatory Guide 1.62
as a design commitment, the licensee was required to comply with the guidelines of the
guide for manual initiation of a protective function.
Ins ecorFoll wu
Following the Three Mile Island (TMI) accident in 1979, the NRC required nuclear plant
operators to make certain modifications to their plants to enhance safety.
These
modifications were called TMIAction Items.
In the area of automatic depressurization,
the BWR Owner's Group proposed methods to comply with the requirements of TMI
Action Item II.K.3.18 concerning the depressurization
system logic. As a part of granting
the licensee's operating license, the NRC issued a safety evaluation report on
December 29, 1983, which accepted the licensee's proposal to use one of the owner's
group methods (Option 2) to meet the TMI action item. This option was to install manual
inhibit switches in the automatic depressurization
system.
These inhibit switches were to
be installed to modify the original design by preventing all seven automatic
depressurization
valves from opening simultaneously after a time delay. This safety
evaluation report required the licensee to install this modification prior to restart from the
first refueling outage.
The licensee installed the modification during a May to June 1985
maintenance outage.
On May 18, 1985, the licensee requested
an amendment to the
technical specifications to address the modified automatic depressurization
system and
the NRC approved the technical specification amendment (as Amendment 11) on
June 23, 1985.
The inspectors reviewed the following documentation:
"BWR Owner's Group Evaluation of NUREG-0737 Item II.K.3.18
Depressurization System Logic," dated February 1983;
Safety Evaluation Report, Supplement 4, dated December 29,.1983;
~
Request for Amendment to Technical Specifications for Automatic
Depressurization System (ADS) Logic Modifications, License Condition 18, dated
May 16, 1985;
-38-
"Issuance of Amendment No. 11 to Facility Operating License NPF-21, WPPSS
Nuclear Project No. 2," dated June 25, 1985;
Amendment 36 to the FSAR dated December 1985;
FCD 731E788;
Elementary Diagram 807E180TC, "Auto Depressurization System";
Problem Evaluation Request 296-0857 dated December 13, 1996; and,
Letter dated September 24, 1997, "WNP-2, Operating License NPF-21 Inspection
Report 96-201 Addendum: Response to Open Items."
The inspectors walked down the control room controls for the automatic depressurization
system and discussed
use of the emergency operating procedures with an operator
regarding the use of the automatic depressurization
system and the inhibit switches.
As the result of these reviews, the inspectors determined that the licensee's actions were
consistent with Regulatory Guide 1.62 as modified by the changes required by the NRC
to meet TMI Action Item II.K.3.18. During this review, the inspectors also noted that the
licensee, in their response to NRC Inspection Report 50-397/96-201 dated June 16,
1997, stated for Item 96-201-10, that a design error existed and would be corrected in
their next refueling outage.
When this statement was questioned by the inspectors, the
licensee responded that'their response to that item was incorrect and would be corrected
in an addendum to that response.
On September 24, 1997, the licensee submitted an
addendum to the June 16 response to the NRC. This addendum stated that their
present design was consistent with Regulatory Guide 1.62 as modified by TMIAction
Item II.K.3.18. In this letter the licensee also acknowledged that FCD 731E788 was
incorrect and would be revised to match the as-built 'plant design.
The inspectors also
noted that Problem Evaluation Request 296-0857 was issued to correct the FCD.,
~
Conclusions
The current design for the manual initiation of the automatic depressurization
system
was consistent with Regulatory Guide 1.62 as amended by the requirements of TMI
Action Item II.K.3.18 and no wiring error existed.
Functional Control Diagram 731E788
was not consistent with the as-'built plant configuration.
-39-
E8.11
I sed
I s ec ion
o lowu
I em 50-397/96201-
11: Inadequate design
documentation for the standby service water system to demonstrate containment
flooding capability.
Backcaround
The NRC identified that a beyond-design-basis
function of the standby service water
system was to flood the reactor vessel and containment, ifrequired, during the post
loss-of-coolant accident period. The report identified that with the standby service water
system in this lineup, the standby service water pump could run out resulting in
insufficient cooling water flowto the Division II emergency diesel generator.
