ML20138J409
| ML20138J409 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 04/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20138J402 | List: |
| References | |
| 50-302-97-02, 50-302-97-2, NUDOCS 9705080201 | |
| Download: ML20138J409 (44) | |
See also: IR 05000302/1997002
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 2
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Docket No:
50-302
License No:
OPR-72
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Report No:
50-302/97-02
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Licensee:
Florida Power Corporation
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Facility:
CrystalRiver3NuclearSt5 tion
Location:
15760 West Power Line Street
Crystal River. FL 34428-6708
Dates:
February 23 through March 29. 1997
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Inspectors:
S. Cahill
Senior Resident Inspector
T. Cooper Resident Inspector
B. Crowley Reactor Inspector, paragra]hs E8.1 - E8.8
M. Thomas. Reactor Inspector, paragra als E8.9 - E8.10
L. Mellen Project Engineer, paragrapls E1.1. E8.11
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M. Miller. Reactor Inspector, paragraphs E8.12 - E8.13
Approved by:
K. Landis, Chief. Projects Branch 3
Division of Reactor Projects
9705000201 970421
ADOCK 05000302
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EXECUTIVE SUMMARY
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Crystal River 3 Nuclear Station
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NRC Inspection Report 50-302/97-02
This integrated inspection included aspects of licensee operations.
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engineering, maintenance, and plant support.
The report covers a 5-week
period of resident ins)ection; in addition, it includes the results of
announced inspections )y five reactor inspectors and one project engineer from
Region II.
Ooerations
A Violation (VIO 50-302/97-02-01) was identified.
This violation is of
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concern in that it involved seven examples of equipment in the incorrect
position and revealed your inadequate controls to maintain the appropriate
status of plant equipment (Section 01.2).
The Operations department was not using the corrective action system
appropriately as a tool to facilitate their problem investigations.
Consequently, senior management involvement and awareness of the corrective
action plans was limited, and the timeliness of the root cause evaluations and
subsequent development of corrective actions was poor (Section 01.2).
The licensee's restraints and required Plant Review Committee reviews for
normal Mode 5 conditions constituted a good means of oversight for shutdown
safety and defense in depth and was considered a licensee strength (Section
01.3).
The inspectors concluded the licensee continued to restructure their self-
assessment activities in an attempt to improve their programs.
Problems
continued to be observed, but they were being recognized and addressed by
licensee management.
The PC problems indicated an underuse of the PC system
as a mechanism to correct large program problems and a lack of visibility of
significant problems for management review.
Changes to the PC tracking
software and processes were being investigated by the licensee to address
these concerns (Section 07.1).
The inspector concluded the Plant Review Committee was providing appropriate
oversig1t and safety perspective.
Changes to restrict membership, assign a
full time chairman and refine expectations were beneficial initiatives by the
licensee and were indicative of an emphasis on improving nuclear safety
performance (Section 07.2).
Maintenance
The inspectors concluded that all observed maintenance and surveillance
activities were performed in accordance with procedures and desired results
were obtained (Section M1.1).
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Enaineerina
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A weakness was identified in that Problem Report 96-0423 was not revised to
address the discrepancies identified with missed identification in
Modification Approval Record packages of needed procedure revisions
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(Section E8.1).
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An Unresolved Item.(URI 50-302/97-02-02) was identified for further NRC review
of the licensee's deletion of primary and secondary plant water quality
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requirements from the Final Safety Analysis Report (Section E8.2).
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A weakness was identified in that the extent of condition was not adequately
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addressed in the corrective actions for a Control Room Emergency Ventilation
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System surveillance test failure (Section E8.3).
A Violation (VIO 50-302/97-02-03) was identified for inadequate procedures for
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taking the plant from hot standby to cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following
main control room evacuation due to a fire (Section E8.9).
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The inspectors concluded that the licensee continued to make progress in
resolving the Improved Technical Specifications (ITS) setpoint program
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deficiencies.
In. general, the calculations reviewed were well documented.
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with well-founded assumptions, and followed the methodology specified in ISA
67.04, part II as referenced by instrumentation and controls Design Criteria
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Instrument String Error /Setpoint Determination Methodology. These
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calculations continue to be a significant improvement over calculations
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reviewed in IR 95-06 (Section E8.11).
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Additional examples of Violation 97-01-07. Instrument Setpoint Calculation
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Assumptions Not Translated into Procedures, were identified.
The temperature
ranges assumed in the Environmental and Seismic Qualification Program Manual.
which were used for the instrument loop uncertainty setpoint calculations,
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were not maintained in the Reactor Building and Intermediate Building (in
addition to the Auxiliary Building, which was previously identified).
Also.
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the temperature assumptions had not been appropriately translated into
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instrument calibration or area monitoring procedures.
In addition,
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3roceduralized controls were lacking for use of certain temperature sensitive
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ieasuring & Test Equipment in the Reactor Building (Section E8.11).
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A Violation (VIO 50-302/97-02-04) was identified for failure to conduct
. Technical Specification-required testing on Engineered Safeguards Actuation
System instrumentation (Section E8.12).
An Inspector Follow-up Item (IFI 50-302/97-02-05) was identified for
outstanding issues associated with the emergency diesel generator power uprate
modification (Section E8.14).
Plant Suonort
The inspector concluded the Security Program Peer Assessment was balanced and
beneficial for the licensee security staff in their efforts to improve
performance and regulatory compliance (Section S1.1).
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The inspectors assessed the licensee *s performance concerning the five areas of continuing NRC concern in
the following paragraphs: the assessments are limited to the specific issues addressed in the respective
paragraphs involving those issues primarily on the MC 0350 Restart Checklist.
NRC AREA 0F CONCERN
ASSESSMENT PARAGRAPH
E8.1
E8.2
E8.3
E8.5
E8.6
E8.7
E8.8
E8.9
E8.10
E8.11
Management Oversight
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G
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G
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Engineering Effectiveness
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G
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Knowledge of design basis
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compliance With Regulations
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Operator Performance
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NRC AREA 0F CONCERN
ASSESSMENT PARAGRAPH
E8.12
E8.13
01.2
01.3
Management Oversight
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G
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Engineering Effectiveness
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Knowledge of design basis
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Compliance With Regulations
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G
Operator Performance
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S = Superior: G = Good: A = Adequate / Acceptable: I = Inadequate: Blank = Not Evaluated / Insufficient
Information
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E8.1:
Corrective actions for VIO 50-302/96-09-04 Failure to Update Operating Curves to Reflect 1981
E8.2:
Corrective actions for VIO 50-302/96-09-03. Failure to Perform 10 CFR 50.59 Safety Evaluation
for Changes to Procedures Described in the FSAR For Controlling Dissolved Hydrogen Concentration
E8.3:
Corrective actions for VIO 50-302/96-06-07. Failure to Initiate a Problem Report to Resolve
CREVS Test Failure
E8.5:
Corrective actions for VIO 50-302/96-15-02. Failure of Reactor Coolant Pump Oil Collection
System to Retain Oil Leaking From Reactor Coolant Pump Motor
E8.6:
Corrective actions for VIO 50-302/96-11-04. Failure to Construct the Reactor Building Sump
Screens and Components in Accordance with the Approved Drawing
E8.7:
Corrective actions for VIO 50-302/96-06-02. Inadequate Procedure for Performing a Demineralized
Water Flush Following a Boric Acid Addition
E8.8:
IFI 50-302/96-201-11. Design Basis for Decay Heat / Core Flood / Reactor Coolant Piping Temperature
E8.9:
URI 50-302/97-01-08. Adequacy of Procedures to Take the Plant from Hot Standby to Cold Shutdown
from Outside the Control Room
E8.10:
Corrective actions for LER 50-302/95-025. Personnel Errors by Arc'hitect Engineer Result in
Operation Outside Design Basis Due to Inadequate Safety /Non-Safety Circuit Isolation
E8.11:
Corrective actions for EA 95-16. Use of Nonconservative Trip Setpoints for Safety-Related
Equipment
E8.12:
URI 50-302/96-17-03. Failure to Conduct Required Technical Specifications Surveillance Testing
on Safety Related Circuitry (GL 96-01)
E8.13:
NRC Generic Letter 96-01. Testing of Safety-Related Logic Circuits
01.2:
Hispositioned Components
01.3:
Shutdown Equipment Availability Controls
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Report Details
Summary of Plant Status
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The unit remained in Mode 5 throughout the inspection period, continuing in
the outage that began on September 2. 1996.
An outage on the "B" train of
emergency core cooling system (ECCS) equipment was conducted to perform
corrective maintenance and implement a design change on the IB Emergency
Diesel Generator (EDG).
The purpose of the design change was to upgrade the
EDG turbocharger nozzle rings and replace the intercooler with a more
efficient version.
These changes were expected to result in 150 kilowatts
(kW) of extra diesel ca)acity.
The 1A EDG was upgraded during an outage in
January 1997.
During t11s inspection period, the licensee had not begun any
other major physical modification work.
L. Operations
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Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707 the inspectors conducted frequent
reviews of ongoing plant operations.
The inspectors followed up on
deficiencies with operator logs documented in NRC Inspection Report (IR)
50-302/97-01 and observed that log content and consistency has improved.
Significant items were logged in both the Operations Shift Supervisor
and Shift Manager logs inconsistencies between Shift Supervisor and
Shift Manager logs were reduced, and the time of turnover was being
logged by Shift Supervisors on Duty (S500). The licensee was nearing
completion at the end of the report period on a new revision of
Operations Instruction (01)-5. Log Keeping. Revision 2. to clarify
requirements and management expectations. The ins)ectors crncluded that
licensee management was appropriately addressing t1e previously
identified logging deficiencies.
The inspectors observed good examples of conservative decision making as
discussed in Section 01.3 regarding shutdown equipment availability
controls.
However. Several attention to detail and poor process
problems discussed in Section 01.2 resulted in the identification of a
violation of requirements for maintaining configuration and status
control of plant equipment.
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01.2 Misoositioned Comoonents
a.
Insoection Scooe (71707. 92901)
The inspectors reviewed the licensee's response to four examples of
valves found in the incorrect position in January 1997 which was
previously documented in NRC Inspection Report (IR) 50-302/97-01.
The
licensee has subsequently discovered several other examples of equipment
status control problems which the inspectors incorporated in their
followup.
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b.
Observations and Findinas
The licensee had taken prompt interim corrective actions for the
incorrectly positioned valves discussed in IR 97-01.
The licensee's
investigation and root cause analysis was still not finalized at the
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close of this Inspection Report period due to the scope and content of
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the investigation being expanded as more examples of incorrect equipment
status and equipment tagging were identified.
The licensee's
preliminary assessment indicated problems in the control of clearance
tagging which was incorporated into preexisting efforts to revise the
clearance and tagging process.
Other problems were attributable to a
single individual with whom the licensee was taking personnel action.
the minor maintenance team control of ventilation equioment and
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instrumentation, and control of plant modification wort.
The licensee
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identified several corrective actions for each of these items.
However.
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the inspector observed that the Operations department had not aggregated
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the individual problems into one corrective action document even though
their effort was focused on a single equipment status control problem.
The inspector also observed that the licensee had not yet formally
documented their corrective action alan to ensure it identified root
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causes. approariately addressed eac1 cause, and would be a comprehensive
solution to t1e entire problem.
Other examples 'of equipment status
control problems were identified during this report period and had not
yet been fully investigated and incorporated into the licensee's
efforts.
Consequently, the inspectors considered these problems as
further examples of significant deficiencies in the licensee's overall
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process for configuration and status control of plant equipment
The
inspector also concluded the licensee has not yet fully investigated and
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corrected these problems so they are being identified as several
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examples of a violation of licensee procedural requirements. VIO 50-
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302/97-02-01. Failure to Follow Equipment Status Control Procedural
Requirements.
