ML20033H009
| ML20033H009 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 03/22/1990 |
| From: | Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20033H006 | List: |
| References | |
| 50-285-90-02, NUDOCS 9004130311 | |
| Download: ML20033H009 (22) | |
See also: IR 05000285/1990002
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APPENDIX C
U.S. NUCLEAR REGULATORY COMMIS$10N
REGION IV
NRC Inspection Report:
50-285/90-02
License: DPR-40
Docket:
50-285
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Licensee: Omaha Public Power District (OPPD)
444 South 16th Street Mall
Omaha, Nebraska 68102-2247
Facility Name:
Fort Calhoun Station (FCS)
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Inspection At:
Inspection Conducted: January 16 through February 28, 1990
Inspectors:
P, Harrell, Senior Resident Inspector
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T. Reis, Resident Inspector
R. Mullikin, Project Engineer
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3 -37-78
Approved:
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T. F. Westerman, CIiief, Project Section B
Date
Division of Reactor Projects
Inspection Summary
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Inspection Conducted January 16 through February 28.1990 (Report 50-285/90-02)
Areas Inspected:
Routine, unannounced inspection of the areas discussed
below.
Results: During this inspection period, the inspectors reviewed the areas
discussed below. The discussion provides an overall evaluation of each area.
The inspectors evaluated the areas of:
review of previously identified
items; operational safety verification; plant tours; safety systems
walkdown; monthly maintenance, surveillance, security, and radiological
protection observations; in-office review of licensee reports; and onsite
followup of events. Within these areas, it appeared that the licensee's
actions met the appropriate regulatory requirements.
In the area of engineering and technical support, the corrective actions
initiated by the licensee as the result of the failure of raw water (RW)
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pump (Pump AC-10A) discharge check valve (RW-125) failed to recognize the
potential for further degradation of the RW system and resulted in an
apparent violation of regulatory requirements.
9004130311 900406
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In the area of radiological protection, a weakness was discovered in that
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the licensee did not have formal proceduralized controls for opening
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doors between the radiologically controlled area and the site
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environment.
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A deviation was identified with the licensee's failure to properly
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install cables in trays located in the auxiliary building in accordance
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with requirements stated in the Updated Safety Analysis Report.
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Other issues brought to the licensee's attention for action, as appropriate,
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included:
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Consideration of AN$1 N45.2.9 requirements during performance of
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modification or maintenance to the records vault,
Improper installation of danger tag on a breaker.
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An improper personnel evacuation route specified on plant emergency exit
signs outside of the technical support center, and
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Observation by the inspectors that most plant management and supervisory
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personnel were not touring the plant operating spaces.
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DETAILS
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1.
Persons Contacted
'R. Andrews, Division Manager, Quality and Environmental Affairs
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'J. Bobba, supervisor, Radiation Protection
'C. Brunnert, Supervisor, Operations Quality Assurance
'J. Chase, Manager, Nuclear Licensing and Industry Af fairs
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'M. Core, $upervisor, Maintenance
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'D. Dale, Supervisor, Quality Control
- $. Gambhir, Division Manager, Production Engineering
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Gates, Division Manager, Nuclear Operations
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Huang, Supervisor, Hurnan Performance Evaluation
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'R. Jaworski, Manager, Station Engineering
'J. Kecy, Supervisor, Systems Engineering
'L. Kusek, Manager, Nuclear Safety Review Group (N$RG)
'D. Matthews, Supervisor, Station Licensing
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'W. Orr, Manager, Quality Assurance and Quality Control
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'G. Peterson, Manager, Fort Calhoun Station
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- R. Phelps, Manager, Design Engineering
A. Richard, Assistant Manager, Fort Calhoun Station
'H. Sawhney, N$RG Specialist
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'J. $efick, Manager, security Services
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- R. Sexton, Supervisor, Radiation Health and Engineering
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P. Sepcenko, Supervisor, Outage Projects
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'C. Simmons, Station Licensing Engineer
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F. Smith, Plant Chemist
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'M. Tesar, Supervisor, Training
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- J. Tesarek, Supervisor Training
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J. Tills, Assistant Manager, Fort Calhoun Station
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Trausch, Supervisor, Operations
'$. W111 rett, Manager, Administretive $ervices
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' Denotes attendance at the monthly exit interview.
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The inspectors also contacted other plant personnel.
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2.
Plant Status
During this inspection period, the plant operated at 100 percent power.
No safety system challenges were experienced during this inspection
period.
3.
Review of previously Identified Items (92701 and 92702)
a.
(Closed) Open Item 285/8937-01:
Inclusion of the verification and
validation process into a formally issued procedure.
The licensee uses a verification and validation process for action
items contained in the Safety Enhancement Program (SEP) to verify
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that each item has been fully addressed.
This open item was issued
to document that the verification and validation process was not
addressed by a formally issued procedure.
The licensee issued Procedure NOD-QP-28, " Safety Enhancement
Program " to document the actions required by licensee personnel to
ensure that adequate verification and validation actions have been
completed for each SEP item.
The inspector reviewed Procedure NOD-QP-28 to verify that adequate
instructions had been provided.
No problems were noted during the
review.
b.
(Closed) Open Item 285/8937-02: The licensee did not provide
personnel with direction or acceptance criteria for
institutionalization.
