ML20141E244
| ML20141E244 | |
| Person / Time | |
|---|---|
| Site: | Fort Calhoun  |
| Issue date: | 06/27/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20141E228 | List: |
| References | |
| 50-285-97-06, 50-285-97-6, NUDOCS 9707010011 | |
| Download: ML20141E244 (66) | |
See also: IR 05000285/1997006
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l ENCLOSURE 2 l
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Docket No.- 50-285
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License No.: DPR-40 l
Report No.- 50-285/97-06
Licensee: Omaha Pubiic Power District
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Facility: Fort Calhoun Station
Location: Fort Calhoun Station FC-2-4 Adm. i
P.O. Box 399, Hwy. 75 - North of Fort Calhoun ;
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Fort Calhoun, Nebraska
Dates: April 14-18 and April .28-May 2,1997
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Inspectors: T. Stetka, Team Leader, Engineering Pranch l
P. Qualls, Reactor inspector, Engineering Branch j
S. Burton, Resident in=pector, Projects Branch C l
R. Wharton, Project Manager, Office of Nuclear Reactor Regulation l
D. Prevatte, Consultant i
Approved By: Chris A. VanDenburgh, Chief, Engineering Branch
Division of Reactor Safety
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ATTACHMENT: Supplemental Information
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9707010011'970627
PDR ADOCK 05000285
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TABLE OF CONTENTS
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EXECUTIVE SUMMARY ... .... ........ ... . ..... ..... .... iv
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Report Details . . . ............. .. .... ........................ 1
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Engineering . . . . . .... ......................................... 1
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El Conduct of Engineering ................... ............. 1 )
E1.1 System Reviews .......................... ........ 1
E1.2 Permanent Plant Modification Review .... .............. 5
E1.3 Temporary Plant Modification Review .... ............... 6
E1.4 Condition Reports ............................. .... 6
E1.5 Engineering Actions and Engineering Action Requests ........ 9
E1.6 Engineering Change Notices . . . . . . . . . . . . . . . . ......... 10 ,
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E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 11 l
E2.1 Review of Facility and Equipment Conformance to the Updated
Safety Analysis Report Description . . .................. 11
E2.2 Validation and Control of Design Basis Documents . . . . . . . . . . 13
E2.3 Engineering Backlog . . . . . . . . . . . . . . ... ............. 14
E2.4 10 CFR 50.59 Implementation ............. .......... 15
E2.5 Technical Specification interpretations . . . . . . . . . . . . . . . . . . . 17 l
E2.6 System Walkdowns . . . . . . . . . . . . ................... 18
E2.7 Configuration Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . 20
E 3.1 10 CFR 50.54(f) Letter Response Review ................ 20
E4 Engineering Staff Knowledge and Performance . . . . . ... ........ 22
ES Engineering Staff Training and Qualification . . . . . . . . . . . . . . .. .. 24
E6 Engineering Organization and Administration ................... 25
E7 Quality Assurance in Engineering Activities ...... ............. 26
E7.1 Quality Assurance Surveillances and Audits . . . . . . . . . . . . . . . 26 i
E7.2 Self Assessments ................................. 26
E8 Miscellaneous Engineering Issues ............... ........... 27
E8.1 (Closed) Unresolved item 50-285/9618-02 . .. .......... 27
E8.2 (Closed) Unresolved item 50-285/9703-02 ............... 28
F1 Fire Protection Program ........... ...... .............. 29
F2 Status of Fire Protection Facilities and Equipment . . . . . . . . . . . . . . . 36
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l F3 Fire Protection Procedures and Documentation . . . . . . . . . . . . . . . . . 37
l F4 Fire Protection Staff Knawledge and Performance ............... 37
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l F5 Fire Protection Staff Training and Qualification . . . . .,........... 38
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F6 Fire Protection Organization and Administration . . . . . . . . . . . . . . . . . 40
F7 Quality Assurance in Fire Protection Activities . . . . . . . .......... 40
F8 Miscellaneous Fire Protection issues . . . . . . . . . . . . . . . . . . . . . . . . . 41
F8.1 (Closed) Unresolved item 50-285/9616-01 ............... 41
V. M a nag em e nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , 41
X1 Exit Meeting Summary . ..............................,,. 41
ATTACHMENT: Supplemental Information
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j EXECUTIVE SUMMARY
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Fort Calhoun Station '
l NRC Inspection Report 50-285/97-06
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This team inspection evaluated the current effectiveness of the licensee's plant and design j
engineering organizations to respond to routine and reactive site activities, which included i
the identification and resolution of technical issues and problems. This inspection assessed
engineering and technical support by focusing on the funct:'onal aspects of the aLxiliary
feedwater system and portions of the component cooling water and raw water systems.
l The inspection also reviewed 10 CFR 50.59 safety evaluations and screenings, engineering
evaluations for design modifications, and the fire protection program implementation. The
inspection covered a 4-week period with 2 of these weeks conducted on site.
Enaineerina
The conduct of engineering activities was considered to be generally good. Aspects i
of good engineering practices included strong system engineers, a reasonable I
engineering backlog, effective control of plant modifications, good interfaces i
between engineering and other plant disciplines, a good design basis information
process, and an effective independent safety engineering group. However,
inadequacies identified regarding the implementation of the fire protection program
detracted from this performance. There were instances where design requirements
were not properly incorporated into surveillance testing procedures and a technical
specification limiting condition for operation and where design calculations were in
error. in addition, there was an instance where an Updated Safety Analysis Report
update was inadequate. The implementation of the 10 CFR 50.59 program and the
technical specification interpretation program were effective.
- The licensee was effective in maintaining the design and operable status of the
reviewed systems, and engineers were knowledgeable of their assigned systems.
However, weaknesses were identified where surveillance test procedure acceptance
criteria for safety-related pumps were inadequate and where a design calculation
was in error. These findings were considered to be the first and second examples
of a violation of 10 CFR Part 50, Appendix B, Criterion ill (Section E1.1).
- Plant modifications were designed, installed, and tested in accordance with
approved procedures. Modification packages were properly evaluated for safety
impact and plant documentation affected by these modifications were properly
revised (Section E1.2).
- Temporary modifications were properly implemented and appropriate application of
10 CFR 50.59 screenings and evaluations were evident (Section E1.3).
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The majority of condition reports had resolutions with proper engineering
justification, adequate proposed corrective actions, and adequate operability
l evaluations. However, weak operability evaluations were identified in three
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condition reports (Section E1.4).
Engineering actions and engineering action requests were completed in accordance
with approved procedures and properly addressed problems that were related to
routine and safe plant operation (Section E1.5).
The substitute replacement item engineering change notice process was being
properly implemented. Self assessments were effective in identifying deficiencies
and providing corrective actions for the associated deficiencies (Section E1.6).
An incorrect technical specification limiting condition for operation involving the
minimum water level for the emergency feedwater storage tank was identified. This
was considered to be a third example of a violation of 10 CFR Part 50, Appendix B,
Criterion 111 (Section E2.1b.1).
- A discrepancy between the plant configuration and the Updated Safety Analysis
Report was identified involving the diesel-dnven auxiliary feedwater pump fuel oil
day tank level. This was considered to be a violation of 10 CFR Part 50.71e
(Section E2.1 b.2).
- The controls for design basis documents were effective in maintaining the
documents current and accurate. Self assessments of these documents were
critical and had good findings (Section E2.2).
- The engineering backlog was reasonable and had properly set priorities. Engineering
was offective in the management of the backlog and maintained an essentially
constant trend (Section E2.3).
- Except for one safety evaluation weakness, the procedural guidance, program
implernentation, and training guidelines for the 10 CFR 50.59 safety evaluation
process were very good (Section E2.4).
- The process for initiating, maintaining, and closing technical specification
interpretations was good. A recently developed technical specification
interpretation review panel initiated procedure revisions, a multi-disciplined technical
specification interpretation technical revi.:w and provided increased management
oversight of the technical specification interpretation process (Section E2.5).
- Plant walkdowns indicated that the material condition of the plant was good and
that housekeeping was acceptable. The recently implemented housekeeping
controls should improve these conditions (Section E2.6).
- Self assessments and reviews to determine root causes and identify improvements
with the configuration process were thorough and self critical (Sections E2.7, E8.1
and E8.2).
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The issues identified in the response to the NRC's 10 CFR 50.54(f) letter on design l
control were resolved or were in the process of being resolved. All issues reviewed !
l were found to be completed or properly scheduled for completion (Section E3). l
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Engineers were well-qualified, familiar with their assigned and supporting systems, l
cognizant of system conditions, and versed in engineering procedures. Engineering
expectations were effectively communicated and well understood by the ]
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engineering staff. Engineering management was effective in establishing a strong
engineering work ethic. Engineers interfaced effectively with other plant
organizations (Section E4).
Engineers were qualified both in assigned and interfacing systems. Training for l
engineers was effective and contained a strong operations interface (Section ES).
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The nuclear safety review group was aggressive in their approach to safe plant
operations. Recent self assessments and management changes resulted in
improved performance and credibility with plant organizations (Section E6).
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Quality assurance audits and surveillances reflected the proper level of detail and
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focused attention in areas of safety significance (Section E7.1). ;
Self assessments addressed areas of safety significance. The methodology for
development of self-assessment activities was sound, drew proper conclusions, and
developed effective recommendations and corrective actions (Section E7.2).
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The implementation of the fire protection program was poor, in that, the inspection
identified five examples of the failure to properly implement the fire protection
program. These included: (1) diesel generator control circuits that were not
protected from a fire, (2) an inadequate alternate shutdown procedure, (3) an
inadequate water curtain, (4) an inadequate reactor coolant pump motor lube oil
collection system, and (5) inadequate control of fire pump operations. These
examples were considered to be five apparent violations of the fire protection
program (Section F1).
! * The fire protection equipment required for program implementation was well
maintained and available for immediate use. The fire detection and alarm capability
were considered to be good (Section F2).
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- With the exception of the procedure inadequacies identified in Section F1 of this
report, the fire protection program procedures adequately implemented the approved
fire protection program (Section F3).
- The fire protection staff was qualified and had a very good working relationship
with other station organizations (Section F4).
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- The fire brigade training was considered to be adequate to meet NRC requirements. i
However, there was a weakness in fire brigade member knowledge concerning the
, use of water to suppress an electrical cable fire. In addition, one deficiency
! regarding the training program was identified and was considered to be a sixth '
l apparent violation of the fire protection program (Section F5).
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- The fire protection organization and administration was being implemented in '
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accordance with the fire protection program (Section F6). l
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- The fire protection program audits were found to comply with the minimum
requirements of the program (Section F7). l
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Report Details
l Enaineering
E1 Conduct of Engineering (37550)
E1.1 System Reviews
a. Inspection Scone
The team reviewed the auxiliary feedwater system and portions of the component
j cooling water and raw water systems to verify that these systems were maintained
l as designed and in an operable status. This review included 11 system drawings,
- 18 procedures,17 design calculations, 7 permanent modifications, 9 operability
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evaluations, and 7 vendor documents. In addition, the team interviewed the
cognizant system engineers to determine the engineers' knowledge of the systems.
l b. Observations and Findinas
The team determined that the engineers were very knowledgeabic of their systems
- and very capable of providing design information. This was evidenced by the
l engineers' ability to provide prompt responses and information for the team's
l questions. In addition, the team found that the licensee was properly maintaining
the design and operational status of the reviewed systems. However, during' review
of the design calculations, the team identified discrepancies that affected system
l design and procedures.
b.1 Auxiliary Feedwater Pumps FW-6 and FW-10
, Calculation FC05361 determined the performance requirements for the motor-driven
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auxiliary Feedwater Pump FW-6 and the turbine-driven auxiliary Feedwater
Pump FW-10. To calculate the required developed head for each pump,
Calculation FC05361 used the maximum steam generator accident pressure,
which is the pressure at which the first main steam safety valve lifts.
Calculation FC05361 used 1,015 psia as the maln steam safety valve's nominal
setpoint. This appeared to be a conservative value since the technical
specifications required a main steam safety valve setpoint of 1,000 psia. However,
upon further review of the calculations, the team determined that the calculation did
not consider the setpoint tolerance of the main steam safety valves. Since the
technical specifications allowed a setpoint tolerance of t 3 percent, the main steam
safety valve could be set as high as 1,030 psia.
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In addition, the team noted that the calculation did not account for safety valve
! pressure accumulation. This added an additional 3 percent, or 31 psia to the 4
l setpoint value. The net effect of these errors was an increase of 46 psia to a ,
l maximum steam generator pressure of 1,046 psia.
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The turbine-driven auxiliary feedwater pump's required performance was determined
for the turbine / pump combination. This required consideration of the differences
between the turbine inlet and exhaust conditions at various operating points and
comparing these to the vendor's performance data. In calculating the pump's l
required performance, the licensee used the vendor's pump performance curves, j
The vendor's data was based on a 5.0 psig turbine exhaust pressure. However, the !
inspection team noted that the licensee's calculation used 1.0 psig as the exhaust
pressure, which made the turbine's calculated performance appear to be better than
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actual performance. However, the inspection team determined that Pump FW-10
was not inoperable due to other conservatisms. These conservatisms included no
credit in the calculation for the remaining steam generator inventory (i.e., it
assumed an empty steam generator) and the assumption in the calculation that the
pump only delivered flow early in the accident, whereas, the pump would actually
provide flow for the entire accident scenario.
The licensee used the data from this calculation to determine the acceptance criteria l
for the pump's surveillance test procedure used for inservice testing. Although the j
inspection team did not identify any problems with the surveillance procedures for
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Pump FW-10, a problem was noted with the surveillance procedure for Pump FW-6. I
Procedure SE-ST-AFW-3005, " Auxiliary Feedwater Pump FW-6 and Check Valve I
Test," stated that the minimum allowable performance was 990 psid (developed
head) at 200 gpm. This value was determined in accordance with the ASME Code,
Section XI, which silowed a 10 percent degradation from the pump vendor's
reference value of 1100 psid during the inservice testing. However, the team also
noted that Calculation FC05361 required a minimum head of 1,032.7 psid at a
200 gpm flow, even before the errors due to steam generator safety valve setpoint
tolerance and pressure accumulation were incorporated. When the calculation was
modified to account for these errors, the team determined that the minimum
required head should have been 1,078.7 psid at 200 gpm. Therefore, the
acceptance criteria for Procedure SE-ST-AFW 3005 allowed this pump to be
considered operable even though it would not have met the accident analysis
minimum performance requirements.
The team noted that the latest completed data for Procedure SE-ST-AFW-3005
performed on February 27,1997, indicated that the pump's performance was
1,100 ps!d at a flow of 200 gpm. These data indicated that the pump's actual
performance was in excess of that required to mitigate the design accident
conditions. Therefore, the team considered the pump to be operable.
NRC guidance regarding inservice testing of pumps was established in
NUREG-1482, " Guidelines for Inservice Testing at Nuclear Power Plants." This
guidance indicated that it was the NRC staff's expectation that pump performance
acceptance criteria be established that does not conflict with operability criteria for
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flow rate and differential pressure in the safety analysis report. Furthermore, this
guidance indicated that the operability limits of pumps must always meet or be
consistent with licensing basis assumptions in a plant's safety analysis. The finding
identified by the team indicated that the licensee's acceptance criteria development I
was inconsistent with this guidance.
