ML20137F766
| ML20137F766 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 03/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20137F728 | List: |
| References | |
| 50-338-97-01, 50-338-97-1, 50-339-97-01, 50-339-97-1, NUDOCS 9704010204 | |
| Download: ML20137F766 (29) | |
See also: IR 05000338/1997001
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50 338, 50 339
License Nos: NPF 4, NPF 7
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Report Nos: 50 338/97 01, 50 339/97-01
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Licensee: Virginia Electric and Power Company (VEPC0)
Facility: North Anna Power Station, Units 1 & 2
Location: 1022 Haley Drive
Mineral, Virginia 23117
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Dates: January 12 through February 22, 1997 !
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Inspectors: R. McWhorter, Senior Resident Inspector i
R. Gibbs, Resident Inspector !
R. Musser, Senior Resident Inspector, Surry (Section M1.3) l
L. Garner, Project Engineer (Sections 01.2, M1.1, M1.4, '
M1.5, and E8.2)
E. Girard, Reactor Inspector (Sections El.1 and E8.1)
Approved by: G. Belisle, Chief Reactor Projects Branch 5
Division of Reactor Projects
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ENCLOSURE 2
9704010204 970321
PDR ADOCK 05000338
O PDR l
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EXECUTIVE SUMMARY
North Anna Power Station Units 1 & 2
NRC Inspection Report Nos. 50 338/97-01, 50 339/97-01 l
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This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a 6 week
period of resident ins)ection; in addition, it includes the results of i
announced inspections )y regional specialists and a regional project engineer. !
Operations !
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. Daily operations were generally conducted in accordance with regulatory '
requirements and plant procedures. Good equipment material conditions l
were evident by problem free plant operation during the inspection !
period (Section 01.1). j
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. An operator did not fully understand abnormal control board pressurizer j
spray line temperature indications (Section 01.2).
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. A Unit 1 Low Head Safety Injection (LHSI) System walkdown revealed that
the system was properly aligned and maintained (Section 02.1). j
e A Violation (VIO) was identified for failures to meet 10 CFR 70.24 '
requirements for criticality monitoring for new fuel storage since the I
issuance of the facility operating license. The licensee recently )
submitted a request to the NRC to be exempted from these requirements in !
the future (Section 02.2).
Maintenance
. The observed outsido Recirculation Spray (RS) pump work activities were
performed in a quality manner. Two examples were observed in which
questio- J attitude could have been enhanced, and one example was noted
in whic., o good questioning attitude was displayed (Section M1.1).
- The licensee collected equivalent data to meet Technical Specification
(TS) surveillance requirements when a weekly surveillance test was not
performed as planned on various Unit 2 batteries (Section M1.2).
. Four surveillance activities were successfully perfnrmed in accordance
with test procedures (Sections M1.3, M1.5, M1.6 and M1.7).
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. Post maintenance testing of a steam flow protection channel demonstrated )
that the channel functioned properly (Section M1.4). ;
Enoineerina
. A Non cited Violation (NCV) was identified, involving a failure to
follow a procedure step relating to the uncertainty in Motor Operated ,
Valve (MOV) opening thrust measurements (Section E1.1.b.2). !
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. The inspectors raised issues regarding the susceptibility of the i
j licensee's quench spray valves to pressure locking, possible thermal
binding of the pressurizer power operated relief valve block valves, and .
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whether residual heat removal system isolation valves should be l
evaluated for pressure locking. The NRC will address these issues in a :
safety evaluation of the licensee's response to Generic Letter (GL)
, 95 07. An Inspection Followup Item (IFI) was identified to track these
- issues (Section E1.1.b.6).
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. Strengths in the M0V program were identified which included technically
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capable and dedicated personnel, effective efforts to organize and i
j develop data to resolve the final concerns developed during the NRC l
review, and good diagnostic test assessments (Section E1.1.b.9).
. The licensee generally met the intent of GL 89-10 by verifying M0V i
- design-basis capabilities. However, the licensee did not have i
, quantitative dynamic test data to support the reliability of the methods
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used to determine the torque requirements for butterfly valves and this
was considered a weakness. The licensee committed to resolve this
weakness through differential pressure testing and/or application of the
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Electric Power Research Institute (EPRI) Performance Prediction Model to
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a sample of their butterfly valves. An IFI was identified to track
completion of the commitment actions (Section E1.1.c).
. Following a surveillance test failure, the licensee adequately evaluated
, out-of-specification data prior to returning the Unit 2 B outside
- recirculation spray pump to operable status. However, the Engineering
i Transmittal (ET) did not clearly document all factors considered in this
evaluation (Section E2.1).
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- As a result of increased licensee awareness and initiatives, numerous
Deviation Reports (DRs) were submitted concerning Updated Final Safety
i Analysis Report (UFSAR) discrepancies. The inspectors reviewed the DRs
- and verified that there were no significant safety concerns or
- unreviewed safety questions (Section E7.1).
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. An Unresolved Item (URI) was identified to track NRC reviews of the DC
power system and charging pump start logic for compliance with
regulatory requirements (Section E8.2).
Plant Support
- Radiation areas and high radiation areas were properly posted and were
locked when required by 10 CFR 20. Independent radiation measurements 1
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found that the licensee's postings and survey results were conservative I
(Section R1.1).
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Report Details
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Summary of Plant Status '
Unit I and 2 operated the entire inspection period at or near full power.
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I. Doerations i
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01 Conduct of Operations >
01.1 Daily Plant Status Reviews (71707. 40500) l
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, The inspectors conducted frequent control room tours.to verify proper i
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staffing, operator attentiveness, and adherence to approved procedures. !
The inspectors attended daily plant status meetings to maintain
- awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with TSs. Instrumentation and
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safety system lineups were 3eriodically reviewed from control room
indications to assess opera)ility.
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Frequent plant tours were conducted >
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to observe equipment status and housekeeping. DRs were reviewed to !
assure that )otential safety concerns were properly reported and
- resolved. T1e inspectors found that daily operations were generally
conducted in accordance with regulatory requirements and plant
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procedures. Good equipment material conditions were evident by problem-
free plant operation during the inspection period.
- 01.2 Operator Knowledae of Control Board Indications (71707)
On January 22, during a control board walkdown, the inspectors observed )
that the Unit 1 pressurizer B spray line temperature was approximately i
75 F lower than the A spray line temperature. The spray valve i
indicating lights associated with the spray valve position controllers l
- revealed that the B spray valve was cracked open and the A spray valve '
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! was closed. Thus, the temperature indications were reversed from the
l expected values. This was discussed with the Unit 1 control operator. i
- The operator was aware that there was a work request outstanding on the
spray valve controllers and indicating lights but was unable to explain
- how the indicated temperatures related to the problem described on the
. work request. The operator was not able to address if the temperature
- mismatch was indicative of- a new problem or was one that was already l
l addressed. Further review indicated that the existing work request '
addressed the problem. This was discussed with the Operations
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. Superintendent. The inspectors concluded that, in this instance, the
operator did not fully understand the abnormal indications on the
] control board. .