Specific examples are discussed below.
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Nuclear Services Cooling System Vent Valve (RWV-73) was inadvertently
left open on January 24. 1997. by an operator verifying an idle Decay
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Heat system heat exchanger was filled per Surveillance Procedure (SP)
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306. Weekly Surveillance Log. Revision 13.
It was discovered by another
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operator after a pum) start a
water flowing from t1e valve.pproximately five hours later resulted in
The inspector noted that SP-306'did not
specify which valve numbers to operate when directing the verification
and it did not have any valve position restoration signature or
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verification.
The inspector considered this as another deficiency in
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the licensee's ecuipment status control process.
Operating Procedure
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(OP) 404. Decay Feat Removal System. Revision 104, requires RWV-73 to be
closed for normal operations.
This is considered the first example of
VIO 50-302/97-02-01. Failure to Follow Equipment Status Control
Procedural Requirements.
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Nitrogen system 3ressure instrument isolation Valve NGV-313 was found
incorrectly in tie closed position on January 26. 1997, when a clearance
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was being im)lemented.
It apparently was closed following maintenance
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activities.
]ut Equipment Alteration Logs were not retained for minor
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maintenance activities so record.s of the valve manipulation were not
retrievable.
The inspector considered this to be inadequate control of
plant equipment positioning.
Procedure OP-414, Nitrogen and Hydrogen
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Systems. Revision 34. requires NGV-313 to be open for normal operations.
This is considered the second example of VIO 50-302/97-02-01. Failure to
Follow Equipment Status Control Procedural Requirements.
The makeup system air isolation to Valve MUV-243. Prefilter 2A Outlet,
was found incorrectly in the closed position on January 24. 1997, when
hanging a clearance.
The valve was apparently closed without any
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procedural controls or documentation to isolate an air leak.
Procedure
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OP-402. Makeup and Purification System. Revision 90, requires MUV-243 to
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be in the open position.
Procedure OP-411. Instrument and Station Air
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System. Revision 53, requires the valves in the instrument air flow path
to MUV-243 to be in the open position for normal operations.
This is
considered the third example of VIO 50-302/97-02-01. Failure to Follow
Equipment Status Control Procedural Requirements.
The inspector had
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previously questioned the method of control and verification for root
isolation valves such as this that are commonly operated by instrument
technicians.
The licensee recognized that they did not have a procedure
to verify the position of these valves to pneumatic valve controllers
and initiated Precursor Card 97-0733 to implement further corrective
action.
Precursor Card 97-0733 was closed by the licensee on March 7
with no further action based on the large number of root valves that are
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not labeled and do not have designated valve numbers.
The closure
documentation noted that Equipment Alteration Log forms are required to
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document mani]ulation of these valves but as noted above in the NGV-313
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discussion. t1ese logs were frequently not maintained.
The closure
documentation also noted that the position of many root valves was
verified by post-maintenance testing that ensured the component supplied
with air could perform its function.
The inspector considered the lack
of control and identification for instrument and component root valves
to be another deficiency in the licensee's process for equipment status
control.
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Normally open station air header drain Valve SAV-49 was found in the
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closed position on January 28, 1997.
It was apparently also closed
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without procedural controls or documentation to isolate a leaking
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downstream solenoid valve.
OP-411. Instrument and Station Air System.
Revision 53, requires SAV-49 to be in the open position for normal
operatiem .
This is considered the fourth example of VIO 50-302/97-
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02-01. Failure to Follow Equipment Status Control Procedural
Requirements.
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Oily water separator tank Vent Valves SDV-107. 108 and 109 were found
open instead of closed as required on March 7. 1997, while reviewing a
draft clearance in the field.
These valves were operated to vent the
tank but were difficult to access.
The licensee's preliminary
investigation revealed that more accessible downstream valves were used
to vent the tank, recuiring SDV-107.108, and 109 to be open.
Procedure
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OP-422. Turbine Builcing Sump Oil-Water Separator Revision 8. does not
allow this alignment when venting and requires SDV-107, 108 and 109 to
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be closed for normal operations.
This is considered the fifth example
of VIO 50-302/97-02-01. Failure to Follow Equipment Status Control
Procedural Requirements.
The licensee was evaluating a procedure change
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to use the more accessible vent alignment.
Fire damper (FD) power links for FD-47 and FD-83 were found open on
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March 21. 1997. during surveillance testing, when the dampers failed to
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actuate.
The licensee's investigation revealed that the links had been
opened and documented as closed by a single verification in October of
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1996 while performing SP-607. Fire Damper Inspection. Revision 18.
The
licensee could not determine any other maintenance or operational
evolutions that could have removed the links.
Step 4.4 requires
restoration of the links to the closed position.
Contrary to that step,
the links were found open.
This is considered the sixth example of VIO
50-302/97-02-01. Failure to Follow Equipment Status Control Procedural
Requirements.
On March 28. a plant operator removed a seal and throttled nuclear
services closed cycle cooling valve SWV-24 open to increase flow to
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600 gpm to the in service spent fuel pool (SFP) cooler B to address a
several degree rise in SFP temperature.
The plant operator then
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replaced the seal.
The plant operator and control room operator
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directing his actions had exhibited questioning attitudes and discovered
the SFP heat exchanger secondary cooling flow to be only 200 gpm but had
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elected to throttle it to 600 gpm without referring to proceoeral
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guidance.
Oncoming shift operators questioned their actions and
verified that OP-408. Nuclear Services Cooling System. Revision 84,
required SWV-24 to be throttled 2 and 1/8 turns o]en.
After positioning
SWV-24 to this setting. flow rose to 2000 gpm.
T1e operators checked
the corresponding valve on SFP cooler A. SWV-23. and found it positioned
incorrectly.
They repositioned it to the required setting of two turns
open.
The failure to follow procedural guidance when repositioning
SWV-24 and the discovery of SWV-23 and 24 in the incorrect throttled
position is considered the seventh example of VIO 50-302/97-02-01.
Failure to Follow Equipment Status Control Procedural Requirements.
The inspector did observe a positive practice in that each later problem
was promptly investigated and documented per Operations Instruction 12.
Investigation of Abnormal Events. Revision 1.
This was indicative of
good responsiveness to problems on the later examples.
Although the
quality of the 01-12 reports varied widely due to the lack of specific
content and format guidance, the inspector noted that management
expectations for shift supervision to take ownership of problems and
initiate corrective actions had been effective.
The 01-12
investigations were generally good initial afforts to gather data,
identify short term corrective actions, and recreate the event.
c.
Conclusions
The inspector concluded, that the Operations department was not using
the corrective action system appropriately as a tool to facilitate their
plan.
Efforts were disjointed and similar problems were not combined
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into one effort to ensure a consistent and comprehensive solution was
developed, documented, and implemented.
Consequently, senior management
involvement and awareness of the Operations department's plans was
limited.
The inspector concluded the timeliness of the root cause
evaluations and subsequent development of corrective actions was poor
because it had taken over two months and still was not complete.
The inspector concluded that the equipment in the incorrect position was
a violation of procedural requirements.
This violation is of concern in
that it involved seven examples of equipment in the incorrect position
and revealed your inadequate controls to maintain the appropriate status
of plant equipment.
The inspectors assessed the licensee's performance relative to their
controls to maintain the appropriate status of plant equipment. in the
five areas of continuing NRC concern:
Management Oversight
- Inadequate
Engineering Effectiveness
- N/A
Knowledge of the Design Basis
- N/A
Compliance with Regulations
- Inadequate
Operator Performance
- Inadequate
01.3 Shutdown Eauioment Availability Controls
a.
Insoection Scooe (71707)
The inspector observed stringent licensee controls of shutdown equipment
during normal Mode 5 plant condition changes and maintenance outages 6nd
reviewed the licensee's process for this control.
b.
Observations and Findinas
The licensee's Administrative Instruction (AI) 504. Guidelines for Mode
5 Outages and Reduced Reactor Coolant System (RCS) Inventory Operations.
Revision 7. contains administrative controls for sensitive shutdown
conditions such as reduced 3rimary inventory evolutions to ensure the
continued availability of slutdown cooling.
Section 4.1 Mode 5
Requirements When RCS is Filled and Vented, also contains requirements
for normal Mode 5 cold shutdown conditions.
These recuirements exceed
Technical Specification requirements to provide an adcitional level of
safety.
For example. AI-504 prefers two EDGs to be 03erable as defense
in depth even though only one is required per the Tec1nical
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Speci fications.
If an activity requires a departure from the
requirements of AI-504, a justification has to be submitted evaluating
the safety effect and presented to the Plant Review Committee (PRC).
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exam31e of the Al-504 controls was a request to perform instrument work
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in tie 230kV switchyard that would affect EDG B operability that was
presented to the PRC.
The PRC originally did not approve the request
due to lack of overall coordination and logistical pbnning. The PRC
recuested a single accountable person be assigned to oversee the work
anc ensure adequate coordination to limit the length of the work and
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minimize the associated risk before they would approve an exce3 tion.
The inspector has observed that the licensee consistently exhiaits a
high degree of conservative questioning and decision making when
reviewing exceptions to AI-504.
c.
Conclusions
The inspector concluded that the licensee's AI-504 restraints and
required PRC reviews for normal Mode 5 conditions constituted a good
means of oversight for shutdown safety and defense in depth.
The
inspector considered this a licensee strength.
The inspectors assessed the licensee's performance relative to shutdown
equipment availability controls, in the five areas of continuing NRC
concern:
Management Oversight
- Good
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Engineering Effectiveness
- N/A
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Knowledge of the Design Basis
- N/A
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Compliance with Regulations
- Good
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Operator Performance
- Good
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06
Operations Organization and Administration
06.1 Effective March 3. 1997. Greg Halnon assumed the acting role of
Assistant Plant Director. Nuclear Safety.
He will be engaged with
issues involving nuclear safety oversight of the plant and conduct of
the Plant Review Committee.
He will also be tasked with assuming the
role of Director. Nuclear Plant Operations in Bruce Hickle's absence.
Additionally, he will be the overall project manager for ensuring the
Final Safety Analysis Report (FSAR) is properly revised and technically
correct for restart of t1e plant.
Mr. Halnon's previous duties of coordinating NRC inspections,
interfacing with NRC Resident Inspectors and coordinating violation
responses will be performed by the Nuclear Regulatory Assurance Group.
07
Quality Assurance in Operations
07.1 Licensee Self- Assessment Activities
a.
Insoection Scooe (71707. 40500)
The inspectors reviewed various licensee self-assessment activities and
corrective action process which included:
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Routine reviews of Nuclear Quality Assessments (NOA) activities
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and findings:
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Observation of the NOA monthly audit exit interview:
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A review of the Plant Management Self Assessment Program and
schedule-
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Observation of the licensee's internal Restart Readiness Review
Panel meetings;
Observations of the full Nuclear General Review Committee (NGRC)
meeting on March 12:
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Reviews of precursor cards entered in the corrective action
systm
Obser ration of a management Corrective Action Review Board (CARB)
meetwig:
Observations of corrective action Precursor Card Screening
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Committee meetings.
b.
Observations and Findinas
NOA inspections continued to be thorough and diverse.
N0A continued to
provide timely and responsive surveillances to )lant management in
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potential plant problem areas.
The inspector caserved that a goal of
N0A management to be proactive and identify problems before they develop
into significant issues remains a challenge.
N0A has not consistently
been the first to identify a significant plant problem and characterize
it properly to get it corrected before it 3ecame self-revealing.