This item concerns the lack of direction or acceptance criteria
being provided to licensee personnel as to what actions constituted
institutional 12ation of each SEP action item.
The lack of specific
criteria resulted in each individual establishing his/her own set of
standards.
The licensee issued Procedure N00-0P-28 to specify the acceptance
criteria that must be met for the institutionalization of an $EP
item to be considered satisfactory.
The inspector reviewed Procedure NOD-QP-28 and noted that the
procedure appeared to adequately address the criteria for
institutionalization,
c.
(Closed) Open Item 285/8937-03:
Licensoe should revalidate all
completed SEP items.
This issue identifies a concern where it appeared to be appropriate
that all completed SEP items should be revalidated. As discussed in
paragraph 3.b above, the licensee had not provided personnel with
criteria for verifying proper institutionalization; therefore, it
appeared that revalidation of all items was appropriate.
The licensee responded to this issue by stating that an independent
assessment of all SEP items would be performed in the near future.
The assessment will verify that proper institutionalization had been
completed.
The inspector reviewed the licensee's response to this item.
It
appeared that the response was adequate because it required that any
discrepancies noted during the independent evaluation be reported to
the NRC.
In addition, an NRC team will review the licensee's
actions during an assessment to be performed in the near future.
Based on the actions described above, this item is considered
closed.
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d.
(Closed) Open Item 285/8937-04:
One SEP item was statused by the
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licensee as completed when all actions required to complete the item
had not been implemented.
This issue identifies that SEP Item 63 had been statused as
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completed by the licensee and it did not appear that the scope of
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work had been completed. The item contained a Phase I and II work
scope and it was determined that only Phase I had been completed,
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To address this item, the licensee issued a letter, dated
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December 21, 1989, that discussed the apparent discrepancy with the
status of $EP Item 63. The letter stated that the term " completed "
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as used in the status of SEP items, indicated that the item had been
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verified but not validated.
If, during the licensee's review of an
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item, discrepancies are noted, the discrepancies are documented on a
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Quality Assurance (QA) deficiency report (DR) form and entered into
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the licensee's tracking system to ensure that action is taken to
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complete the identified discrepancy.
In this case, the discrepancy
had been identified w'.th the work scope not being completed for SEP
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Item 63, therefore, the licensee statused the item as completed and
issued a QA DR.
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The licensee instituted a system where the NRC is notified of the
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existence of any significant discrepancies identified by the
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licensee during validation of SEP items.
This information will be
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provided to the NRC in addition to the status of each item.
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The inspector reviewed the newly established program initiated by
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the licensee to keep the NRC informed of the status of SEP items.
It appeared that this program adequately addressed the concerns
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identified by this item.
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e.
(Closed) Open Item 285/9937-05:
Licensee individuals were
performing validation activities u $EP items without the latest
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work scope listing.
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This item is related to a concern where individuals were performing
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validation activities and were not using documentation that provided
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a complete listing of the work scope for the item being reviewed.
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In the specific example identified, Revision 0 of the SEP plan was
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being used when Revision I had been issued.
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To address this concern, the licensee placed a requirement in
Procedure N00-QP-28 that instructs the individual to use a
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controlled copy of the latest revision of the SEP plan.
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The inspector reviewed Procedure N00-QP-28 and noted that it
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appeared that the licensee had adequately addressed this concern.
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Review of the licensee's implementation of this requirement will be
performed by an NRC assessment team during a future inspection.
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(Closed) Open Item 285/8937-06:
Identification of weaknesses during
validation of SEP action items.
This item documented a concern related to the licensee's
identification of 96 weaknesses during validation of SEP items. The
licensee had not kept the NRC informed of the existence of the
weaknesses and had not provided a status of the closeout of the
weaknesses.
In a letter dated December 21, 1989, the licensee provided a listing
of the weaknesses for each SEP item and provided a status for each
weakness. The licensee stated in the letter that the information
regarding weaknesses would be provided to the NRC in each submission
of the SEP item updated status list.
The inspector reviewed the licensee's actions taken to address this
concern.
It appeared that the actions were adequate,
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(Closed) Open Item 285/8937-07:
Issuance of QA DRs for significant
weaknesses identified during the validation process.
This item involved a licensee commitment to issue QA DRs for all
significant weaknesses identified during the $EP item validation
process.
Significant weaknesses were defined by the licensee as
those weaknesses that indicate that all commitments in the SEP item
were not completed or intent of the SEP item was not met. DRs are
being issued by the licensee to ensure that the significant
weaknesses are reviewed by the appropriate levei of management.
To establish a program for the identification of significant
weaknesses and documenting the weaknesses as QA DRs, the licensee
established requirements in Procedure N0D-QP-28.
The inspector reviewed Procedure NOD-QP-28 for the established
requirements regarding identification and documentation of
significant deficiencies and no problems were noted. The
implementation of the requirements will be reviewed by an NRC
assessment team in the near future,
h.
(Closed) Severity Level IV Violation 285/88201-16:
Inadequate
ASME Section XI testing.