02 Operational Status of Facilities and Equipment
02.1 LHSI System Walkdown (71707)
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- . During the weeks of January 13 and February 18, the ins)ectors performed ;
a walkdown of the Unit 1 LHSI system in the Safeguards 3uilding and
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Quench Spray Pump House. The UFSAR, TS, system drawings, and procedure
1 0P-7.1A, Valve Checkoff - Low Head Safety Injection, Revision 15, were
reviewed and used as references for the walkdown. The inspectors found
that all system components were aligned in accordance with applicable
requirements and were in good material condition. The inspectors l
concluded that the Unit 1 LHSI system was properly aligned and j
maintained. 1
02.2 Criticality Accident Monitorina
a. Inspection Scope (71707)
On February 12 and 13 the inspectors reviewed plant systems and
licensee procedures for criticality accident monitoring for new fuel l
stored on site prior to placement in the spent fuel pool. The !
inspectors reviewed the licensee's compliance with UFSAR, TS, and 10 CFR '
70.24 requirements. ;
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UFSAR Sections 3.1.53, 4.3.2.7, 9.1.1 and 12.1.4 described plant i
features supporting the storage of nuclear fuel prior to placement in
the spent fuel pool. These features included new fuel storage rack
design to prevent inadvertent criticality, new fuel handling equipment
design, radiation monitoring system design, and new fuel storage rack ;
seismic qualifications. UFSAR descriptions also stated that analyses l
were completed to demonstrate that if the new fuel storage rack area
were filled with aqueous foam, a k , less than or equal to 0.9 would be
maintained. TS3.3.3.1andTSTabN3.36delineatedtherequirement
that one area radiation monitor in the new fuel storage area, also
described as a criticality monitor, be operable when fuel was present in i
the Fuel Building. !
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10 CFR 70.24 requirements for criticality accidents applied to the l
possession of special nuclear material (new reactor fuel) from removal
from transportation containers until handled or stored beneath water
shielding (placed in the spent fuel pool). For plants licensed after
December 6,1974, these requirements included:
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A gamma or neutron sensitive monitoring system which would
ener31ze alarm signals if accidental criticality occurs for each j
area where material was handled, used or stored [70.24(a)],
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A monitoring system of specific design sensitivity (capable of l
detecting a criticality that produced an absorbed dose of 20 rads
combined neutron and gamma radiation at an unshielded distance of
two meters from the reacting material) [70.24(a)(1)],
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A monitoring system consisting of two detectors [70.24(a)(1)],
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Emergency procedures for personnel evacuation upon system alarm
[70.24(a)(3)],
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Procedures for the conduct of drills to familiarize personnel with !
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Designation of responsible individuals for determining the cause
of the alarm [70.24(a)(3)], and
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Placement of radiation survey instruments in accessible locations
q for use in an emergency [70.24(a)(3)].
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b. Observations and Findinas
The inspectors found that the UFSAR sections discussed above accurately
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described existing plant features. The new fuel storage rack area was 1
consistent with the UFSAR description and was in good material
condition. One radiation monitor (1-RMS RM 152) was permanently
installed in the new fuel storage area, and the inspectors verified that
the monitor was operable in accordance with TS requirements. A second
radiation monitor (1-RMS RM 153) was attached to the fuel building
bridge crane which was parked over the new fuel storage area when not in
use, and the inspectors verified that the monitor was operable. Both
radiation monitors used gamma sensitive geiger mueller detectors, had
radiation level meters locally and in the control room, and had audible
and visible alarm indications locally and in the control room. The
inspectors concluded that the UFSAR and TS requirements for criticality
accident-related features were met by the licensee.
The inspectors reviewed the facility operating licenses and determined
that the licensee did not have an exemption from 10 CFR 70.24 )
requirements at the time of the inspection. The inspectors noted that !
on January 28, 1997, the licensee submitted a request for exemation from !
the 10 CFR 70.24 requirements to the NRC. The letter stated t1at the
exemptions existed during facility construction, but were not
incorporated into the 10 CFR 50 operating licenser when they were
issued. Concerning the licensee's compliance with 10 CFR 70.24 -
requirements listed above, the inspectors found:
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One gamma-sensitive radiation monitoring system (1 RMS RM 152)
capable of detecting high radiation levels and actuating an alarm
was installed in the new fuel storage area. No radiation
monitoring system was installed in the new fuel receiving area
where new fuel was unloaded from transportation containers for
movement to the storage area. The new fuel storage area radiation
monitor was located in the same end of the Fuel Building, but was
on a level above the receiving area and shielded from the
receiving area by concrete structures.
- The ability of the new fuel. storage area radiation monitor to meet
the requirements for monitor sensitivity could not be
demonstrated. The licensee had no readily available information
demonstrating that the monitor had been analyzed for compliance
with the 10 CFR 70.24 sensitivity requirements.
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The new fuel storage area radiation monitor consisted of only one
detector. Although a second radiation monitor and detector on the
fuel building bridge crane was frequently present in the area, it
was periodically moved away from the new fuel rack area during
fuel handling activities and did not continuously meet the
requirement for a second detector.
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Emergency procedures for evacuating the area upon a radiation
monitor alarm were available for use, but did not specifically
require evacuation of the area upon receipt of an alarm. The
inspectors reviewed abnormal operating procedure 0 AP-5.1. Common
Unit Radiation Monitoring System, Revision 9. and found that it
contained direction for control room operators to respond to an
alarm on the new 91 storage area radiation monitor. The
procedure directeu o>erators to investigate the validity of
alarms, notify Healt1 Physics (HP) personnel to survey the area. '
stop fuel movements in the area, verify any automatic ventilation
system lineup changes, and notify personnel in the area.
Additionally, if the alarm occurred during fuel handling, '
operators were directed to enter other abnormal 3rocedures for
fuel handling accidents including 0 AP-30, Fuel railure During
Handling, Revision 6. Procedure 0 AP 30 contained direction to l
evacuate the area after placing the fuel in a safe location. !
However, 0 AP 5.1 did not contain a step directing area evacuation
upon receipt of any valid alarm during situations other than fuel l
handling. !
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The licensee did not conduct drills specifically to familiarize
personnel with evacuation plans. Licensee managers informed the
inspectors that drills had not been conducted to meet this i
requirement. ;
- Licensee personnel were designated to determine the cause of .
system alarms. As discussed above, procedure 0 AP 5.1 required
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control room operators to respond to alarms on the new fuel ,
storage area radiation monitor and take actions which were
appropriate to determine the cause of the alarm.
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Numerous radiation survey instruments of various types were
available for use by emergency response personnel and were located
in an accessible storage area near the HP shift office.
The inspectors reviewed the significance of the above non compliance
items and concluded that the safety significance was low.
The inspectors concluded that the licensee failed to meet 10 CFR 70.24
requirements for criticality accidents, and no exemption from the
requirements had been granted by the NRC. Specifically, contrary to
10 CFR 70.24 requirements, radiation monitors installed in fuel handling
and storage locations did not provide full coverage for the area used
for new fuel receipt and consisted of only one permanently installed ;
detector. Additionally, emergency procedures did not clearly direct
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3 area evacuation upon receipt of any alarm, and drills were not conducted
to familiarize personnel with evacuation plans. This condition had
existed since issuance of the facility operating license until the
inspection on February 13, 1997. During that time, the new fuel
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receiving and storage areas were used to handle, use and store new fuel
. assemblies on a regular basis prior to each unit refueling outage. This
is identified as a violation of 10 CFR 70.24 requirements (50 338,
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, 339/97001-01). This violation will be considered as an engineering I
violation. '
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l c. Conclusion
) A violation was identified for failures to meet 10 CFR 70.24
requirements for criticality monitoring for new fuel storage since the i
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issuance of the facility operating license. The licensee recently :
submitted a request to the NRC to be exempted from these requirements in j
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II. Maintenance
i M1 Conduct of Maintenance
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M1.1 Unit 2 Outside RS Pumo Maintenance
l a. Scope (62707)
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{ On January 21 through 23, the inspectors observed corrective maintenance' u
associated with the Unit 2 A RS aump, 2-RS-P 2A. Observed work '
! included: correcting a leak on t1e seal head tank accumulator per 0 MCH-
0650 01, Disassembly, Inspection, and Repair of the Outside
Recirculation Spray Pump Seal Accumulator, Revision 0 P1; replacement of
, a seal system water fill valve per W0 00358048 01: and, repair fittings
j on mechanical seal system water fill line per W0 00357986-02. i
b. Observations and Findinas
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Huch of the work observed was performed as skill of the craft. The work
performed was of high quality. Procedures were followed when ;
applicable. Two areas in which questioning attitude could be enhanced i
were discussed with the Maintenance Superintendent. The first involved !
the proper orientation of the replacement fill valve. Maintenance ;
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personnel noted that the installed valve was oriented with the indicated l
! flow direction opposite the direction of flow when the valve is opened !
to fill the system. The individuals discussed this among themselves and !
decided to install the replacement valve in the as found orientation. 1
. When questioned by the inspectors, the craftsmen contacted Operations
1 who referred to a flow diagram and informed maintenance that the valve
, should be turned around from the as-found configuration. Engineering l
subsequently reviewed the issue and determined that based upon operating l
- conditions it was more important for the valve to be installed in an 4
orientation backwards from its indicated flow direction. This would .