However, the ins)ector has observed that the NOA staff has identified
several notewortly findings and were continuing to utilize outside
assistance to provide different audit perspectives.
The NGRC conducted an extensive review of site activities.
The
inspector observed that a new offsite member was attending his first
meeting and as yet had not been assigned to a subcommittee.
The new
member replaced a former member who resigned.
The former member's
subcommittee, the Quality and Regulatory Verification Subcommittee,
again had to meet without the outside member chairman as previously
mentioned in IR 50-302/97-01.
The inspector concluded that the NGRC
questioning and discussing issues were beneficial and served to
highlight several ongoing problem areas to the new site management team
such as poor commitment tracking, lack of a sitewide integrated
schedule, and management of significant site process backlogs.
The
inspector did not identify any deficiencies.
The inspector reviewed the licensee's new self-assessment process and
the 1997 master schedule.
The inspector did not identify any
deficiencies with the process and concluded the schedule was both
diverse and aggressive.
The inspector also concluded that successful
implementation could give the licensee broad assessments of varying
areas and be essential to sustaining long term improvement.
Only one
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assessment had been completed under the new program.
The inspector's
review of that assessment is ongoing and will be documented in a
subsequent report.
The inspectors continue to observe problems with the licensee's
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Corrective Action Program implementation as noted above in Section 01.2.
The inspectors have also observed problems with the cross referencing of
precursor cards (PC) in the system to Licensee Event Reports (LERs) and
Violations.
Numerous extra PCs have been generated and issued for
problems already in the system such as PC 97-2089 which was issued on
reportability problems although PC 97-0841 had been issued and was the
focal point for the licensee's investigation.
The inspectors have
'
observed another problem with the failure to include corrective action
work in PC documentation and scope and the failure to aggregate problems
,
into one larger level PC.
j
c.
Conclusions
The inspectors concluded the licensee continues to restructure their
self-assessment activities in an attempt to improve their programs.
Problems continue to be observed. but they are recognized and being
addressed by licensee management.
The PC problems indicated an underuse
!
of the PC system as a mechanism to correct large program problems and a
lack of visibility of significant problems for management review.
Changes to the PC tracking software and processes were being
i
investigated by the licensee to address these concerns.
}
07.2 Plant Review Committee Activitie.1
a.
Insoection Scoce (71707. 40500)
,
!
Inspectors have attended numerous planned and emergent PRC meetings to
l
assess the licensee's control of safety significant activities.
The
inspector reviewed recent planned changes to the PRC procedure, AI-300.
1
Plant Review Committee Charter. Revision 39. and reviewed primary and
alternate membership changes against the licensee's commitments in FSAR
c
Section 12.8.1.
The inspector discussed various initiatives and goals
,
for PRC reviews with the PRC Chairman.
He was recently reassigned to
!
the position of Assistant Plant Director Nuclear Safety to allow him to
'
devote more time to PRC oversight.
1
b.
Observations and Findinas
The inspector has observed that recent PRC reviews are thorough and
'
detailed.
A significant focus has been ) laced on the completeness and
i
adequacy of 10 CFR 50.59 evaluat e s.
T1e formality of PRC meetings has
!
notably increased with the adoptiu of standard review item formats, the
requirement for each PRC review item to have a presenter, and PRC
presentation expectations.
Questioning of presenters by PRC members was
detailed and beneficial and held to consistently high standards of
!
performance.
The inspector observed a PRC meeting was canceled on
March 5 because an issue did not have a presenter.
The PRC would not
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_ . ,
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9
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consider the issue until their requirement for an individual to present
was fulfilled.
The inspector reviewed the revised membership of the PRC
and did not identify any problems with the licensee's choices as members
and alternates.
The inspector did observe that the number of alternates
was decreased in an attempt to utilize more effective individuals and
'
ensure greater consistency.
Revision 40 to AI-300 was issued March 27.
1997. The inspector's review of the new procedure commenced at the end
of the report period and will be documented in the next NRC inspection
l
report period.
The .inspoctor identified a concern with screening of
items to ensure they were considered for PRC review when required.
The
PRC Chairman had similar concerns and was investigating methods to
ensure required items did not bypass the PRC.
The licensee currently
l
does not have a formal process to ensure this although the inspector was
i
not aware of any recent examples where a required PRC review was not
obtained.
The inspector was satisfied with the current initiative of
l
the PRC chairman but will review the ultimate fix.
,
'
c.
Conclusions
The inspector concluded the PRC was functioning well and was providing
,
appropriate oversight and safety perspective.
The changes to restrict
l
membership, assign a full time chairman, and refine expectations were
l
beneficial initiatives by the licensee and were indicative of an
emphasis on improving nuclear safety.
l
JL. Maintenance
l
M1
Conduct of Maintenance
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M1.1 General Comments
a.
Insoection Scoce (62703. 62707. 61726)
l
The inspectors observed all or portions of the following work requests
!
(WR) and surveillances and reviewed associated documentation.
The
l
following activities were included:
WR NU 0341383: Change out cells #61 and #107 on the B battery
.
train. DPBA-1B
WR NU 0339715:-Upgrade EGDG-1B in accordance with Modification
.
Approval Record (MAR) 96-10-05-01
SP 907A: Monthly Functional Test of 4160V Engineered Safeguards
l
(ES) Bus A Undervoltage Relaying
b.
Observations and Findinas
,
.
l
The inspectors observed the activities identified above and concluded
j
that all work was accomplished in accordance with the work instructions
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and procedures.
All work observed was performed with the work packages
l
present and in active use.
Pre-job planning was thorough and in
l
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. ~,- .
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10
sufficient detail to prepare the technicians for the assigned tasks.
Technicians were experienced and knowledgeable of their assigned tasks.
The inspectors frequently observed supervisors and system engineers
monitoring job progress, and quality control personnel were present
whenever required by procedure.
c.
Conclusions
The inspectors concluded that all observed maintenance and surveillance
activities were performed in accordance with procedures and desired
results were obtained.
JJL Enoineerino
/
El
Conduct of Engineering
El.1 Precursor Card 97-1517 (37551)
The inspector reviewed PC 97-1517. which requested an evaluation of FPC
Mechanical Calculation M94-0003. Pressure Locking and Thermal Binding
Evaluation. Revision 1.
The PC reported that the mechanical calculation
did not account for both closing and reopening of the Emergency
'
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Feedwater (EFW) isolation valves by automatic Emergency Feedwater
i
Initiation and Control (EFIC) actuations. The PC stated that the
l
evaluation of the possibility of pressure locking and thermal binding on
the Emergency Feedwater Pump (EFP) flow isolation to the "B" steam
'
generator. Emergency Feedwater Valve (EFV)-32 and EFV-33. should be
reevaluated.
Valves EFV-32 and EFV-33 are flexible wedge valves and are
susceptible to pressure locking and thermal binding.
The original
i
evaluation relied on the fact that once closed, these two valves would
'
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not open again during the accident.
The valves closed to isolate
i
feedwater to the effected generator. using Feed Only Good Generator
(F0GG) logic criteria.
I
During the design verification review. the licensee discovered that the
valves may have to be reopened if the steam generator pressure recovers
i
or if there were certain overcooling event.
The licensee intends to
l
evaluate these conditions prior to restart.
The inspector reviewed the
flow diagram discussed the condition with the shift manager, reviewed
the applicable portions of M94-0003, and reviewed the PC.
The inspector
concluded that the licensee had done a good job of identifying and
documenting the problem and found this to be an example of both
j
appropriate and critical self analysis.
Additionally. Emergency Feedwater Pump (EFP) flow isolation to the "A"
'
steam generator. EFW-11 and EFW-14. are double-disk. Parallel flexible
i
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wedge valves.
These valves are equipped with an integrated relief from
,
the bonnet to the upstream side and are not susceptible to pressure
locking and thermal binding.
4
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11
E8
Miscellaneous Engineering Issues
E8.1
(Closed) VIO 50-302/96-09-04 Failure to Uodate Ooeratina Curves to
Reflect 1981 Power Vorate
a.
Insoection Scoce (92903)
,
This violation involved failure to translate design requirements into
procedures in that Operating Procedure OP-103A. Start-up Curves, was not
updated until July 1995 to reflect the 1981 reactor power u] rate.
The
inspectors reviewed the licensee's corrective actions for t11s
,
violation.
b.
Observations and Findinos
The inspectors verifie-
at the licensee had completed corrective
actions for this violation. as stated in their letter of response dated
November 4. 1996, which included:
-
Revising 0P-103A to provide updated curves.
As noted in NRC
Inspection Report 50-302/96-03, the curves were revised in 1995.
-
Sampling additional packages for safety system modifications to
ensure the appropriate operations procedures were identified and
revised.
.
The corrective actions were detailed in Problem Report (PR) 96-0423.
For extent of condition, the licensee selected a sample of Technical
Specification (TS) Amendments and associated MARS and verified that all
.
necessary procedures were revised in a timely manner.
The review found
'
i
that all necessary procedures had been revised in a timely manner and
Operations had notified the Nuclear Safety Assessment Team (NSAT) to
close the PR.
However, in reviewing the PR and associated corrective
,
actions. the inspectors noted that the Operations documentation of
review of the TS Amendments and MARS found that, even though all
necessary procedures were revised in a timely manner, many procedures
tied to modifications did not appear on the Procedure Revision
Verification Sheet for the MAR. and identification of required Jrocedure
'
changes was inconsistent for TS Amendments. After questioning Jy the
inspectors, the licensee agreed that these weaknesses should be
'
addressed before closure of the PR.
The PR Corrective Action Plan was
revised to address these weaknesses.
Also, the licensee pointed out
that in-process corrective actions for another PR (96-0189) included a
review to determine the extent of condition for MARS not identifying
procedures needing revision.
In addition. Nuclear Engineering Procedure
(NEP)-212. Processing of Modification Projects By Nuclear Projects, had
.
recently been revised to enhance the review for determining which
,
departments need to review MAR packages for procedure changes.
Based on
the corrective actions completed and those ongoing. this item is closed.
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c.
Conclusions
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The inspectors concluded that the licensee's completed and ongoing
i
corrective actions were adequate to resolve this violation.
However,
e
i
failure to revise PR 96-0423 to address the discrepancies identified,
relative to identification in MAR packages of needed procedure
i
revisions, was considered a weakness.
I
j
The inspector assessed the licensee *s performance, with respect to this
j
issue, in the five NRC continuing areas of concern:
1
Management Oversight
- Adequate
Engineering Effectiveness
- Adequate
i
Knowledge of the Design Basis - N/A
Compliance with Regulations
- Adequate
Operator Performance
- N/A
j
e
E8.2 (Closed) VIO 50-302/96-09-63. Failure to Perform 10 CFR 50.59 Safety
i
Evaluation for Chances to Procedures Described in the FSAR For
?
Controllino Dissolved Hydroaen Concentration
a.
Insoection Scoce (92903)
,
4
)
This violation involved failure to perform a 10 CFR 50.59 evaluation for
changing the reactor coolant dissolved hydrogen concentration specified
i
in the FSAR from 15 - 40 cc/kg to 25 - 50 cc/kg.
The inspectors
i
reviewed the licensee's corrective actions for this violation.
1
)
b.
Observations and Findinas
)
The inspectors ve'rified that the licensee had completed corrective
j
actions for this violation, as stated in their letter of response dated
i
November 4.- 1996. which included:
1
,
1
Performing a 10 CFR 50.59 evaluation for revising Tables 4-10 and
j
-
j
9-3 of the FSAR to specify 25 - 50 cc/kg dissolved hydrogen
'
concentration in the reactor coolant.