The Operational safety Team Inspection (OSTI) witnessed the
performance of Procedure ST-ISI-CA-1, " Compressed Air Valve
In-$ervice Testing," for Valve HCV-1749 and noted that there were no
communications established between the remote station initiating the
valve stroke for timing and the local station that timed the valve
stroke,
$1nce communications were not established between the
remote and local stations, the local station started timing on
actuation of the local solenoid rather than on operation of the
control switch.
This is contrary to ASME Section XI,
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$ubsection 1WV-3413, 1980 Edition which states that full-stroke time
is the time from initiation of the actuating cycle until the valve
completes cycling.
The licensee admitted the violation and stated that corrective
action was to modify all survei) lance tests as part of the
procedures upgrade project.
The improved procedures would include
timing the valves from the remote station to include full-stroke
time from initiation of the actuating signal. Additionally, remote
position indication will be periodically verified such that the
2 year ASME code requirement would be met.
This commitment is a
subpart of the licensee's surveillance test performance improvement
effort incorporated into the SEP with a current completion date of
September 1990.
The inspector reviewed Procedure OP-$T-DW-3001, " Demineralized Water
System Category A Valve Exercise Test." This procedure, which was not
yet issued, served as an example of the forthcoming upgraded proce-
dures.
It was found to have the valve's stroke time recorded from the
remote position indication only while verification of actual change in
position was made locally.
The inspector confirmed that this approach
was in accordance with ASME Section XI, Subsection IWV-3413.
The
inspector also reviewed Procedure OP-$T-VX-3001, " Auxiliary Feedwater
System Remote Position Indicator Verification Surveillance Test."
This test, which is a formally issued and upgraded procedure, served
as fulfilling the ASME code requirement for verifying the accuracy of
the remote position indicators at a 2 year interval. The inspector
found the procedure to comply with code requirements.
In the interim, the licensee is still using its old procedures,
where the stroke time is measured both locally and remotely, for
ASME Section XI stroke time testing.
The inspector interviewed two
licensed operators to determine how they would conduct such a test.
Both indicated they would establish communications with the
individual recording the local stroke and that establishment of
communications was a part of their training.
Based on the current method of conducting such tests and
incorporating permanent corrective action into the SEP, this
violation is considered closed.
The actions taken by the licensee in response to previously identified
items appeared to be conservative and provide adequate controls to
prevent recurrence.
No additional violations or deviations were identified.
4.
Operational Safety Verification (71707)
The inspectors conducted reviews and observations of selected activities
to verify that facility operations were performed in compliance with the
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appropriate regulatory requirements.
The inspectors made control room
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observations to verify the following:
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Proper shift staffing was maintained and conduct of control room
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personnel was appropriate.
Operator adherence to approved procedures and Technical
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Specification (TS) requirements was evident.
Operability of instrumentation and controls was maintained.
If not,
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the appropriate TS limiting condition for operation (LCO) was met.
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Logs, records, recorder trat;es, annunciators, panel indications, and
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switch positions complied with the appropriate requirements.
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Proper return to service of components was performed.
Maintenance work orders (MWO) were initiated for equipment in need
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of maintenance.
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Control room access was properly controlled.
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Control room annunciator status was reviewed to verify operator
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awareness of plant conditions.
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Mechanical and electrical temporary nodification logs were properly
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maintained,
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Engineered safeguards systems were properly aligned for the specific
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plant condition.
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During review of this inspection area, the inspectors identified the
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following items:
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a.
On January 31, 1990, the inspector observed the licensee perform
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accountability of personnel during an emergency evacuation drill in
accordance with Criteria J.5 of NUREG-0654.
In the recent past, the
licensee has had trouble meeting the 30-minute criteria and it
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attributed the dif ficulty to a large number of personnel on site.
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1ess than perfect procedures, the unreliability of the security
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computer, use of slow manual accountability methods. and the small
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number of practice drills.
The inspector observed the licensee
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perform accountability from the security work area.
The licensee
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u nd a newly implemented manual method and achieved accountability
in 28 minutes.
The inspector considered the exercise to have been
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well orchestrated and efficiently executed,
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b.
The cables that supply power to the containment spray (CS) and low
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pressure safety injection (LPSI) pumps are routed through the same
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fire area in the basement of the auxiliary building.
In the event
of a worst-case fire, power to the CS and LPSI pumps could be lost
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and result in a loss of the capability to remove decay heat since
the C$ and/or LPS! pumps are used in the shutdown cooling ($DC) mode
of operation.
To address this vulnerability, the licensee issued
Procedure $P-$1-5, " Emergency Repairs to Cor.tainment $ pray
Pump $1-3C." This procedure provided instructions for connecting
temporary power cables from an available electrical source to the C$
pump 50 the pump could be used in the $DC mode.
The tools and
material were maintained in an emergency repair kit.
Use of
temporary power cables is allowed by Section !!!.G.1.b of Appendix R
to 10 CFR Part 50 which states that the systems necessary to achieve
and maintain cold shutdown from either the control room or emergency
control station (s) shall be repairable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
As discussed in NRC Inspection Report 50-265/89-50, the licensee
determined that the suction piping for the C$ pumps was not
qualified to meet the entry requirements (250 psig and 300'F) for
shutdown cooling. Therefore, the instructions provided in
Procedure $P-51-5 could not be implemented in all possible
scenarios.
To address this problem, the plant review committee approved, on
January 22, 1990, and issued Safety Analysis for Operability
($AO) 90-01.