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allow the valve to better seal to prevent air leakage into the system >
which is under a vacuum during normal operation. The second instance
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involved an observation by the inspectors that the two mounting bracket :
bolts were not lubricated prior to torquing and had no washers
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installed. These bolts were installed through a bracket and then
screwed into the accumulator head flange, thus compressing the ,
accumulator head gasket. The other bolts that attached the accumulator
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head were lubricated arior to torquing. The licensee indicated that -
they would evaluate t1ese observations. In both instances, maintenance ,
personnel had the opportunity to identify that deviations from normal
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! practices existed and to pursue these deviations with the appropriate
organization. The ins >ectors observed that maintenance personnel -
questioned if a small ) ore pipe was correctly supported and initiated a
DR to resolve the observation.
c. Conclusions
The observed RS pum) work activities were performed in a quality manner. I
Two examples were o) served in which questioning attitude could have been
enhanced and one example was noted in which a good questioning attitude
was displayed. ,
M1.2 Potential Missed Battery Surveillances Review
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a. Inspection Scope (61726)
On January 30, licensee engineers and maintenance personnel submitted DR
N-97 274 documenting failures to perform weekly surveillance procedures
for several Unit 2 batteries during a recent refueling outage. The DR
stated that reviews of other tests and maintenance procedures performed
during the outage demonstrated that the surveillance requirements of TS 4.8.1.2 and 4.8.2.2.2 were met during the period the weekly procedures
were not performed. During the weeks of February 3 and 10, the
inspectors reviewed the problem to verify the validity of the licensee's
conclusions that TS surveillance requirements were met.
b. Observations and Findinas
The inspectors found that test 2-PT 85, DC' Distribution System,
Revision 30, was missed for various Unit 2 batteries during a three week
period of September 1996. The DR stated that during this period
procedures 2 PT 86A/B, DC Distribution Systems H/J Bus, Revision 18, and
maintenance procedures for battery equalization charges and test
discharges recorded equivalent data. The inspectors reviewed the data i
recorded by these 3rocedures and compared them to 2-PT 85. The !
inspectors found t1at the other procedures did record the same data as ;
2 PT 85 and contained data required to be checked weekly by TS
surveillance requirements.
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The inspectors reviewed record copies of the procedures performed during ;
the period in question. With the assistance of system engineers, the i
inspectors found that for all cases where 2 PT 85 was not performed, the
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other procedures were performed and included records of the information I
. which would have been recorded by 2-PT-85.
The inspectors questioned why 2 PT 85 was not performed as planned
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during the three week outage period. Licensee engineers informed the
- inspectors that the test was the responsibility of the electrical
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maintenance department. During the unit outage, when equalization
charges and test discharges on the batteries were being performed,
maintenance personnel failed to perform the weekly surveillance test as
scheduled. At the inspection period's end, further investigations and
planning of corrective actions were continuing.
c. Conclusions l
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The inspectors concluded that the licensee collected equivalent data to
meet TS surveillance requirements when a weekly surveillance test was
not performed as planned on various Unit 2 batteries.
M1.3 Ouadrant Power Tilt Ratio (0PTR) Surveillance Test (61726)
On January 29, the inspectors observed the performance of 1-PT 23,
Quadrant Power Tilt Ratio (QPTR) Determination, Revision 19, for Unit 1. ;
This test was performed to satisfy TS Surveillance requirement 4.2.4.1.a. to demonstrate that the core QPTr did not exceed 1.02. The
- QPTR was calculated utilizing the P-250 plant computer in accordance
with paragraah 6.3 of 1-PT-23. The-inspectors observed the operator 4
, performing t1e work to be closely following the )rocedure and using good '
self check practices. The inspectors reviewed t1e results of the
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surveillance and concluded that the OPTR calculated (1.007) fully ,
satisfied the requirements of TS 3.2.4.
M1.4 Unit 2 Steam Flow Channel Post Maintenance Testina (62707)
On February 4. Unit 2 main steam flow channel III failed downscale. The
licensee dete mined that a circuit card associated with instrument
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- F MS 2474 hac failed. The circuit card was replaced, the circuit was
successfully tested, and the flow channel was returnect to service. The
inspectors verified that related protection channels were placed in trip
i as required by TS and observed post maintenance testing of n.he channel.
- The testing was performed in accordance with 2 ICP MS-F-2474, Steam
Generator A Steam Flow and Feed Flow Protection Channel III (F MS 2474
4 and F FW 2477), Revision 1. The inspectors independently verified that
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portions of the data were correctly recorded, the data met acceptance !
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criteria, and the channel functioned properly.
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M1.5 Unit 2 B Motor Driven Auxiliary Feedwater (AFW) Pumo Quarterly Test
(61726)
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On February 4, the ins)ectors witnessed performance of the quarterly '
surveillance test of t1e Unit 2 B motor driven AFW pum). The inspectors
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verified that the test was performed in accordance witi 2-PT-71.30,
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that the data recorded was correct and met the acceptance criteria
contained in the procedure.
M1.6 LHSI Pumo Surveillance Test
a. Insoection Scoce (61726)
The inspectors observed the quarterly pump operability test for Low Head
Safety Injection Pump 2 SI-P-1B to ensure TS 4.5.2.f.2 and TS 4.0.5
requirements were satisfied. Additionally, the inspectors reviewed
selected sections of the UFSAR and historical test records.
b. Observations and Findinas
On February ll, the inspectors observed operators performing 2-PT 57.1B,
Emergency Core Cooling Subsystem Low Head Safety Injection Pump (2-SI-P-
1B), Revision 27 P2. The purpose of the test was to demonstrate pump
operability requirements for discharge pressure and pump vibration.
Prior to the test, the inspectors ensured the acceptance criteria in the
controlling procedure agreed with the TS requirements. Additionally,
the inspectors reviewed the associated pump performance curve (UFSAR
Figure 6.3 7) to verify the test accurately reflected what was assumed
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in the UFSAR. The inspectors also verified that performance of the test :
had been ap> roved by management, was properly planned, and the I
associated _imiting Condition for Operation was entered. During the i
test, the inspectors inde>endently measured and calculated pump data
associated with pump disc 1arge pressure requirements and found them to l
be within TS requirements. The inspectors also verified that test
instruments had been properly calibrated. Upon completion of the test,
the inspectors reviewed the completed test procedure for accuracy and
completeness. Additionally, the inspectors ensured proper review was
performed by the Senior Reactor Operator and no problems were noted.
The inspectors later reviewed historical test records from 1996 to
ensure that the testing frequencies had been completed in accordance
with TS requirements. The inspectors also reviewed the operating data
and no adverse trends were evident.
c. Conclusions
The inspectors concluded that the quarterly pump operability test for
Low Head Safety Injection Pump, 2-SI P 1B, was properly performed and
that TS requirements were satisfied.