The NRC
noted in the report that the licensee had initiated preliminary evaluations that indicated
the emergency diesel generator would receive adequate cooling water flow and standby
service water pump run out would not occur.
Ins ecor
I owu
The inspectors reviewed the licensee's preliminary calculation that indicated there was
sufficient head to provide emergency diesel generator cooling when the standby service
water system was in a containment flooding lineup. The licensee stated that a formal
evaluation of this concern was in process and the scheduled completion date was
September
1, 1997. The inspectors discussed the licensee's preliminary findings and
noted that the emergency diesel generators would receive an adequate cooling water
flow and that standby service water pump run out would not occur.
E8.12
I
d
U
solved
I
50-397/96201-1:
Inadequate corrective action to implement
high pressure core spray service water corrosion monitoring.
~Bkclrouu~n
The NRC. identified that the licensee had not addressed
corrosion monitoring of the high
pressure core spray system standby service water loop after a pin hole leak in a socket
weld on Loop B of the standby service water system vent line was identified. The NRC
reviewed Performance Evaluation Request 295-1229, initiated due to the pin hole leak,
and noted that the corrective actions included improved corrosion monitoring and water
treatment programs, annual nondestructive examination wall thickness measurements
at
selected locations, and trend analysis of general corrosion.
The NRC concluded that the
-corrective actions were incomplete since they only addressed
Standby Service Water
Loops A and B and did not address the high pressure core spray standby service water
loop.
-40-
or
oil wu
The inspectors discussed the failure to include the high pressure core spray standby
service water loop in the corrosion program with the licensee and reviewed Problem
Evaluation Request 295-1229.
The inspectors noted that the licensee had not classified
the problem evaluation request as significant because the small size of the leak did not
affect system operability.
In addition, the licensee stated that no leaks were found in the
high pressure core spray standby service water loop and the only additional leak found in
the standby service water loops was caused by cavitation instead of corrosion.
However, based on the NRC findings, the licensee revised their corrective actions to
include the high pressure core spray service water loop in the annual preventive
maintenance program for wall thickness measurement.
The inspectors reviewed the
applicable work order that would implement this task and noted that the wall thickness
measurement for the'high pressure core spray standby service water loop was added to
the program.
Conclusions
The lack of inclusion of the high pressure core spray service water loop in the corrosion
program was appropriate considering the type of failure that occurred.
In addition, the
inclusion of the high pressure core spray standby service water system in the wall
thickness measurement
program was considered to be a proactive approach toward
eliminating any future problems.
E8.13
los d Ins
cionF Ilowu
I
5 - 9
620 - 3: Licenseeto redevelop
Calculation ME-02-96-28 to identify standby ser'vice water system potential for cavitation.
~Ba k Zoaud
The NRC identified that the licensee could not locate Calculation ME-02-96-28, which
was referenced
in Problem Evaluation Request 295-1002.
The calculation documented
an evaluation to determine potential locations for cavitation within the standby service
water system.
r
I
u
In a discussion with the licensee, the inspectors determined that
Calculation ME-02-96-28, "Evaluation of Cavitation Potential in the Standby Service
System," Revision 0, had been misfiled and was available for review..The inspectors
reviewed this calculation and found that the potential for cavitation existed at two flow
elements.
The inspectors noted that the licensee implemented a design change to
increase the back pressure on the flow elements and eliminate the cavitation potential.
The inspectors determined that the calculation was adequate.
-41-
E8.14
lose
Ins ec ion Foll wu
I
m 50-
7/96201-1:
The fuel pool heat exchanger and
the control room emergency chiller were excluded from the standby service water flow
balance test.
~B>~kclrou~n
The NRC identified that the fuel pool heat exchangers
and Control Room Emergency
Chiller CCH-CR-1B were not included in the standby service water flow balance test.
While this was considered to be a weakness,
there were no safety concerns since
calculations indicated that all served components would receive adequate standby
service water flow.
Ins ec or Followu
E8.15
The inspectors reviewed draft Operating and Engineering Test Procedure 8.4.81, "SW
System Performance with FPC HX (Fuel Pool Cooling Heat Exchangers) Valved In."