SAO 90-01 stated that automatic fire detection is
available in the fire area and would alert the fire brigade to
immediately respond to a fire; therefore, the fire damage would be
minimized,
in addition, $A0 90 01 stated that an hourly fire patrol
was established for the fire area to ensure that transient combustible
material does not accumulate in the area.
SAO 90-01 also stated that a new repair procedure will be issued by
May 1,1990, to provide instructions for connecting temporary power
to an LPSI pump, in lieu of to a C$ pump, in the event that the
normal power cables are damaged by fire.
The LPSI pumps are fully
qualified for use in all SDC system conditions.
The appropriate
tools and materials will be placed in a repair kit prior to issuance
of the new repair procedure.
On Februt,ry 5,1990, the licensee issued Licensee Event Report
(LER)89-024 to describe the actions that would be taken to address
this issue.
The inspector will review the completion of the
licensee's actions during routine followup on the LER.
On February 8, 1990, a conference call was conducted between the
inspector and personnel in Regian IV and the Office of Nuclear
Reactor Regulation (NRR). As a result of the call, NRR stated that
SAO 90-01 provided adequate actions to address the potential fire
vulnerabilities and that the schedule established by the licensee
for implementing a new repair procedure was acceptable.
No violations or deviations were identified.
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5.
Plant Tours (71707)
The inspectors conducted plant tours to assess plant and equipment
conditions. The following items were observed:
General plant conditions, including operability of standby
equipment, were satisfactory.
Equipment was being maintained in proper condition.
Valves and/or switches for safety-related systems were in the proper
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position.
Plant housekeeping and cleanliness practices were implemented.
Performance of work activities was in accordance with approved
procedures.
Tag-out of equipment was performed properly.
Management personnel toured the operating spaces on a regular basis.
During tours of the plant, the inspectors noted the items listed below:
a.
On January 19, 1990, the inspector observed that the ventilation
system serving the QA records vault had been dismantled, leaving two
holes (approximately 1 by 3 feet) in the structure.
The inspector
was concerned that the condition may not meet tSe requirements for
proper records storage.
The inspector found the licensee to be
committed to ANSI N45.2.9, " Requirements for Collection, Storage,
and Maintenance of Quality Assurance Records for Nuclear Power
Plants." Af ter reviewing ANSI N45.2.9, the inspector considered the
status of the vault to meet stated requirements for the facility,
safekeeping, and preservation.
Although it met the ANSI requirements, the vault was in a degraded
condition. Upon notification by the inspector, the licensee took
compensatory actions by directing that fire watches, when patrolling
this area, look into the openings to check for fire or entry by
unauthorized personnel. As permanent corrective action to prevent
recurrence of this degraded condition, design engineering was tasked
with modifying its procedures to ensure that AN$1 N45.2.9
requirements are considered in maintenance or modification
activities.
Corrective action by design engineering is considered
an open item.
(285/9002-01)
b.
On January 23, 1990, the inspector noted that a danger tag had not
been properly installed on Breaker 7 in Panel 103A1, a
safety-related distribution electrical panel.
The tag was issued to
prevent operation of Breaker 7.
Instead of being installed over
Breaker 7, the tag was installed on Breaker 5 which was immediately
adjacent to Breaker 7.
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The inspector immediately notified personnel in the control room and
a licensed operator immediately responded. The operator removed the
tag from Breaker 6 and placed the tag over Breaker 7.
Although the tap' was installed incorrectly, Breaker 7 was in'the
designated "off position and there was no indication that the
breaker had been operated,
c.
On January 23, 1990, the inspector noted that the plant emergency
exit signs located adjacent to the technical support center directed
individuals to exit the plant in the wrong direction. The exit path
designated by the signs would require that individuals pass through
an area posted as a radiation materials controlled area. The
inspector notified the plant licensing engineer of this concern on
January 23, 1990, and again on February 6, 1990.
On February 8,1990, the licensee moved the radiation materials
control area so that personnel could exit the plant without having
to pass through the area,
d.
On January 19, 1990, the inspector observed work in progress in
Room 25, a radiologically controlled area.
The inspector noted that
the large rollup door was open to the site environment.
The
inspector investigated and found there were no proceduralized,
formal controls over opening the door and controlling area exit and
entrance.
The inspector notified the Supervisor, Radiation Protection of the
issue. On February 15, 1990, a memorandum was generated from the
Supervisor, Radiation Protection to the Supervisors. Operations and
Security describing the interim controls to be placed on the opening
of the door. The issuance of a formal procedure to control opening
of the door is considered an open item.
(285/9002-02)
e.
During plant tours, the inspectors noted that most management and
supervisory personnel were not routinely touring the plant operating
spaces.
The inspectors did note that the Supervisor, Radiation
Protection frequently toured the radiation controlled area and that
the Plant Manager and Supervisor, Operations toured the control
room.
The inspector discussed this issue with the Plant Manager who stated
that the time available for plant tours was limited due to other
activities such as review and approval of a large number of new
procedures being issued to meet the milestones established for the
SEP upgrade of safety-related procedures effort.
The Plant Manager
also stated that considerable efforts were expended in preparation
for the refueling outage.