Subsequent to the team's discovery of these discrepancies, the licensee initiated a ;
review of all safety-related pumps in their inservice testing program. Eight l
additional pumps were reviewed, including the boric acid transfer, charging,
component cooling water, diesel generator fuel oil transfer, high pressure safety
injection, containment spray, low pressure safety injection, and raw water pumps.
Of these, the high pressure safety injection, containment spray, low pressure safety
- injection, and raw water pumps were determined to have surveillance procedure I
acceptance criteria lower than what was required by the accident analyses. ,
However, the team's review of the actual test data indicated that all these pumps '
had sufficient discharge head and flows for accident mitigation.
10 CFR Part 50, Appendix B, Criterion 111, requires that the design bases are
correctly translated into procedures. The failure of the licensee to implement design
basis requirements into surveillance test procedure acceptance criteria for auxiliary i
Feedwater Pump FW-6, the high pressure safety injection pumps, the containment I
spray pumps, the low pressure sa%ty injection pumps, and the raw water pumps l
was considered to be the first example of a violation of 10 CFR Part 50,
Appendix B, Criterion 111(50-285/9706-01),
b.2 Auxiliary Feedwater Pump FW-54
Calculation FC05336 determined the performance requirements for diesel-driven
auxiliary Feedwater Pump FW-54. This calculation contained the same error
discussed previously for Calculation FC05361 regarding the error in the maximum
steam generator pressure. As a result, the team determined that this pump must
also provide feedwater into a steam generator at a maximum pressure of
1,046 psia.
The data from this calculation were used to set the acceptance criteria for the
pump's preventive maintenance procedure. Procedure OP-PM-AFW-0004, " Third
Auxiliary Feedwater Pump Operability Verification," provided the performance
testing criteria for Pump FW-54. This procedure stated that the minimum
allowable performance was 915 psid at 299 gpm. However, the team noted that
Calculation FC05336 required a minimum head of 1,078.1 psid at 325 gpm, even
before the error in this calculation was corrected. When corrected, the minimum
required head should have been 1,124.1 psid at 325 gpm.
The team noted that the latest completed date for Procedure OP-PM-AFW-0004
performed on March 31,1997, indicated that the pump provided 1,223.7 psid at a
flow of 325 gpm. These data indicated that the pump's actual performance was in
excess of that required to provide feedwater to the steam generators.
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j The team noted that this pump was not safety related and, as a result, no credit ;
l was taken for this pump in any accident analysis. However, the errors noted in this ;
! calculation were considered to represent a weakness in the licensee's design
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b.3 Component Cooling Water Temperature Transient j
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j Calculation FC06378 determined the final nitrogen pressure in the component
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cooling water surge tank after a loss-of-coolant-accident temperature transient. !
This pressure was required to assure sufficient component cooling water pump net !
positive suction head for all accident scenarios.
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A loss-of-coolant accident would increase the bulk component cooling water system
temperature causing thermal expansion of the water in the system and a surge tank ,
level rise. This would compress the nitrogen blanket in the tank and cause the l
pressure control valve to open and release nitrogen. As the system cooled, the
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water volume would shrink and lower the tank level and pressure because some
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nitrogen was lost during the transient. The calculation indicated that the final tank I
pressure from this transient would be 13.2 psig.
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During the review of this calculation, the team noted that the calculation used a l
pressure control valve reset pressure of 29.8 psig. However, the calculation did not l
consider the single failure potential for this valve. If the valve failed, the tank's !
safety relief valve would have to open to protect the tank. The reset pressure for .
this valve was 26 psig. When the single failure was postulated, the tank pressure
reduction would begin at 26 psig instead of 29.8 psig resulting in a lower final l
pressure. This final pressure was 9.4 psig or 3.8 psig lower than that used in the
calculation, in addition, the team noted that, due to the effects of heatup, the initial l
system volumes for all components in the system needed to be considered in the I
calculation. However, the team noted that the total system volume did not include l
the volume of the containment coolers. When these volumes were included, the j
final system pressure was lowered by an additional 0.5 psig to 8.9 psig. l
The pump data indicated that the component cooling water pump net positive
suction head requirements would be met with a tank pressure as low as 5 psig.
Therefore, the team concluded that these calculation errors did not render the
component cooling pumps inoperable.
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10 CFR Part 50, Appendix B, Criterion Ill, requires that the design control rneasures l
be adequate to assure the adequacy of hydraulic analyses. The failure of the
licensee to verify the adequacy of the calculation for the hydraulic analysis of the
component cooling water surge tank temperature transient was considered to be the ,
second example of a violation of 10 CFR Part 50, Appendix B, Criterion 111 l
(50-285/9706-01). l
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c. Conclusions
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The licensee was effective in maintaining the design and operable status of the
reviewed systems. Engineers were determined to be very knowledgeable of their
assigned systems. However, weaknesses were identified, in that, the surveillance
j test acceptance criteria for safety related pumps were not conservative. In
addition, the team identified a design error in the hydraulic analysis of the
l component cooling water surge tank temperature transient. These findings were
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considered to be two examples of a violation of 10 CFR Part 50, Appendix B,
Criterion Ill.
E1.2 Permanent Plant Modification Review
a. insoection Scope
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The team reviewed 14 plant modifications to verify conformance with applicable
installation and testing requirements as prescribed by procedures. Specific ,
attributes reviewed and/or verified by the team included 10 CFR 50.59 safety )
evaluations, post-modification testing requirements, safety-related drawing updates,
conformance with the Updated Safety Analysis Report and design basis documents, j
training requirements, and field installations.
b. Observations and Findinas l
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The modification packages contained the required 10 CFR 50.59 screenings. The l
team verified that affected drawings, procedures, and references were updated
associated with two fire protection modification packages, an emergency diesel
generator air compressor modification package, and a spent fuel pool rerack
modification package. A check of the field changes added to the modification
packages indicated that they were implemented in accordance with procedures and
contained the proper safety reviews. The team verified by a walkdown of the
modifications that the installed changes were consistent with the package
descriptions.
c. Conclusions
The plant modifications reviewed were designed, installed, and tested in accordance
with approvcd procedures. Modification packages were properly evaluated for
safety impact utilizing 10 CFR 50.59 screenings and evaluations as required.
Design basis and plant documentation affected by the modifications were properly
revised.
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E1.3 Temporary Plant Modification Review
a. Insoection Scope
The team reviewed 13 temporary plant modifications to verify conformance with
applicable installation and testing requirements as prescribed by procedures.
Specific attributes reviewed by the team included 10 CFR 50.59 safety evaluations
and plant installations,
b. Observations and Findinas '
There were 13 open temporary plant modifications. Of these 13 temporary
modifications,12 were nonsafety related. Temporary Modification 96-042, "CCW
System Relief Valve Setpoint Change," was safety related and required a 10 CFR
50.59 safety evaluation. The modification increased the component cooling water
tank operating pressure and gagged several system relief valves. The modification
was developed in accordance with approved procedures, the appropriate safety
evaluation was completed, and any Updated Safety Analysis Report references were
identified. The team also reviewed the content and safety evaluation screenings on
the remaining 12 temporary modifications and noted no discrepancies,
c. Conclusions
Temporary modifications were implemented in accordance with approved
procedures. Effective control of the number of outstanding temporary modifications
and appropriate application of 10 CFR 50.59 screenings and evaluations were
evident.
E1.4 Condition Reports
a. Inspection Scoce
The licensee issued condition reports as a means to identify problems with
components and systems and to place these problems in their corrective action
system for resolution. The team reviewed 21 condition reports to determine the
adequacy of the resolution, whether the component / system operability was properly
determined, and that the proposed corrective actions were adequate to preclude
recurrence. In addition, the team interviewed the applicable licensee personnel to
discuss the resolution of the condition reports.
b. Observations and Findinas
The team noted that 18 of the 21 condition reports had resolutions with proper
engineering justification, adequate proposed corrective actions, and adequate
operability evaluations. However, the team identified three operability
determinations that were considered to be weak.
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b.1 Failure of Nonsafety-Related instrument Air Regulator
Condition Report 199600161 identified that nonsafety-related instrument air
regulators supplied 15 safety-related solenoid operated valves. The concern
identified in the condition report was that a regulator failure to the full open position
would subject the solenoid valves to differential pressures greater than their rated
maximum operating differential pressure. The operability evaluation for this
condition report, however, stated that the air regulators were not expected to fail
because they were high quality, tested by the vendor, and replaced on a 5-year
frequency.
The team considered this operability evaluation to be inadequate, in that,
inappropriate credit was being taken for nonsafety-related equipment. However,
further review by the team indicated that, as the result of this condition report, the
licensee replaced the solenoid valves with valves that would operate with full
instrument air system pressure applied.
Since these air regulators and solenoid valves provided the operating air supply to
safety-related, air-operated valves, the team questioned the licensee regarding the
operability of the air-operated valves, if at the time of a regulator failure, the
solenoid valve was open. Under these conditions, full instrument air system
pressure would be supplied to the air-operator. The licensee was unable to provide
information to the team regarding the effect of fullinstrument air system pressure
on the air operators. The licensee will review this finding to determine effect of full
instrument air system pressure on the valve air-operators. The NRC will review the
results of this evaluation. This is considered to be an inspection followup item
(50-285/9706-02).
b.2 Gate Valve Pressure Locking and Thermal Binding
Condition Report 19970067 documented that shutdown cooling isolation
Valves HCV-347 and HCV 348 could be susceptible to pressure locking and thermal
binding conditions. To address the valve's operability for the pressure locking
issue, the associated operability evaluation determined that these valves were not
susceptible to pressure locking due to existing valve seat and packing leakage. This
determination reasoned that this leakage prevented the valve bonnets from
becoming pressurized and causing pressure locking.
The team considered this determination to be inadequate because pressure locking
was a function of the valve design, whereas, the valve seat and packing leaks were
a function of the valve's current material condition. The team was concerned that if
these leakage conditions were corrected, the pressure locking phenomena could
occur. The team noted that while the licensee developed a modification to drill the
valve disks, such that bonnet pressure relief would be assured, the licensee had not
yet decided to perform this modification on these valves. However, the licensee
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informed the team that any maintenance on these valves was controlled by the
system engineer and that these valves were inaccessible during plant operations.
As a result, the licensee was confident that leak repairing maintenance on these
valves would not be performed without appropriate engineering controls.
To address operability for thermal binding, the associated operability evaluation
determined that the valves would be closed during startup, with a maximum
temperature of 400 F and a pressure of 250 psig in the reactor coolant system.
Furthermore, since'the valves would not be required to open for an accident until
the reactor cooling system temperature and pressure was less than 353 F and
140 psig, the evaluation determined that the valves would not be significantly
cooler when they were needed to be opened. Therefore, the evaluation concluded
that the valves were not susceptible to thermal binding.
The team noted, however, that since the reactor could be completely depressurized
when these valves were required to open, the valves could be significantly cooler
when required to open (212 F versus 400 F). Therefore, the team concluded that
the potential for thermal binding still existed.
The licensee stated that since these valves were in the alternate hot leg injection
flow path, for which they did not take accident mitigation credit, they had not
determinec if the functioning of these valves was a safety concern. The licensee
was still reviewing this issue and expected to resolve the issue before the
completion of the next refueling outage. Their decision to make the disk
modification would be based on resolution of this issue.
The NRC requested alllicensees to address the valve thermal binding and pressure
locking issue by responding to Generic Letter 95-07, " Pressure Locking and Thermal
Binding of Power Operated Gate Valves." In their response to this generic letter,
the licensee included these two valves as valves subject to this review. Since the
licensee commitments with respect to these valves are being reviewed by the Office
of Nuclear Reactor Regulation, further followup on this issue will be pursued by the
program office, in addition, these specific concerns have been discussed with the
appropriate program office reviewers.
'
b.3 Safety-Related, Air-Operated Equipment Not Protected with Local Filter
Condition Report 199700168 documented that the air operators and their
respective solenoid valves (HCV-3008-0 and HCV3009-0) for Valves HCV-3008
and HCV-3009 were not protected with local air filters even though Design Basis
Document SDBD-CA-105 stated that they were equipped with local air filters. The
function of Valves HCV-3008 and HCV-3009 was to actuate the fire suppression
deluge systems for the charcoal filters in the control room heating, ventilation, and
air conditioning units. The function of Solenoid Valves HCV-3008-0
and HCV3009-0 was to protect the charcoal filters from inadvertent actuation of
the fire water deluge systems. These valves were required to remain closed to
perform this safety function.
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The operability evaluation determined that local filters were rot required because:
(1) the air was filtered and dried by the plant instrument air system; therefore, the
l
chances were remote that a particle could plug the solenoid valve orifice; (2) the
deluge valves could be actuated manually; and (3) Valves HCV-3008-0 and i
HCV-3009-0 would f ail closed and would not inadvertently actuate the deluge i
valves.
1
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The team noted that the requirement for local filters was in addition to the filters
and dryers at the air source. In addition, the team noted that the concern was loose
particulates between the air source and the valve operators, and that the filters at
the air source could not provide such protection. Furthermore, the plugging of the
solenoid valves or air supplies was not a concern. The primary concern was that a
particle could prevent the valves from closing completely, thereby inadvertently
actuating the deluge valves.
The team concluded that the actual operability evaluation was that, since the valves
were normally closed and only opened to actuate the deluge, there was no credible
condition that would allow particulates to get into valves to prevent closure.
However, this reason was never identified in the operability evaluation, j
c. Conclusions
The majority of the condition reports had resolutions with proper engineering
justification, adequate proposed corrective actions, and adequate operability i
evaluations. However, three condition reports were identified in which the
operability evaluations were weak,
l
E1.5 Enaineerina Actions and Enaineerina Action Reauests l
a. Inspection Scope
The team reviewed one safety-related engineering action and four safety-related
engineering action requests. This review compared the engineering action and
action requests to associated procedures and determined if the assumptions were
technically reasonable and properly supported,
b. Observations and Findinas
The team found that the calculations, analysis, and methodology supported the
assumptions and criteria identified for completion of the analyses. The team noted
that information required by the engineering action requests properly identified the
safety impact and provided resolutien of the pertinent operational or maintenance
problems.