The inspectors determined that the draft test procedure now included the fuel pool heat
exchangers
and Control Room Emergency Chiller CCH-CR-1B as part of the flow
balance.
The inspectors noted that the heat exchanger test acceptance
criterion was
that the heat exchangers
met their minimum design flows. The licensee stated that this
new test would be performed, as a minimum, every 5 years.
The first test was scheduled
to be performed in September 1997. The inspectors determined that the licensee's
corrective actions were adequate.
These corrective actions included preparing a test
procedure to include the heat exchangers
in the flow balance test and providing a
schedule for testing.
Closed
Ins e
ion Fol owu
I em 50-397/9
2 1-1: Use of the FSAR instead of the
source calculations to set the battery profile for the load test.
~Back round
During a review of the results for the battery profile load test, the NRC noted that
licensee personnel relied on the load table in the FSAR instead of the load calculation to
set the battery load profile. Based on the NRC observation, the licensee stated that they
updated the FSAR whenever the battery load calculation was revised.
However, the
NRC noted during a review of Calculation 02.05.01 that the list of documents affected by
the calculation did not include the FSAR load table.
"""EJ"
'he
inspectors reviewed the applicable FSAR Table 8.3-7 and were informed that
Calculation 02.05.01 would be revised to include the FSAR load table in the calculation's
list of affected documents.
In addition, instead of continuing the practice of using the
FSAR as the battery profile source document as stated in their June 16 response
letter,
the licensee has decided to revise the applicable plant procedures used for battery
'V
-42-
surveillance testing such that these procedures reference the dc load calculation as the
battery load profile source.
The licensee stated that the procedures and calculation will
be revised by January
1, 1998, which is prior to the date that the calculation will be
needed for the load profile test.
E8.16
Closed
ns ec io
Follow
I em
0-3 7/9 201-1:
Did not meet the guidance of
Engineering Directorate Manual 2.15 concerning outstanding calculation modification
records.
~Bck ro nd
During a review of the Engineering Directorate Manual 2.15, "Preparation, Verification
and Approval of Calculations," Revision 2, the NRC noted that the procedure
recommended that calculations be revised iffive or more calculation modification
requests (CMRs) are outstanding against a calculation.
The NRC found evidence
that three sampled calculations had more than five calculation modification
requests outstanding against them. The NRC identified 77 CMRs against
Calculation E/l-02-90-01, 29 CMRs against E/l-02-85-07, and 23 CMRs against
Calculation E/I-02-87-02.
In
o Folowu
The inspectors reviewed Procedure 2.15 and noted that while Steps 1.2.3 and 4.5.3 of
this procedure stated that the limitof CMRs was five, the procedure permitted more than
five "plant implemented" CMRs to be outstanding against a calculation ifthe CMRs were
authorized by the responsible supervisor/manager.
The inspectors selected ten
calculations with greater than five outstanding CMRs and reviewed these CMRs to
determine ifresponsible supervisor/manager
approval was obtained.
This selection
included Calculations E/I-02-85-07 and E/I-02-87-02. The inspectors also selected two
calculations that had less than five CMRs to verify the accuracy of the licensee's CMR
number tracking system.
The inspectors verified that the selected calculation CMRs had
the appropriate approvals.
Based on this review, the inspectors determined that the
licensee's activities were in accordance with Procedure 2.15.
The inspectors also reviewed a listing of calculations dated July 3, 1997, and found that
46 calculations had more than 5 CMRs. The inspectors found that 30 of these
calculations had less than 10 CMRs. The remaining 16 calculation CMR breakdown was
as follows:
-43-
+aalu~lion
mb r fCMR
E/I-02-85-07
E/I-02-87-02
E/I-02-87-05
E/I-02-87-07
E/I-02-90-01
E/I-02-92-12
FP-02-85-03
NE-02-85-19 .
TR-2512-1
2.05.05
2.06.20
2.07.03
5.49.50
5.49.51
5.49.52
5.52.07
.