-
Increased sensitivity within the Chemistry Department to the
process for the review of the FSAR during procedure revisions.
!
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Establishment of a Procedure Writer position in the Chemistry
i
Department to assure a standard and consistent approach to
procedure changes.
-
Instruction of the new Chemistry Department Procedure Writer in
the proper review of FSAR during procedure changes.
-
Training of the new Chemistry Department Procedure Writer in 10 CFR 50.59 evaluations and causal analysis.
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13
Use of details of this violation in Supervisor Workshop on Safety
-
Culture being developed as part of Management Corrective Action
Plan (MCAP).
The inspectors verified the above corrective actions through interviews
with the Chemistry Department Manager and the Chemistry Department
Procedure Writer review of PR 96-0422. review of documentation of
initial.10 CFR 50.59 training, and review of FSAR changes.
The
Chemistry Department Procedure Writer assumed his position on August 5,
1996.
He received Causal Analysis training on November 13, 1996 and
initial 10 CFR 50.59 training on January 23. 1997.
He was scheduled for
additional 10 CFR 50.59 training on March 31 - April 1,1997.
During review of corrective actions. the inspectors noted that a FSAR
change and associated 10 CFR 50.59 evaluation were documented to change
the reactor coolant hydrogen concentration to 25 - 50 cc/kg.
Before the
change was included into the next FSAR Revision (Revision 23). as part
of an overall review of FSAR chemistry requirements, another change and
10 CFR 50.59 evaluation deleted Tables 4-10 and 9-3. which included the
hydrogen concentration and other reactor coolant water quality
requirements. . from the FSAR.
The change also deleted Table 4-11. which
covered steam generator Feedwater Quality Specifications.
The change
was incorporated in Revision 23 to the FSAR.
The water quality
requirements deleted from the FSAR were included in a site procedure.
Licensee Chemistry Department personnel revealed that the reason for
moving the water quality to procedural control was that the water
quality requirements need to be changed frequently because of changes
needed based on site specific and industry experience.
The water
quality requirements are specified in Site Procedure CH-400, Revision 9.
Nuclear Chemistry Master Scheduling Program.
The inspectors verified
<
that Chemistry Procedure CH-400 contains all of the requirements from
deleted FSAR Tables 4-10, 4-11. and 9-3 and that any changes to
procedure CH-400 were controlled by a 10 CFR 50.59 evaluation.
Based on the corrective actions completed for the specific violation,
,
this item is closed.
However, removal of water chemistry requirements
from the FSAR without NRC approval may not meet the requirements of 10 CFR 50.59.
This issue is considered unresolved pending further review-
,
by the NRC and is identified as Unresolved Item (URI) 50-302/97-02-02.
Deletion of Water Quality Requirements from the FSAR.
c.
Conclusions
,
l
The inspectors concluded that the licensee's completed and ongoing
corrective actions for the specific violation were adequate to resolve
the violation.
VIO 50-302/96-09-03 is closed.
However, subsequent
actions to remove water quality requirements from the FSAR without NRC
4
j
approval may not meet the requirements of 10 CFR 50.59.
f
14
The inspector assessed the licensee's performance, with respect to the
specifics of the violation, in the five NRC continuing areas of concern:
hnagement Oversight
- Adequate
.
Engineering Effectiveness
- Adequate
Knowledge of the Design Basis - N/A
Compliance with Regulations
- Adequate
Operator Performance
- N/A
.
E8.3 (Closed) VIO 50-302/96-06-07. Failure to Initiate a Problem Reoort to
Resolve CREVS Test Failure
a.
Insoection Scooe (92903).
This violation involved failure to follow procedures in that a PR was
not issued to document a failed surveillance (SP-186) on Control Room
Emergency Ventilation System (CREVS) Filter AHFL-4A.
Procedure CP-111
required initiation of a PR for test failures.
The issue was initially
identified as URI 50-302/96-03-10.
An additiona.1 example of this URI
was identified in paragraph M1.1 of NRC IR 50-302/96-04.
This example
involved failure to issue a PC or PR for a failed surveillance on Makeup
Tank Instrumentation Calibration (SP-169G).
URI 50-302/96-03-10 was
upgraded to a violation in IR 50-302/96-06, but the example from IR
50-302/96-04 was not specifically identified. The inspectors reviewed
the licensee's corrective actions for the violation.
b.
Observations and Findinos
The inspectors verified that the licensee had completed corrective
actions for this violation. as stated in their letter of response dated
August 26. 1996, which included:
-
Discussion with Engineering personnel involved with this issue to
ensure they were clear on the expectations for implementing the
requirements of CF-111.
-
Revision of SP-186 to clarify the requirement for generating
appropriate corrective action documentation for surveillance
failures.
The inspectors verified the above corrective actions through interviews
with responsible Engineering personnel. review of PR 96-0142, and review
of SP-186 and associated procedure CP-148. Ventilation Filter Testing
Program.
In addition to the specific corrective actions identified in
the letter of response. a new corrective action program has been
implemented with increased emphasis on initiating PCs for any problem
identi fied.
Although the URI specific example identified in IR
50-302/96-04 was not addressed in the violation or the licensee's
response the new corrective action program and the increased emphasis
on identification of problems should be sufficient to resolve the
additional example identified in IR 50-302/96-04.
4.
15
Also, the inspectors noted that the corrective actions did not
i
adequately address the " extent of condition." When questioned by the
inspectors. the licensee performed word searches on all surveillance
procedures and determined that only 96 out of a total of approximately
250 surveillance procedures adequately addressed the need to initiate a
PC for failed surveillances.
A PC (97-1556) was immediately issued to
specify and document corrective actions for this problem,
c.
Conclusions
!
The inspectors concluded that the licensee's completed corrective
actions for the specific failed surveillance identified in the violation
were adequate.
However, failure to adequately address the " extent of
condition" is considered a weakness.
The vfolation is closed.
The inspector assessed the licensee's performance, with respect to this
issue, in the five NRC continuing areas of concern:
.
Management Oversight
- Adequate
Engineering Effectiveness
- Adequate
.
Knowledge of the Design Basis - N/A
-
e
Compliance with Regulations
- Adequate
Operator Performance
- N/A
.
E8.4 (Closed) VIO 50-302/96-05-01. Failure to Follow Procedures to Initiate
Corrective Actions for Bent Main Steam Line hanaers (92903).
,
'
This violation was closed in NRC IR 50-302/97-01 based on the NRC Safety
Evaluation Report (SER) dated January 22. 1997.
During the current
inspection the inspectors field verified the replacement of the bent
)
hanger rods.
The inspectors noted that the rod for Support MHS-13B was
in hard contact with two structural members on an adjacent whip
restraint.
The system and sgport were in their cold position.
Review
of the Engineering analysis revealed that when the pipirg is heated up
the system growth will be in a direction to move the rod away from the
structural members.
(The replacement of the bent rod had been
accomplished while the piping was hot).
However. in the cold position.
the condition of the support, i.e., the amount of force being exerted on
the hanger rod by the structural members was unknown.
The hanger rod
was removed and determined to be in good condition with no permanent
deformation.
By the end of the inspection, the licensee had issued WR NU 0341874. DCN
97-081. Revision 1 to Calculation S96-0130. and Plant Equipment
Equivalency Replacement Evaluation (PEERE) 1495 to move the hanger rod
upper lug support so that the rod would not be in contact with the whip
restraint structural steel.
This will resolve this issue.
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E8.5 (Ocen) VIO 50-302/96-15-02. Failure of Reactor Coolant Pumo 011
Collection System to Retain Oil Leakina From Reactor Coolant Pumo Motor
a.
Insoection Scoce (92903)
i
This violation involved failure of the reactor coolant pump (RCP) oil
collection system to retain the leakage from RCP "D" motor lube oil
system. The inspectors revi ed the licensee's corrective actions for
this violation.
b.
Observations and Findinas
The inspectors ve fied that the licensee's corrective actions were
i
completed to date for this violation, as stated in their letter of
1
response dated December 20, 1996, which inc10ded:
-
Identifying and repairing the source of leakage in RCP "D" lube
oil piping system.
J
_
Identifying and repairing the leaking section of RCP "D" oil
-
collection system.
-
Inspection of the oil collection system for the other 3 RCP
motors.
Stressing the importance of cleaning all oil collection enclosure
-
joint surfaces of all residual oil before applying sealants.
The inspectors verified the above corrective actions through ~ interviews
with the res3cnsible Maintenance personnel and review of WRs NU 0338636
(repair of t1e leaks in RCP D lube oil system) and NU 0338186
(inspection and repair of the oil collection enclosures for all 4 RCP
motors). At the time of the inspection, all inspection and repa'ir work
j
had been completed on RCPs A and D.
Inspection and necessary repair
work was in process on RCP B and scheduled to begin on RCP C the week of
March 24. 1997.
On March 19. 1997, during their Reactor Coolant System Readiness Review.
the licensee found that the following RCP lube oil components were
located outside the lube oil collection system: upper oil reservoir
drain line and valve for RCPs B. C and D. a check valve in the low
pressure oil piping for RCP B and two check valves in the low pressure
oil piping for RCP C.
PC 97-1519 was written and the issue was still
being evaluated at the close of the inspection.
The violation remains
open pending resolution this new issue.
c.
Conclusions
The inspectors concluded that the' licensee's completed and ongoing
corrective actions were adequate to resolve the violation.
However, the
violation remains open pending resolution of the new issue relative to
i
components outside the oil collection system.
.
17
The inspector assessed the licensee's performance, with respect to the
specific violation, in the five NRC continuing areas of concern:
Management Oversight
- Adequate
.
Engineering Effectiveness
- Adequate
.
Knowledge of the Design Basis - N/A
Compliance with Regulations
- Adequate
.
Operator Performance
- N/A
.
E8.6 (Ocen) VIO 50-302/96-11-04. Failure to Construct the Reactor Buildina
Sumo Screens and Comoonents in Accordance with the ADDroVed Draw 1na
a.
Insoection Scoce (92903)
This violation involved failure to construct (original construction) the
Reactor Building (RB) Sump Screen support frame in accordance with
drawing recuirements.
Sup3 ort frame welds were missing or of poor
quality anc some gaps in t1e structure exceeded the maximum screen mesh
criteria.
The inspectors reviewed the licensee's corrective actions for
this violation,
b.
Observations and Findinas
The inspectors verified that the licensee's corrective actions were
completed to date for this violation as stated in their letter of
,
response dated November 27, 1996, which included:
-
PR 96-0374 was issued to document and resolve this issue.
-
The support structure and welds were inspected and repaired to
meet drawing requirements.
1
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_An operability review was performed to evaluate the "as-found"
condition to determine if the structure was capable of performing
,
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its design basis function in the degraded condition.
-
Plant records were reviewed to attempt to identify the contractor
responsible for installation of the sump screens.
Since the
records did not clearly identify the contractor, samples of other
similar installations were inspected for other deficiencies.
,
Current surveillances for the sump would be evaluated for
-
adequacy.
The inspectors verified the above corrective actions through interviews
with the responsible plant personnel and review of the documents listed
above.
In addition, the NRC observed inspection of the sumps for
missing welds and reviewed documentation of repairs as detailed in NRC
Inspection Report 50-302/96-11.
Review and revision of the RB sump surveillance procedures was not
scheduled until June 1. 1997.
.
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18
,
The licensee's sample inspection of similar installations included 6
components / structures.
Discrepancies (missing structural members) were
,
identified on 2 structures (a lead shielding support for Makeup System
Jiping and a support for the Nuclear Service and Decay Heat Exchanger.
'
l
Joth in the Auxiliary Building).
At the time of the NRC inspection, the
!
licensee was evaluating these inspection findings to determine the scope
i
for expanding the inspection sample.