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c. Conclusion
Engineering actions and engineering action requests were completed in accordance
! with approved procedures and properly addressed problems that were related to
routine and safe plant operation.
l
E1.6 Enaineerina Chanae Notices
l 1
l a. Insoection Scoce
1
l The team reviewed 14 safety-related, substitute replacement item engineering
change notices to verify conformance with applicable procedures. This review
included a verification that the plant modification process was not circumvented by I
the use of this process. The team also reviewed a nuclear safety review group self
assessment of the substitute replacement item process.
b. Observations and Findinas
l
The substitute replacement item engineering change notice process was used to
- perform technical evaluations to determine suitability for an item that replaces an
'
original or installed component. It was used when the replacement component did
not have the same make, model, and/or part number as the original component,
i
The team found all substitute replacement item engineering change notices to be in
I
compliance with the applicable procedures. The team also found that the nuclear
safety review group sampled 50 substitute replacement item engineering change
notices during their self assessment. This self assessment identified two instances,
involving applications of the substitute replacement item process where the process
was not effective. One discrepancy involved the installation of a nonsafety-related
local steam generator direct-reading, blow-dr .vn temperature indicators with ,
thermocouples that had'a remote readout mounted locally on the wall. The other '
discrepancy involved a lack of detail in the engineering change notice. This
engineering change notice did not provide the information to explain the reason for
the expanded c.alibration ranges on the containment spray sodium injection tank
level switches. The actual switch calibration was not affected by this discrepancy
and the switches were properly calibrated. The team noted that these discrepancies
were entered into the condition reporting process and were being tracked for
resolution,
c. Conclusions
The substitute replacement item engineering change notice process was being
l implemented properly. Self assessments were effective in identifying deficiencies
- and providing corrective actions for the associated deficiencies.
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E2 Engineering Support of Facilities and Equipment (37550)
l
E2.1 Review of Facility and Eauioment Conforrnance to the Updated Safety Analysis
- Report Descriotion
a. Insoection Scope
l A recent discovery of a licensee operating its facility in a manner contrary to the
l Updated Safety Analysis Report description highlighted the need for a special
focused review that compares plant practices, procedures, and/or parameters to the l
l Updated Safety Analysis Report descriptions. As the result of this discovery, the l
l team reviewed selected sections of the Updated Safety Analysis Report. l
1
- b. Observations and Findinas
t. ,
Procedure PED-QP-2, " Configuration Control," defines configuration changes and
references the appropriate procedures for control of the same. The Updated Safety
- Analysis Report was maintained current using this procedure and the 10 CFR 50.59
( safety review process. The team's review of one permanent modification, four
temporary modifications, and two engineering change notices indicated that l
appropriate changes to the Updated Safety Analysis Report were completed. In l
l addition, the team reviewed five condition reports and four quality assurance i
'
! surveillances that identified discrepancies in the Updated Safety Analysis Report.
l The team noted that all of these licensee-identified deficiencies were administrative l
!
or typographical in nature and had no safety significance. l
The team also verified portions of the Updated Safety Analysis Report while l
conducting detailed reviews of the auxiliary feedwater, component cooling, and raw I
water systems. Reviews of these systems identified the following deficiencies
between the Updated Safety Analysis Report and the design specifications:
b.1 Emergency Feedwater Storage Tank
Updated Safety Analysis Report, Section 9.4.6, and the basis for Technical
Specification 2.5 specified that the amount of water in the emergency feedwater
storage tank was adequate to remove decay heat for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Calculation FC06148
determined the water volume needed to satisfy this statement. During a review of
this calculation, the team noted that Updated Safety Analysis Report,
Sections 14.10 and 14.12, specified that the initial core power for accidents
requiring auxiliary feedwater was 102 percent of rated thermal power (1,530 MWt);
however, the calculation used 100 percent (1,500 MWt) to determine the auxiliary
feedwater needs. Calculation FC06148 also did not account for the main steam
safety valve setpoint tolerance and accumulation in determining the maximum
steam generator pressure (as previously discussed in Section E1.1 of this inspection
report).
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l Calculation FC06148 indicated that the required storage was 52,654 gallons.
l However, due to the power level and steam generator pressure errors in this
calculation identified by the team, the required storage should have been 53,824
l gallons (1,170 gallons more). In addition, the team found that the technical
l specification limit of 55,000 gallons, when decreased to account for the expected
instrument error of 13.9 percent, was ontv 52,855 gallons (55,000 gallons minus
2145 gallons). Therefore, the technical specification limit, when decreased due to
! the instrument error, was 969 gallons (53,824 gallons minus 52,855 gallons) less
than the 53,824 gallons required to meet the 8-hour Updated Safety Analysis
Report requirement.
The team questioned the licensee regarding the levels being maintained in the tank.
The licensee responded that they maintained the tank at a level of between 90
(57,500 gallons) to 100 percent of indicated full level. Therefore, the licensee was
maintaining the tank at levels in excess of that determined by the corrected
calculation.
10 CFR Part 50, Appendix B, Criterion lil, requires that the design bases are
correctly translated into specifications, drawings, procedures and instructions. The
failure of the licensee to correctly translate the design basis requirement for the
emergency feedwater storage tank into the technical specification !imiting condition
for operation is considered to be the third example of a violation of 10 CFR Part 50,
Appendix B, Criterion 111(50-285/9706-01).
b.2 Diesel-Driven Auxiliary Feedwater Water Pump Fuel Oil Day Tank Capacity
i
Updated Safety Analysis Report, Section 9.4.6, stated that the fuel oil day tank for
the auxiliary feedwater pump (FW-54) provided fuel storage capacity for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of
continuous operation. The team requested documentation of this capacity from the ,
licensee. The licensee informed the team that no calculation or test results were l
available to demonstrate this capacity. However, dee to the team's question, the
licensee performed Calculation FC06638 to demonstrate the tank's capacity.
The team also reviewed Preventive Maintenance Procedure OP PM-AFW-0004,
" Third Auxiliary Feedwater Pump Operability Verification," which was used to test
the capability of Pump FW-54. This procedure required refilling the fuel oil day tank
if the tank was les.s than one-half of full after completion of the test. Using
information from Calculation FC06638, the team calculated that at one-half full, the
tank would contain sufficient fuel for only approximately 4.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of continuous
operation.
The licensee stated that it was not their intent in the Updated Safety Analysis
Report that the tank be kept at a level to assure 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of fuel. The licensee's
position was that the Updated Safety Analysis Report documented only that the
tank volume could provide 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of continuous operation (if full) and not that it be
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maintained full at all times. Howeve:r, the team noted that this position was
inconsistent with a statement in the pump installation modification package
(MR FC-88-17). This modification package stated that the fuel oil day tank would
supply sufficient fuel for a minimum of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of fullload operation.
10 CFR 50.71e requires that the Updated Safety Analysis Report be updated
periodically to assure that the information included in the Updated Safety Analysis
Report contains the latest material developed. The failure to provide an adequate
update to the Updated Safety Analysis Report to reflect the actual intent of the
Auxiliary Feedwater Pump FW-54 day tank capacity was considered contrary to the
requirements of 10 CFR 50.71e and is considered to be a violation
(50-285/9706-03),
c. Conclusion
With the exception of deficiencies associated with the emergency feedwater
storage tank and the diesel-driven, auxiliary feedwater pump fuel oil day tank level
requirements, no safety-significant discrepancies in the Updated Sefety Analysis
Report were noted. Additionally, the team concluded that the licensee was
identifying and correcting deficiencies between the plant configuration and the
Updated Safety Ana!ysis Report.
E2.2 Validation and Control of Desian Basis Documents
a. Inspection Scoce
The team reviewed two design basis documents for conformance with the
requirernents identified within the Updated Safety Analysis Report, in addition,
the team reviewed the licensee's procedures and controls to assess the ability
to retrieve design basis documents and supporting information. The team also
reviewed the licensees response to the request for information pursuant to
10 CFR 50.54(f). The results of this review are discussed in Section E3 of this
report.
b. Observations and Findinas
i
The team found that design basis documents 'nere controlled in accordance with
applicable procedures which required design documents be updated as relative
information changes.
The team also reviewed three self assessments of the design basis documents
against the Nuclear Energy Institute guidelines for maintaining design basis. These
self assessments were critical toward identifying deficiencies, in addition, self-
assessment findings were prc,perly entered into the corrective action program.
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c. Conclusions
The controls for design basis documents were effective in maintaining them current
and accurate. Self assessments of design basis documents were critical toward
identifying deficiencies. Deficiencies were appropriately entered into the corrective
action program.
E2.3 Enaineerina Back!oa
a. Insoection Scope
The team evaluated the extent of backlogged engineering work to determine the
size of the backlog and to determine whether the backlog was being managed
properly. The evaluation included a review of the backlog reports and interviews
with eight members of the engineering staff.
b. Observations and Findinas :
The team reviewed the licensee's method used to set priorities for backlogged
engineering tasks. The licensee groups priorities into categories called safety, plant
operability, regulatory significance, plar.t improvement, and corporate significance.
The safety category was the most significant and the corporate significance
category was the least significant. Each category had priority levels numbered one
through six with the first priority being the most significant and the sixth priority
level being the least significant.
The licensee assigned engineering change notices, engineering action requests and
modifications to each of these categories. EngineerMg actions were not included in
these categories because they were already associated with a task that was
assigned to a specific category and, therefore were completed when the associated
task was completed. The team reviewed seven backlogged items that involved
safety-related systems or items that were important to safety. The team found that
the priorities for the selected items were appropriate, that they did not involve
safety significant issues and that they were being properly addressed. l
The team reviewed backlog trends, backlog reports, and conducted interviews to
assess the management of the backlog. Interviews with engineering management
indicated that better management of the backlog was required. This better
management was needed to aid the engineers with their work-load management.
This included integrating tasks of the same priority, implementing new procedural .
requirements, and accommodating any staff reductions.
Design engineering had a methodology to capture all open engineering items on one I
computer data base to assist the engineer with managing the backlog. The team I
found that system engineering was adapting the design engineering process of
putting all of the backlog on one computer data base. Interviews also indicated that
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engineers manage their ast.gned backlog by due date, it was management's
expectation that engineers ae familiar with assigned tasks and integrate tasks with i
different due dates as aporopriate Conflicts with due dates and task priorities were l
resolved by the applicable engineering supervisor. Changes in the due dates were !
often referred back to a committee to set priorities and were also tracked by date l
change occurrences. 1
!
Interviews with four engineers indicated that there has been no appreciable impact j
on their assigned backlog due to staff reductions, new training requirements, or i
additional procedural requirements. I
l
A review of the backlog indicated that the amount of backlogged engineering work
items remained approximately constant over the last 2 years. The team found that
the engineering backlog consisted of 455 engineering change notices,240 i
engineering action requests, and 84 modification requests, for a total of 779 open I
items. The team found that the oldest modification request was dated 1991 and
that the oldest requests did not involve safety or plant significant issues. The team
noted a slight increase in the backlog. The licensee attributed this increase to the
large number of configuration control related items identified as a result of increased
awareness of these type issues,
c. Conclusions j
I
The engineering backlog was reasonable and had properly set priorities. Engineenng )
was effective in their management of the backlog and was maintaining an i
essentially constant trend. ,
l
E2.4 10 CFR 50.59 Imolementation (37001)
a. Insoection Scoge
!
'
The team reviewed the licensee's 10 CFR 50.59 program guidance, implementation,
and associated training. The team also reviewed 10 CFR 50.59 applicability
screenings and subsequent nuclear safety evaluations for temporary modifications,
permanent modifications, engineering change notices, engineering analyses, and
procedure changes,
b. Observations and Findinas
The licensee's 10 CFR 50.59 safety evaluation process was implemented by
Procedure NOD-QP-3, "10 CFR 50.59 Safety Evaluations." This procedure
delineated the policy, requirements, and responsibilities rerading the preparation
and associated review of nuclear safety evaluations. The policy established a low
threshold for screening applicability. Guidelines were provided for conducting the
initial screening and for determining if an unreviewed safety question was involved.
The procedure required a documented basis to support the screening conclusion or
j the safety significance determination. The team's review of previous
l
Procedure NOD-QP-3 revisions and a current in-process revision indicated that the
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process was constantly being reevaluated and enhanced. The team also noted that
the licensee developed a 10 CFR 50.59 improvement program and established a
10 CFR 50.59 oversight committee. The team found these initiatives to be
l effective in identifying, reviewing, and resolving programmatic issues regarding the
-
10 CFR 50.59 review process.
l
1
l In general, the team found the background documentation contained in the nuclear
l
safety evaluations to be well developed and complete. The safety evaluations j
l provided appropriately detailed bases for reaching conclusions regarding changes, '
l tests, and experiments. All conclusions appeared to be logically suoported and did
not represent any unreviewed safety questions. However, during a review of one of I
the engineering change notices, the team identified a minor weakness.
i
!
Engineering Change Notice 95-130, "CCW Relief Valve Setpoint Changes," changed
@e component cooling water system's surge tank pressure control valve setpoint l
from 45 to 34 psig and the setpoints of Relief Valves AC-341 and AC-364 from 50 l
l
to 36 psig. The purpose of this modification was to assure that thermal relief l
valves on system heat exchangers would not open due to the increase in system i
pressure as the result of a system post loss-of-coolant accident heatup and,
therefore, prevent a component cooling water system inventory loss.
As discussed in Section E1.1 of this report, the primary reason for maintaining
l nitrogen pressure on the component cooling water surge tank was to assure
l adequate component cooling water pump net positive suction head under all 1
l accident conditions. This modification effectively lowered the component cooling )
l water pump Snal accident suction pressure. Therefore, the potential existed that l
this modification could have unacceptably reduced the available net positive suction i
head.
, The team noted that the 10 CFR 50.59 safety evaluation written for this
I
modification only addressed the potentia' of relief valve lifting with the resultant
loss-of-inventory. This safety evaluation did not address the potential loss of the
i component cooling water pump net positive suction head. Therefore, the team
l concluded that this safety analysis was weak in that it did not address all the safety
parameters affected by this modification. In spite of this safety evaluation
I weakness, the team noted that the component cooling water pumps still had
adequate net positive suction head.
The team also interviewed training personnel and reviewed requirements, materials,
and records for initial and requalification 10 CFR 50.59 training. The instructor's
lesson plans were comprehensive and corr.plete. They reflected numerous revisions j
to incorporate instructional improvements. The lesson plans addressed historical
perspective, regulatory definition, enforcement issues, industry concerns, licensee
weaknesses, and recent process enhancements. The most noted enhancement was
j the ISYS word search computer program, which allowed 10 CFR 50.59 preparers
and reviewers to search the documented licensing and design basis for
commitments and related safety impact.
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l The team reviewed the various training feedback mechanisms, student feedback
j forms, in-class manager evaluations, training advisory committee input, and direct
,
requests for training. The team also reviewed the audit and interviewed the auditor
l
responsible for the 10 CFR 50.59 portion of the recent Safety Audit and Review
Committee Audit 62, " Performance Training and Qualification of Facility Staff."
This audit did not identify any problems with the 10 CFR 50.59 training process.
The team noted that the licensee had a very effective training program. The
i licensee recently conducted training for approximately 90 percent of the personnel
l required to prepare and perform 10 CFR 50.59 safety evaluations.