26*
18'2
15
71*
24
30
15
11
15
26
25
22
13
11
12
- Note: The number of CMRs for these calculations were different from the
numbers listed originally in NRC Inspection Report 50-397/96-201 due to
the different dates that the data was obtained.
As the result of this NRC finding, the licensee reemphasized
expectations to engineering
personnel, which included that new CMRs for calculations that already have five changes
against them, willnot be accepted unless due dates were established,
the dates entered
into the plant tracking log', and an evaluation be performed to assure that the outstanding
CMRs did not adversely affect the calculation.
In addition, the licensee established an
engineering team to self-assess
their calculation process and controls.
The inspectors reviewed his self-assessment,
which was completed on October 16,
1997. The inspectors noted that while the assessment
identified numerous problems
with the retrieving and handling of calculations and with the Controlling Procedure 2.15, it
did not determine if it was necessary to verify the effect of the numerous CMRs on the
technical content of the existing calculations.
The potential for numerous CMRs affecting
the technical content of the calculations is considered to be a inspection followup item
= (50.-397/9713-04).
~Con
I sions
While Engineering Directorate Manual 2.15 was properly implemented, actions were
being taken to further control the number of calculation modification records for plant
calculations.
A self-assessment
performed by the licensee did not identify ifthe
~ l
0
44
outstanding calculation modification records potentially affected the technical content of
the calculations.
E8.17
I s d Ins
ion Fo owu
e
50-397/96202-03:
Problems were identified on gold
cards when they should have been identified as problem evaluation requests.
~Bckc~run I
,The licensee developed the gold card system to identify human performance issues, that
if left uncorrected, could contribute to a significant event.
In NRC Inspection
Report 50-397/96-202, the NRC found that two gold cards, 4207 and 4727, contained
potential engineering or hardware issues.
Therefore, the NRC considered that problem
evaluation requests,
instead of gold cards, should have been issued to identify these
plant problems.
The inspectors found that Problem Evaluation Requests 296-0732 and 296-0869 were
written to address the issues that were the subject of gold cards 4207 and 4727. The
inspectors noted that these problem evaluation requests were written prior to issuing the
gold cards.
In addition, the inspectors determined that the gold cards in question were
properly written to track human performance issues on the identified problems.
The
inspectors reviewed five additional gold cards and determined that the cards were
appropriately written in accordance with the licensee's program.
The inspectors
determined that the gold card system was properly implemented.
V.Mana em
n
ee'
X1
Exit Meeting Summary
The inspectors conducted an onsite exit on August 2, 1997, to present the preliminary
inspection results.
An additional exit, conducted by telephone on January 12, 1998,
presented the final inspection results to members of licensee management.
The
licensee acknowledged the inspection findings.
No proprietary information was identified by the licensee.
'i'
TTACHMENT
SUPPLEMENTAL INFORMATION
PARTIALLIST OF PERSONS CONTACTED
Licensee
B. Adami, Engineer
R. Barbee, Manager, System Engineering
G. Brastad, Consulting Engineer
D. Brown, System Engineer
R. Brownlee, Licensing Engineer
R. Chaudhuri, Engineer
D. Coleman, Supervisor, Regulatory Services
J. Gearhart, Manager, FSAR Upgrade
G. Gelhaus, Assistant to Engineering General Manager
P. Harness, Supervisor, Engineering
V. Harris, Assistant Maintenance Manager
J. Hunter, Manager, Radiation Protection
D. Mand, Manager, Design/Projects
M. Monopoli, Manager, Operations
J. Muth, Supervisor, Quality Support
J. Peterson,
Engineer
J. Swailes, Engineering General Manager
R. Webring, Vice President, Operations Support
INSPECTION PROCEDURE USED
92903 Followup of Engineering Issues-
ITEMS OPENED, CLOSED, AND DISCUSSED
~Oened
50-397/9713-01
Corrective actions were not adequate to prevent recurrence of
conditions that were adverse to quality.
50-397/9713-02
APV
Failure to maintain acceptance
criteria and maintain testing of
reactor core isolation cooling system valves as required by
50-397/9713-03
APV
Potential 'unreviewed safety question due to the failure to obtain
NRC approval prior to downgrading the reactor cooling isolation
system.