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The Division Manager, Nuclear Operations stated that measures will
be taken to increase the frequency of plant tours by onsite
management.
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f.
On February 5,1990, the inspector noted that the instrumentation
and control cables installed in safety-related Trays 5-4A and 5 48,
located in the east switchgear room, did not comply with
Figu . 8.5-1 of the Updated Safety Analysis Report (USAR) that
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Paragraph 20.c states, in part, that the fill in '. rays for -
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125-Vdc and 120-Vac cables shall generally not 9xceed a maximum
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of 50 percent.
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Paragraph 22 states, in part, that prefixed (safety-related)
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cables may be routed in raceways containing nonprefixed cables
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(nonsafety-related) provided the cables are separated by
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metallic barriers.
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Paragraph 18 states, in part, that control and instrument
cables shall be tied down in a neat configuration after
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installation in trays.
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The inspector identified the discrepancies listed below that did not
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comply with the U$AR criteria:
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The volume of cables installed in Trays 5-4A and 5-4B was so
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large that the cables extended above the metallic barrier
separating the raceways in the cable trays. This condition
caused the cables in adjacent raceways to come in contact.
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Trays 5-4A and 5-4B in the switchgear room are vertical trays
approximately 25 feet high.
Cables installed in the trays were
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not tied down in a neat configuration.
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The failure to install cables in accordance with the USAR
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requirements discussed above is an apparent deviation,
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(285/9002-03)
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On February 16, 1990, the inspector met with the Manager, Design
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Engineering and the Supervisor, Electrical and Instrumentation and
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Control Engineering.
During the meeting, these licensee personnel
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provided the following information concerning the installation of
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the cables:
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An operability determination had been made and no concerns had
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been identified,
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Since the cables in the trays were low voltage, heating
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problems within the trays were not a concern.
The cable installation problems identified by the inspector in
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the east switchgear room had been corrected.
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Procedure ETS-10. " Cable Installation $pecification," provided
instructions to the craf tspersons for installing cables in the
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plant,
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Two trays (95 and 115) containing power cables appeared to
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exceed the tray fill limit criteria specified in Figure 8.5-1
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of the USAR.
This problem was identified during review of this
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issue. An evaluation was in process to determine the
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significance of the tray overfill problem.
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Twelve different facility modifications had installed cable in
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Trays 5-4A and 5-4B.
It could not be determined which specific
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modification had installed the cables.
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The inspector reviewed the information provided during the meeting
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and noted the following:
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Procedure ETS-10 did not contain all the requirements stated in
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Figure 8.5-1 of the USAR for cable installation.
For example.
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the requirement to maintain separation between safety- and
nonsafety-related cables by metallic barriers was not addressed
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by Procedure ETS-10.
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The problems identified with the cables in the east switchgear
room had been corrected.
However, the inspector noted, on
February 19, 1990, that the same type of problems existed in
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the cable spreading room with the same cable trays.
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Based on the plant tours performed by the inspectors, it appeared that
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the licensee was providing adequate attention to the physical condition
of the plant; however, licensee attention to the issues identified above
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is warranted.
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6.
Safety-Related Systems Walkdown (71710)
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The inspectors walked down accessible portions of the 120-Vac and the
fire protection systems to verify operability as determined by
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verification of selected valve and switch positions. The following
documents were reviewed:
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Procedure 01-EE-4, " Normal Operation of 120 Volt AC System,"
Revision 40, Checklist EE-4-CL-4
Figure 8.1-1, " Simplified One Line Diagram, Plant Electrical
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System," Revision 45
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Drawing 11405-E-9, Sheet 2, "120 Volt AC Instrument Buses One Line
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Diagram," Revision 0
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Procedure 01-FP-6, " Fire Protection System Inspection and Test,"
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Revision 76
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Drawing 11045-M-266, Sheet 1, " Fire Protection Flow Diagram,"
Revision 56
Drawing 11405 M-266, Sheet 9, " Fire Protection Dry Pipe and Deluge
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System Details," Revision 17
During the walkdown, the inspector noted minor items with the system
alignment checklists that did not affect system operability. The minor
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discrepancies were provided to onsite licensing personnel who stated that
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the discrepancies would be corrected, as appropriate, in the near future.
No violations or deviations were identified.
7.
Monthly Maintenance Observations (62703)
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The inspectors observed selected station maintenance activities on
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safety-related systems and components.
The following items were
considered:
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T5 LCOs were met while systems or components were removed from
service.
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Approvals were obtained prior to initiating the work.
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Activities were accomplished using approved MW0s.
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Functional testing and/or calibrations were performed prior to
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returning components or systems to service.
Quality control records were maintained.
Activities were accomplished by qualified personnel.
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Parts and materials used were properly certified.
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Radiological and fire prevention controls were implemented,
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The inspectors observed the following maintenance activities:
a.
On January 24, 1990, the inspector observed portions of the
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maintenance performed to remove and replace Valve RW-115, the
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discharge check valve for RW Pump AC-10D.
The maintenance work was
performed in accordance with MWO 894523.
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b.
On January 22, 1990, the inspector observed portions of the
maintenance activities performed to repair Traveling Screen CW-2F.
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The maintenance was performed in accordance with MWO 900278.
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c.