!
c. Conclusions
Except for one weak safety evaluation, the team concluded that the licensee's
procedural guidance, program implementation, and training guidelines for the
10 CFR 50.59 process were very good.
E2.5 Technical Specification Interpretations
a. Insoection Scope
The team conducted a review of the licensee's technical specification
interpretations and the process for requesting, maintaining, and dispositioning these
interpretations. This review was conducted due to increased NRC interest in
licensee implementation of technical specification interpretations and potential
inconsistencies between the technical specifications and licensee developed
interpretations. The team reviewed 19 of 29 current technical specification
interpretations to determine the adequacy of the program and ensure that there
were no conflicts with the technical specifications.
b. Observations and Findinas
The team found the technical specification interpretation program was controlled by
Procedure NOD-QP-32, " Technical Specification interpretations." This procedure
provided guidance for the intent of technical specification interpretations,
documented clarification for existing technical specifications, and established
interpretation consistency. The procedure stated that technical specification
interpretations would not be used as a revision of, or substitution for, the technical
specifications. It further stated that technical specification interprethtions would
not be considered part of technical specifications and would never cor tradict or
change wording, meaning, or intent of technical specification requirements. The
team noted that Procedure NOD-OP-32 was being re-evaluated and enhar:ced as
evidenced by the processing of a recent revision.
Based on a review of the 19 technical specification interpretations, the team
determined that none of these interpretations were in conflict with the technica!
specification requirements and that the program was technically adequate.
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l The. team also noted that the licensee convened a technical specification
interpretation technical review panel in response to a licensee-identified violation of
technical specifications (that was reported in Licensee Event Report 96-006) that
occurred due'to an inconsistent interpretation of technical specifications. The
technical specification interpretation panel reviewed all open technical specification
interpretations for technical adequacy and consistency with technical specifications.
The panel also provided programmatic recommendations and initiated process-
improvements. One major programmatic improvement was the use of technical
specification interpretations for only in-process technical specification changes.
Other improvements were that technical specification interpretations were assigned
a finite validation period of 2 years and that revised technical specification
interpretations would no longer be given a new number designation,
c. Conclusions
1
, The team concluded that the licensee's current process for initiating, maintaining i
j and closing technical specification interpretations was good. The licensee's I
l
recently convened technical specification interpretation review panel initiated
,
procedure revisions, provided a multi-disciplined technical specification
l interpretation technical review and increased management oversight of the technical J
specification interpretation process. '
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l- E2.6 System Walkdowns !
l I
a. Inspection Scope
At different times during the inspection, the team performed walkdowns of selected
- plant areas to determine the overall material condition of equipment and the
maintenance of housekeeping.
b. Observations and Findinas
A tour of the containment building revealed what appeared to be excessive
corrosion (rust) on the component cochng water system piping. This observation
was discussed with licensee personnul, at which time, the team was informed that
a program had already been developed to monitor this corrosion. In addition, the
licensee entered the corroded cond: tion into the their condition reporting process as
Condition Report 199700154 to assure tracking and closure. The team's review of
this program, which included a review of ultrasonic test results used to monitor pipe
wall thinning, indicated that the corrosion was not causing any pipe wall thinning ,
problems at this time. The team also noted that the licensee was developing a l
protective coating plan to cure the problem.
.
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The team also noted that while the housekeeping was acceptable, there were some
- instances where there was an accumulation of tools, cleaning supplies and carts in
the auxiliary building. These observations were discussed with licensee personnel.
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The team was informed that the licensee developed a program to control such
[
instances and that the program should be effective in reducing these accumulations.
j, None of the accumulations observed by the team were considered to be excessive
'
and the licensee's control of transient combustibles was considered to be effective.
l The team also identified several issues involving fire protection equipment and the
!' collection of reactor coolant pump motor lubrication oil. These observations are
! discussed in Section F1 of this inspection report.
l c. Conclusions
!
The team's walkdown of the plant indicated that the material condition of the plant
l was good and that housekeeping was acceptable. The licensee's recently
implemented housekeeping controls should improve these conditions.
E2.7 Confiauration Control
a. insoection Scope
The team reviewed the corrective actions associated with configuration control. As
a part of this review, the team evaluated the licensee's self assessment for
configuration control to determine if the associated conclusions, recommendations,
and corrective actions were adequate to address the issue. j
L b. Observations and Findinas
On November 22 through December 10,1996, the NRC conducted a special
inspection (NRC Inspection Report 50-285/96-17) on the post-accident sampling
system. As a response to the enforcement actions, which resulted from this
inspection, as well as, internal concerns associated with other configuration control
deficiencies, the licensee committed to perform a self assessment of their ;
configuration control practices. The licensee committed to complete this self
assessment by April 30,1997, and send the report to the NRC by May 30,1997.
The licensee completed their self assessment on April 11,1997, and provided the
results to the inspection team.
The report, " Configuration Control Self Assessment Final Report," dated April 11,
1997, assessed current procedures, condition reports, industry experience, and
included field observations. This self assessment encompassed the period of
September 1995 through March 1997, which was the period that the new condition
reporting program was implemented. The team noted that this period included
previous plant status reports (e.g., incident reports) because these historical reports
were captured by issuing new condition reports for the issues identified in these
reports. Included in this assessment was a review of approximately 2400 condition
reports, of which 222 were identified for further evaluation. Of the 222 condition
reports identified for further evaluation,197 were related to labeling issues and
l only 6 were classified as significant conditions. Other than a tornado venting issue,
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which had been identified prior to the self assessment as a significant condition,
l 19
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none of the new significant conditions had an impact on plant safety. In addition,
the heightened sensitivity to configuration control issues resulted in the licensee
identifying an increased number of configuration discrepancies, The team concurred
with the licensee's conclusion that the majority of events related to configuration
control were historical in nature.
The team reviewed the corrective actions and recommendations identified in the
configuration control self assessment. The report identified 7 recommendations,
which included standardized trending for configuration issues, reinforcement of
coaching and counseling for human performance issues, multiple procedural
enhancements, amplification of the use of the corrective action program to include
configuration issues, and revision of the corrective action program. Additionally,
the report drew several conclusions which identified areas for improvement. These
conclusions were dispositioned by recommendations to incorporate related items,
such as procedure changes, into appropriate programs and procedures.
The team sampled condition reports relating to configuration control that were not
identified within the self assessment. The team's review of these condition reports
indicated that the screening process used by the licensee was effective and
accurate. The team considered the corrective actions for the sampled condition
reports to be reasonable for the correction of the configuration control deficiencies.
The team also reviewed the licensee's response to the 10 CFR 50.54(f) letter on
design basis issues, dated October 9,1996. The team found the material contained
within this response to be consistent with the application of the configuration
control process,
c. Conclusions
Self assessments and reviews to determine root causes and identify improvements
with the configuration process were thorough and self critical. Configuration
control issues identified prior to the completion of the configuration control self
assessment resulted in two non-cited violations that are discussed in Sections E8.1
and E8.2 of this report.
E3 Engineering Procedures and Documentation (37550)
E3.1 10 CFR 50.54(f) Letter Resoonse Review
a. Inspection Scoce
The team reviewed specific attributes from the Fort Calhoun Station response to the
NRC's 10 CFR 50.54(f) letter regarding adequacy and availability of design basis
information. The team's review encompassed the following conditions that had, or
were in the process of, being accomplished:
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l. :
l * The status and resolution of the licensee's action plan and open
' discrepancies identified from their latest review of technical specification
surveillt.nce requirements;
- The remaining 200 open items in the licensee's design basis document open j
item program;
- The status of the licensee's plans and scope of commitment for ;
l implementation of the Nuclear Energy institute methodology for review of all j
j. safety systems; )
- The results of the findings from the licensee's Nuclear Energy Institute style
review of the chemical and volume control system, safety injection system, l
and auxiliary feedwater system; and,
- The status of configuration control a, sues. !
I
b. Observations and Findinas '
l
The team reviewed the latest technical specification surveillance and testing '
assessment performed by the licensee. The results of the review indicated that
discrepancies identified in the response were closed with the exception of four
technical specification related items that were submitted to the NRC for an
amendment to the technical specifications.
I
The team reviewed the status of the 200 open items identified during the licensee's I
review of design basis documents and entered into the design basis document open )
item prog.am. The team found that 194 items were closed. The remaining six l
items were reassigned to the corrective action process for resolution and tracking.
These items involved Design Basis Documents PLDBD-CS-52, " Heavy Loads," and
SDBD-CONT-5501, " Containment." The reassignment of these six items to the l
corrective action process closed all design basis document open items. The team j
concluded that the licensee was effective with the tracking and resolution of open j
items related to design basis documents.
The team reviewed the licensee's plan and scope of commitment associated with
the review of all safety systems in accordance with the Nuclear Energy Institute's
proces.s. The team noted that, while the formal plan was not yet established, a
! resource estimate to complete the plan was complete and plans for completion of
the design basis document review were under development. The licensee was on
schedule for completion of the design basis document review of all safety-related
and safety-significant systems. This plan was scheduled for completion by the
February 1999 commitment date that the licensee provided in their respot.se to the
10 CFR 50.54(f) letter.
<
l 21
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The team compared the review of the design basis documents to the Nuclear
Energy Institute process. The team reviewed self assessments of the licensing i
basis for the chemical and volume control system, safety injection system, and !
auxiliary feedwater system. The team noted that the reviews exceeded the l
requirements contained in the Nuclear Energy Institute recommended process.
]
l
The team also noted that the licensee reduced the scope on subsequent design )
basis documents based upon repetition of reviews conducted in other self
assessments or conducted during the review of prior design basis documents. j
Examples of overlapping reviews were the configuration control self assessment and j
the review of technical specification interpretations. The team did not identify any
safety impact associated with the elimination of repetitive or overlapping reviews
from the design basis document self assessment process.
A review of design basis document self assessments indicated that the hcensee was
identifying discrepancies and deficiencies associated with design documents and
that these discrepancies were properly dispositioned utilizing the licensees
corrective action program.
The team also reviewed the licensee's efforts to address configuration control
issues. Information on these efforts are discussed in Section E2.7 of this report.
c. Conclusions
The Scensee resolved or was resolving the issues identified in their response to the
NHC 10 CFR 50.54(f) letter. Allissues reviewed were found to be completed or
properly scheduled for completion. The team concluded that the licensee was
utilizing the Nuclear Energy Institute process and effectively dispositioning
deficiencies.
E4 Engineering Staff Knowledge and Performance (37550)
a. Insoection Scope
The team interviewed three engineering department managers, one engineering
supervisor, four system engineers, one fire protection engineer, six mechanical
engineering personnel, and four design engineers. Interview topics included
management expectations for staff engineers, training regarding systems
interrelations, calculational analysis, and interface with other plant organizations.
The team questioned staff engineers on knowledge of their assigned areas and
conducted system walkdowns with the system engineers. In addition, the team
conducted detailed walkdowns of the auxiliary feedwater system and fire protection
system.
l
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b. Observations and Findinas
.
l The team found an engineering staff with little change in personnel. Engineers were
! alllong-term employees with the most junior person possessing 11 years experience
! at the station with 5 of those years in engineering. .
Engineers were cognizant of management expectations which were clearly defined
and disseminated via supervision to the engineering staff. Expectations for system *
l engineers were issued as engineering Procedure PED-SEl-20, " Duties and
Responsibilities of System Engineers." Although Procedure PED-SEl-20 contained a
multitude of information, engineers were familiar with the contents and did not find
.the requirements excessive.
Management encouraged aggressive problem identification and resolution. The
team sensed a strong questioning attitude and a sense of ownership among system
engineers. System and design engineers were knowledgeable of their assigned
systems and duties. System engineers conducted periodic walkdowns of their
systems. Additionally, engineers were familiar with the associated engineering
backlog, deficiencies, operator workarounds, and emergent maintenar.ce items on
their assigned systerns.
The team found that engineers were aware of the risk significance of their assigned
and interfacing systems. Also, engineers indicated a willingness to consult risk
I
analysis engineering during the development of system outages and modifications.
Application of risk models to the day-to-day engineering process was evident.
The team noted that system engineers periodically developed system report cards
for their assigned systems. System report cards are managerial level documents
which assess the overall health of the system. Management and engineering
generally found this to be an effective overview of system condition. Additionally,
engineers and management stated that this tool was useful in forcing the
engineering staff to assess system operability and material condition in the
aggregate.
The team also assessed the familiarity of system engineers with related engineering
procedures. Engineers were familiar with the requirements and applications for
procedures associated with modifications, temporary modifications, engineering
changes, substitute replacement items, and configuration control.
The team interviewed and observed the performance of engineers with respect to
their interface with other departments. System and design engineers interfaced
- regularly and were in communication over many issues. During plant tours
engineers demonstrated familiarity with other organizations such as maintenance
- and operations. Interviews with other plant department personnel indicated a
'
willingness to contact the system engineer when questions arose. Additionally, the
team noted that personnel in the instrumentation and control, electrical, and
mechanical maintenance departments had a very good working relationship with
these engineers.
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The team noted that all of the engineers seemed motivated, capable, and well l
- qualified with a strong sense of ownership in the plant and in their individual
l responsibilities. During the team's review of materials and interviews, the
engineering staff appeared attentive to detail and demonstrated a comprehensive i
understanding of overall plant operations, engineering principles, and regulatory l
j requirements. l
c. Conclusions l
l
Engineers were motivated, well qualified, familiar with their assigned and supporting l
systems, cognizant of system conditions, and versed in engineering procedures. l
Engineering expectations were effectively communicated and well understood by I
the engineering staff. Engineering management was effective in establishing a
strong engineering work ethic. Engineers interfaced effectively with other plant
organizations. The team concluded that the use of system report cards was an
effective management tool, j
E5 Engineering Staff Training and Qualification (37550) l
l
a. Inspection Scoce
The team reviewed the licensee's training and certification program requirements for
the engineering staff. This review included a review of training records and ;
interviews with three engineering managers, three system engineers, and one i
design engineer. l
b. Observations and Findinas
The team reviewed the training and qualification records cf the engineering staff and
found all to be qualified both in their assigned and interfacing systems. The team
also noted that significant modifications had been made to the engineering training
program. Some training program changes included requalification on all systems
and enhanced training in procedures. System qualifications required the engineer to
review the system with a licensed operator. The engineers indicated that this
qualification requirement provided several benefits including better communications
with the operations staff, increased credibility with the operations staff, and an
operations perspective on system performance.
c. Conclusions
Engineers were qualified both in assigned and interfacing systems. Training for
engineers was effective and contained a strong operations interface. The benefit
obtained, through the training program interf ace with operations department, was a
strength in the engineering training program.
24
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! E6 Engineering Organization and Administration (37550)
a. Inspection Scope
l
The team evaluated the overall effectiveness of the nuclear safety review group by
- interviewing group personnel, reviewing selected reports, and determining if issues
i identified by the safety review group were properly dispositioned.
l
l b. Observations and Findinas
! The nuclear safety review group is the licensee's independent safety engineering
group, which consisted of five engineers and a manager who reported to the
Division Manager, Nuclear Assessments. The team interviewed the nuclear safety
review group manager and two nuclear safety review specialists. The interviews
with the manager and specialists indicated that current management expectations
included an aggressive approach to issues. Interviews with nuclear safety review
group specialists indicated that recent organizational changes and managerial
guidance resulted in an increased focus on safety.
The nuclear safety review group recently conducted a self assessment of their own
organization and, as a result, modified procedures to enhance the performance and
credibility of the organization. Recent nuclear safety review group efforts
associated with boric acid batching tank heaters and the reactor coolant pump
motor lube oil collection system indicated that the nuclear safety review group was
aggressive in their pursuit of safety-related issues. An example of the nuclear
safety review group's strong questioning attitude was the reopening and issuance
of additional condition reports associated with the boric acid batching tank heaters.