'
c.
Conclusions
The inspectors concluded that the licensee had completed the corrective
1
actions for the specific violation on the Reactor Building Sump Screens.
I
However. the violation remains open )ending review of corrective actions
'
for the discrepancies found during t1e " extent of condition"
l
inspections.
The inspector assessed the licensee's performance, with respect to the
specific violation, in the five NRC continuing areas of concern:
,
l
'
Management Oversight
- Good
Engineering Effectiveness.
- Adequate
.
Knowledge of the Design Basis - N/A
Compliance with Regulations
- Adequate
Operator Performance
- N/A
E8.7 (Closed) VIO 50-302/96-06-02. Inadeauate Procedure for Performina a
Demineralized Water Flush Follow 1na a Boric Acid Addition
a.
Insoection Scooe (92903)
This violation involved the failure of Procedure OP-402 to specify
flushing with demineralized water following a boric acid addition.
The
inspectors reviewed the licensee's corrective actions for this
violation.
b.
Observations and Findinas
The inspectors verified that the licensee's completed corrective actions
for this violation, as stated in their letter of response dated August
26, 1996, had been completed.
The corrective actions included revising
Procedure OP-402 to provide details for flushing after the addition of
i
The inspectors reviewed Revision 90 of Procedure OP-402 Makeup and
Purification System, which contained the necessary details for flushing
,
after the addition of boric acid.
This violation is closed.
1
c.
Conclusions
The inspectors corcluded that the licensee completed the corrective
actions for this violation and the corrective actions were adequate.
i
.
e--r--,
-
--e-,
m---
, .
-
.
19
The inspector assessed the licensee's performance, with respect to the
specific violation. in the five NRC continuing areas of concern:
Management Oversight
- Adequate
.
Engineering Effectiveness
- N/A
.
Knowledge of the Design Basis - N/A
Compliance with Regulations
- Adequate
.
Operator Performance
- N/A
.
E8.8 (Closed) IFI 50-302/96-201-11. Desian Basis for Decay Heat / Core
Flood / Reactor Coolant Pioina Temoerature
a.
Insoection Scoce (92903)
This item is the same as Inspector Follow-up Item IF-201-01 identified
by the Integrated Performance Assessment Process (IPAP) Team.
The IPAP
Team questioned the use of 300 F (280 F operating temperature) as the
design temperature for the piping upstream of the Core Flood check valve
CFV-3 since the valve is relatively close to the reactor vessel.
The
design temperature for the piping downstream of the valve to the reactor
vessel is 650 F (600 F operating temperature).
The inspectors
reviewed the licensee's actions relative to this IFI.
b.
Observations and Findinas
i
The inspectors verified licensee's corrective actions for this issue,
which included:
-
PR 96-0216 was issued to document and resolve this question.
-
Calculation M96-0044 was performed for the vertical riser
(approximately 20 feet) upstream of valve CFV-3 to demonstrate
1
that the entire riser meets design basis Code allowables if heated
to the 600 F operating temperature.
Based on review of the above documents and discussions with responsible
engineering personnel, the inspectors considered the above actions
j
appropriate for resolution of this issue.
c.
Conclusions
'
The inspectors concluded that the licensee's completed corrective
actions for this issue were good.
A detailed calysis of the piping in
question was performed to assure that the piping met Code requirements.
l
The inspector assessed the licensee's performance, with respect to
i
resolution of this issue in the five NRC continuing areas of concern:
Management Oversight
- Good
.
Engineering Effectiveness
- Good
.
Knowledge of the Design Basis - Good
-
Compliance with Regulations
- Good
.
Operator Performance
- N/A
.
[
.
4
.
20
E8.9
(Closed) URI 50-302/97-01-08. Adeauacy of Procedures to Take the Plant
from Hot Standby to Cold Shutdown from Outside the Control Room
a.
Insoection Scone (40500. 92903)
The inspector followed up on this URI which involved a concern
identified by the NRC where it was determined that the licensee did not
have procedures in effect which provided adequate instructions for
taking the plant from hot standby to cold shutdown from outside the main
control room.
b.
Qbservations and Findinas
The inspector reviewed this item for compliance with 10 CFR 50 Appendix
R. NRC SER requirements, the CR-3 operating license. FSAR and
operations procedures.
Crystal River's Operating License Condition
2.C.(9). Fire Protection and FSAR Section 9.8.8. Safe Shutdown, states
in part that the capability of the plant to achieve safe shutdown in the
event of a fire was analyzed in the licensee's Fire Hazards Analysis:
NRC SERs dated July 27. 1979. October 14. 1980. November 24, 1980.
January 22. 1981. January 6. 1983. July 18. 1985, and March 16. 1988:
and the licensee's 10 CFR 50 Appendix R Fire Study.
The inspector
reviewed the applicable SERs issued by the NRC which discussed the
licensee's Appendix R program.
The inspector reviewed FSAR Section
7.4.6. Auxiliary Control Stations (Remote Shutdown System) and FSAR
Section 9.8. Plant Fire Protection Program.
Section 7.4.6.5 of the
FSAR stated in part that the design basis for the remote shutdown system
was 10 CFR 50. Appendix R. Section L. and 10 CFR 50. Appendix A.
Criterion 19.
Section 7.4.6.5 of the FSAR further stated that the
design basis for remote shutdown assumed a loss of offsite power.
Section 9.8.6 of the FSAR stated that plant procedures developed in
accordance with 10 CFR 50. Appendix R. Sections III.G and III.L
establish means to bring the plant from operating to cold shutdown.
As discussed in URI 50-302/97-01-08. the inspector reviewed licensee
abnormal 3rocedures (AP) to determine if any of the procedures were
im) acted )y MAR 94-09-02-01.
MAR 94-09-02-01. DC Cooling Instrument
Enlancement, addressed the issue of non-safety related positioners cn
safety-related air-operated valves DCV-17, 18. 177. and 178.
One of the APs reviewed by the inspector was AP-990. Shutdown From
Outside Control Room. Revision 8
The inspector noted that this AP
provided procedural steps for taking the plant to hot standby and then
directed operations personnel to maintain the plant in hot standby until
a specific cooldown plan was formulated.
The AP did not contain steps
for taking the plant from hot standby to cold shutdown and the AP did
not provide a reference or transition to any other procedure that would
be used by the operators to take the plant from hot standby to cold
shutdown.
The inspector discussed this issue with licensee personnel
who indicated that operating procedure OP-209. Plant Cooldown.
Revision 87 provided guidance to the operators for taking the plant
from hot standby to cold shutdown.
The inspector reviewed OP-209 and
.
.
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_.
_
_
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. _
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21
.
'
noted that Enclosure 1 to the 3rocedure provided information concerning
cooldown following a fire in tie main control room or cable spreading
i
room. This enclosure 3rovided general guidance for certain fire
scenarios and stated tlat this information was intended to assist plant
-
personnel in designing a specific cooldown procedure following main
control room evacuation.
I
The inspector determined that the procedures (AP-990 and OP-209 being
i
used either separately or in conjunction with each other) did not
-
provide adequate instructions for taking the plant from. hot standby to
cold shutdown from outside the main control room. The inspector further
'
concluded that licensee Administrative Procedures AP-990 and OP-209 did
not meet the requirements of 10 CFR 50. A)pendix R.Section III.L.
The
1
guidance in Operating Procedure OP-209 w11ch directed o)erations
personnel to develop a specific cooldown 3rocedure to tace the plant to
cold shutdown based on an assessment of t1e fire scenario and equipment
i
availability, did not meet the criteria in Section III.L.
Section III.L
states that procedures shall be in effect to implement the capability of.
being able to take the plant to cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> following
'
main control room evacuation due to a fire.
The inspector noted that
CR-3 License Condition 2.C.(9) states in part that Florida Power
Corporation shall implement and maintain in effect all provisions of the
i
approved fire protection program as described in the FSAR for the
l
facility and as approved in the SERs.
i
,
The inspector informed the licensee that failure to have procedures in
4
effect to implement the capability of being able to take the plant to
cold shutdown following main control room evacuation due to a fire was a
.
violation of NRC requirements and will be identified as VIO 50-302/97-
a
02-03. Adequate Procedures Not in Effect to Take the Plant from Hot
$
i
Standby to Cold Shutdown froni Outside the Control Room.
Based on
identification of this VIO. URI 50-302/97-01-08 will be closed.
1
4
c.
Conclusions
-
The inspector concluded that adequate procedures were not in effect to
meet the requirements of 10 CFR 50. Appendix R.Section III.L. in that
.
i
licensee Procedures AP-990 and OP-209 used either separately or in
conjunction with each other, did not provide adequate instructions for
4
taking the plant from hot standby to cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
following main control room evacuation due to a fire.
This issue was
.
identified as a violation.
i
The inspector assessed the licensee's performance, with respect to this
issue, in the five areas of continuing NRC concern:
.
Management Oversight
- Adequate
.
Engineering Effectiveness
- N/A
1
.
Knowledge of the Design Basis - Good
.
Compliance with Regulations
- Inadequate
.
Operator Performance
- Adequate
.
l
.
,
.
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.
.
l
.l
E8.10 (Ocen) LER 50-302/95-025.' Personnel Errors by Architect Enaineer Result
in Ooeration Outside Desian Basis Due to Inadeauate Safety /Non-Safety
Circuit isolation
i
'
(Ocen) VIO 50-302/95-2:.-03. Failure to Isolate the Class IE from the
Non-Class IE Electrica' Circuitry for the RB Purae and Mini-Purae Valves
,
1
a.
Insoection Scooe (37550. 92903)
The inspector reviewed the subject LER. which involved improper
isolation of Class IE from Non Class IE electrical circuitry for the
i
reactor building purge valves.
The inspector followed up on the
{
licensee's corrective actions for this LER.
l
b.
Observations and Findinas
The inspector reviewed the corrective actions specified in the LER and
the licensee's response to the NRC Violation 50-302/95-21-03 that was
issued for this concern.
The corrective actions were reviewed for
compliance with the FSAR. TS. and applicable licensee procedures.
The
'
inspector noted that some of the corrective actions specified in the
.
responses had been completed. Other corrective actions involved
implementation of modifications to address the issue.
Some of the
modifications had been implemented.
During review of the corrective
actions, the inspector noted that the licensee's evaluation of
,
alternatives to the present non-isolated design of the control circuits
for reactor building purge Air Handling Valves AHV-1A and AHV-1D was not
com)leted by the scheduled date of December 20. 1996, as' specified in
.
bot 1 the LER and the NOV response.
The new date for completion of the
evaluation was changed to May 1998.
The ins)ector discussed this change
with licensee personnel who indicated that tie schedule change was due
to an increase of other higher priority issues such as EFIC/EFW and EDG
loading.
The inspector also questioned whether Supplement 02 to this
LER had been submitted by December 20. 1996, as indicated in supplement
01 to LER
50-302/95-025. dated December 22. 1995.
A copy of Supplement 02 to this
i
LER was not included with the documentation provided to the inspector.
Licensee personnel indicated that they were continuing to review their
records to determined if Supplement 02 to LER 50-302/95-025 had been
submitted to the NRC.
This item remains open.
]
c.
Conclusions
The inspector concluded that the licensee had completed some of the
specified corrective actions to address this issue.
However. due to
workload and higher priority issues related to the EFIC/EFW and EDG
loading. the scheduled completion date for other corrective actions was
not met and the completion date was extended.
Additionally, the
licensee was reviewing its records to determine if Supplement 02 to LER
50-302/95-025 had been issued.
- - . .- . - . - . - . - . . - _ - - - - - - - - - . - . . . . - - -
-. -
--
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.