M1.7 Turbine Valve Freedom Test (61726)
On February 14, the inspectors observed operators performing 2 PT 034.3.
Turbine Valve Freedom Test, Revision 18 Pl. The test was required by TS 4.7.1.7.2.a to demonstrate the operability of the turbine governor and
throttle valves. The inspectors found that operators performed the
evolution carefully and in accordance with approved o>erating
procedures. The inspectors noted that communication 3etween the reactor
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cperator and the unit senior reactor operator was good and the level of
supervisory oversight during the test was appropriate. The inspectors
verified that the valves performed acceptably during the test and that
TS requirements were met. The inspectors concluded that the Unit 2
turbine valve freedom test met TS requirements and was properly
performed.
III. Enaineerina
El Conduct of Engineering
El.1 Generic Letter 89-10 Proaram Implementation
a. Inspection Scope (Temocrary Instruction 2515/109)
- This inspaction provided an assessment of the licensee's implementation
of GL 8910, Safety-Related Motor-0perated Valve Testing and
Surveillance. The inspection was conducted through a review of the
licensee *s GL 89-10 implementing documentation and through interviews
with licensee personnel. Documents reviewed included the licensee's
technical overview and closecut document (PE 0016. Revision 6), MOV
program (VPAP-0805, Revision 6), diagnostic testing procedure (0 ECM-
1505 01, Revision 17), gate and globe valve thrust and torque
calculations, guidelines for addressing MOV design issues (NASES 3.10,
Revision 4), butterfly valve torque calculations and assessments of test
results, and summary matrices of M0V available valve factors and .
margins. ]
To assess details of the licensee's implementation of GL 8910, the
inspectors selected the sample of valves tabulated following this
paragraph for particular attention. Other valves were also addressed,
where appropriate to the areas being reviewed by the inspectors.
2-CH-2275B High Head Safety Injection Pump Recirculation Valve
2 RC 2536 Power Operated Relief Valve (PORV) Block Valve
2-RH 2700 A Hot Leg to Residual Heat Removal (RHR) Pump Suction
Valve
2-SI 2864B Low Head Safety Injection Pump Discharge Valve
2 SI 2867A Boric Acid Injection Tank Inlet Valve
1-SW-105A Recirculation Spray Heat Exchanger Return Header Valve
1 SW 117 Auxiliary Service Water Pump Discharge Valve
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1-SW 123A Service Water Discharge Winter Bypass Valve
1-SW-104C Recirculation Spray Heat Exchanger Outlet Valve
2 SW 220B Auxiliary Service Water Return Header Valve
2-CC-2008 Component Cooling Supply to RHR Heat Exchanger Valve
b. Observations and Findinas
1. Scope of MOVs Included in the Pr:. J
The scope of valves originally in the licensee's GL 8910 program was
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- reviewed and determined acceptable by the NRC during Inspections 50 338, !
339/91 09 and 93-16. In the current inspection the inspectors verified i
that the scope had not been changed. The MOV program contained a total ,
of 249 MOVs (consisting of 142 gate, 22 globe, and 85 butterfly valves). J
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! 2. Determinations of Settinas and Verifications of Capabilities for i
{ Gate and Globe Valves !
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tLOV Sizino and Switch Settinas i
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North Anna's gate valve thrust and torque calculations utilized standard i
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industry equations. An assumed stem friction coefficient of 0.20 was i
used to convert thrust to torque. Generally, the valve factors used in '
, the gate valve design thrust calculations were based on original vendor
information and were lower than ere now typically used in the nuclear
industry. Except for Westinghouse valves, a valve factor of 0.20 was
used for double disc gate valves and 0.30 for flex and solid wedge gate
valves. Westinghouse gate valve thrust requirements were calculated
using the Westinghouse equation and a valve factor of 0.55. The
licensee added 15 percent margin to the minimum total thrust
requirements calculated for their gate valves to account for variations
in valve factor, load sensitive behavior, and degradation of stem
lubricant. Further, the thrust requirements calculated for the
Westinghouse and other gate valves were increased to account for
diagnostic equipment uncertainties and torque switch repeatability.
Maximum thrust limits were based on the component with the lowest
capability and were lowered to account for diagnostic equipment
uncertainties and torque switch repeatability.
Globe valve thrust requirements were calculated using standard industry
equations with a 1.1 valve factor and a 0.20 stem friction coefficient.
Similar to the gate valves,.the globe valves' minimum and maximum
calculated thrust requirements were adjusted to account for diagnostic
.
,
equipment uncertainties and torque switch repeatability. !
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Groupina and Desian Basis Caoability
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North Anna divided their MOVs into 42 groups. A group consisted of
identical valves each having the same drawing number. The only
differences found within a valve group were slight variations in the ;
design basis differential pressure requirements for particular valves. '
The gate and globe valve grou3s were separated into two categories
depending on whether or not tie licensee had used dynamic test results
to justify the design-basis capabilities of the valves in the group.
The first category of gate and globe valves contained 19 groups. The
inspectors found that the capabilities of these valves had been
justified through dynamic testing. The number of valves dynamically
tested from each group met GL 89-10, Supplement 6 recommendations. From
their review of the licensee's test results, the inspectors found that
the settings determined using the licensee's methodology bounded the .
actual requirements for all of the dynamically tested MOVs. except 2-SI- I
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2864B. This valve had a calculated minimum required thrust of 8155 lbs.
From testing, the thrust at flow cut-off at 100 percent of design basis
differential pressure was 8792 lbs. Based on this test result. North
Anna used 115 percent of 8792 lbs as the minimum required thrust applied
to all MOVs in the valve group. The inspectors found that the licensee
had satisfactorily demonstrated design basis capability for MOVs in the
19 groups in the first category.
The second category of gate and globe valve groups consisted of 13
groups that were impractical to dynamically test. No dynamic test data
were available for these valve groups. The inspectors requested that
North Anna >ersonnel calculate an available valve factor (AVF) for each
M0V using tie formulas given below.
AVF (Close) = (Th * [1 - (LSB + U)]) PL - SR/ (Disc Area * DBDP)
AVF (0 pen) = (Th * [1 - (LSB + U))) PL + SR/ (Disc Area * DBDP)
where.
Th = thrust available for limit switch control, thrust at
torque switch trip for torque switch control
LSB =
load sensitive behavior
U = uncertainty (instrument and other uncertainties
combined by square root sum of squares method)
PL = packing load
SR = stem rejection load
DBDP = design basis differential pressure
Based on the above calculations, the lowest available valve factors were
for MOVs FW 154C (0.64) and RH 2700 (0.67). All other MOVs in these
groups had available valve factors of 0.70 or higher. Based on industry
experience and the results of the licensee's tests, the inspectors
considered the MOVs with available valve factors above 0.70 to have
adequate capabilities. FW-154C and RH 2700 are discussed below:
FW-154C was a Crane,16-inch, 900# class, flex wedge gate valve
that was powered from a non vital electrical bus. This valve
performed a back-up close function to isolate main feedwater.
Based on industry experience with this valve design, the
inspectors considered the 0.64 available valve factor of this
valve sufficient to ensure its design basis capability. Further,
the inspectors noted that the valve provides a back up rather than
a primary isolation function.