As the result of these interviews, the team independently reviewed and assessed
the nuclear safety review group actions for these two issues. The team found that
the issues identified by the NRC involving the reactor coolant purnp motor tube oil
collection system were similar to those identified by the nuclear safety review
group, in addition, as the result of the review of condition reports associated with
the boric acid tank heaters, the team found that the nuclear safety review group ,
identified that the heaters had insufficient capacity. Furthermore, the team noted l
that the nuclear safety review group persisted in their followup of this issue to l
assure that heater capacity was restored. The team noted that, with the exception l
of the completion of some minor documentation, all actions involving these heaters '
were completed.
c. Conclusions
The team concluded that the nuclear safety review group was aggressive in their
approach to safe plant operations. Recent self assessments and management
! changes resulted in improved performance and credibility with plant organizations.
!
25
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E7 Quality Arsurance in Engineering Activities (37550)
E7.1 Quality Assurance Surveillances and Audits
a. inspection Scope
The team reviewed 11 quality assurance surveillance reports and 1 quality .
assurance audit on plant engineering. These reports were reviewed to evaluate the
licensee's effectiveness to self identify and resolve plant problems,
b. Observations and Findinas
The team found that the licensee was self critical with the application of quality
assurance audits and surveillances. Quality assurance surveillances included a
sufficient sampling of items necessary to meet the scope of the surveillance.
Corrective actions and recommendations were appropriate for the deficiencies
identified during the surveillance process. e
l
The team noted that there were 25 surveillances and audits of engineering activities
during the last 2 years. The team found that the surveillances covered diverse ,
topical areas and reflected similar findings to those identified by the team. An i
example of the licensee's effectiveness with identifying quality related issues was !
demonstrated in Surveillance Report E-96 4. .in this report, the licensee identified
discrepancies associated with cable tray locations and entered these items into the
corrective action system for tracking and resolution. )
c. Conclusions
Quality assurance audits and surveillances reflected the proper level of detail and
focused attention in areas of safety significance.
E7.2 Self Assessments
a. Inspection Scope
The team reviewed various self assessments to assess the depth and critical nature
of internal assessments of engineering and related activities.
b. Observations and Findinas ,
in addition to those self assessments discussed in other sections in this report, the
team reviewed an additional nine self assessments.
l 26
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These nine self assessments were conducted by the nuclear safety review group.
- The process included interviews, document reviews, and observation of activities.
Nuclear safety review group recommendations were assigned and tracked within
their own tracking system. Issues warranting corrective action were entered into
the condition reporting system. The team found that nuclear safety review group
! findings were being properly resolved.
- c. Conclusion
,
l Self. assessments addressed areas of safety significance. The methodology for
l development of self-assessment activities was sound and drew proper conclusions )
l and effective corrective actions. l
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) Unresolved item 50-285/9618-02: Failure to follow configuration change
control Procedure PED-QP-2 for: (1) replacing springs and spiral pins on main steam
line radiation monitor isolation valves; (2) installing an actuator cylinder on a
component cooling water outlet valve; and (3) installing a gasket on the safety ,
ajection and refueling water tank vent. !
l
(Closed) Unresolved item 50-285/9703-01: Failure to follow a preventive
maintenance order to replace a needle spring on the turbine-driven auxiliary
feedwater pump control relay.
Backaround - These two items were identified as unresolved items because of the
continuing NRC concerns with the adequacy of the licensee's configuration control
program. In both cases, maintenance personnel failed to follow plant procedures
resulting in a loss of configuration control for applicable plant cumponents.
On November 22 through December 10,1996, the NRC conducted a special
inspection (NRC Inspection Report 50-285/96-17) on the post-accident sampling
system. As a response to the enforcement actions which resulted from this
inspection, the licensee committed to perform a self assessment of their
configuration control practices. The licensee committed to complete this self
assessment by April 30,1997, and send the report to the NRC by May 30,1997.
Insoection Followuo Both of these unresolved items were licensee identified and
involved the failure to follow plant procedures. As a result of this procedure
adherence problem, plant configuration control was lost. A review of the licensee's
self assessment of the configuration control process (discussed in Section E2.7 of
this inspection report) concluded that the licensee had aggressively pursued the
resolution of the configuration control issues. Specifically, with respect to these
procedure adherence issues, the licensee had planned coaching and counseling for
personnel and procedure enhancements to provide clarification.
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l The failure to follow procedures ana instructions was considered to be a violation of
10 CFR Part 50, Appendix B, Criterion V. However, the team noted that the
l licensee's corrective actions for an escalated enforcement action
(50-285/EA96-489) that could have prevented this occurrence were in progress and
were not yet completed when these items were identified. Therefore, these
violations could not reasonably be expected to have been prevented by the
licensee's corrective actions for a previous violation or a previous licensee finding.
In addition, the licensee had documented the correction of these violations in the
corrective action program. Based on these findings, these licensee-identified and
corrected violations are being treated as noncited violations, consistent with
l Section Vll.B.1 of the NRC Enforcement Policy (50-285/9706-04).
E8.2 (Closed) Unresolved item 50 285/9703-02: Failure to follow an engineering change
l notice and maintenance work document for the replacement of a mechanical seal on
'
a spent fuel pool cooling pump and a demineralized water transfer purnp.
Backaround - Although the two spent fuel cooling pumps and the two demineralized
water transfer pumps were identical, they had different shaft flinger ring
configurations. Maintenance personnel failed to follow the instructions of
engineering change notices and maintenance work documents during the
replacement of the pump seals. This item was identified as an unresolved item l
because of the continuing concerns by the NRC with the adequacy of the licensee's
! configuration control program.
l
Insoection Followuo - On November 22 through December 10,1996, the NRC
conducted a special inspection (NRC inspection Report 50-285/96-17) on the post-
accident sampling system. As a response to the enforcement actions which
resulted from this inspection as well as internal concerns associated with other
configuration control deficiencies, the licensee committed to perform a self
assessment of their configuration control practices. The licensee committed to
complete this self assessment by April 30,1997, and send the report to the NRC by
May 30,1997. ]
The spent fuel cooling pump discrepancy was identified by the NRC, while the
demineralized water transfer pump discrepancy was identifieo by the licensee. As a
result of this procedure adherence problem, plant configuration control was lost. A l
review of the licensee's self assessment of the configuration control process
(discussed in Section E2.7 of this inspection report) concluded that the licensee was
aggressive in their approach to the resolution of the configuration control issues.
Specifically, with respect to these procedure adherence issues, the licensee planned
coaching and counseling for human performance issues and procedure
enhancements to provide clarification.
The failure to follow procedures and instructions was considered to be a violation of
- 10 CFR Part 50, Appendix B, Criterion V. However, the team noted that the
licensee's corrective actions for an escalated enforcement action
l (50-285/EA96-489) that could have prevented this occurrence were in progress and
l
! were not yet completed when these items were identified.
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The team further noted that the configuration control concern was a flinger ring left
installed on one of the spent fuel cooling pumps and one of the demineralized water
l transfer pumps during replacement of the seals with a new type seal. Since the
new seal design did not require such a ring, the installed ring had no effect on the
operation of the pumps and, therefore, would not become a more significant safety
and regulatory concern. Therefore, the violation old not have any actual or potential
i impact on safety. In addition, while this violation did suggest a programmatic
problem with procedure adherence by maintenance personnel, this problem was
being corrected and there was minor safety or regulatory impact.
The team concluded that, while this was a violation of 10 CFR Part 50, Appendix B,
Criterion V, it constituted a violation of minor significance and is being treated as a
noncited violation, consistent with Section IV of the NRC Enforcement Policy
(50-285/9706-05).
F1 Fire Protection Program (64704)
a. inspection Scoce
The team inspected the licensee's fire protection program to verify that the licensee
had properly implemented and maintained the fire protection program required by
the operating license. The team reviewed fire protection procedures, administrative
controls, quality assurance findings, fire brigade qualifications, and fire brigade
staffing in accordance with the approved fire protection program. The team also
conducted extensive walkdowns of the facility to verify licensee implementation of
the approved fire protection program.
b. Observations and Findinns
During the inspection, the team noted that most administrative controls were
properly implemented and that most administrative control procedures were
adequate. In addition, the firewatch personnel were well qualified, plant
housekeeping was adequate for control of transient combustible materials, and the
station fire response equipment was well maintained. However, the team also
identified the following examples where the fire protection program was not
adequately implemented,
b.1 Alternate Safe Shutdown Procedure AOP-06
During the plant walkdowns, the team observed that the redundant electrical cables
fe ' plant safe shutdown equipment were in close proximity to each other in the
l cable spreading room. 10 CFR Part 50, Appendix R, Section lit.G.2, provides
separation criteria for redundant safe shutdown trains in the same fire area. The
licensee did not meet the Appendix R, Section Ill.G 2, cable separation in the cable
29
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spreading room, which was directly below the control room. 10 CFR Part 50,
Appendix R, Section Ill.G.3, requires that if Section Ill.G.2 criteria cannot be met
then alternative or dedicated shutdown capability be provided. For this reason, the ;
licensee's Fire Hazards Analysis took credit for alternative shutdown capability for a
fire in this area.
The team reviewed Procedure AOP-06, " Fire Emergency." .This procedure provided
!
the operators' direction on implementing the alternative shutdown method for a fire
in either the control room or cable spreading room. During this review, the team
noted that the procedure did not direct the operators to implement alternate
shutdown for a cable spreading room fire, in that, the procedure did not provide any
criteria for the operators to use to determine when a control room evacuation
should be made during a cable spreading room fire. Specifically, Procedure AOP-06,
Section 4.0, Step 7, directed that if a control room evacuation is required, the
operators should evacuate the control room by performing additional steps in the ,
procedure. These steps did not provide the guidance necessary to ensure a timely '
control room evacuation for a cable spreading room fire. This was inconsistent with
other steps of the procedure where the operators were provided guidance regarding
actions to be taken to mitigate other plant fires that did not involve control room
evacuation.
A subsequent interview with one shift supervisor indicated that the shift supervisor
would not evacuate the control room until the control room became uninhabitable.
The team considered that such an extended control room evacuation delay could
threaten the ability to achieve alternative shutdown. Additional interviews with j
operations management indicated that management expectations were that the
operators would judge fire severity in the cable spreading room before evacuating
the control room.
10 CFR Part 50, Section Ill.L.3, requires that procedures shall be in effect to
implement the alternative shutdown capability. The failure to have a procedure to
provide guidance regarding alternative shutdown implementation for a cable
spreading room fire is considered to be an apparent vioiation of 10 CFR Part 50,
Appendix R, Section Ill.L.3. This is considered to be the first apparent violation of
fire protection program requirements (50-285/9706-06).
On April 18,1997, the licensee issued a memorandum to operations department
personnel to inform the operating crews, as an interim action until the procedure
can be revised, about the necessity of implementing alternative shutdown for a
cable spreading room fire. At the conclusion of the inspection, the licensee's
engineering staff was evaluating the issue to determine the most effective method
of ensuring that alternate safe shutdown can be implemented and to prevent a
premature control room evacuation.
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b.2 Diesel Generator B Not Electrically Isolated for Control Room Fire
Subsequent to the onsite team inspection, while evaluating the needed guidance for
the operators to respond to a fire in the cable spreading room, the licensee identified
that the Diesel Generator 2 engine tachometer circuit was not protected from the
effects of a control room or cable spreading room fire. As a result, these potential
fires could damage the tachometer circuit and render the diesel speed sensing
circuit inoperable. If the speed sensing circuit was inoperable, the diesel would fail
to start and could not be started or operated locally.
The licensee issued Condition Report 199700523 to provide an operability
evaluation for this condition. In addition, the team discussed the condition and
corrective actions with licensee personnel. The licensee's report identified that the
output of speed sensing circuit, YE-6148-DG-2, was not isolated from the control
room. Therefore, a fire could cause 120 AC voltage or 125 DC voltage to be
induced on the tachometer circuit and render the diesel speed sensing circuitry
inoperable, in addition, since this diesel generator was protected for use as the AC
power supply in the event of a control room or cable spreading room fire, the diesel
generator was required to achieve safe shutdown conditions.
The speed sensing circuit's function was to disengage the air start motors, open the ,
diesel generator outside air dampers, flash the generator field, and to provide engine '
speed indication at the local panel and the control room. Failure of this circuit
would prevent the diesel from automatically starting and would prevent local control
due to lack of speed indication for the operator. in the event of a control room or
cable spreading room fire requiring alternative shutdown, the operators were
required to operate Diesel Generator 2 locally.
l
The team noted that this condition existed since the original design of the facility I
and was not found during the initial safe shutdown analysis to comply with the
10 CFR Part 50, Appendix R, requirements, which was conducted during the early
1980's.
10 CFR 50.48(b) requires that all nuclear power plants licensed to operate prior to
January 1,1979 satisfy the requirements of Sections Ill.G, Ill.J, and Ill.O of ;
Appendix R to 10 CFR Part 50. Fort Calhoun Station was licensed on August 9, l
1973. 10 CFR Part 50, Appendix R, Section Ill.G.1.a, requires that one train of l
systems necessary to achieve and maintain hot shutdown conditions from either the
control room or alternate shutdown be free of fire damage. This is considered to be )
a second apparent violation of fire protection program requirements
'
(50-285/9706-07). ,
l
b.3 Fire Barrier Separating Fire Areas 6 and 20 l
l
During a plant walkdown, the team noted that the stairwell opening between the
grade and basement levels was also between Fire Areas 6 and 20 in the auxiliary l
building. This stairwell cpening had a deluge system installed around the lower part
of the opening rather thcn a " water curtain" as approved in the licensee's fire
31
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,
protection program. The system consisted of six pendant heads evenly spaced with
two on each side, approximately 5 feet apart and one on each end of the opening in
the center. 'There was no draft curtain installed around the stairwell opening. There
also was no area sprinkler system installed on either level of the auxiliary building in
these fire areas. This deluge system would actuate when two smoke detectors,
located in the area of the opening on the ceiling of the basement level, detected
i
smoke. The lower portion of the opening would then be filled with a water spray.
The team also noted by reviewing the licensee's fire hazards analysis' that Fire
i- Area 6 contained cables for the low pressure safety injection pumps and high
I pressure safety injection pumps. In addition, Fire Area 20 contains charging pump
L cables and the charging pumps. Therefore, a single fire could damage both trains of
l reactor makeup water and prevent achieving and maintaining hot' shutdown ,
conditions. In addition, licensee personnel stated that most of the other equipment
and cables needed to achieve safe shutdown conditions were also in one of these
fire areas.
l
National Fire Protection Association, National Fire Code 13, Section 4-4.8.2.3,
requires that large unenclosed floor openings be protected by draft stops in
combination with closely spaced sprinklers. The code then describes the design
requirements for a " water curtain." These design requirements involve high density
water spraying against a draft stop to form a water curtain around the opening.
l The code provides a . exception for large openings where both floors are protected
by an automatic sprinkler system.
l. The team reviewed licensee submittals dated December 12,1979, January 18,-
'
]
1980, and May 20,1980; NRC Safety Evaluation Reports dated August 23,1978, '
and November 17,1980; National Fire Protection Association, National Fire
Code 13, " Standard for the installation of Sprinkler Systems," and licensee !
evaluations dated April 17 and May 1,1977, to determine if the installed I
configuration was previously approved by the NRC and if the installation was
adequate to protect redundant safe shutdown equipment from damage from a single
fire.