23
!
The inspector assessed the licensee's performance, with respect to this
!
issue, in the five areas of continuing NRC concern:
'
,
Management Oversight
- Adequate
i
Engineering Effectiveness
- Adequate
Knowledge of the Design Basis - N/A
>
Compliance with Regulations
- Adequate
.
Operator Performance
- N/A
,
E8.11 L0cen) EA 95-16. Use of Nonconservative Trio Setooints for Safetv-
!
Related Eauloment
i
(Ocen) VIO 97-01-07. Instrument Setooint Calculation Assumotions Not
Translated into Procedures
a.
Insoection Scoce (92903. 37550)
!
As part of the conti tuing review of corrective actions for EA 95-16.
the insx ctors reviewed several new instrument loop uncertainty setpoint
calculatioas and the implementation of the corrective actions for VIO
50-302/97-(1-07. Instrument Setpoint Calculation Assumptions Not
!
Translated Into Procedures.
In IR 95-06 the inspectors found that some
safety-related trip setpoint calculations did not follow the methodology.
specified in Instrument Society of America (ISA) 67.04, part II as
referenced by instrumentation and controls Design Criteria Instrument
String Error /Setpoint Determination Methodology.
To assess the progress
,
the licensee had made in this area, the inspector reviewed a. sample of
the most recent instrument string error /setpoints.
The inspectors also
revie;ed the preliminary corrective actions for VIO 50-302/97-01-07 and
the 10 CFR 50.72(b)(2)(1) report made by the licensee to document the
degraded or unanalyzed condition associated with this violation.
b.
Observations and Findinas
,
1)
EA 95-16. Use of Nonconservative Trip Setpoints for Safety-Related
Equipment.
>
The inspector reviewed several recent instrument loop uncertainty
(instrument string error) setpoint calculations with the following
comments:
<
I-94-0011. RB Fan Service Water Flow Accuracy. Calculation.
i
Revision 0. dated 2/14/97.
The inspector had one minor
comment on Section V. Detailed Calculations subsection 1.
Process Errors. First Design Condition - Ecuation for
3
specific volume at 175 F used 0.I650 ft / lam for the
'
!
specific vplume at 170* F.
The value should have been
0.01650 ft /lbm.
Additionally. the service water flow transmitters were
.
located in the Auxiliary Building in E0 zone 11. which had
an assumed normal ambient temperature of 55* to 97
F.
!
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24
These ambient temperatures were not reflected in the service
water current flow transmitter calibration procedures, nor
had the calibration procedures been updated to reflect the
changes to the " graded approach" methodology. These will be
'
reviewed as part of the corrective action for VIO 50-302/97-
01-07.
Apart from these questions, the calculation was clear,
concise, with well-founded assumptions, and used standard
ISA methodology.
I-95-0015. Core Flood Tank Level & Pressure Loop Error
Calculation. Revision 0.
SP-169A. Surveillance Procedure,
Core Flood Tank Instrument Calibration.
j
l
I-95-0015 required that the M&TE in the reactor building be
maintained at various temperatures below the normal
,
operating temperatures specified in the Environmental and
'
Seismic Qualification Program Manual (ESOPM).
Contrary to
'
this for the core flood tank level transmitters and pressure
sensors. the licensee failed to include instructions for
accomplishing this task in the surveillance )rocedure which
i
was used for the instruments' calibration.
3 ruck 510 has an
i
upper operating temperature of 81* F.
In ambient
temperatures greater than 81* this required an ice bath.
l
refrigeration unit. cooling fan, or some other method for
cooling the instrument before using it in the calibration
process.
The methodology for cooling this instrument had
not been evaluated, had not been approved, and were not part
of the calibration procedure.
Not translating design
,
requirements I-95-0015 into procedures was an additional
'
example of VIO 50-302/97-01-07
Instrument Setpoint
l
Calculation Assumptions Not Translated Into Procedures.
i
The inspector noted one additional minor discrepancy in this
j
calculation.
On page 21 of 87 the 13.9 C value used for
j
<
the temperature delta for the M&TE error associated with the
'
Druck DPI 510 could not be reproduced.
The value should be
3
the maximum allowable calibration temperature minus the
lowest allowable temperature in the ESOPM zone.
This was
4
i
11* F or approximately 6.1* C.
The inspector calculated the
j
M&TE error associated with the Druck DPI 510 as 0.112 span.
J
.
The value-in the calculation was 20.123% span.
The effect
!
on the final loop uncertainty was minor and in the
j
conservative direction.
The inspector found no other
'
1
analytical discrepancies in this calculation.
!
2)
Corrective actions for VIO 50-302/97-01-07. Instrument Setpoint
Calculation Assumptions Not Translated Into Procedures:
,
i
The inspectors reviewed Florida Power Corporation Crystal River
Unit 3. Restart Action Plan / Issue Description. Issue Number: 0-26
,
4
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25
!'
l
Rcv. O. Action Plan / Issue Title: Calculation Temp Ranges Not
Consistent With Actual Ranges which was written to restore an
adequate design margin or ensure conformance with the design
.
'
basis.
The specific issue was that normal temperature ranges used
l
'
in existing Analysis / Calculation were not consistent with the
t
actual temperature ranges to which the equipment was subjected.
l
This was identified as a generic concern with recorded
temperatures .in the reactor building and the auxiliary recorded
temperature,
i
The licensee's program to resolve this issue included-
l
Identification of all instrument surveillance procedures
!
3erformed since last refueling outage.
The licensee
r
Selieved that this would define the safety related
instrument channels potentially involved.
l
Identification of the dates the affected surveillance
procedures were performed.
'
Identification of the average daily temperature data for
each of the dates for the identified surveillances.
This
.
'
was defined as the lowest hourly average of ten second
meteorological data.
The inspector was told that the
i
licensee intends to evaluate the meteorological data
available during the period of the last instrument
calibration
Evaluation of data obtained to identify those instrument
loops which could potentially be adversely impacted by
temperature variations larger than those addressed in the
-
calculations,
i
Evaluation of the impact of temperature variations
associated with identified instrument loops.
The inspector
was informed that due to present plant status, all
applicable instrumentation required for mode 5 operation
1
would be evaluated on a priority basis.
Identify and initiate required corrective actions and
j
determine impact to design basis.
On March 6. 1997. the licensee reported some of these conditions
i
under 10 CFR 50.72(b)(2)(i) to document a condition discovered
,
while shutdown, that, had it been discovered during reactor
operation would have resulted in the nuclear plant being seriously
i
degraded or in an unanalyzed condition that significantly
i
'
compromised plant safety.
In the report the licensee stated that
-
they consider all instrumentation located in the auxiliary
building and the reactor building to be in a degraded condition.
The licensee's actions taken to resolve these conditions will be
r
evaluated during the review of EA 96-16. Use of Nonconservative
,
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t
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,
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1
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26
)
Trip Setpoints for Safety-Related Equipment and during the review
'
of the 10 CFR 50.72 report review.
,
The calculations relating to instrument loop uncertainty that
remained to be reviewed included:
Calculations being revised -
I-86-0003
Off Site Dose and Maximum Allowable Filtration
I-87-0003
EFW. Flow Control and Interlock
I-88-0012
Gamma-Metrics Indicator. Loop Error
I-88-0021
Pressurizer Level Loop Accuracy
I-89-0013
Containment Air Temperature Loop Accuracy
I-90-0018
Decay Heat Closed Cooling. Water Surge Tank Level -
Loop Accuracy Calculation '
I-92-0011
Control Room Habitability Evaluation of Potential
Inleakage
I-95-0012
Core Flood Tank Level and Pressure Loop Error
Evaluation
Calculations being developed -
I-95-0010
Diesel Fuel Day Tank - DFT - 31/3B Analysis
Additionally, the calculations that were completed in late 1996
i
and early 1997 have not been implemented in the field.
Therefore.
1
the field im)lementation portion of these setpoints were not
reviewed.
T1ese included:
I-85-0004-
Rev 4. 11-19-96. EFW Tank Level Accuracy .
'
I-85-0005
Rev 3, 11-19-96. EFW Tank Level Settings
I-88-0019
Rev 3. 02-13-97. Incore Thermocouple Loop Accuracy
I-88-0022
Rev 4. 02-21-97. RC (Thot) Temperature Loop Accuracy,
,
RC-4A. 4B. TE1. 4
'
I 91-0012
Rev 3. 11-20-96. BWST Level Accuracy
I-91-0021
Rev 1.-02-27-97. RC Flow Loop (NNI) Accuracy
I-94-0011
Rev 0. 02-14-97. RB Fan Service Water Flow Loop
Accuracy
I-95-0015
Rev 0. 01-24-97. Core Flood Tank Level and Pressure
i
Loop Error Evaluation
i
c.
Conclusions
The inspectors concluded that the licensee continued to make progress in
resolving the Improved Technical Specifications (ITS) setpoint program
deficiencies.
In general, the calculations reviewed were well
documented, with well-founded assumptions, and followed the methodology
specified in ISA 67.04 part II. as referenced by instrumentation and
controls Design Criteria Instrument String Error /Setpoint Determination
Methodology.
These calculations continue to be a significant
improvement over calculations reviewed in IR 95-06.
l
.
27
The inspectors concluded that the Reactor Building. Intermediate
Building, and Auxiliary Building tem)erature ranges which the ESOPM
environmental assumptions used for t1e instrument loop uncertainty
setpoint calculations were not maintained. Also, the design assumptions
had not been appropriately translated into instrument calibration or
room monitoring procedures.
In addition, proceduralized controls were
lacking for use of M&TE in the reactor building.
These issues are
additional examples of VIO 97-01-07, Instrument Setpoint Calculation
Assumptions Not Translated into Procedures.
The inspectors assessed the licensee's performance relative to lack of
design control for assumptions in instrument setpoint calculations, in
the five areas of continuing NRC concern:
Management Oversight
- Inadequate
.
Engineering Effectiveness
- Inadequate
.
Knowledge of the Design Basis
- Inadequate
e
Compliance with Regulations
- Inadequate
e
Operator Performance
- N/A
.
,
E8.12 (Closed) URI 50-302/96-17-03. Failure to Conduct Reauired Technical
Soecifications Surveillance Testina on Safety Related Circuitry
(GL 96-01)
a.
Insoection Scoce (92903)
4
The ins)ectors reviewed the concerns listed in URI 50-302/96-17-03 and
the Tec1nical Specifications to determine the appropriate method for
closure,
1
b.
Observations and Findinos
On April 12, 1996, the licensee in response to GL 96-01. Testing of
Safety Related Logic Circuits. identified two circuits which were not
being appropriately tested in accordance with TS requirements.
These
circuits were the " auto reset of ES blocks 4 and 6 load sequencing
i
relays and the load shed circuit that trips EFP~ 1 when EGDG-1A is
-
supplying the ES Bus and a High Pressure Injection (HPI) signal is
received." On October 22. 1996, the licensee identified that two
contacts in each of the six pressure bistables in the ESAS (Engineered
Safeguards Actuation System) logic were not being tested in accordance
with TS requirements.
These bistable contacts were all part of the ESAS
Reactor Coolant System (RCS) Pressure - Low and: Low Low actuation
circuits.
TS Surveillance Requirement (SR) 3.3.5.2 requires that a channel
functional test of ESAS instrumentation be performed once every 31 days.
The failure to test ES blocks 4 and 6 did not comply with this TS
requirement.
_
TS SR 3.8.1.10 requires testing of load shedding from emergency buses
on loss of offsite power in conjunction with
. . an ES actuation
.
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28
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signal once every 24 months. The failure to test load shedding of EFP-1
,
did not comply with this TS requirement.
