ML18152A080
| ML18152A080 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 12/15/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A081 | List: |
| References | |
| 50-280-97-10, 50-281-97-10, NUDOCS 9712300182 | |
| Download: ML18152A080 (33) | |
See also: IR 05000280/1997010
Text
Docket Nos:
License Nos:
Report Nos:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9712300182 971215.
ADOCK 05000280
G
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280. 50-281
50-280/97-10. 50-281/97-10
Virginia Electric and Power Company (VEPCO)
Surry Power Station. Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
.October 5 - November-15. 1997
R. Musser. Senior Resident Inspector
K. Poertner. Resident Inspector
P. Byron. Resident Inspector
_
J. Blake. Reactor Inspector (Sections Ml.1.
Ml.2. and Ml.3)
P. Hopkins. Project Engineer (Sections 01.7.
Ml.5 and Ml.6)
D. Jones. Reactor Inspector (Sections Rl.1 and R8.1)
W. Stansberry, Security Inspector (Sections
Sl.2. S2.1. S2.2. S2.3. S3.1. and S3.2)
R. Haag, Chief. Reactor Projects Branch 5
Division of Reactor Projects
ENCLOSURE 2
.
EXECUTIVE SUMMARY
Surry Power Station. Units 1 & 2
NRC Inspection Report Nos. 50-280/97-10 and 50-281/97-10
This integrated inspection included aspects of licensee operations. engineer-
ing. maintenance. and plant support.
The report covers a six-week period of
resident inspection; in addition. it includes the results of announced inspec-
tions by four regional inspectors.
Operations
Operators performed their assigned duties in an excellent manner during
the Unit 2 shutdown for a scheduled refueling outage.
The Senior
Reactor Operator maintained excellent command and control during the
evolution (Section 01.2).
The licensee's actions to identify an intake canal level probe common
mode failure scenario demonstrated a good safety perspective and were
conducted in a conservative and professional manner.
An Inspection
Followup Item was identified to review the licensee's root cause
evaluation and proposed corrective actions to prevent recurrence
(Section 01.3).
Increased Unit 1 reactor coolant activity indicated that a* fuel cladding
defect had occurred.
The licensee was monitoring and trending coolant
activity on a routine basis.
The activity was well below Technical
Specification allowable values (Section 01.4).
Licensee actions to identify and report the Anticipated Transient
Without A Scram Mitigating System Actuation Circuitry enable setpoint
problem exhibited a good questioning attitude and conservative approach
to operations.
An Inspection Followup Item was identified to review
licensee actions to resolve the issue (Section 01.5).
A Non-cited Violation was identified concerning the failure to perform a
Technical Specification required surveillance on the diesel driven fire
pump within the required frequency (Section 01.6).
Control room charts were observed to be operating correctly and control
room logs were routinely reviewed by operations personnel.
Plant
startup evolutions were conducted in accordance with approved procedures
(Section 01'.7).
No problems were identified during a review of Unit 2 containment
integrity during fuel movement (Section 01.8).
The licensee's preparation of the Unit 2 containment prior to restart
from the refueling outage was adequate.
Minor deficiencies were
identified and corrected prior to containment closeout (Section 01.9) .
Observations by the inspectors during the defueling of the Unit 2
reactor indicated a well controlled process being carried out in
accordance with Technical Specifications (Section 01.10).
2
Maintenance
The licensee's inservice inspection results were well documented. and
the bases for conclusions were conservative (Section Ml.l).
The decision to repair a leaking spare reactor head penetration seal
weld using a mechanical fixture was fully supported-by engineering
analysis (Section Ml.l).
Radiographs of replacement piping welds were in .accordance with required
codes and standards (Section Ml.1).
Consistent evaluations of eddy current inspection results and
conservative tube plugging decisions were strengths in the licensee's
steam generator inspection program (Section Ml.2).
The licensee's flow accelerated corrosion monitoring program continued
to be a well-engineered and conservative program (Section Ml.3).
Surveillance activities associated with s~fety injection accumulator
check valve testing and Number 3 EOG testing were conducted in
accordance with approved procedures and met acceptance criteria
(Section Ml.4).
Maintenance activities on protective relays and the condenser water box
were performed satisfactorily.