A review of these submittals and the NRC Safety Evaluation Reports indicate that a
" water curtain" was to be installed around this opening. No exception to National
Fire Protection Association, National Fire Codes was mentioned in any of the
referenced documents concerning the design of the water curtain. The licensee
informed the tearn that, since the system's installation in 1980, they considered this
configuration to be a " water curtain". In addition, the licensee considered this
configuration to be previously approved by the NRC.
Based on the team's questions, the licensee performed an additional analysis to
justify the acceptability of the installation. This analysis, dated May 1,1997,
concluded that the water curtain design was adequate. However, review of this
analysis by the team and the NRC program office, concluded that the license's
installation did not constitute a " water curtain" as described by the National Fire
Code.
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10 CFR Part 50, Appendix R, Section Ill.G.1 requires that Fire protection features ,
shall be provided for structures, systems, and components important to safe l
shutdown. In addition, it requires that these features shall limit fire damage so that i
one train of systems necessary to achieve and maintain hot shutdown conditions
from either the control room or alternate shutdown station was free of fire damage.
I
! The failure to install a " water curtain" as approved in the licensee's fire protection
program, resulted in a lack of protection against a single fire from damaging both
l trains of hot shutdown equipment required to achieve hot shutdown. This is
considered to be an apparent violation of 10 CFR Part 50, Appendix R,
Section Ill.G.1 and is a third apparent violation of the fire protection program
requirements (50-285/9706-08).
The licensee did not agree with this apparent violation. The licensee stated that fire
barriers, allowed by 10 CFR 50.48(a) and previously approved by the NRC, were
acceptable. However, alllicensing documentation presented to and reviewed by the
team indicated that a " water curtain" would be installed around this opening and
that this " water curtain" would be designed as described by National Fire Protection
Association, National Fire Code 13. None of the documentation provided a
description of the actual configuration of the installed " water curtain." Therefore,
the NRC did not have an opportunity to review and accept the installed j
configuration. The inspectors conciuded that the " water curtain" currently installed
at the station does not meet these fire protection requirements and, as such, is not
an adequate installation,
b.4 Reactor Coolant Pump Motor Lube Oil Collection System )
Reactor coolant pump motor lubo oil leakage from the Reactor Coolant Pump D l
motor was identified in 1995 by the licensee. During the 1996 outage, NRC )
inspectors noted that this leakage was continuing from the Reactor Coolant Pump D l
motor. As a result of this observation, a December 20,1996, conference call was i
held between the NRC and the licensee. This call raised NRC concerns regarding i
the adequacy of the pump motor lube oil collection system. I
1
The licensee responded to the NRC's concerns by letter dated February 7,1997. In :
that letter, the licensee stated that they believed that their lobe oil collection system
was already approved by the NRC and that they had an exemption from having a
collection system for the low pressur6 components. Furthermore, the letter ,
provided details of the licensee's compensatory measures for continued operation '
with uncollected leakage from the Reactor Coolant Pump D motor. The NRC staff
reviewed the licensee's response and did not agree that the NRC granted an
exemption for collection of low pressure component oil leakage and did not find the
licensee's compensatory ineasures to be adequate. The NRC staff also did not find
the licensee's corrective actions to be appropriate. These conclusions were
provided to the licensee in a telephone conference call prior to the inspection and
l the licensee implemented additional compensatory measures.
!
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! 33
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4
During this inspection, the team further reviewed the licensee's reactor coolant
pump motor lube oil collection system. This review included a review of the
licensee's compensatory measures for continued plant operation with lube oil
collection system deficiencies, in addition, because of a forced shutdown due to a
steam line rupture, the team had the opportunity to perform a visual inspection of
the reactor coolant pump motor lube oil collection system.
During a walkdown in the containment building on April 29,1997, the inspection
team observed that the upper reservoir level transmitter and three resistance
temperature detectors for the Reactor Coolant Pump A, C, and D motors did not
have any lube oil collection system. The team also noted that the three drain ports
for the shaft air seal and the lower reservoir resistance temperature detector and
levelinstrument for each pump also did not have a lube oil collection system.
Furthermore, the team noted that the high pressure collection system for these
pump motors was degraded such that all oilleakage would not be collected by the
existing oil collection system. The team noted that the Reactor Coolant Pump B
motor was of a different design than the other pump motors and, therefore, this
motor had different tube oil collection requirements. The team noted that this motor
also did not have a lube oil collection system for the lower bearing reservoir level
indication instrumentation, sight glass, and resistance temperature detector.
As a result of walkdowns in the lower level of the containment building, the team
observed tube oil on reactor coolant system insulation near the "B" reactor coolant
pump motor. The team noted that this finding was observed a week after the plant
had been shutdown and after the licensee's staff had conducted two inspections of
the area for evidence of lube oil.
As corrective action prior to restarting from the forced outage, the licensee installed
a lube oil collection system for the "A", "C", and "D" reactor coolant pump motor
upper drain ports and the "B" reactor coolant pump motor lower bearing
instrumentation. This installation provided adequate collection of the lobe oil that
was actually leaking from the "D" reactor coolant pump motor. In addition, the
licensee repaired the degraded seats on the high pressure lobe oil collection system.
l
On April 30,1997, the licensee proposed compensatory measures to the team to
l
allow operation with a deficient lube oil collection system. The compensatory i
measures allowed the licensee to safely operate the unit while evaluating additional l
corrective actions for the collection of leakage from low pressure components. The
!
inspection team,in consultation with the program office, concluded that these initial '
compensatory measures lacked specificity and were not acceptable. Therefore, the
licensee provided new compensatory measures on May 2,1997, which contained
the appropriate level of detail concerning how the operators would monitor the
condition of the tube oil collection system and the compensatory actions to be
taken. These compensatory measures included closely monitoring oillevels and
specifying actions for the operators to take if levels changed by Lpecified amounts.
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l 10 CFR Part 50, Appendix R, Section 111.0, requires reactor coolant pumps to be
equipped with a lube oil collection system capable of collecting lube oil from all
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pressurized and unpressurized leakage sites on the reactor coolant pump motors.
The failure to have an adequate lube oil collection system on the reactor coolant
pump motors is considered to be a fourth apparent violation of fire protection
program requirements (50-285/9706-09),
b.5 Fire Suppression Water System Flushing
in 1977, when proposing the technical specifications for the fire suppression water
system, the licensee included a statement that the system would be operab!e during
flushing operations. The NRC approved the proposed technical specifications in
June 1977, but did not agree (nor approve) that the system was operable during
flushing operations.
During flushing operations, the licensee placed both fire suppression water pumps in
the " pull-to-lock" position. This action disabled automatic starting of the pumps, as
described in the fire protection program. The fire suppression water system was
then connected to the potable water supply to flush the system of silt, which might
accumulate in the piping since the normal water supply to the suppression system
was from the Missouri River.
The potable water system was not designed to supply an adequate amount of water
to meet system requirements during a fire. In addition, the plant review committee,
when reviewing Technical Specification Interpretation 90-01, in 1990, noted that
the NRC's intent was that the system be considered inoperable when performing
flushing operations and that the appropriate technical specification limiting condition
for operation be entered.
In 1994, the licensee removed the fire protection requirements from the technical
specifications and placed them in the Updated Safety Analysis Report. On
August 8,1996, the licensee issued Standing Order SO-G-103, " Fire Protection
'
Operability Criteria and Surveillance Requirements," which allowed the operators to
place the pumps in the " pull-to-lock" position without declaring the system
inoperable. Declaring the pumps inoperable would require the stationing of
continuous firewatches during flushing operations.
While reviewing the licensee's control of the fire suppression water pumps, the
team noted that on November 10,1996, and on February 10,1997, the licensee
performed fire suppression water flushing operations. While these operations
rendered the fire suppression water system inoperable, the team noted that the
operators did not declare the fire suppression system inoperable or station firewatch
personnel to compensate for the inoperable sunnression systems.
License Condition 3.F of Facility Operating License DPR-40, for the Fort Calhoun
Station, requires implementation of the approved fire protection program, as
described in the Updated Safety Analysis Report for the facility. Table 11.2 of the
Updated Safety Analysis Report states that the fire suppression water system shall
35
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.
.
( be operable, except during system testing, jockey pump maintenance, or training.
Table 11.2 also requires that a continuous firewatch be established for the diesel. ;
generator rooms, the compressor room, and in the corridor between Fire Areas 6 ,
t and 20 when the suppression systems are inoperable. The failure to declare the fire
'
water suppression system inoperable and to establish firewatches is considered to
- be a fifth apparent violation of fire protection program requirements
! (50-285/9706 10).
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c. Conclusions '
The team considered the implementation of the fire protection program to be poor.
L The team identified five examples of apparent failures to properly implement the fire
protectiors program. These examples were considered to be apparent violations of
fire protection program requirements.
F2 Status of Fire Protection Facilities and Equipment (64704)
a. Inspection Scoce
{
The team performed a walkdown of all areas of the facility containing safe
shutdown equipment. These walkdowns encompassed the fire detector system in-
Fire Area 32 and the air compressor room, which contained both auxiliary feedwater
pumps. The team also visually inspected fire protection equipment located
throughout the facility and visually inspected fire brigade response equipment
located in the turbine building storage locker outside of the control room.
The team also randomly selected components required for post control room fire
safe shutdown by Procedure AOP-06, which could be required for safe shutdown
during a control room fire, to verify that they were accessible,'well labelled, and had
adequate emergency lighting to perform required tasks.
b. Observations and Findinas
The team observed that all fire response equipment was well maintained,
accessible, within calibration, and in good working order. All valves observed by
the team in the fire suppression system were in their proper position. Fire water l
pumps and equipment were operable and well maintained. !
!
The fire detectors in Fire Area 32 were installed in accordance with National Fire
Protection Association, National Fire Code 72E, " Automatic Fire Detectors." The
licensee tested the control room fire alarm for the team. The team considered that
the alarm Would alert the operators to a plant fire and would isolate the location of
the alarming detector for the operators. The licensee's plant computer kept a
record of all alarms and thus allowed event reconstruction. ,
!
The team noted that all fire brigade response equipment located in the turbine
building storage locker was well maintained and ready for immediate use. l
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w g. g y. meg,.. y-- aw----- y-7 w. - y e-- p , -J -
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<
The team also noted that randomly selected components which were required for
use in Procedure AOP-06 were welllabelled, accessible, and had adequate
emergency lighting available.
During the plant walkdown, in Fire Area 32, the team noted a sprinkler nozzle over
the steam-driven auxiliary feedwater pump which was partially blocked by a
security cage. The licen'see wrote Condition Report 199700410 to document and
to correct the deficiency. The !icensee's evaluation concluded that the sprinkler
.was degraded but not inope able. The team agreed with the licensee's evaluation.
c. Conclusions
Fire protection equipment required for program implementation was well maintained
and available for immediate use. The team considered the fire detection and alarm
capability to be good.
F3 Fire Protection Procedures and Documentation (64704) '
i a. Inspection Scope
l The team reviewed the licensee's approved program as defined in the Updated i
Safety Analysis Report for the facility. The team reviewed the procedures listed in
I the attachment to this report to verify that the procedures adequately implemented ,
l the licensee's approved program. l
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b. Observations and Findinas
The team found that, with the exceptions noted in Section F1 of this report, the
l procedures reviewed properly implemented the program as approved by the NRC.
c. Conclusions
With the exception of the procedure inadequacies identified in Section F1 of this )
report, the team determined that the fire protection program procedures adequately
implemented the approved fire protection program.
F4 Fire Protection Staff Knowledge and Performance (64704)
a. inspection Scope
The team reviewed the adequacy of the fire protection engineering staff by
interviewing engineers and conducting plant walkdowns with staff members,
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b. Observations and Findinas
l Discussions with the engineers indicated that they understood NRC requirements for
! the fire protection program and the National Fire Protection Association, National .j
Fire Code requirements. They also demonstrated a detailed understanding of fire '
hazards associated with the station and a detailed knowledge and understanding of
the systems, testing, and analysis associated with the fire protection program.
- During the walkthrough inspection, the team observed discussions, regarding the
j orogram, between the fire protection staff and various other site personnel. The i
team observed that the fire protection personnel had a very good working
relationship with other onsite organizations.
The team noted that the fire protection program discrepancies, identified during this
inspection, were the result of the 10 CFR Part 50, Appendix R, analysis performed
by the licensee during the early 1980's. The problems predate the current
engineers and were not considered to be problems which would be identified during
routine program duties,
c. Conclusions
The plant had a qualified fire protection staff which had a very good working i
relationship with other station organizations, i
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F5 Fire Protection Staff Training and Qualification (64704)
o. Inspection Scooe
The team reviewed the readiness of fire brigade personnel to fight fires. The review
included fire brigade composition, qualifications, and training. The team also
reviewed the fire brigade training records to determine if the fire brigade was being
trained in accordance with the fire protection plan,
b. Observations and Findinas
The fire brigade consisted of five individuals per shift. In addition, the fire brigade
leader was a licensed operator and had sufficient knowledge of safety-related
systems to understand the effects of fire and fire suppressants on plant safe
shutdown capability.
All personnel were trained in an initial training class and subsequent requalification
classes. Each member was required to participate in at least one drill annually. In
addition, the licensee performed quarterly fire drills. The team verified that the
required annual physical examinations were performed on all fire brigade members.
The team also verified that the licensee's program required that all classroom
j training be repeated over a 2-year period that was implemented to meet license
! condition 3.F.
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As a result of this review effort, the team identified that one of the required training
sessions, Lesson 1604-03, " Fire-Brigade Equipment," was not conducted since the
,
April through June training cycle in 1994 for qualified fire brigade members. The
! team determined that eight out of the nine randomly selected fire brigade members
had not received the required training. During the inspection, the licensee informed
the team that while they did not meet their fire protection program required
classroom training, they had conducted practical training under other programs such
as the health physics respiratory program. Therefore they considered their fire
brigade personnel qualified to perform their fire brigade duties. The team verified 1
selected portions of the other training requirements (e.g., fire extinguisher training)
was conducted. As the result of this independent verification, the team concurred
with the licensee's conclusion.
License Condition 3.F requires that all provisions of the approved fire protection l
program described in the August 23,1978, Safety Evaluation Report, be !
implemented. Section 3.5 of the August 23,1978, Safety Evaluation Report j
required that fire brigade classroom training be repeated every 2 years. This is
considered to be a sixth apparent violation of fire protection program requirements
(50-285/9706-11).