-2-
50-397/9713-04
IFI
The affect of excessive CMRs on the technical content of
calculations.
~CI ~
50-397/9604-01
IFI
Use of Generic Letter 89-10 valve factors for operability
determinations.
50-397/9611-01
Failure to followmodification and scaffolding procedures.
50-397/9611-02
Determination of the safety-related status of the reactor core
isolation cooling system which was downgraded from safety-
related to nonsafety-related
in 1985.
50-397/9611-03
Failure to maintain plant design basis.
50-397/9611-04
Failure to implement adequate and timely corrective actions.
50-397/9611-05
Failure to implement a Nuclear Safety Assurance Division
procedure.
50-397/96201-01
Discrepancies between residual heat-removal heat exchanger test
analysis data and the Final Safety Analysis Report.
50-397/96201-02
Failure to periodically update the Final Safety Analysis Report as
required by 10 CFR 50.71(e).
50-397/96201-03
IFI
Design Basis Documentdiscrepancies.
50-397/96201-04
IFI
Plant procedure did not reflect the plant response to an under
voltage condition.
50-397/96201-05
IFI
Design Basis Documentdiscrepancies.
50-397/96201-07
Inadequate analysis of design pressure for the automatic
depressurization
system actuators.
50-397/96201-08
.
IFI
Incomplete data for the main steam safety relief valve quencher
and tail pipe support design.
50-397/96201-09
IFI
Design Basis Document discrepancies.
50-397/96201-10
Failure to implement the requirements for Regulatory Guide 1.62
for the automatic depressurization
system initiation.
'
-3-
50-397/96201-11
IFI
Inadequate design documentation for the standby service water
system to demonstrate containment flooding capability.
50-397/96201-12
Inadequate corrective action to implement high pressure core
spray service water corrosion monitoririg.
50-397/96201-13
IFI
50-397/96201-14
IFI
Licensee to redevelop calculation ME-02-96-28 to identify standby
service water system potential for cavitation.
The fuel pool heat exchanger and the control room emergency
chiller were excluded from the service water flow balance test.
50-397/96201-15
IFI
Use of the FSAR instead of the source calculations to set the
battery proflile for the load test.
50-397/96201-16
IFI
Did not meet the guidance of Engineering Directorate, Manual 2.15
concerning outstanding calculation modification records.
50-397/96202-01
Failure to prevent the recurrence of significant conditions that were
adverse to quality.
50-397/96202-02
Two examples where significant problem evaluation requests
failed either to provide a root cause analysis or to provide a root
cause analysis of sufficient depth.
50-397/96202-03
IFI
= Problems were identified on gold cards when they should have
been identified as problem evaluation requests.
50-397/96202-04
IFI
Corrective action program timeliness goals not met.
DOCUMENTS REVIEWED
OCB
U
S.
~umber
PM 1.10.8
SWP-ASU-01
Nuclear Safety Assurance Assessments
Evaluation of Programs, Processes,
and Suppliers
10.2.53
15.1.13
Seismic Requirements for Scaffolding, Ladders, Man-Lifts, Tool
Gang Boxes, Hoists and Metal Storage Cabinets
Fire Suppression Systems Tamper Switch Operability
~
I
0
15.1.18
3.3.1
2.8.7
1.4.1
4.7.1.8
4.7.1.9
7.4.7.1.1.1
7.4.7.1.1.2
7.4.7.1.1.3
Fire Suppression Systems Valve Alignment
Master Startup Checklist
Fire Protection System
Plant Modifications
Loss of Power to SM-7
Loss of Power to SM-8
Standby Service Water Loop A Valve Position Verification
Standby Service Water Loop B Valve Position Verification
High Pressure
Core Spray Standby Service Water Loop Valve
Position Verification
Tl 1.2
EDP 2.15
E 2.8
EDP 2.50
EDP 2.11
1.3.12
1.3.12A
1.3.48
8.4.81
8.4.42
IS
Q
7.4.7.3.3
OSP-RCIC/
T- 702
Equivalent Change Evaluations
Preparation verification and approval of calculations
Generating facility design change process
Generating facility minor design change process
Field changes
Problem Evaluation Request (PER)
Processing of Problem Evaluation Requests
(PER)
Root cause analysis
SW system" performance with FPC HXvalved in
Thermal performance monitoring of RHR HXs
RCIC operability test
RCIC valve operability test
RCIC operability test
I
0
-5-
TM-2043
EDP 2.41
Augmented quality requirements
Classification of structures components and subcomponents
B
EV LU T
NR
E
292-0231
293-0346
295-1002
295-1229
296-0119
296-0489
296-0639
296-0649
Valve test push buttons open recombiner isolation valves.