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'
TS SR 3.3.5.2 requires that a channel functional test of ESAS
instrumentation be 3erformed once every 31 days.
TS SR 3.3.5.3 requires
'
that a channel cali] ration be performed of ESAS instrumentation once
every 24 months. The failure to test the pressure bistable contacts did
not comply with these TS requirements.
i
c.
Conclusions
The inspectors concluded that the licensee did not comply with TS
recuirements for testing logic circuits.
URI 50-302/96-17-03 is closed
i
anc VIO 50-302/97-02-04 Failure to Conduct TS Logic Testing, is opened.
-
The inspector assessed the licensee's performance, with respect to the
licensee's prior noncompliance with TS requirements. in the five areas
i
of continuing NRC concern:
Management Oversight
- Inadequate
.
Engineering Effectiveness
- Inadequate
Knowledge of the Design Basis - Inadequate
4
~
Compliance with Regulations
- Inadequate
Operator Performance
- N/A
E8.13 (Ocen) NRC Generic Letter 96-01. Testina of Safety-Related Loaic
'
4
Ci rcuits
a.
Insoection Scoce (92903)
Generic Letter (GL) 96-01. issued January 10, 1996, requested the
following certain actions from all operating nuclear power reactors
<
relative to the problems with testing of safety-related logic circuits:
,
l
!
Compare electrical schematic drawings and logic diagrams for the
i
reactor protection system. EDG load shedding and sequencing, and
i
,
actuation logic for the engineered safety features systems against
.
j
plant surveillance test procedures to ensure that all portions of
the logic circuitry, including the parallel logic, interlocks.
bypasses, and inhibit circuits are adequately covered in the
'
'
surveillance procedures to fulfill the TS requirements.
This
review should also include relay contacts, control switches, and
other relevant electrical components within these systems utilized
in the logic circuits performing a safety function.
i.
i
Modify the surveillance procedures as necessary for complete
e
i
testing to comply with technical specifications.
During this inspection, the inspectors examined the licensee's actions
i
'
to date relative to the testing of TS safety-related logic circuits
4
described in GL 96-01.
.
.
i
,
29
b.
Observations and Findinas
The licensee responded in FPC Letter 3F0496-25. dated April 1996. that a
'
plan was being developed and that a firm schedule would be determined
following completion of a pilot program.
Florida Power Corporation
Letter 3F0796-09. dated July 1996. reaffirmed the FPC commitment to
complete the review requested by GL 96-01 ]rior to restart from the next
l
refueling outage in the Spring of 1998. T1e licensee had GL 96-01
review listed as their Restart Issue #R-1.
The inspectors reviewed the GL 96-01 program and schedule. The
licensee's GL 96-01 program was implemented by an engineering contractor
firm at the contractor firm's home office.
A licensee ]roject engineer
managed the program.
In addition, the contractor firm lad an on-site
engineer to review and validate the work performed at the home office.
The on-site engineer reviewed the documents sent from the home office
and compared them against the TS. drawings, and surveillance procedures.
Each logic circuit and component was red lined by the on-site engineer -
to ensure nothing was overlooked.
The inspectors verified that the
contractor completed five logic circuitry review packages for the
emergency diesel generators, the emergency feedwater systems, the main
steam isolation function. and the main feedwater isolation function.
The EDG packages (M218-96-02.013) were dated March 10. 1997. The
emergency feedwater, main steam isolation and main feedwater isolation
packages (M218-96-02.015) were dated March 13, 1997.
The inspector performed a preliminary review of the on-site engineer's
work packages and drawings to determine if the packages were validated
and if any additional discrepancies were being identified.
Several test
discrepancies were identified by the on-site engineer and documented in
PC 97-0054. PC 97-0057, and PC 95-1516.
PC 97-0054 listed test
deficiencies for the EDGs in procedures SP-907A and B.
PC 97-0057
listed test deficiencies for the emergency feedwater in procedures
SP-146A and B.
PC 97-1516 listed a potential procedure weakness for
testing the ESAS system.
The inspectors reviewed several logic circuits
in the emergency feedwater system to verify there were no additional
discrepancies and that the contractor and on-site engineer were
implementing a detailed review.
The licensee's GL 96-01 program was a
large complex program and was not completed at the time of this
inspection.
Completion was not expected until Summer of 1997.
Therefore, the inspectors only performed a partial inspection to
determine if the licensee was in the process of implementing an adequate
program.
c.
Conclusions
The inspectors concluded the licensee was in the process of implementing
-
a GL 96-01 program that met the intent of GL 96-01.
The contractor's
on-site engineer was thorough and had identified several additional
discrepancies during his validation review.
However, the GL 96-01
program still has a lot of work remaining before it will be completed.
_ _ .
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3
5,
30
4
The inspector assessed the licensee's performance, with respect to the
"
licensee's response to GL 96-01, in the five areas of continuing NRC
concern:
,
i
Management Oversight
- Adequate
Engineering Effectiveness
- Adequate
i
'
Knowledge of the Design Basis - Adequate
Compliance with Regulations
- Adequate
Operator Performance
- N/A
l
E8.14 Emeraency Diesel Generator Power Vorate
,
a.
Insoection Scooe (37551)
,
-
'
The inspectors reviewed the MAR for the emergency diesel generator
interim power uprate.
MAR 96-10-05-01 implementation, for EDG 1A. was
!
discussed in IR 97-01.
The MAR package and implementation for EDG 1B
were reviewed for technical accuracy and compliance with regulatory and
administrative requirements.
'
b.
Observations and Findinas
!
Phase 1 of the MAR replaced the nozzle rings in the turbochargers with
i
larger rings to increase the combustion air flow rate. made minor
adjustments to the fuel rack on the engine, and replaced the single pass
combustion air intercooler with a dual pass intercooler.
This
'
modification increased the efficiency of the diesel engine and was a
necessary modification to support Phase 2 of the modification which
increases the power rating for the emergency diesel generators.
This
modification depends on the review and approval by the NRC.
This
modification does not change the continuous and 30 minute ratings on the
EDG. The 200 hour0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> and 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> ratings will be changes from 3000 kW to
3250 kW for the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating and from 3250 kW for 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> to 3400
'
kW.
<
The ins)ectors noted the improvements on scheduling and implementation
of the EDG-1B modification.
The outage was completed within one day of
the schedule.
No post maintenance testing was omitted from the
schedule, and all work appeared to be accomplished in accordance with
the work instructions.
The inspectors reviewed the safety evaluation performed per the
requirements of 10 CFR 50.59.
The licensee identified certain
assumptions in the safety evaluation that were used as the basis for the
conclusion reached in the Phase 2 evaluation.
Plans were made to verify
these assumptions during the Phase 1 post modification testing.
Following the completion of Phase 1 of the modification, the licensee
performed the post modification testing procedure.
During this test,
data were gathered to prove operability of the EDG and to be used in
calculations to support Phase 2 of the modification.
.
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- - - .
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31
Precursor Card 97-996 was written to document a concern identified
l
during the review of the modification.
A discrepancy was identified
with diesel fuel oil volume requirements. TS 3.8.3.2 requires each EDG
day tank to have a minimum volume of 233 gallons.
TS 3.8.3.1 requires
each fuel oil storage tank to contain at least 18,589 gallons of fuel
i
with a combined fuel oil storage level of at least 37,177 gallons.
These numbers were derived assuming a maximum American Petroleum
i
Institute (API) specific gravity of 32.
The licensee reviewed sampling
'
data since 1986 and identified that they had been receiving fuel oil
with s)ecific gravities ranging from 28 to 38.
If the maximum number
that tie licensee had received was used in the supporting calculations.
,
l
the TS number would be non-conservative.
Using an API specific gravity
'
of 38. the licensee concluded that a minimum of 261 gallons per tank
were needed for the day tanks and 38.694 gallons needed to be maintained
in the storage tanks.
The licensee procedure SP-345A and 345B. Monthly
Functional Test of the Emergency Diesel Generator EGDG-1A and EGDG-18.
requires that a minimum volume of 345 gallons be maintained in each day
tank and that the fuel oil storage tank volumes be maintained above
20.300 gallons per tank.
These administrative limits are maintained
i
'
above the number calculated for the more conservative API specific
gravity values.
Precursor Card 97-999 was issued on March 3. 1997. which documented that
following the MAR functional testing on EDG 1A. data collected indicated
,
that the EDG engine room temperature could potentially exceed the design
maximum temperature of 120 F at maximum loading of the diesel generator.
This data was in conflict with data collected in 1992. used to verify
the impact of an earlier power uprate.
The licensee is continuing to
analyze this data and data collected following the EDG 1B MAR to analyze
I
final impact.
Precursor Card 97-1501 was issued on March 3, 1997. which indicates that
EDG exciter maximum field current capability could potentially exceed
the-design limitation of 54 amperes at maximum loading of the diesel
generator.
This PC was written for EDG-1A. but also applies to EDG-1B.
The licensee is continuing to assess the impact of the power uprate to
determine if the limiting current would be exceeded.
j
c.
Conclusions
Three issues are in process of being evaluated by the licensee to
,
determine final impact of identified discrepant conditions resulting
l
from the implementation of MAR 96-10-05-01.
These issues will be
i
tracked as an Inspector Follow-up Item. IFI. 50-302/97-02-05.
Outstanding Issues Associated with tbn Emergency Diesel Generator Power
Uprate Modification.
!
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32
E8.15 Toxic Gas Monitor Imorovements
a.
Insoection Scoce (37551)
The inspectors followed up on the toxic gas monitoring system
improvements as discussed in Inspection Report 97-01.
b.
Observations and Findinas
The licensee continueC in its efforts to identify needed improvements in
the toxic gas monitoring system.
Working with the vendor, the licensee
identified that besides a potential susceptibility to preconditioning
the detectors, the detectors are manufactured with a wide variance in
response times.
,
.
l
The licensee was in the process of revising the Surveillance Procedures
PT-366. Toxic Gas Detection System Calibration (Train A) and PT-367.
t
.
Toxic Gas Detection System Calibration (Train B). to require response
time testing prior to performing the saan test.
In addition. the
licensee has procured detectors with s1 ort response times.
Installing
these detectors and testing the res3onse time without any
~
preconditioning, the licensee was a31e to readily meet the acceptance
1
criteria for the calibration procedure. The toxic gas monitors were
j
declared operable and returned to service on March 18. 1997.
I
c.
Conclusions
1
i
The licensee is continuing to evaluate the reliability of the toxic gas
j
monitoring system and develop a permanent solution to the issue.
E8.16 Radiation Monitorina Confiauration Control (37551. 71750)
,
l
On March 22,1997. RM-L7. the secondary drain tank liquid effluent line-
!
radiation monitor, sustained damage and failed.
During the restoration
efforts, per WR NU 0341950. the licensee discovered that the detector
1
i
installed in the radiation monitor was not a high temperature rated
detector, as required to be installed under MAR 86-09-22-01.
Further
investigation by the licensee revealed that a high temperature detector
was installed in RM-L2, the primary side liquid waste effluent line
.
radiation monitor.
This monitor did not require a high temperature
detector.
,
)
The licensee determined that the manufacturer part numbers for the two
detectors were 943-36 for the low temperature application and 943-36H
for the high temperature application.
The part number that the licensee
assigned to these two detectors did not differentiate between the high
1
j
temperature and low temperature applications.
1
The licensee contacted the manufacturer to determine the im3act of
j-
switching the detectors in these two radiation monitors.
T1e
manufacturer informed the licensee that the high temperature detector
'
!
has thermal insulation around the crystal and photomultiplier tube.