On February 16, 1990, the inspector observed continued work in
progress toward the installation of air dryers for the emergency
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diesel generator (EDG) starting air systems in accordance with
Modification Request MR FC-86-077, " Installation of Air Dryers for
Emergency Diesel Generators 1 and 2."
d.
The inspector observed work in progress toward the installation of
insulation on the EDG exhaust lines.
This process completes
Modification Request MR-FC-88-60, "EDG 1 and EDG 2 Exhaust Piping
Seismic Supports."
During observation of the maintenance activities performed by licensee
personnel, the inspectors observed that the maintenance evolutions were
performed in accordance with the appropriate regulatory requirements.
No violations or deviations were identified.
8.
Monthly Surveillance Observations (61726)
The inspectors observed TS-required surveillance testing on
safety-related systems and components. The inspectors verified the
following items during the testing:
Testing was performed by qualified personnel using approved
procedures.
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Test instrumentation was calibrated.
TS LCOs were met.
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Removal and restoration of the affected system and/or component were
accomplished.
Test results conformed with TS and procedural requirements.
Test results were reviewed by personnel other than the individual
directing the test.
Deficiencies identified during the testing were properly reviewed.
Testing was performed on schedule and complied with the TS-required
frequency.
A discussion of each surveillance observed is provided below:
a.
On February 8,1990, the inspector observed a portion of the monthly
testing of EDG 1 in accordance with Procedure ST-ESF-6, " Monthly
Testing of the Emergency Diesel Generator." The inspector observed
the emergency response facility computer readout of EDG 1 parameters
as it was fully loaded for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
None of the parameters indicated
an abnormality.
After EDG 1 was unloaded and stopped, the inspector
toured the EDG 1 room and found the system engineers finishing
recording a temperature profile of the room. The data indicated
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that the newly installed block insulation on the EDG 1 exhaust line
was effectively inhibiting heat transfer from the exhaust line to the
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room, which had been a problem in warmer months.
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b.
On February 6,1990, the inspector observed a portion of the testing
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of the engineered safeguards features per surveillance test
Procedure $T-51/C$-1, " Safety Injection / Containment Spray Pump and
Valve Testing." Specifically, the inspector witnessed machinists
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measure and record vibration and bearing temperatures on HPSI
Pump $1-2B.
It was observed that one machinist who was fully clad
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in anticontamination clothing took the readings in the contaminated
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area of the pump and relayed the readings to another machinist
adjacent to him in a clean area.
The second machinist had a copy of
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the procedure and appropriately recorded the readings.
The
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inspector considered the coordination between the two machinists and
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the operator, who was controlling the test from the control room, to
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have been good.
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c.
On February 2,1990, the inspector witnessed instrumentation and
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control (!&C) technicians calibrating Temperature Channel 255 on Boric
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Acid Storage Tank B.
The work was directed by Procedure IC-CP-01-0255,
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" Calibration of Temperature Channel 255." The procedure was in the
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new format being used for upgrading safety-related procedures.
The
inspector interviewed the technicians and they offered that the new
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procedure was thorough and readily understandable. No problems were
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encountered during the observation.
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d.
On February 10, 1990, the inspector observed I&C technicians
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performing Procedure ST-CONT-1, " Local Leak Rate Test," on various
mechanical penetrations in Rooms 59 and 69.
The group of technicians
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performing the task were well coordinated and were following the
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established procedure,
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Based on the observations made by the inspectors, it appeared that
the licensee was adequately implementing the surveillance testing
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program.
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No violations or deviations were identified.
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9.
Security Observations (71707)
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The inspectors verified that the physical security plan was being
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implemented by observation of the following items:
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The security organization was properly manned.
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Personnel within the protected area (PA) displayed their
identification badges.
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Vehicles were properly authorized, searched, and escorted or
controlled within the PA.
Persons and packages were properly cleared and checked before entry
into the PA.
The offectiveness of the security program was maintained when
security equipment f ailure or impairment required compensatory
measures to be employed.
The PA barrier was maintained and the isolation zone kept free of
transient material.
The vital area barriers were maintained and not compromised by
breaches or weaknesses.
It appeared, based on the observations made by the inspectors, that the
physical security plan was adequately implemented.
No violations or deviations were identified.
30.
Radiological Protection Observations (71707)
The inspectors verified that selected activities of the licensee's
radiological protection program were implemented.
The activities listed
below were observed and/or reviewed:
Health physics (HP) supervisory personnel conducted plant tours to
check on activities in progress.
HP technicians were using calibrated instrumentation.
Radiation work permits contained the appropriate information to
ensure that work was performed in a safe and controlled manner.
Personnel in radiation controlled areas (RCA) were wearing the
required personnel monitoring equipment and protective clothing.
Personnel were properly frisked prior to exiting an RCA.
Radiation and/or contaminated areas were properly posted and
controlled based on the activity levels within the area.
Based on the reviews performed by the inspectors, it appeared that the
licensee was implementing an ef fective radiological protection program.
No violations or deviations were identified.
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11.
In-Office Review of Licensee Reports (90712 and 90713)
In-office review of licensee reports was performed to verify the
following:
Correspondence included the information required by appropriate NRC
requirements.
Test results and supporting information were consistent with design
predictions and specifications,
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Planned corrective actions were adequate for resolution of
identified problems.