. Pressure suppression bypass leakage in excess of technical
specification allowable during CAC surveillance and possible
internal flooding of CAC.
Leak discovered on bottom of SW A line
Pin hole leak found in SW vent line
The motor-pump coupling for AC powered standby lube oil
circulation pump DLO-P-3B2 was found to be failed during
investigation of a low lube oil pressure annunciator.
Threshold for writing a PER.
Temporary stock piles of scaffold components
PER written on findings from July 1996 engineering inspection
296-0857
296-0285
296-0299
ADS Functional Control Diagram 02B22-04, 23, 3 Rev 18 shows
two seal-in's in each logic string, but only one is implemented in
Elementary 02.
Adverse trend in valve and switch mispositioning
On 4/24/96 while performing MOVATS base-line test - WO
RK1603 it was discovered that Wire 2M8B-502 (white) was landed
on LimitSwitch
1 and Wire 2M8B-401 (black-2) was landed on
LimitSwitch 1-C.
296-0362
296-0364
During release of CO 960402261 on CFD 1E 8 1F, water was
noted coming out of condensate
piping on T441.
l8 C was working WOT YG3903 on RCIC-PCV-15 and required no
clearance order.
-6-
296-0382
SPTM-TE-10 as found wiring does not match top tier drawing
EWD-251-004;
296-0415
296-0428
Two clearances were not accepted prior to working on MS-V-
172A/B.
Work order ¹WF3301 was worked without personnel signing on to
the danger clearance order (¹96-01-0135).
296-0453
Loss of power occurred on Division 1 ARI during performance of
PPM 8.3.361, ATWS-ARI functional test.
296-0497
A low level condition occurred in the main condenser hotwell due
to a clearance order.
296-0587,
Two potential violations were identified in the NSAD (ISEG) area
during the NRC engineering inspection.
296-0650
A laborer cleaned sump T-2 with the work package for the job at
status 40.
296-0869
296-0351
Service water pump SW-P-1A tripped during
Clearance order 96-04-0402 should have tagged pump control
switches for sump 5-7, EDR-P-18A and the breakers for these
PulllPS.
296-0537
During swing shift the production reactor operator found a work
order task had been added to clearance order 96-02-0074
paperwork without a proper second level review of the add on
sheet.
296-0775
Industrial safety issue from working two independently planhed
work packages on components associated with the same system.
296-0519
296-0680 ,
Document adverse trend in PERs.
The orange/black conductor of cable BRR-9228 is landed at TB2-8
in E-SH-1D instead of at TB2-1 2, as shown on EWD 3E022.
296-0686
The black conductor of cable AIVD-9086was found terminated on
the wrong limitswitch at CAC-EHO-FCV/4A limitswitch enclosure
during conduct of WOT ZR4401 to correct faulty TDAS valve
position indication for this valve.
~
4q
0
-7-
296-0688
Correct the meeting minutes for CNSRB Meeting ¹96-05 to
correctly reflect that safety evaluation ¹95-095 was reviewed.
296-0690
During performance of PPM 8.9.1, HCU scram solenoid pilot valve
replacement and electrical checks. The power supply leads into
the SSPV electrical termination box for CRDSPV117/2215 were
found reversed.
296-0692
As the craft performed WO BSM90, terminals 3 &4 were shorted
out which cleared the fuse F 24-2 located a E-DP-S1/1F, circuit
19, and damaging the edge connector of the relay case..
296-0693
This PER is issued to document a trend, based on the review of
five PERS listed below which address wiring termination problems.