The
i
e
1
'
'
33
effect of the thermal insulation was to attenuate the response to low
energy gamma (80 kev). According to the manufacturer, the effect was
small compared to the attenuation of the stainless steel case of the
detector and would not affect the use in a liquid monitor. The
manufacturer's representative stated that the attenuation from the
thermal insulation would only be a factor. in gas application for gamma
from Xe-133.
According to the manufacturer, the failure mode of the low temperature
detector due to heat would be indicated by increasing counts in response
to the check source.
The increase would be caused by the gain changing
in a conservative direction.
This would cause the detector to trip at a
lower. more conservative setpoint. than expected.
ThelicenseereplacedthedetectorinRM-L7biththehightemperature
detector from RM-L2.
A low temperature detector was then installed in
RM-L2.
The licensee is continuing to access the root cause and
consequences of this issue under PC 97-2222 and PC 97-2229.
IV. Plant Sucoort
P1
Conduct of Emergency Preparedness Activities
Pl.1 Emeroency Precaredness Drill Initiatives (71750. 92904)
The inspectors discussed some drill initiatives with licensee Emergency
Preparedness personnel.
The licensee has announced plans to perform an
unannounced staffing drill of the Technical Support Center (TSC) at some
off-hours time during a two month period.
The licensee will require
individuals to respond to the site to assess the time needed to activate
the TSC with an adecuate staff against regulatory requirements. The
inspectors concludec this was a valid test of the ability to respond to
,
an actual event and was a good initiative.
The licensee has also
revised their normal event drill schedule to increase the frequency of
drills to quarterly and include a full TSC activation which will include
use of the control room simulator.
The inspector concluded this was an
improvement over previous licensee practices.
The inspectors will
assess implementation of these initiatives when completed.
S1
Conduct of Security and Safeguards Activities
S1.1 Security Procram Peer Assessment
a.
Insoection Scooe (71750)
On March 10 through 14. 1997, an assessment of the licensee's security
program was conducted by a group of four other utility Security
Managers, a fifth support person, and a retired former NRC security
inspector.
The inspector reviewed the scope of the assessment and
attended the entrance and exit meetings.
.
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34
b.
Observations and Findinas
The licensee requested the assessment from outside personnel to assist
,
them in correcting previously documented security program problems.
A
conscious effort was made to select managers from good performing plants
that have had problems in the past and successfully rectified them.
A
manager from a plant in each of the four NRC regions was selected to
'
balance regulatory perspectives and get diverse input.
The team used
existing NRC inspection guidance to focus their reviews and provided the
licensee with numerous insights and comments for improvement.
Strengths
were identified by the team in training and use of a Central Alarm
.
,~
. Station simulator and performance of the guard force.
Deficiencies were
identified in the lack of issued procedures for recent upgrades and the
need for a Physical Security Plan (PSP) revi.sion, inconsistent vehicle
and personnel search processes, and the extent of required compensatory
,
measures.
One notable finding the team discovered when verifying how
.
the licensee fulfilled their PSP was that the licensee did not have a
-
!
commitment cross reference matrix that ensured all requirements and
commitments were addressed and delineated specifically how they were
i
met. The licensee commenced development of a matrix to address the
i
finding.
3
c.
Conclusions
l
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The inspector concluded the Security Program Peer Assessment was
balanced and beneficial for the licensee security staff in their efforts
to improve performance and regulatory compliance.
V. Manaaement Meetinas
,
!
X1
Exit Meeting Summary
The inspection scope and findings were summarized on March 21 and
-
March 31, 1997.
Proprietary information is not contained in this
report.
Dissenting comments were not received from the licensee.
X2
Pre Decisional Enforcement Conference Summary
X3
Management Meeting Summary
l
X3.1 A public meeting was held on site at Crystal River March 21. 1997.
The
purpose of the meeting was to discuss items related to restart. A
l
separate meeting summary was issued on March 31. 1997.
PARTIAL LIST OF PERSONS CONTACTED
Licensees
'
R. Anderson. Senior Vice President. Nuclear Operations
J. Baumstark. Director. Quality Programs
'
J. Campbell. Assistant Plant Director. Maintenance and Radiation Protection
J. Cowan. Vice President. Nuclear Production
1
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R. Davis. Assistant Plant Director. Operations and Chemistry
B. Gutherman, Manager. Nuclear Licensing-
G. Halnon. Assistant Plant Director. Nuclear Safety
8. Hickle. Director. Nuclear Plant Operations
J. Holden. Director. Nuclear Engineering and Projects
D. .Kunsemiller. Director. Nuclear Operations Site Support
t
[
E
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H. Christensen. Engineering Branch Chief. Region II (March 21, 1997)
.
B. Crowley. Reactor Inspector. Region II (March 3 through March 7, 1997.
4
March 17 through 21. 1997)
'
P. Fillion. Reactor Inspector Region II (March 17 through March 21. 1997)
-
.
F. Hebdon. Director. Dirrctorate II-3. NRR (March 21. 1997)
J. Jaudon. Director. Division of Reactor Safety. Region II (March 21. 1997)
K. Landis. Branch Chief. Region II (February 26 through 27. 1997. March 21.
j
1997)
^
B. Manili. Licensing Reviewer. NRR (March 17 through March 19. 1997)
L. Mellen. Project Engineer. Region II (March 3 through 7. March 17 through
21, 1997)
!
M. Miller. Reactor Inspector. Region II (March 17 through March 21. 1997)
L. Raghavan. Project Manager. NRR (March 5 through 6, 1997. March 20 through
21. 1997)
L.'Reyes, Regional Administrator. Region II (March 21. 1997)
.
j
R. Schin. Reactor Inspector. Region II (March 3 through March 7. March 19
through March 21, 1997)
L. Stratton. Physical Security Specialist. Region II (March 17 through
'
March 21. 1997)
M. Thomas. Reactor Inspector Region II (March 17 through March 21, 1997)
INSPECTION PROCEDURES USED
IP 37550:
Engineering
i
s
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IP 37551:
Onsite Engineering
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IP 40500:
Effectiveness of Licensee Controls in Identifying. Resolving and
Preventing Problems
<
i
IP.61726:
Surveillance Observations
i
IP 62703:
Maintenance Observations
IP 62707:
Conduct of Maintenance
- .
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Followup - Operations
i
IP 92903:
Followup - Engineering
>
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IP 92904:
Followup - Plant Support
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36
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
IY2g Item Number
Status
Descriotion and Reference
50-302/97-02-01
Open
Failure to Follow Equipment Status
Control Procedural Requirements.
(paragraph 01.2)
50-302/97-02-02
Open
Deletion of Water Quality
Requirements from the FSAR.
(paragraph E8.2)
50-302/97-02-03
Open
Adequate Procedures Not in Effect to
Take the Plant from Hot Standby to
Cold Shutdown from Outside the
Control Room.
(paragraph E8.9)
50-302/97-02-04
Open
Failure to Conduct TS Logic Testing.
(paragraph E8.12)
IFI
50-302/97-02-05
Open
Outstanding Issue- "ssociated with
the Emergency Diesel Generator Power
Uprate Modification. (paragraph
E8.14)
Closed
IY2g Item Number
Status
Descriotion and Reference
50-302/96-09-04
Closed
Failure to Update Operating Curves
to Reflect 1981 Power Uprate.
(paragraph E8.1)
50-302/96-09-03
Closed
Failure to Perform 10 CFR 50.59.
Safety Evaluation for Changes to
Procedures Described in the FSAR For
Controlling Dissolved Hydrogen
Concentration.
(paragraph E8.2)
50-302/96-06-07
Closed
Failure to Initiate a Problem Report
to Resolve CREVS Test Failure.
(paragraph E8.3)
.
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._
.
37
50-302/96-05-01
Closed
Failure to Follow Procedures to
Initiate Corrective Actions for Bent
Main Steam Line hangers.
(paragraph
E8.4)
50-302/96-06-02
Closed
Inadequate Procedure for Performing
a Demineralized Water Flush
Following a Boric Acid Addition.
(paragraph E8.7)
IFI
50-302/96-201-11 Closed
Design Basis for Decay Heat / Core
Flood / Reactor Coolant Piping
Temperature.
(paragraph E8.8)
50-302/97-01-08
Closed
Adequacy of Procedures to Take the
Plant from Hot Standby to Cold
Shutdown from Outside the Control
Room.
(paragraph E8.9)
50-302/96-17-03
Closed
Failure to Conduct Required
Technical Specifications
Surveillance Testing on Safety
Related Circuitry (GL 96-01).
(paragraph E8.12)
Discussed
lypjg Item Number
Status
Descriotion and Reference
50-302/96-15-02
Open
Failure of Reactor Coolant Pump Oil
Collection System to Retain Oil
Leaking From Reactor Coolant Pump
Motor. (paragraph E8.5)
50-302/96-11-04
Open
Failure to Construct the Reactor
Building Sump Screens and Components
in Accordance with the Approved
Drawing. (paragraph EB.6)
LER
50-302/95-025
Open
Personnel Errors by Architect
i
!
Engineer Result in Operation Outside
Design Basis Due to Inadequate
Safety /Non-Safety Circuit Isolation.
(paragraph E8.10)
50-302/95-21-03
Open
Failure to Isolate the Class IE from
the Non-Class IE Electrical
Circuitry for the RB Purge and Mini-
Purge Valves. (paragraph E8.10)
,
.
$
38
50-302/97-01-07
Open
Instrument Setpoint Calculation
Assumptions Not Translated into
Procedures. (paragraph E8.11)
95-16
Open
Use of Nonconservative Trip
Setpoints for Safety-Related
Equipment. (paragraph E8.11)
LIST OF ACRONYMS USED
AI
- Administrative Instruction
- Abnormal Procedure
- American Petroleum Institute
- Corrective Action Review Board
CFR
- Code of Federal Regulations
-
CREVS - Control Room Emergency Ventilation System
CR3
- Crystal River Unit 3
- Enforcement Action
- Emergency Core Cooling System
- Emergency Feedwater Initiation and Control
- Emergency Feedwater Pump
EFV
- Emergency Feedwater Valve
- Emergency Feedwater
- Engineered Safeguards
- Engineered Safeguards Actuation System
ESOPM - Environmental and Seismic Qualification Program Manual
- Fire Damper
FOGG
- Feed Only Good Generator
- Florida Power Corporation
- Final Safety Analysis Report
GL
- Generic Letter
- High Pressure Injection
IFI
- Inspection Followup Item
IPAP
- Integrated Performance Assessment Process
IR
- NRC Inspection Report
- Instrument Society of America
- Improved Technical Specifications
Kw
- Kilowatts
LER
- Licensee Event Report
- Modification Approval Record
MCAP
- Management Corrective Action Plan
MUV
- Make-up Valve
NEP
- Nuclear Engineering Procedure
i
NGRC
- Nuclear General Review Committee
l
NQA
- Nuclear Quality Assessments
NRC
- Nuclear Regulatory Commission
- Office of Nuclear Reactor Regulation
NSAT
- Nuclear Safety Assessment Team
01
- Operating Instruction
OP
Operating Procedure
l
T
.
4
39
PC
- Precursor Card
PEERE - Plant Equipment Equivalency Replacement Evaluation
PR
- Problem Report
- Plant Review Committee
- Physical Security Plan
- Reactor Building
- Reactor Coolant Pump
- Regulatory Guide
- Safety Evaluation Report
- Spent Fuel Pool
- Surveillance Procedure
,
SR
- Surveillance Requirement
SSOD
- Shift Supervisor on Duty
- Nuclear Services Closed Cycle Cooling
TS
- Technical Specification
- Unresolved Item
- Violation
- Work Request
I
e
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