RH 2700 was a Copes Vulcan,14 inch, 2500# class, parallel disc
Gate valve with open and close safety functions. The inspectors
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reviewed the static diagnostic trace for this MOV and verified
that it showed no abnormalities in valve performance. Based on
general industry experience with parallel disc gate valve testing
and the absence of any performance abnormalities, the inspectors :'
considered the 0.67 available valve factor of this valve
i
sufficient to ensure its design basis capability. ,
, The inspectors accepted the licensee's verification of the design basis
capability of the non-dynamically tested gate and globe valves based on
,
currently available valve factors. However, there was no assurance that !
these values of available valve factor would be maintained long term and i
the inspectors were concerned that the reliability of the licensee's
analytical method of determining thrust requirements for these valves
had not been demonstrated through dynamic testing. Licensee personnel
indicated that they would review industry and North Anna test results as
part of their long term test program and would look for further su) port i
for the application of their thrust determination methodology to t1eir
non dynamically tested M0Vs. The inspectors considered this -
appropriate.
Openino Diaanostic Measurement Uncertainty
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In 1993 and 1994 the licensee's diagnostic equipment vendor, Liberty
Technologies, re>orted previously unrecognized opening measurement !
uncertainty in t1eir Customer Service Bulletins 031 and 037. The NRC i
inspectors verified that the licensee's current diagnostic procedure
'
provided appropriate requirements to address this uncertainty.
Additionally, the inspectors asked licensee personnel to review tests i
performed prior to the issuance of the Customer Service Bulletins to '
verify that the uncertainty had been adequately evaluated. The licensee
completed this review and found no problem in the tests performed prior
to Customer Service Bulletins. However, the licensee also reviewed more
recent tests and found that a diagnostic procedure step addressing the
uncertainty had not been >erformed for one test. Procedure 0-ECH 1505-
01, revision 17 P2, Attac1 ment 5, step 4 was not completed in evaluating
opening diagnostic test results for valve '. RS 100A in February 1996
and, as a result, the licensee failed to recognize that the test results
indicated that the operability of this valve was in question. When this
was discovered by the licensee during the current inspection, it was
identified for resolution in DR N 97-68, dated January 9,1997.
Licensee corrective actions included issuance of a work request to
inspect the valve and reduce the seating thrust (No. 078981) and
immediate completion of an o>erability evaluation. The inspectors 1
reviewed the completed opera)ility evaluation and found that it
'
demonstrated that the valve was operable based on comparisons of opening
and closing motor current and spring pack deflection data. The
inspectors considered the missed procedure step to be a violation of 10
CFR 50, Appendix B, Criterion V (Instructions, Procedures, and 1
Drawings). This licensee identified and corr-:ted violation is being I
treated as an Non cited Violation consistent with Section VII.B.1 of the '
I
NRC Enforcement Policy (50-338, 339/97001 02).
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Load Sensitive Behavior I
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The licensee determined a load sensitive behavior mean and variability i
from their tests. These values were used in calculating available valve !
factors (as described above) for valves in grou)s that were not i
dynamically tested. The mean was a) plied as a aias value of 5.27 I
percent (LSB in the equation) and t1e variability value of 12.54 percent 1
(95 percent confidence level) was combined with other uncertainties. '
The inspectors found the licensee's determinations satisfactory.
However, they noted that the mean and variance in load sensitive
behavior had been determined using a limited amount of data (only 10
data points) and questioned whether the results of future tests would be
analyzed to strengthen the determination. The licensee stated that the
results of any future dynamic testing for GL 96-05. Periodic
Verification of Design Basis Capability of Safety Related Motor 0perated
Valves, would be evaluated to provide further confidence in the values
used.
Stem Friction Coefficient
The licensee typically used a 0.20 stem friction coefficient in
determining static settings. To assess this assumption, North Anna
personnel first converted their static data to equivalent dynamic test
data by using the fold line method described in NRC Report NUREG/CR 6100. The equivalent dynamic test data was then used in a statistical
analysis which yielded a 95 percent confidence level stem friction
coefficient value of 0.23. This study contained 34 data points. North i
Anna personnel screened their GL 89 10 MOVs using the 0.23 stem friction
coefficient. No operability concerns were identified. The inspectors
noted that North Anna should use the 0.23 stem friction coefficient
value to statically set up their MOVs instead of just for screening.
North Anna personnel stated that in the future they would use the value
obtained from their testing in establishing the static set ups.
Toraue Switch Repeatability
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The licensee used the guidance 'from Limitorque Maintenance Update 92 02
to obtain values for torque switch repeatability. These values were
combined with other random uncertainties in determining available valve {
factors. The inspectors found that the licensee's methodology
satisfactorily accounted for torque switch repeatability. j
Linear ExtraDolation
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Procedure NASES 3.10 required dynamic testing to be performed at a j
differential pressure of least 80 percent of the design basis value for
satisfactory extrapolation of the test data to design basis conditions.
However.-the licensee did not have a stated absolute minimum pressure or
contact seating force below which extrapolation would not be performed.
The inspectors found no instances where this resulted in inappropriate
testing or evaluations. North Anna personnel stated that they would
revise their procedure to specify that the M0V coordinator or Engineer
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should be contacted for an evaluation if absolute minimum pressure or
contact seating forces were low.
3. Determinations of Operatino Reauirements and Verifications of
Capabilities for Butterfly Valves
The North Anna GL 8310 program included 85 butterfly valves that were '
separated into 10 groups. The valves operated at moderately low design-
basis differential pressures (125 psi maximum) and ranged in size from 8
to 24 inches. The valves were from two manufacturers Allis Chalmers
and Contramatics.
The torques required to operate the valves under design basis conditions
were either determined by the licensee using the vendor's equations
(Allis Chalmers valves) or were provided by the vendor (Contramatics
valves) . As the valves were limit seated, their torque capabilities
were based on the limiting component (motor, o)erator, or valve). The
licensee's spreadsheet calculation indicated t1at all of the valves had
capability margins at least 20 percent above the vendor torque
requirements and, in most cases, the margins exceeded 50 percent. This
provided margin for any discrepancy between actual torque requirements
and vendor requirements.
The licensee had dynamically tested the number of valves from each group
recommended by GL 8910, Supplement 6: but had not measured the
operating torques. Lacking quantitative torque measurements, it was not
possible to demonstrate whether the vendor torque requirements were
reliable. In most cases the licensee's dynamic tests had been performed
at or above design basis differential pressure, which provided increased
confidence in the capabilities of the valves to perform their design- i
basis functions. However, uncertainties remained becau.se the potential l
adverse effects of reduced voltage and increased temperature during j
design basis operation were not addressed. Subsequent to the j
inspection, in a January 20, 1997 letter to the NRC, the licensee i
submitted commitments to resolve these uncertainties. The licensee I
committed to perform instrumented dynamic testing and/or to apply the '
Electric Power Research Institute (EPRI) Performance Prediction Model to
validate their design basis calculation methodology for determining i
butterfly valve torque requirements. The commitments proposed were l
considered adequate to resolve this issue (see Section E1.1.c). l
4. Periodic Verification
The licensee incorporated MOV periodic verification requirements into
the preventive maintenance (PM) tasks specified in their database. The
inspectors found that the database specified lubrication, diagnostic !
testing, and actuator inspection intervals and identified when the tasks
'
were last performed. This implementation of periodic verification was
considered adequate for closure of GL 89-10. The NRC may re-assess the
licensee's long term periodic verification program as part of its review
of GL 96 05, " Periodic Verification of Design Basis Capability of '
Safety Related Motor-0perated Valves", dated September 18, 1996. j
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- 5. Post Hodification Testina !
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i Licensee personnel stated that post modification test requirements were '
determined by engineers using post maintenance testing requirements as :
guidance. The licensee's implementation of post maintenance testing for !
4 GL 8910 had been previously reviewed by the NRC and determined r
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acceptable during Inspection Report 50-338, 339/94 04. l
1
To assess the adequacy of the post modification testing implemented by
the licensee, the inspectors selected and reviewed the testing recorded
for five modifications. These modifications were either completed
i during the past two years or were still in process. The modifications >
, were identified as follows: Nos. 273758 01 (valve replacement), 287719- l
4
01 (change to limit seating), 317913-01 (motor pinion gear replacement), !