Correspon a nce did not contain any information that should be
classified as an abnormal occurrence or required additional reactive
inspection.
Correspondence did not contain incorrect, inadequate, or incomplete
information.
Correspondence reviewed included:
12 licensee letters to the NRC, 5
licensee requests for amendoments of the TS, 2 special licensee reports,
and 2 licensee event reports.
No violations or deviations were identified.
12. Onsite Followup of Events (93702)
The FCS uses, as its ultimate heat sink, the Mitsouri River.
River water
is supplied to the heat loads via the raw water (RW) system.
Delivery is
made by four RW pumps powered by two vital electrical buses,
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Pumps AC-30A and AC-100 are served by one bus and AC-10B and AC-10D are
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served by the other.
The discharge piping of the pumps are each equipped
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with check valves to prevent reverse flow through an idle pump.
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On January 26, 1990, while performing replacement of the discharge check
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valve (RW-115) for Pump AC-100, it was discovered that Valve RW-115 had
failed, in that one of the flappers of this duo-check valve had eroded
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off of its hinge pin.
This rendered Pump AC-10D inoperable until such
time as the missing flapper could be retrieved from the system, the new
Valve RW-115 installed, and postmaintenance testing performed on the
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system.
In the interir., the Plant Manager ordered that ASME Section XI
inservice testing be performed on the discharge valves for Pumps AC-10B
and AC-10C to verify their operability.
The discharge check valve for
Pump AC-10A had been replaced and satisfactorily tested on January 23,
1990. The testing perfurmed requires the running of one pump other than
the one associated with the check valve being tested and closing the
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dhcharge isolation valves in line with the other two check valves not
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being tested.
Then the pressure drop is measured across the valve being
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tested,
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Testing on January 24, 1990, revealed that Valve RW-121, the discharge
check valve for Pump AC-10B, did not meet the ASME Section XI testing
criteria.
Subsequently, Pump AC-10B was declared inoperable rendering
two RW pumps inoperable. Although Valve RW-121 could not meet the
Section XI criteria, engineering was able to evaluate it as capable of
performing its intended safety function and, with this information,
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operations was able to declare Valve RW-121 and the associated
Pump AC-10B operable 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> af ter declaring it inoperable.
The testing of the check valve (RW-117) for RW Pump AC-100, was
apparently delayed until January 25, 1990, while evaluating the results
of the testing of Valve RW-121. The test of Valve RW-117 yielded
similiar results as those of Valve RW-121 and engineering similiarly
evaluated Valve RW-117 as being capable of performing its safety function
although it was outside the ASME Section XI testing criteria.
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licensee has been informed that the testing of Valve RW-117 could have
been more timely.
Although the licensee was proactive in initiating corrective actions
following the discovery of the degraded condition of the RW pump check
valves in July 1988, as discussed below, these corrective actions and
related engineering evaluations did not appear to have given
consideration to the potential for further check valve degradation as
first identified during back flow testing in July 1988.
This was further
compounded by the discontinuation of check valve backflow testing in
January 1989 until January 1990.
The failure to have initiated
corrective actions with regard to the potential for further degradation
of RW pump discharge check valves is an apparent violation.
(285/9002-04)
In response to NRC Information Notice 88-70, " Check Valve Inservice
Testing Program Deficiencies," the licensee added the RW pump discharge
check valves to the inservice testing (IST) program in May 1988.
In the
first test (July 1988), unacceptable pressure drop was identified across
all four of the check valves. An incident report was generated and at
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that time management did not see a problem with the excessive backflow
since credit could be taken for the discharge isolation valves and
engineering determined that the actual flow loss did not constitute a
safety concern as far as delivering adequate flows to design basis heat
loads.
Corrective actions associated with the incident report
concentrated on upgrading the instrument air supply to the discharge
valves.
It was felt that these actions would ensure that the discharge
valves were capable of being held closed during a loss of instrument air
and thus provide the backflow prevention function of the check valves.
The licensee initiated action to purchase replacement check valves.
In the next quarterly IST test of October 3,1988, again all four valves
failed their Section XI acceptance criteria.
At this time, the plant was
off line for refueling and the corrective action was to complete the
modification of the instrument air and accumulator operating mechanisms
on the discharge isolation valves prior to coming out of the outage. The
modification, MR-FC-88-61, " Seismic Qualification of Raw Water Discharge
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Valve Accumulator Assemblies," upgraded the operating assemblies to
seismic grade so that, in the event of a loss of instrument' air, the
discharge isolation valves could perform their intended safety function.
With the modification, the licensee justified that the discharge
isolation valves could perform the des M function of the faulty check
valves.
In the first querte test of January 1989, the check valves again failed
the Section XI au.eptuce criteria. At this time, the Supervisor, System
Engineering femn addressed the rMt r(view committee (PRC) via
Memorandum PED-SYE-89-60 and recommendcd that testing of the check valves
be _ discontinued until they could be replaced since they had been proven
defec'.ive several times.
In the interim, he recommended that the testing
of the discharge isolation valves be modified such that it adequately
demonstrated the reverse flow function for which the licensee was taking
credit.