296-0711
Technicians found vent valve CRD-V-157D partially open.
This
'alve's normal position is closed.
296-0780
XN7101 SGT-FT-1A2 loop cal. The wiring to SGT-FS-1A2 alarm
B was found wired to contacts 13 and 14, the prints show they
should be 11 and 12.
296-0782
Three wiring problems found in carbon bed heater No. 1 control
box.
296-0832
297-0016
Surveillance PPM 7.1.2 steps improperly N/A'd.
Service water and diesels rendered inoperable for work order
without a voluntary entry into technical specifications.
297-0020
Technical specification bypass leakage exceeded during
performance of PM 2.3.3A, Section 5.5.
297-0035
HPCS diesel generator tripped on reverse power immediately after
paralleling to the SM-4 bus.
297-0039
B RBM power supply failed when a screwdriver was dropped into
the drawer.
297-0042
FSAR Tables 6.2-2 and 9.2-5 appear to conflict with
PPMs 7.4.7.1.1.1 and 7.4.7.1.1.2 for the minimum SW flowto the
RHR heat exchanger.
297-0044
Discrepancies were identified in the design requirements
documents for the ADS, RHR, and SSW systems.
c~
~ ~t
297-0055
CRD found out-of-position during PPM 7.4.1.3.1.2 position
verification steps.
297-0070
While performing WO CZ501 it was'discovered that the wrong type
relay.was installed under WO ZK4401 for K1.
297-0071
297-0072
RHR-V-176B found open when danger tagged shut.
An adverse trend of human performance problems have occurred
recently.
297-0073
297-0092
297-0116
Apparent tagging error discovered.
Found DMA-FN-21 switch in mid-position.
There, is an adverse trend in the number of inadequate clearance
orders being prepared by personnel at WNP2.
'297-0161
297-0157
Hold down clamp has stripped, threads
WO BTV017 was to install additional monitoring on the ASD drive.
Test point FBAR was misconnected to FCA, due to
misidentification of label.
297-0414
297-0437
During PMT of HD-MO-15C WO DCR7 and DGP6, the actuator's
torque switch failed to stop the valve motion. Torque switch
miswired.
During performance of the loop seal flush of PPM 2.11.17, a valve
was found not per the lineup in Step 7.3.1 and prohibited the flush.
297-0485
Errors found in storage and marking of radioactive material
containers on the radwaste building 507'levation.
297-0537
Recent PERs suggest a potential lack of understanding of portions
of the radiation protection program.
297-0546,,
While attempting to shift to the CAS "B" dryer set, relief valve on
CAS-AR-1B lifted due to no flow path through the "A"or "B" CAS
dryers.
297-0582
297-0663
During testing, the DFWLC logic was found to have the control
system trouble alarm point in override.
CIA-PCV-2B seal wire was found broken and stem lock nut loose.
-9-
N
E
UE T
~micr
97-0093-0
97-0087-0
97-0029-0
96-0213-0
94-0306-0
96-0004-0
CL
LAI
Interference between flow controller and pipe hanger
Condensation
in pipe causing corrosion problems
Substituting relief valves
Small bore pipe lines require removal of flanges
Substituting sst piping for carbon steel
Valves were identified to have a potential for not opening
~ver
RCIC-1484-1
CMR 96-0245
CMR 96-0244
ME-02-96-28
NE-02-89-18
CMR-92-0192
CMR-94-1154
5.46.05
CMR-94-0348
Qualification of new sst piping
Analyze pipe system as modified by TER 94-0306
Qualify support per as-built information
Evaluation of cavitation potential in the SW system
Safety relief valve variables
Pressure
limits for ADS accumulators
Effects of reactor power on CIA system pressure
Maximum CIA system pressure
This CMR revises the static loading information for MC-7A and
MC-8Adue to the affect of BDC 91-0438-OA
E/I-02-87-02
E/I-02-85-07
DE IGN
ANGE
480V MCC Load Data for LOCA Operation
480V MCC Load Data for Normal Full Load Operation
~Nu ~br
PMR 96-0133-0
PMR 95-0268-0
PMR 93-0082-0
Install restricting orifice in SW line
Remove the electronic overspeed trip from the RCIC system
Correct system level analysis
-10-
PMR 84-0623-0
P
MR 92-0161-0
PMR 96-0046-0
PMR 84-0331-0
PMR 94-0631-0
PMR 87-0146-0
P
MR 89-0397-0
HA
E N T
Provide direction to delete motor operator
Replace turbine lube oil alarm pressure switch
Replace cap on the nipple with a valve
Rework hanger
Void calculation
Redesign operator to removable type design
Install pressure indicator to RCIC test return line
~Nor
90-119
95-044
T e
Update Table 9.2-5 to reflect the heat loads used in the thermal
performance analysis for the ultimate heat sink.