Work procedures were adequate and were
being followed (Section Ml.5).
Thirteen observed surveillance tests were performed satisfactorily
(Section Ml.6).
An unresolved item was opened to track resolution of an interpretation
of Technical Specification surveillance frequency requirements
(Section Ml.7).
A violation was identified for inadequate work instructions resulting in
the failure to implement the prerequisite requirements of a safety
evaluation during the replacement of a Consequence Limiting Safeguards
relay (Section Ml.8).
The licensee rebuilt the pressurizer Power Operated Relief Valves during
the Unit 2 Refueling Outage.
Following return of the unit to service.
no indication of seat leakage was observed (Section Ml.9).
The licensee successfully replaced the "C" Reactor Coolant Pump flange
seal.
Installation of pump flange seal bolt number 16 as a "no load"
bolt was determined to be a viable option (Section Ml.10).
Testing on the Unit 2 pressurizer power operated relief valves was
conducted in a cautious and controlled manner and as specified by the
procedure.
The Senior Reactor Operator supervising the test
3
demonstrated superior command and*controi over the evolution
(Section Ml.11).
Engineering
Letdown line modifications were performed during the Unit 2 refueling
outage to correct previous problems with weld leakage (Section El.1).
The inspectors verified that the Unit 2 vital bus Appendix R
modifications had been implemented during the refueling outage
(Section El.2).
Plant Support
During the Unit 2 Refueling Outage, the licensee was properly monitoring
and controlling personnel radiation exposure and posting area
radiological conditions in accordance with 10 CFR Part 20
(Section Rl.l).
Personnel entering the Radiological Controlled Area (RCA) were
adequately briefed on radiological hazards and protective measures
(Section Rl.1).
Housekeeping in the RCA was very good during the Unit 2 Refueling Outage
C Section Rl. 1) .
A significant amount of activity was removed from the Reactor Coolant
System by shutdown chemistry controls in order to reduce exposure to
workers during the Unit 2 Refueling Outage (Section Rl.1).
Health physics practices were observed to be proper (Section Rl.2).
Security and material condition of the protected area perimeter barrier
were acceptable (Section Sl.1).
Compensatory measures were used for vital area access breaches
(Section Sl. 2).
The evaluation of the licensee's program for protected area access
controls for packages. personnel and vehicles revealed that the criteria
of the Physical Security Plan were being followed (Section S2.1).
Criteria in Chapters 1. 4. and 6 of the Physical Security Plan and
Security Plan Implementing Procedures were complied with for alarm
stations and communications (Section S2.2).
Intrusion detection systems and assessment aids were functional. well
maintained. effective for both covert and overt penetration attempts.
and met licensee commitments (Section S2.3) .
4
The review and verification of commitments of selected security and
administrative procedures did not identify any inconsistencies or
ndncompliance (Section S3.1).
The review of three quarterly Security Event Logs verified that the
licensee was appropriately analyzing. tracking, resolving. and
documenting safeguard~ events (Section S3.2).
Report Details
Summary*of Plant Status
Unfr 1 operated at power the entire reporting period.
Unit 2 shutdown for a scheduled refueling outage which began on October 6.
The unit was returned to service on October 31 after the completion of a 25
day refueling outage.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707 40500).
1. 2
a.
The inspectors conducted frequent control room tours to verify proper
staffing. operator attentiveness. and adherence to approved procedures.
The inspectors attended dai.ly plant status meetings to maintain
awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with Technical Specifications
(TSs).
Instrumentation and safety system lineups were periodically
reviewed from control room indications to assess operability. Frequent
plant tours were conducted to observe equipment status and housekeeping .
Deviation Reports CDRs) were reviewed to assure that potential safety
concerns were properly reported and resolved.
The inspectors found that
daily operations were generally conducted in accordance with regulatory
requirements and plant procedures.
Unit 2 Shutdown for Refueling Outage (RFD)
Inspection Scope (71707)
On October 5. the inspectors observed the licensee remove Unit 2 from
service and shutdown the reactor in preparation for RFO 14.
b.
Observations and Findings
On October 5. the licensee commenced shutting down the Unit 2 reactor in
preparation for RFO 14.