317856 04 (actuator modification), and 287720-01 (change to limit !
- seating). The inspectors found that the testing specified was !
appropriate and concluded that the licensee had implemented acceptable l
post modification testing. l
6. Pressure Lockina and Thermal Bindina
f
l The inspectors reviewed the evaluation of gate valves susce tible to !
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pressure locking and/or thermal binding which the licensee ad completed '
i in response to GL 95 07 Pressure Locking and Thermal Binding of Safety-
Related Power-0 prated Gate Valves. In letters to the NRC dated
February 7 and July 3,1996, the licensee identified valves that were
4
susceptible to pressure locking and/or thermal binding and corrective
,
actions.
!
- The licensee's GL 95 07 submittals stated that an analytical method was
utilized to demonstrate that the actuators on valves RC MOV X535, RC-
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thrust to overcome pressure locking. Pressure locking thrust ;
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requirements for these valves were determined using either a method '
. developed by Virginia Power or one from Westinghouse Owners
- Group (WOG)/ Commonwealth Edison. The inspectors independently calculated ,
i the thrust required to overcome pressure locking and the actuator ;
- capability for these valves and concluded that the actuators were able !
to develop the thrust required to overcome pressure locking. The
1
inspectors used the WOG/ Commonwealth Edison methodology with the
appropriate GL 89 10 3arameters for calculating the thrust required to
- . overcome pressure loccing.
,
The licensee's GL 95-07 submittals stated that valves SI MOV X867A B,
C, and D: 1 RS MOV 100B: and 2 RS MOV-200A and B were not susceptible to
pressure locking. The licensee indicated that the valves might
initially pressure lock in attempting to open, such that the motors
, would'be incapable of unseating the valves and would undergo locked
, rotor conditions. However, they considered that the respective safety
injection or recirculation spray pump would start and the discharge
! 3ressure applied to the upstream side of each valve would equalize
i >onnet pressure allowing the valves to open prior to reaching their
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thermal overload settings. The inspectors considered that even
temporary actuator operation at a locked rotor condition was not an
acceptable solution. The inspectors independently calculated the thrust
required to overcome pressure locking and the actuator capability for
these valves and concluded that the actuators were able to develo) the
thrust recuired to overcome pressure locking without reaching loc (ed '
rotor concitions. The inspectors used the WOG/ Commonwealth Edison
methodology with the appropriate GL 8910 parameters for calculating the
thrust required to overcome pressure locking.
The licensee's GL 95 07 submittals stated that valves SI-MOV X860A and B
were not susceptible to pressure locking, as the valve bonnets were
vented. The inspectors verified the installation of vent lines on the
Unit 2 valves through a review of Design Change Package (DCP) 96106
which implemented the bonnet vent modification on September 21, 1996.
The licensee's GL 95 07 submittals stated that the PORV block valves,
RC MOV X535 and RC-h0V X536, were susceptible to thermal binding. The
licensee evaluated thermal binding caused by stem growth and determined
that their valves had sufficient capability to overcome this binding.
However, the licensee did not evaluate thermal binding caused by
mechanical interference due to different expansion and contraction
characteristics of the valve body and disk materials. The inspectors
informed the licensee that thermal binding caused by mechanical
interference between valve body and disk should be evaluated and
corrective actions implemented if required in order for the NRC staff to 1
determine if the licensee met the intent of GL 95 07. )
The licensee's GL 95-07 submittals stated that quench spray pump l
discharge valves QS MOV-X01A and B, were not susceptible to pressure
'
locking. The licensee indicated that the valves might initially
pressure lock in attempting to open, such that the motors would be
incapable of unseating the valves and would undergo locked rotor
conditions. However, they considered that the quench spray pumps would
start and that the discharge pressure applied to the upstream side of
each valve would equalize bonnet pressure allowing the valves to open
prior to reaching the thermal overload setting. The inspectors
considered that actuator o>eration at a locked rotor condition was not
an acceptable solution. T1e inspectors informed the licensee that these l
valves should be reevaluated for pressure locking and corrective actions
implemented if required in order for the NRC staff to determine if the
licensee met the intent of GL 95 07.
The licensee's GL 95 07 submittals stated that RHR system isolation i
valves, RH H0V-X700/X701 and RH-MOV X720A and B, were determined to be !
potentially susceptible to pressure locking. Since North Anna Power
Station is licensed to achieve hot shutdown, the licensee concluded that
l these valves were outside the scope of GL 95-07. Therefore, the
! licensee did not evaluate these valves for pressure locking. The NRC ,
l staff is continuing its evaluation of this issue. !
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The adequacy of the licensee's actions to address pressure locking and l
thermal binding remain under NRC evaluation. During the current
inspection, the inspectors raised issues regarding the susceptibility of
the licensee's quench spray valves to pressure locking, possible thermal
binding of the PORV block valves, and whether RHR system isolation
valves should be evaluated for pressure locking. In the future, the NRC l
staff will address these issues in their safety evaluation of the i
licensee's response to GL 95 07. Followup of adequacy of GL 95 07 l
actions was identified as an IFI (50 338, 339/97001-03)
7. Trendina i
The licensee's trending requirements were specified by VPAP 0805, Motor- ,
operated Valve Program, Revision 6, and consisted of a periodic review l
and issuance of MOV program reports indicating the status of l
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programmatic improvement measures, types of problems found, trend ;
information, failure rates, etc.
The inspectors obtained and reviewed the last two MOV program reports, l
which were dated May 5 and December 31, 1996, and covered nine month i
periods. Additionally, the inspectors performed a review of l
approximately 60 licensee DRs documenting MOV problems and reviewed
trendable MOV data maintained in a licensee V0TES database. The
inspectors found that the licensee was tracking failure trends and
maintaining data for use in identifying trends in M0V degradation. The
inspectors considered this adequate for GL 8910 closure. ,
The inspectors had one negative comment. The amount of attention which i
the program reports devoted to causes of MOV failures and to discussing
some significant MOV problems was considered too limited. For example,
l
regarding MOV problems, the inspectors noted that the reports provided !
little discussion of improper gear combinations that had been documented !
in a number of DRs. The cause was not mentioned. This problem had
resulted in many evaluations and corrective maintenance actions.
8. NRC Information Notice 92 18. Potential For Loss Of Remote
Shutdown Caoability Durina A Control Room Fire
Information Notice (IN) 9218 alerted licensees of the potential for I
loss of safe shutdown capability during a fire in the control room. The
IN reported that hot shorts occurring during the fire could potentially
cause the MOVs needed for safe shutdown to go to a stall condition.
This stall could result in valve and/or actuator damage that would
preclude use of the MOVs for shutdown.
The inspectors reviewed the licensee's evaluation of IN 9218, which
concluded that thermal overload devices provided adequate MOV protection
if a hot short occurred. The licensee provided the inspectors with an
NRC Safety Evaluation issued to North Anna which stated that the
licensee had proposed satisfactorily electrical isolation to assure that
hot shorts would not preclude safe shutdown (letter to the licensee
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dated November 18, 1982). The inspectors determined that further
internal NRC review of this issue was required to determine if further
inspection or review were warranted.
9. Strenaths
The inspectors observed a number of strengths in the licensee's
implementation of GL 8910. Particular examples included:
. Technically capable and dedicated personnel,
e Effective efforts to organize and develop data to resolve the
final concerns developed during the NRC review.
]
- Good diagnostic test assessments.
c. Conclusions
The inspectors determined that the licensee had generally met the intent
of GL 8910 in verifying the design basis capabilities of their MOVs.