Revise surveillance testing and inspection frequencies
in FSAR
Appendix F, Section F.5.
DO
MEN
CHANGE NOTI
E FOR
~Numb
FSAR-96-092
LDCN-97-000
LDCN-FSAR-97-019
F SAR-97-035
LDCN-FSAR-97-008
I
ELLANE US
Changed the description of the SW keepfill subsystem to indicate that the
subsystem has been deactivated and spared in place.
Annual LDCN to include administrative type corrections, drawing and
figure updates. (DRAFT)
FSAR Table 8.3-18 shows that DP-S1-1D supplies control power
to several switchgears that are actually supplied by DP-S1-1F.
Update the FSAR system load tables (duty cycles) to those
defined in the Battery Sizing Calculations: 2.05.01/rev 9 (Div-1/-2,
125 8 250 VDC) and E/I-02-85-02/rev
1 (Div-3, 125 VDC) as
revised by their respective calculation modiTication records (CMR).
The tabulations in Table 9.2-5 are being modified to reflect
changes
in plant usage of equipment. (DRAFT)
~Nu
be
54314106
Tl e
C
4
Dedication package for globe valves
-11-
60117050
54403013
25506824
56507934
Dedication package for actuators
Dedication package for relief valves
Dedication package for screw lock vacuum pump
Dedication package for piston seal
CNSRB Meeting Minutes96-062
Information and schedules for the FSAR Upgrade Project
Engineering Calculation Self Assessment
dated October 1997
Gold Card 4744, ....found CO-V-2A out of normal Vol 2 lineup
CATEGORY
2
REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)
ACCESSION NBR:9803050276
DOC.DATE: 98/02/18
NOTARIZED: NO
FACIL:50-398 Mendocino, Unit 1, Pacific
Gas
& Electric Co.
AUTH.NAME
AUTHOR AFFILIATION
HAAG,R.C.
Region
2
(Post
820201)
RECIP.NAME
RECIPIENT AFFILIATION
TAYLOR,G.J.
Southern California Edison Co.
DOCKET ¹
05000398
SUBJECT: Ack receipt of 980122 ltr informing NRC of steps
taken to
correct violations noted in insp rept 50-398/97-13
on
971223.
DISTRIBUTION CODE:
IE01D
COPIES
RECEIVED:LTR
ENCL
SIZE:
TITLE: General
(50 Dkt)-Insp Rept/Notice of Violation Response
NOTES:Application withdrawn 1/19/73.
05000398 E
RECIPIENT
ID CODE/NAME
COPIES
LTTR ENCL
RECIPIENT
ID CODE/NAME
COPIES
LTTR ENCL
INTERNAL: AEOD/SPD/RAB
DEDRO
NRR/DRCH/HHFB
NRR/DRPM/PERB
OE DIR
RGN5
FILE
01
AEODJ'.
E CENTE
NRR DRPM PECB
NUDOCS-ABSTRACT
EXTERNAL: LITCO BRYCE,J H
NRC PDR
NOAC
NUDOCS FULLTEXT
D
NOTE TO ALL "RIDS" RECIPIENTS:
PLEASE HELP US TO REDUCE WASTE. TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS
OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL
DESK
(DCD)
ON EXTENSION 415-2083
0
TOTAL NUMBER OF COPIES
REQUIRED:
LTTR
17
ENCL