Fire brigade personnel were also interviewed by the team to determine if they were
knowledgeable of the fire brigade program requirements, specific locations of safety
equipment in the plant, and understood the effects of fire on the safe shutdown
capability of the plant. Each fire brigade member stated that they were not
assigned duties which would interfere with the ability to respond to a fire. The
team questioned three fire brigade members and one fire brigade leader concerning _
the use of water on an electrical cable fire. The team found that the fire brigade
members were deficient in their knowledge of such fires when they stated that
water would be used on cable fires only as a last resort. The fire brigade leader,
however, had a good understanding of the need to use water to extinguish electrical
cable fires. Subsequent to the interviews with the fire brigade members, the
licensee issued further training information to all fire brigade members which
provided emphasis concerning the use of water to extinguish electrical cable fires,
c. Conclusions
The team considered the fire brigade trair'ing tr> be adequate to meet NRC
requirements. However, the team identified a weakness in fire brigade
member knowledge concerning the use of water to suppress an electrical
cable fire. In addition, one deficiency regarding the training program was
identified and was considered to be a sixth apparent violation of fire
protection program requirements.
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F6 Fire Protection Organization and Administration (64704)
a. Inspection Scope
The team reviewed the fire protection organization designated to implement the fire
protection program.
b. Observations and Findinas
The fire protection organization was described in Standing Order, S0-G-102, " Fire
Protection Program Plan " This plan detailed staffing and responsibilities for the '
,
implementation of the program. The team noted that the program was implemented
according to the approved program.
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c. Conclusions i
The team found that the fire protection organization and administration was
implemented in accordance with the fire protection program.
F7 Quality Assurance in Fire Protection Activities (64704)
a. Insoection Scope
The team reviewed the 1994,1995, and 1997 quality assurance audits to verify
that the audits met the requirements of the approved fire protection program.
1
b. Observations and Findinas
Section 3.7 of the licensee's Fire Hazard's Analysis contained the fire protection
quality assurance requirements. Section 3.7.11 contained the audit requirements.
4
The team found that the program required annual audits which audited design and
procurement documents, procedures, surveillances, and test activities. The team
noted that the audits accomplished the minimum program requirements. The team
also noted that the audits did not identify the problems identified in this report
because the audits reviewed the implementation of program procedures but did not
review the early 10 CFR Part 50, Appendix R, compliance assumptions.
c. Conclusions
The team found the fire protection program audits to be in compliance with the
minimum requirements of the program.
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F8 Miscellaneous Fire Protection issues (92903)
F8.1 (Closed) Unresolved item 50-285/9616-O_1,: Observation of lube oil leakage from
Reactor Coolant Pump Motor RC-3B.
Backaround - During the 1996 outage, the NRC resident inspectors identified that oil
leakage from the Reactor Coolant Pump D motor had accumulated inside the
containment. As a result of this finding, a December 20,1996, conference call was
held between the NRC staff anc ihe licensee. This call resulted in NRC concerns
regarding the adequacy of the reactor coolant pump motor lube oil collection
system. This item was considered unresolved pending resolution of the NRC's
.
questions. The licensee responded to the NRC's concerns by letter dated
February 7,1997.
Insoection Followuo - The team reviewed the adequacy of the reactor coolant pump
motor lube oil collection system as documented in Section F1.b.4 of this report. For
the reasons discussed in that section, the failure to have an adequate reactor
coolant pump motor oil collection system was considered to be an apparent
violation of 10 CFR Part 50, Appendix R, Section 111.0.
V. Management Meetings
,
X1 Exit Meeting Summary
The team presented the inspection results to members of licensee management at
the conclusion of the inspection on May 2,1997. The licensee acknowledged the
findings presented. In addition, the licensee stated that they disagreed with the
NRC regarding the design adequacy of their water curtain discussed in
Section F.1.b.3 of ine inspection report. They considered their design to be
adequate and to be previously approved by the NRC.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No information supplied to the team
was considered to be proprietary.
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( ATTACHMENT
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SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
l Licensee
G. Cavanaugh, Licensing
J. Chase, Plant Manager
S. Chomos, Fire Protection System Engineer !
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R. Conner, Manager, Training
K. Erdman, Fire Protection Design Engineer
C. Fritts, Auxiliary Feedwater System Engineer i
S. Gambhir, Division Manager, Engineering and Operation Support i
J. Gasper, Manager, Nuclear Projects l
G. Gates, Vice President, Nuclear
R. Jaworski, Manager, Design Engineering ,
E. Jun, Mechanical Design Engineer l
J. MacKinnon, Chairman, Safety Audit and Review Committee l
R. Mueller, Supervisor, Instrumentation and Control l
R. Phelps, Manager, Station Engineering l
J. Rossler, Senior Nuclear Design Engineer
A. Richard, Supervisor Mechanical Systems (Design Engineering)
R. Ridenoure, Operations Supervisor
R. Short, Manager, Operations
J. Tills, Manager, Nuclear Licensing
D. Trausch, Manager Nuclear Safety Review
R. Wylie, Manager, Nuclear Construction Management
LIST OF INSPECTION PROCEDURES USED
IP 37001 10 CFR 50.59 Safety Evaluation Program
IP 37550 Engineering
IP 64704 Fire Protection Program
IP 92903 Followup - Engineering
LIST OF ITEMS OPENED AND CLOSED
Onened
50-285/9706-01 VIO Failure to translate design criteria into plant operations,
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procedures, and specifications.
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50-285/9706-02 IFl Review the licensee's determination of the effect of high l
pressure air on safety-related, air-operated valves. l
50-285/9706-03 VIO . Failure to update the Updated Safety Analysis Report to ' l
provide actual intent of diesel-driven auxiliary feedwater pump I
fuel oil day tank capr 'ty.
50 285/9706-04 NCV Failure to follow configuration control procedures.
50-285/9706-05 NCV Failure to maintain configuration control or, plant equipment.
50-285/9706-06 APV Failure to have an adequate alternative shutdown procedure.
l 50-285/9706-07 APV Failure to have a protected train for alternate shutdown that ,
was free from fire damage. l
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50-285/9706-08 APV Failure to have an adequate water curtain fire barrier.
50-285/9706-09 APV Failure to have an adequate reactor coolant pump motor lube
_
oil collection system. l
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50-285/9706-10 APV Failure to declare the fire water suppression system inoperable
and to establish firewatches during flushing operations.
50-285/9706 11 APV Failure to conduct all fire brigade classroom training every two
years.
Closed
50-285/9616-01 URI Review adequacy of the licensee's reactor coolant pump motor
lube oil collection system.
50-285/9618-02 URI Failure to fellow configuration change control procedure.
50-285/9703-01 URI Wesk configv.ation control during maintenance on auxiliary
feedwater control relay.
50-285/9703-02 URI Spent fuel pool pump and demineralized water transfer pump
configuration differences.
50-205/9706-04 NCV Failure to follow configuration control procedures.
50-285/9706-05 NCV Failure to' maintain configuration control on plant equipment.
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LIST OF DOCUMENTS REVIEWED
Plant Procedures
Procedure Revision Title
AOP-06 4.2 Fire Emergency l
OI-FP-1 25 Fire Protection System Water System
OI-RC-9 31 Reactor Coolant Pump Operation )
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OP-PM-FP-1000 2 Quarterly Fire Protection Drain Valve Flush and Alarm i
Test
PEC-gel-3 18 Preparation of Design Change Packages
PED-gel 29 4 Facility Change Evaluation
PED-gel-35 1 Preparation of Engineering Assistance Requests for
Minor Configuration Changes /Replaccment I
PED-gel-52 O Preparation of Field Design Change Requests l
PED-gel-60 6 Substitute Replacement Item Evaluations I
PED-SEl-20 0 Duties and Responsibilities of System Engineers
PED-eel-1 4 Human Factors Engineering Instruction
PED-QP-1 8 Engineering Assistance Requests
PED-QP-24 24 Configuration Change Control
PED-OP-13 3 Design Basis Document Control
NSRG-1 8 Nuclear Safety Review Group Charter
MD-AD-0007 0 Bolting
SS ST-MS-3003 18 Main Steam Isolation Check Valve Inspection
SE-ST AFW-3006 14 Auxiliary Feedwater Pump FW-10, Steam Isolation
Valve and Check Valve Tests
OP-ST-AFW-0004 12 Auxiliary Feedwater Pump Operability Test
SE-ST-AFW-3005 10 Auxiliary Feedwater Pump FW-6 and Check Valve
Test
IC-CP-01-1183 13 Calibration of Emergency Feedwater Storage
Tank FW-19, Loop L-1183
IC-CP-01-1188 11 Calibration of Emergency Feedwater Storage
Tank FW-19, Loop L-1188
OP-PM-AFW-0004 9 Third Auxiliary Feedwater Pump Operability
Verification
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ARP CB10,11/A9 11 Annunciator Response Procedure A9 Control Room
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Annunciator A9
I ARP-Al-66A/A66A 5 Annunciator Response Procedure A66A Control Room
Annunciator A66A, AFWAS/ DSS
ARP-Al-66B/A66B 6 Annunciator Response Procedure A66B Contrcl Room
Annunciator A66-B, AFWAS/ DSS
ARP-Al-30A/A33-1 8 Annunciator Response Procedure A33-1 Control
Room Annunciator A33-1 Engineered Safeguards
OP-ST-AFW-0004 12 Auxiliary Feedwater Pump Operability Test
OI-DW-3 26 Condensate Storage Tank Operations
OI- AFW-4 24 FO-37 Fuel Oil Transfer Pump Operation
IC-ST-AFW-3002 1 Instrument Air Accumulator / Check Valve Operability
Test
IC-ST-AFW-3001 2 Accumulator Check Valve Test for Auxiliary
Feedwater Pump Minimum Flow Recirculation Valves
SS-ST-SI-3018 3 Inspection of Check Valves SI-139 and SI-140
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NOD-QP-3 16 10 CFR 50.59 Evaluations l
NOD-QP-31 11 Operability and Reportability Determinations
NO D-QP-22 11 Preparation and Approval of a Safety Analysis for
Operability
NOD-QP-32 4 Technical Specification Interpretations
NOD-QP-7 17 Facility License Changes
NOD-QP-10 10 NRC Exercise of Enforcement Discretion :
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PED-OP-5 9 Engineering Analysis Preparation, Review and j
Approval
PED-QP-2 24 Configuration Change Control
Standing Orders
O
S_O Revision Title
SO-R-02 3 Condition Reporf.!ng and Corrective Action
SO-G-21 62 Modification Control
S0-0-25 49 Temporary Modification Control
SO-M-101 2 Maintenance Work Control
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SO-G-6 5 Housekeeping
S0-G-28 '39 Station Fire Plan
SO-G-5 8 . 24 Control of Fire Protection System impairments
SO-G-91 9 Control and Transportation of Combustible Materials !
SO-G-102 1 Fire Protection Program Plan ;
SO-G-103 5 Fire Protection Operability Criteria and Surveillance
Requirements !
SO-G 107 - 4 Storage of Transient Equipment and Material to
Prevent Seismic Interactions
SO-M-9 21 Fire Protection During Flame Cutting, Grinding, and
Welding Operations
SO-O 1 31 Conduct of Operations i
S0-0-38 10 Firewatch Duties and Turnover Procedures
Temporary Plant Modifications .
.T.M Title
. TM 96-014 Reactor Coolant Gas Pressure Hi
TM 96-018 Equipment Drain Header Soft Patch
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TM 96-022 Containment Low Purge Flow
TM 96-033 In-line isotopic Post Accident Sampling System Samples I
TM 96-039 Irstall Door Between Railroad Siding and Corridor 26
TM 96-041 Turbine Bearing SLOP Orain Valves
TM 96-042 Component Cooling Water System Relief Valve Setpoint Change
TM 96-044 SI 7B Pressure Gage Replaced with a Plug
TM 96-046 SI-7B Charging Valve Replacement
TM 96-048 CET 89 and B15 Cable Swap
TM 97-002 TE-3123 Jumper and Wiring Change
-TM.97 005 Temporary Air Supply for FCV-1904C
TM 97-006 CW-1C Discharge Pipe Leak Repair
Permanent Plant Modifications
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Modification' Title
MR-FC-94-020 VA-46 A and B improved Reliability
M R-FC-92-040 Temporary Compressor for Diesel Generator 1 Starting Air
Modification 1
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MR-FC-94-024 Diesel Generator 1 Inlet Damper Upgrade l
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MR-FC-92-019 New Sectional Valve in Turbine Building Standpipe Loop FP-795 I
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MR-FC-93-022 HCV-746 A/B Replacement
MR-FC-91-009 Spent Fuel Pool Rerack
MR-FC-94-018 Back-Up Raw Water Tie-in for Emergency Feedwater Water
Storage Tank in Room 81 !
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l MR-FC-88-017 Diesel-Driven Auxiliary Feedwater Water Pump j
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Drawings
Drawina Revision Title l
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11405-M-10, Sht 2 9 Auxiliary Coolant Component Cooling System Flow !
Diagram ;
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11405-M-10, Sht 1 65 Auxiliary Coolant Component Cooling System Flow -l
Diagram
11405-M-10, Sht 3 12 Auxiliary Coolant Component Cooling System Flow
Diagram
11405-M-10, Sht 4 7 Auxiliary Coolant Component Cooling System Flow
Diagram
11405-M-40, Sht 1 33 Auxiliary Coolant Component Cooling System Flow
Diagram
11405 M-40, Sht 2 25 Auxiliary Coolant Component Cooling System Flow
Diagram
11405-M-40, Sht 3 21 Auxiliary Coolant Component Cooling System Flow l
Diagram
80048 5 Emergency Feedwater Tank
11405-M-253, Sht 1 33 Steam Generator Feedwater and Blowdown
11405-M-253, Sht 4 21 Steam generator Feedwater and Blowdown
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11405-M-254, Sht 2 22 Flow Diagram Condensate !
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- Calculations
FC05692 3 Minirnum Net Positive Suction Head Available
Calculation for Component Cooling Water Pumps
FC06378 2 Determination of Final N2Pressure in Component
Cooling Water Surge Tank Following a Component
Cooling Water Temperature Transient
EA-FC-95-012 O Effect of Post-Design Basis Accident Component
Cooling Water Temperature Transient on Components
.FC05346 1 Accumulator Sizing for Auxiliary Feedwater Control
Valves HCV-1107A&B, HCV-1108A&B, HCV-1105,
HCV-1106, FCV-1368, FCV-1369
2 Auxiliary Feedwater System Calculation (Pump Design
FC05361 and Turbine Drive)
FC05691 2 Air Accumulators Operable Time Requirements
FC05336 0 Determine Differential Head and Suction / Discharge
Pipe Sizes for Startup Feedwater Pump
EA FC-93-032 0 Feed-Rate of Steam Generator Following a Loss of
FC05071 0 Emergency Feedwater Storage Tank Level for Pump i
Total Dynamic Head Calculation
FC06148 1 Auxiliary Feedwater Storage Requirements
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FC06111 0 Tank Curve FVV-19 I
FC05336 0 Determine Differential Head and Suction / Discharge
Pipe Sizes for Startup Feedwater Pump i
FC06537 B Raw Water Fill Line to FW-19 Friction ioss l
1
FC06024 1 N2 Cylinder Sizing for HCV-480,481,484,485
FC04286 A Evaluation Criteria for Threaded Fasteners with
Incomplete Thread Engagement j
FC06638 0 Capacity of Fuel Oil Tank FO-38'
FC06641 1 Analysis of Auxiliary Building Water Curtains
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Operability Evaluations !