However, the licensee had not adequately established the reliability of
their vendor based methods for determining butterfly valve torque
requirements and this was considered a weakness. In a letter to the NRC i
dated January 20, 1997, the licensee committed to resolve this issue !
through further validation of their methods for determining butterfly ,
valve torque requirements. They proposed to accomplish this by ;
performing instrumented differential pressure testing on one 18 inch I
Contramatics and one 24-inch Contramatics valve and by either performing
instrumented differential pressure testing or applying the EPRI l
Performance Prediction Model to four representative Allis Chalmers
valves. The letter stated that the Contramatics valve testing would be !
completed during the 1997 Unit I refueling outage and that any
application of the EPRI model would be completed by the end of 1997, i
Testing of the Allis Chalmers valves, if performed in place of applying
the EPRI model, would be completed during the Spring 1998 Unit 2
refueling outage. The letter also indicated that the NRC staff would be
notified of the results and status by the end of 1997. Based on the
results of this inspection and the above commitments, the NRC concluded
that their review of the licensee's implementation of GL 8910 could be
closed. NRC verification of the licensee's completion of the above
commitments was identified as an IFI (50 338, 339/9700104).
The inspectors noted several licensee strengths, which are described in
Section E1.1.b.9.
One related NCV was identified, involving failure to follow a procedure
step relating to the uncertainty in valve opening thrust measurements.
This NCV is described in Section E1.1.b.2.
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E2 Engineering Support of Facilities and Equipment {
E2.1 Surveillance Test Enaineerina Evaluation Review
3
a. Insoection Scope (37551)
During the weeks of February 3 and 10, the inspectors reviewed )
Engineering Transmittal (ET) TI 97-001, Evaluation of High Differential l
Pressure on 2 RS P-2B, dated February 1. 1997, and discussed its '
conclusions with test engineers. The ET was written to evaluate the
results of an outside recirculation spray pump, 2 RS P 2B, surveillance
test in which the pump differential pressure was found to be above the
required action range. The ET concluded that the aum) could be ;
considered operable, and the inspectors reviewed tie ET to verify that l
the pump's return to operable status was supported by engineering ;
analysis and that applicable code requirements for Inservice Testing I
(IST) were met,
b. Observations and Findinas
The ET stated that the pump's history had been reviewed, and no adverse l
behavior was found. Additionally, the evaluation noted that all other I
test parameters were satisfied within acceptable ranges. The ET stated
that the pump was operating satisfactory based on the wide oscillations
observed in the pump discharge pressure gage, difficulties obtaining
consistent indication, and the narrow amount by which the value exceeded i
the limit (2.5 psid greater than the 192.3 psid limit). The ET ;
recommended that instrument snubbers be installed after which new i
baseline values would be established, as well as, decreasing the test
frequency from 18 months to 9 months. ;
The inspectors obtained and reviewed pump performance data from past l
tests for 2 RS P 28 and other outside recirculation spray pumps. The
inspectors found that the values for past tests were consistently high
for 2-RS P-2B and that this was the first time that the pump's
differential pressure had entered the required action range. These
findings supported the ET's conclusion that comparing current test data
and past history did not indicate an adverse trend. While reviewing
past data, the ins)ectors also verified that past tests had been
performed within t1e required surveillance test intervals.
The inspectors then met with test engineers and reviewed how the i
licensee's actions complied with IST code requirements. The inspectors j
reviewed the a)plicable code sections which required that the pump i
remain inoperaale until the cause was determined and corrected. The
correction was normally required to be replacement or repair. An
allowed alternative action was to complete an analysis to demonstrate
that the condition did not impair operability followed by establishing a
new set of reference values. The inspectors questioned how the ET met
these requirements and were provided additional information from the
engineers. This information was not clearly stated in the ET but had
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l (SNSOC) meeting held prior to returning the pump to operable status.
The engineers informed the inspectors that in addition to the facts !'
discussed in the ET, the SNSOC had also discussed difficulties
experienced by operators performir,g the test. Tests in the past had
been )erformed under the Engineering Department's cognizance, and this
was t1e first time the test was performed entirely by Operations ;
l 3ersonnel. . As a result, the engineers believed that operators may not
lave been sensitive to the effects that pump heatup could have on the
test. The pump's recirculation test flow path was extremely small in
volume and quickly heated up during the test. This was believed to :
cause a wide variance in data if it was not collected at consistent !
times following pum) start. This fact had been known to engineers
during past tests, )ut the test procedure did not provide o>erators with !
guidance to ensure consistency in times to collect data. T1e engineers
stated that the intent was to install the instrument snubbers and ,
establish a new set of baseline data during the next test. '
Additionally, the test 3rocedure would be revised to ensure that pump
performance data was ta(en promptly at the end of the five minu+e
waiting period required by the code. Based on the additional l
information, the inspectors found that the licensee's evaluations I
supported returning the pump to operable status. I
c. Conclusions
i
The inspectors concluded that following a surveillance test failure, the l
licensee adequately evaluated out of-specification data prior to '
returning the pump to operable status. However, the ET did not clearly
document all factors considered in this evaluation.
E7 Quality Assurance in Engineering Activities
E7.1 Review of UFSAR Commitments
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A recent discovery of licensee operating their facility in a manner l
contrary to the UFSAR description highlighted the need for a special ,
focused review that compared plant practices, procedures and/or
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parameters to the UFSAR description. While performing the inspections :
discussed in this re) ort, the inspectors reviewed the applicable i
portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the
observed plant practices, procedures and/or parameters.
1
The inspectors noted that as a result of increased licensee awareness !
and initiatives', numerous DRs were submitted concerning UFSAR
. discreaancies during this inspection period (DRs N 97 334 through -338,
l 348 t1 rough -353, -452, and -482). The inspectors reviewed the DRs and
l verified that there were no significant safety concerns or unreviewed
l safety questions.
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E8 Miscellaneous Engineering Issues (37551, 92700, 92903) i
E8.1 LGlosed) IFI 50 338. 339/95008-03, MOV stem rejection thrust and MOV )
program changes. This item addressed followup of MOV related issues and '
was divided into two parts. Part 1 was for followup on a finding that !
licensee GL 89-10 calculations determined valve stem rejection thrusts l
from differential pressure rather than upstream pressure. It appeared
that this could be non-conservative in some instances. Part 2 was for
followup on licensee actions to ensure satisfactory lubrication of valve
stems. Lubrication problems had been identified during torque testing
and the licensee planned to develop " lessons learned" and implement i
appropriate changes to their MOV lubrication program practices. The
inspectors followup for each part was as follows: 1
Part 1: The licensee had evaluated their use of differential pressure in
place of upstream pressure. The inspectors reviewed the results of the
evaluation and the actions taken, which were documented in Engineering
Transmittal CHE 96-0079. The ins)ectors found that the evaluation
demonstrated that the impact of tie error was generally small. The
error did not result in the operability of any valve being questioned.
Part 2: Licensee actions to address the lubrication program changes were
specified in DR N 95 759 and resulted in Commitment Tracking System
(CTS) items 02 95 2172 07 through 010. These CTS items specified
development and implementation of a lubrication program that i
incorporated the " lessons learned" from investigation of valve stem i
lubrication problems. The items also provided for monitoring the )
effectiveness of the program. The inspectors verified the procedure (0- i
MPM 0400 05, Revision 2) and planning database entries that the licensee
developed to implement the new lubrication program. Additionally, the l
inspectors confirmed that the licensee had evaluated the effectiveness
of the program one refueling outage after revising stem lubrication
aractices. The study containing this evaluation was documented in
Engineering Transmittal SE 96 059 and concluded there was no significant
change in lubricant performance over the 18 month period between stem
re-lubrications.