Similarly, the inspector documented in NRC Inspection
Report 50-285/89-09 of February 1989, that the discharge isolation
valves, with their seismically upgraded instrument air operating
assemblies, appeared to adequately fulfill the reverse flow function of
the check valves but that a backflow test on the discharge isolation
valves would be required to be added to the IST program.
The licensee
formally added this test to the IST program on June 30, 1989, although it
had data verifying the integrity of these valves from previous tests.
Based on systems engineering recommendation, the licensee did not perform
Section XI testing on the check valves for the second, third, and fourth
quarters of 1989.
On June 24, 1989, during the removal of the pump assembly on Pump AC-10A
for maintenance, it was discovered that associated discharge check valve,
RW-125, had catastrophically failed in that one of the flappers had
eroded off its hinge pin.
In its evaluation of this condition, the
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licensee discovered an error in its position that the discharge isolation
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valves could fully substitute for the degraded check valves.
The limiting event for which the RW system is analyzed is a
loss-of-coolant accident coincident with a loss of all offsite power and
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a single failure.
It was determined that, with the check valves unable
to fulfill their design function, the worst case single failure scenario
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is the loss of a single DC bus.
Loss of DC Bus I would render EDG 1
Output Breaker 1AD1 inoperable.
Failure of Breaker 1AD1 to close,
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coincident with the loss of offsite power, would leave Pumps AC-10A and
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AC-100 without supply power.
The loss of DC Bus I would also deenergize
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the solenoids which operate the instrument air pilot valves for Discharge
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Valves HCV-2850 of Pump AC-10A and HCV-2852 of Pump AC-100.
Loss of
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power to the solenoid-operated pilot valves would cause instrument air
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pressure to vent off the air operator allowing the discharge valves to
fail open. Thus, a reverse flow path would be created through open
Valve HCV-2850 and nonfunctional Check Valve RW-125 back to the river.
Flow calculations demonstrated that insufficient flow would be available
to serve the design basis accident heat loads under this condition.
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As a result, the licensee generated SAO 89-10, " Raw Water Check
Valve RW-125." The analysis iustified that the plant could continue to
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safely operate in this condition provided credit was taken for operator
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action in manually restoring the flow path by handjacking shut the failed
open discharge valves.
The inspector verified that the licensee
adequately revised Emergency Operating Procedure E0P-20, " Functional
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Recovery Procedure," and Abnormal Operating Procedure A0P-18. " Loss of
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Raw Water," to provide instructions to close the discharge valves and had
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provided training to the operators on the scenario. Based on these
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ections and concurrence from NRR and Region IV, the inspector considered
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the SAO adequate for continued safe operation of the plant.
Although the SAO was specifically written to address the total failure of
Valve RW-125 for Pump AC-10A, it could be applied to any failed check
valve since Procedure AOP-18 was revised to instruct operations personnel
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to close the associated disch:rge valves for all nonoperating RW pumps,
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The evaluation supporting the SAO assumed that the reverse flow through a
pump without an installed check valve would be approximately 5000 gallons
per minute (gpm). Also a liberal allowance of 1000 gpm was assumed for
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backflow losses through Pump AC-10C. With these assumptions,
calculations demonstrated that a minimum of 10 minutes would be available
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for operator action to manually close the discharge isolation valves
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before component cooling water temperature reached its design value of
200 F.
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Based on SAO-10, it appeared that the discharge isolation valves could
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adequately serve the design function of the check valves provided no more
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than one check valve associated with pumps on the same emergency bus had
failed catastrophically.
For example, if Pump AC-10C had also
catastrophically failed, this would have placed the plant outside a
condition analyzed in the SA0 in that nearly all RW flow from the
remaining pumps would have been lost back to the river and the 10 minutes
allowed for operator action may not be conservative.
In fact, SAO-10
states that the calculations supporting it consider reverse flow through
Pump AC-10C to be on the order of 1000 gpm.
It further states that
should surveillance testing determine that the check valve leakage
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differs significantly from this value, then the impact must be assessed
and the SA0 revised accordingly. However, the Section XI backleakage
test had been suspended since January 1989 and was not performed again
until January 1990.
Therefore, the corrective action taken to restore
the RW system to an operable condition was inadequate in that it failed
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to reinstitute the backflow test of remaining degraded Check
Valves RW-115, RW-117, and RW-121.
SAO-10 was based on data of
backleakage through these valves determined through testing in June 1988.
Withcut reinstituting the backflow test to determine if there was
subsequent degradation of the check valves, the licensee could not ensure
that plant operations was bounded by the SAO. When tested in January
1989, the results for Valves RW-121 and RW-117 did not indicate
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degradation from the values assumed in SAO-10. The system engineer was
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able to produce data from his personal log of an informal test performed
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on November 8, 1989, which indicated reverse flow through Valve RW-115
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was not excessive at that time. Therefore, it appears that although the
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potential existed for the degradation of the RW system pump discharge
check valves, the situation does not appear to have occurred.
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13. Exit Interview
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The inspector (P. Harrell) met with Mr. W. G. Gates, (Division Manager,
Nuclear Operations) and other members of the licensee staff on
February 23, 1990.
The meeting attendees are listed in paragraph 1 of
this inspection report. At this meeting, the inspector summarized the
scope of the inspection and the findings.
During the exit meeting, the
licensee did not identify any proprietary information.
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