Number Title
199500216 - Operability Evaluation of Safety-Related, Power-Operated Gate
Valves (Generic Letter 95-07)
199500383 Operability of Valves HCV-1384, HCV-1386 and Associated l
Piping and Isolation Valves
199600161 Generic Letter 91-15 Review -
199600927 Steam Generator Orifice Plates Design
199700015 Net Positive Suction Head of Safety Injection and Containment !
Spray Pumps
199700C19 Parts Replacement on Solenoid Valves
199700049 Pressure Drop to Main Steam Safety Valves
199700067 Gate Valve Pressure Locking and Thermal Binding .
1
199700168 Missing Local Instrument Air Filters
{
Condition Reports
Number Title
199700410 Evaluation of Wet Pipe Sprinkler System for Turbine Driven
Auxiliary Feedwater Pump
199700416 Missed Fire Brigade Classroom Lecture
199700495 Missing Tubing Clamps on Reactor Coolant Pump Lube Oil
Collection System Drain Lines
199700498 Pull-to-Lock Operability of Fire Suppression Water Pumps
199700523 Diesel Generator 2 Speed Sensing Circuit Not Isolated from
Effects of Control Room Fire
199700350 Containment VA-8B Cooling Coil; Component Cooling Water
Outlet Valve
199700264 Demineralized Water Surge Tank DW-39; Transfer Pump
199700206 Spent Fuel Pool; Circulating Pump
199700153 Auxiliary Feedwater Pump; Turbine Driven
199700133 Boric Acid Batching Tank Heater 4
199700111 Rockshaft for HCV-1042A Missing Set Screw Holes
199700019 Radiation Monitor RE 064 Isolation Valve
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199700014 Jumper on TB-1 Not on Drawing
199700008 Safety injection & Refueling Water Tank (Safety injection ,
Refueling Water Tank) j
199601556 Shutdown Cooling Heat Exchanger AC-4A; Component Cooling l
Water Outlet valve !
1
199601030 Boric Acid Batching Tank Heater 4
'
.lR 950617 Boric Acid Batching Tank Heaters
IR 950166 Boric Acid Batching Tank Heaters 1
199700409 Component Cooling Water Pump Flange Thread Engagement
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! Safety Audit and Review Committee Audits
l- Number, Title
94-SARC-013 SARC Audit Report 25S and QA Audit 25 Fire Protection / Loss
Prevention
95 SARC-020 SARC Audit Report 25A Fire Protection / Loss Prevention
96 SARC-022 SARC Audit Report 25A and 25B Audit Report 25 Fire
Protection / Loss Prevention
Quality Assurance Audit and Surveillance Reports
Number Title
96-QA/QC-002 Quality Assurance Audit Report 69 Safety System Functional
inspection Diesel Generator System
95-COA-033 Quality Assurance Surveillance Report E2-951 Electrical
Equipment Qualifications
95-COA-024 Quality Assurance Surveillance Report E4-95-2 Modifications
During Outages
95-CQA-018 Quality Assurance Surveillance Report E6-95-1 Design Basis
Document / Drawing Verification
95-COA-066 Quality Assurance Surveillance Report E6-95-3 design basis
document / Drawing control
95 CQA-086 Quality Assurance Surveillance Report E6-95-4 de;n basis
document / Drawing control
95-COA-019 Quality Assurance Surveillance Report E7-95-1 Station
l Engineering and Technical Reviews
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96-CQA-008 Emergent Quality Assurance Surveillance Report E-96-1 Use of
Teflon Tape in Chemical Feed (Hydrazine) System l
96-COA-042 Quality Assurance Surveillance Report E4-96-1 Modifications l
During Outages
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97-QA/QC-032 Quality Assurance Surveillance Report E6-97-1 Desi0n Basis l
Document / Drawing Control l
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10 CFR 50.59 Screening and Safety Evaluations:
Number Title
MR-FC-84-155C Replacement Process and Effluent Radiation Monitors-Package C
which included 1150.59 Applicability Screenings and 7
Unreviewed Safety Question Determinations
MR-FC-95-026 Fuel Storage Tanks inside of Protected Area i
ECN 95-337 New Test Terminal Blocks for Waste Gas Analyzer Relays
ECN 95-394 HCV-482/3 A/B Valve Blocks
ECN 92-559 Circulating Water Pump Motor Lower Bearing Oil Drain Valve
1
ECN 93-415 Change Out of Blowdown Pump Trip Override Switch i
ECN 96-159 Plug for CW-1C Upper Drain Line
Technical Specification Interpretaticas
Number Technical Specifications /Uodated Safety Analysis Report Section
97-06 Technical Spe .ifications 1.3(B) and Technical
Specifications 2.15 Bases
92-08 Technical Specifications 2.1.1(3)c and 2.1.1(4) Exception
96-10 Technical Specifications 2.1.6(4)
97-05 Technical Specifications 2.1.6(4) Bases
96-06 Technical Specifications 2.1.6(5)
96-03 Technical Specifications 2.1.7
93-03 Technical Specifications 2.4(1)a
97-08 Technical Specifications 2.5
95-04 Technical Specifications 2.7(1)j
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97-07 Technical Specifications 2.7(1)j
97-03 Technical Specifications 2.7(2)j
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I 97-04 Technical Specifications 2.10.2(4)a j
94-13 Technical Specifications 2.10.2(4)
-95-12 Technical Specifications 2.10.4(5)(b)
)
95-06 Technical Specifications 2.10.4(5)(b)
95 16 Technical Specifications 2.12(3)
95-15 Technical Specifications 2.12(4) )
93-12 Technical Specifications 3.1 Table 3-2
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j 96-14 Technical Specifications 3.2 Table 3-4
93-15 Technical Specifications 5.0 I
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Substitute Replacement item Engineering Change Notices
Number Revision Title
ECN 91-361 2 Replacement of SA-170 Valve
ECN 96-307 1 Packing Substitution for Crane Valves l
ECN 96-354 0 Replacement of Defective Mounting Track for Relays i
l
ECN 96-312 0 Replacement of LlA-906Y j
ECN 96-322 0 Replacement of SBM Switch
ECN 96 398 0 HCV-484/485 Coupling
ECN 96-402 1 Safety injection Accumulator Pressure Gage
Replacement
ECN 96-415 0 Control Element Drive Mechanism Threaded Seal
Substitute
ECN 96-428- 1 Subcooled Margin Monitor Power Supply
ECN 96-462 0 Bushing for Anchorhead on Containment Dome
Tendon
ECN 97-002 0 Replacement of HCV-348 Breaker
ECN 97-030 0 HE-2 Accumulator Substitute Replacement
ECN 97-093 0 Replacement CR120A for HCV-2877A
ECN 97-127 0 Replacement B/ PIA-102Y
ECN 95-130 0 CCW Relief Valve Setpoint Changes
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ECN 95-124 0 CB-520-SR-60 Spring Replacement
ECN 95-321 -0 FW-10 Oil Relay Assembly
ECN 96-277 0 . FW-663 Valve Replacement
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. ECN 96-278 0 Replacement of HC-1045 Hand Control Switch l
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Engineering Assistance Requests 1
Number Title
l
EAR 97-092 . Replacement Spring Pack for Limitorque Operator SMB-00
[
- EAR 97-073 Diesel Generator Droop Setting l
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EAR 95-111 Containment Spray Pump Recirculation Valves
EAR 93-030 Auxiliary Feedwater Pump FW-10 Differential Pressure Indicators
Engineering Analyses
Number Revision Title -
EA-FC-96-051 2 IE Bulletin 80-06, ." Engineered Safety Features Reset"
EA-FC-96-001 0 Criticality Safety Evaluation of the Fort Calhoun Spent
Fuel Storage Racks for Maximum Enrichment
Capability
EA FC-92-077 0 Licensing Report for Spent Fuel Storage Capacity
Expansion
EA-FC-93-042 1 Containment Seal Penetration Evaluation
EA-FC-93-047 1 Halon System Operability Evaluation
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Design Basis Documents
l
Number Revision Title
SDBD-AC-SF-102 9 Spent Fuel Pool and Fuel Pool Cooling Design Basis
Document
SDBD-DG-112 15 Emergency Diesel Generators Design Basis Document
l
SDBD-MS-125 9 Main Steam and Turbine Steam Extraction Design
Basis Document
Nuclear Safety Review Group Assessments and Special Reports
Number Revision Title
SRG-95-018 0 Oversight of the Test Engineering Group
SRG-95-036 0 Followup Assessment of Operator Work-arounds I
SRG-95-057 0 4160 Volt Circuit Breaker Replacement
SRG-95-086 0 Diesel Generator Hot Weather Operation issue i
SRG-96-046 0 Reactor Coolant Pumps Vibration Monitoring ;
SRG-96-079 0 Backlog of Engineering Change Notices / Engineering
Analysis Requests / Maintenance Requests ;
i
SRG-96-084 0 Absence of Steam Generator Orifice Plates in
Loss-of-Coolant Analysis
SRG-96-091 0 Maintenance Timeliness and Configuration Control
SRG-97-006 0 Steam Leak Resulted Due to Blown Gasket
SRG-97-015 0 Auxiliary Feedwater Pump (FW-110) Low Discharge
Dif ferential Pressure i
SRG-97-022 0 Nuclear Safety Review Group Review of Substitute
Replacement item Engineering Change Notice 1
1
Maintenance Work Request
)
MWR 9701551 SealHg Reactor Coolant Pump Lube Oil Collection System !
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Miscellaneous Documents
Technical Specifications
Updated Safety Analysis Report i
NOD Te'chnical Staff (Technical Specifications) Training Handbook Lesson Plan 2327-07,
Revision 10, dated February 3,1997 (Initial)
NOD Qualified Reviewer Process and 10 CFR 50.59 Safety Evaluation 8iennial
i
Requalification Training Lesson Plan SEAD-36, Revision 3 (Requalification) i
LIM-97-0034, " Cancellation of Technical Specification Interpretation 95-12 and 91-02,"
dated March 31,1997
, LIM-97-0020, " Cancellation of Technical Specification Interpretation 95-09," dated
'
February 19,1997
l
LIM-96-0165, " Review of Technical Specification Interpretations," dated November 14, l
1996
LIM-96-0164, " Review of Technical Specification Interpretations," dated November 11,
!
1996
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LIM-96-0163, " Review of Technical Specification Interpretations," dated November 11,
!
1996
l
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LIM-96-0145, " Meeting to Review Technical Specification Interpretations," dated i
October 18,1996 )
LIM-96-0047, "10 CFR 50.59 Oversight Committee Charter," dated April 2,1996
!
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LIM-96 0015, "50.59 Improvement Plan Action Assessment Team," dated January 18, '
1996
PED-FC-95-33, "10 CFR 50.59 Improvement Program," dated September 28,1995
l LER 96-006-00, "All Charging Pumps Disabled Due to an inadequate Administrative
l Control," dated October 6,1996
!
Licensee letter to the NRC dated December 12,1979, concerning a water curtain
Licensee letter to the NRC dated January 18,1980, concerning a water curtain
Licensee letter to the NRC dated May 20,1980, concerning a water curtain
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EOS-DEN-97-0165, " Final Report for the Self Assessment of Licensing Basis Conformance
for the Auxiliary Feedwater System," April 17,1997
PED-DEN-97-0049, " Final Report for the Self Assessment of Licensing Basis Conformance
for the Safety injection System," February 7,1997 i
PED-DEN-96-0442, " Final Report for the Self Assessment of Licensing Basis Conformance
j at Fort Calhoun Station (Chemical and Volume Control System)," October 3,1996
,
PED-DEN-95-574, Modification MR-FC-91-009, " Spent Fuel Pool Rerack," August 7,1995
PED-FC-94-1172, " Revision of Updated Safety Analysis Report," Sections 9.3.1 and
9.7.4.2, September 29,1994
i
LIM-95-0208, " Updated Safety Analysis Report Changes for the 1995 Updated Safety '
Analysis Report Update," September 3,1995
PED-FC-93-2426, "P! ant Review Committee Interim Subcommittee for Updated Safety .
Analysis Report Changes," July 7,1993
FC-T-058-97, " Personnel Qualified to Perform / Review 10 CFR 50.59 Safety Evaluations,"
' March 13,1997
FC-T-253-96, " Personnel Qualified to Perform / Review 10 CFR 50.59 Safety Evaluations,"
October 23,1996
LIC-97-0039, NRC Inspection Report 50-285/96-17, Reply to a Notice of Violation,
March 31,1997
Configuration Control Self Assessment Report, April 11,1997 I
Production Engineering Division Organizational Chart, Chart 3.1.01, Revision 0 ,
Nuclear Program Planning Manual, Section 5, "Prioritization," Revision 6, March 15,1996 l
Nuclear Energy Institute, NEl-96-05, " Industry Initiative to Address Licensing Basis
Conformance issues," Revision 0
Vendor test curves for Auxiliary Feedwater Water Pump Serial 691-N-0436 l
. Vendor test curves for Auxiliary Feedwater Water Pump Serial 891-C-0033
Vendor test curves for Auxiliary Feedwater Water Pump Serial 8494DBE
Vendor Manual TD C438.0020, " Instructions for Installation, Operation, and Maintenance
of Coffin Turbo Pump Type DEB Auxiliary Feed Pump," Revision 3, December 5,1994
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l Vendor Manual TD B580.0160, " Installation and Operation Instructions for Motor Driven
Auxiliary Feed Pump Type DVMX," Revision 1, June 28,1994 l
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Vendor Manual TD G080.2260, " instruction Manual for Custom 8000 Horizontal Induction
1
Motors Dripproof, Splashproof or Weather-Protected Type 1," Revision 2, June 8,1990
Dresser Relief Valve Bulletin 71.4:98 concerning valve reset pressures
Calculation, " Usable Capacity of Emergency Feedwater Storage Tank FW-19," dated
November 23,1988
Engineering Evaluation for Technical Specification Interpretation 90-01, Operability of Fire
Water Suppression System
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Omaha Public Power District -5-
E-Mail report to T. Boyce (THB)
E-Mail report to NRR Event Tracking System (IPAS) l
E-Mail report to Document Control Desk (DOCDESK)
bec to DCD (IE01)
bec distrib. by RIV:
Regional Administrator DRS-PSB
DRP Director MIS System
Branch Chief (DRP/B) RIV File
Project Engineer (DRP/B) Branch Chief (DRP/TSS)
Resident Inspector
.
DOCUMENT NAME: R:\_FCS\FC706RP.TFS
To receive copy of document, indicate in box: "C" n Copy without enclosures "E" = Copy wth enclosures "N" = No copy /
RIV: SRI:EB E _
Rl:EB RI:PBC j PM:NRR l C:EB .,/l D:DRP l, D:DRSV
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06/fl /97 06/g /97p 06/gl /977 06/il/977p 06/\\/97 06/i t./97f 06/4fjlr7
OFfTCIAL RECORD COPY
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