E8.2 (Closed) Licensee Event Report (LER) 50 338. 339/96006, charging pump
interlock logic renders pumas ino>erable due to a design error. The
licensee reported that if t1e C clarging pump was operating on a train
with that train's charging pump not available for service, then a loss
of DC power (caposite the train powering the C charging pump) would
result in no c1arging pumps operating. The interlock logic would trip
the running C charging pump and the loss of DC control power on the
other train would prevent that train's charging pum) from automatically
starting. Thus, a single failure could cause the c1arging pumps not to
be able to automatically perform their safety function during certain
accidents. The ability to manually close the charging pump (the one
that loses DC control power) breaker remained available. This was
reported as a condition that alone could have prevented the fulfillment
of the safety function of a system needed to mitigate the consequences
of an accident.
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In the LER. the licensee indicated that a modification was installed to
correct this condition. The inspectors reviewed the pre modification
elementary electrical drawings and confirmed that the interlock logic
would respond as reported in the LER. The inspectors noted that this
L condition existed only on one train since original licensing. In 1996,
wiring modifications were made in accordance with DCP 95 226, Charging
Pump Interlock Modification /NAS/ Unit 1, and DCP 95 227, Charging Pum)
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Interlock Modification /NAS/ Unit 2, to replicate the design on the otler
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train. The inspectors also confirmed that DCP 96 231, Charging Pump
- Interlock Modification /NAS/ Units 1&2, corrected this condition on both
- units.
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After reviewing UFSAR Section 3.1, Conformance with AEC General Design
Criteria: 10 CFR 50.46, Acceptance Criteria for Emergency Core Cooling
.
Systems for Light Water Nuclear Power Reactors: Appendix K to Part 50, i
.
Emergency Core Cooling System Evaluation Models; and associated design i
criteria in Appendix A to Part 50, General Design Criteria For Nuclear
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Power Plants, the inspectors asked the licensee to clarify their design l
bases for the charging pumps and supoorting DC power system. On i
February 12, the licensee informed t1e inspectors that failure of a DC
power system train was not an active failure, i.e., the DC system can
experience only passive failure modes. Therefore per UFSAR Chapter 3, a l
loss of DC power does not have to be considered during the first 24 ;
s hours of an accident. In addition, the licensee indicated that the !
l interlock logic design reported in the LER was most likely acceptable u
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and that they were evaluating withdrawing the LER. At the end of the ,
- report period, the inspectors were reviewing the licensee's position l
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that the DC power system had no active failure modes. In addition, the '
ins)ectors were reviewing the licensee's licensing bases for compliance
wit 1 regulatory requirements contained in 10 CFR 50.46 and associated
criteria. Pending completion of these reviews, this item is identified ;
, as an URI (50 338, 339/97001 05).
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IV. Plant Support
Radiological Protection and Chemistry (RP&C) Controls
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R1.1 Radiation Area Locks and Postinas .
a. Inspection Scope (71750)
- During the period from January 23 27, the inspectors reviewed the
posting of radiation areas and the labeling of radioactive material
containers to verify that 10 CFR 20 requirements were met by the
licensee. The inspectors performed direct radiation measurements to
verify the accuracy of the licensee's radiation surveys and postings.
Additionally, the inspectors verified the proper locking of doors to
high radiation areas required to be locked by 10 CFR 20 and TS 6.12.1.
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b. Observations and Findinas
The inspectors checked approximately 30 doors leading into the
Radiologically Controlled Area (RCA) and found that all were properly ,
posted as required by 10 CFR 20.1902. Areas designated as high !
a radiation areas and locked high radiation areas in the Auxiliary i
i Building were checked and found to be posted and locked where required. !
- Numerous containers of radioactive material in the Auxiliary Building
'
and outside areas were checked and found to be marked in accordance with
<
! The inspectors obtained a radiation survey instrument and measured
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radiation levels at various locations in the Auxiliary Building. The i
! inspectors checked that radiation areas did not contain radiation levels I
which would require high radiation area postings. Additionally, the !
inspectors verified the accuracy of selected radiation survey results ,
!
listed on copies of survey maps located at high radiation area entry )
j points. The inspectors also checked that informational signs denoting )
general radiation levels at various points in the Auxiliary Building i
accurately reflected area radiation levels. The inspectors found that i
in all cases, actual radiation levels measured were at or lower than the j
levels posted for the areas. i
c. Conclusions
Radiation areas and high radiation areas were properly posted and were
locked when required by 10 CFR 20. Independent radiation measurements
found that the licensee's postings and survey results were conservative.
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- VI. Manaoement Meetinas
X1 Exit Meeting Sunnary
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The inspectors ) resented the inspection results to members of licensee i
management at tie conclusion of the inspection on March 10, 1997. The !
- licensee disagreed that they were in violation of 10 CFR 70.24 (See Section i
- 02.2). This was based on
- 1) correspondence, dated May 11, 1988, that the
.
NRC had sent to the Tennessee Valley Authority indicating that an exemption
request was not necessary, and 2) that an implicit exemption to the
requirements existed when TS Table 3.3 6, Radiation Monitoring
, Instrumentation, was approved. Item 1 of this table required only one
l criticality monitor for the fuel storage pool area. The licensee acknowledged
i the other findings presented.
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- The inspectors asked the licensee whether any materials examined during the
! inspection should be considered proprietary. No proprietary information was
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identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
W. Anthes, Superintendent, Outage Planning ;
B. Foster, Superintendent Station Engineering ;
E. Grecheck, Assistant Station Manager, Operations and Maintenance i
J. Hayes, Superintendent, Operations
D. Heacock, Assistant Station Manager, Nuclear Safety and Licensing )
M. Kansler, Vice President Nuclear Operations i
P. Kemp, Supervisor, Licensing ;
T. Maddy, Superintendent, Security 1
W. Matthews, Station Manager
H. McCarthy, Director Nuclear Oversight
D. Roberts Supervisor, Station Nuclear Safety
H. Royal, Superintendent, Nuclear Training
D. Schappell, Superintendent, Site Services
R. Shears, Superintendent, Maintenance
A. Stafford, Superintendent, Radiological Protection
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering )
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IP 40500: Effectiveness of Licensee Controls in Identifying, ,
Resolving, and Preventing Problems !
IP 61726: Surveillance Observations
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IP 62707: Maintenance Observations
IP 71707: Plant Operations ,
IP 71750: Plant Support Activities
IP 92700: Onsite Followu) of Written Reports of Nonroutine Events at
Power Reactor racilities .
IP 92903: Followup - Engineering
TI 2515/109: Inspection Requirements For Generic Letter 89 10, Safety
Related Motor 0perated Valve Testing and Surveillance
ITEMS OPENED AND CLOSED
Opened
50-338, 339/97001-01 VIO Failure to Install a Radiation Monitoring
System, Establish Procedures, and Conduct
Training as Required by 10 CFR 70.24
(Section 02.2).
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50 338. 339/97001 02 NCV Failure to Follow Procedure Step in ;
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Evaluating MOV Diagnostic Test (Section
E1.1.b.2). I
50 338, 339/97001 03 IFI Resolution of GL 95 07 Issues (Section !
E1.1.b.6).
!
50 338, 339/97001 04 IFI Validation of Methods for Determining .
Butterfly Valve Torque Requirements :
(Section E1.1.c). (
50 338, 339/97001 05 URI Review DC Power System Failure Modes and !
Compliance With 50.46 (Section E8.2). !
Closed
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50-338, 339/95008 03 IFI MOV Stem Rejection Thrust and MOV Program
Changes (Section E8.1).
50 338, 339/96006 LER Charging Punp Interlock Logic Renders
Pumps Inowrable Due to Design Error
(Section E8.2).
50 338, 338/97001 02 NCV Failure to Follow Procedure Step in
Evaluating MOV Diagnostic Test (Section
E1.1.b.2).
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