The inspectors noted that the Senior Reactor
Operator (SRO) maintained excellent command and control. Briefings were
thorough and detailed.
The SRO gave frequent briefings before each
significant evolution.
The operators did an excellent job maintaining
steam generator level and feedwater flow.
Procedures were at the
stations and were utilized: The generator output circuit breaker was
opened at 12:37 a.m. on October 6 and the reactor was tripped 20 minutes
later. All systems functioned as designed .
C.
2
Conclusions
Operators performed their assigned duties in an excellent manner during
the Unit 2 shutdown for a scheduled refueling outage.
The SRO
maintained excellent command and control during the evolution.
01.3 Inoperable Intake Canal Level Probes
a.
Inspection Scope (71707)
b.
C.
The inspectors reviewed licensee activities associated with inoperable
intake canal level probes due to marine growth.
Observations and Findings
On October 14. with Unit 2 shutdown for a scheduled refueling outage,
intake canal level probe 2-CW-LE-202 was removed from service to perform
response time testing. The as-found response time did not meet the
required minimum response time.
The level probe was cleaned. retested.
and returned to service.
Canal level probe 2-CW-LE-203 was then removed
from service for testing. The as-found response time for level probe
2-CW-LE-203 also did not meet the a~ceptance criteria. The probe was
cleaned. retested. and returned to service.
Based on the conclusion
that both Unit 2 canal level probes had been inoperable due to a common
mode failure mechanism (marine growth) the licensee declared both Unit 1
canal level probes inoperable and entered a six-hour action statement at
5:26 p.m. to place Unit 1 in hot shutdown in accordance with TS 3.0.1.
The Unit 1 level probes were tested. cleaned. and returned to service.
The as-found values for the Unit 1 canal level probes did not meet the
response time acceptance criteria. The six-hour action statement was
exited at 8:10 p.m. following the return to service of the Unit 1 level
probes.
The inspectors monitored testing activities in progress. reviewed the
applicable TS and verified that the NRC was notified as required by
The licensee initiated a Category 1 root cause evaluation
to determine the cause of the event and corrective actions to prevent
recurrence.
The root cause evaluation was still in progress at the end
of the inspection period.
Review of the licensee's root cause
evaluation and proposed corrective actions is identified as Inspection
Followup Item (IFI) 50-280. 281/97010-01.
Conclusions
The licensee's actions to identify an intake canal level probe common
mode failure scenario demonstrated a good safety perspective and were
conducted in a conservative and professional manner.
An IFI was
identified to review the licensee's root cause evaluation and proposed
corrective actions to prevent recurrence .
3
01.4 Unit 1 Failed Fuel
a.
Inspection Scope (71707)
The inspectors reviewed licensee actions with respect to increased
Unit 1 coolant activity.
b.
Observations and Findings
On October 7. an increase in Unit 1 containment gaseous activity was
observed. Subsequent sampling of the Reactor Coolant System (RCS)
identified that the xenon and Iodine 131 concentrations had increased
from previous samples.
On October 15, power was reduced to perform
maintenance activities. Subsequent to the power reduction an iodine
spike was observed.
When the unit was returned to 100 percent power.
iodine levels subsequently returneo to the previous steady state values.
The increased activity and subsequent iodine spike following a power
reduction indicated that a fuel cladding defect had occurred.
Discussions with reactor engineering determined that the fuel failure
was most likely located in a low power positfon on or near the periphery
of the core and was limited to one fuel pin.
The inspectors routinely
reviewed reactor coolant sample results and activity levels were well
within TS allowable values.
The licensee plans to monitor and trend RCS
activity on a normal frequency unless a significant increase in RCS
activity occurs.
c.
Conclusions
Increased Unit 1 RCS activity indicate that a fuel cladding defect had
occurred.
The licensee was monitoring and trending RCS activity on a
routine basis.
RCS activity was well below TS allowable values.
01.5 Anticipated Transient Without A Scram Mitigating.System Actuation
Circuitry (AMSAC)
a.
Irispecti on Scope (71707)
The inspectors reviewed a one hour non-emergency event report associated
with arming of the AMSAC circuitry.
b.
Observations and Findings
On November 12. the licensee made a one hour non-emergency report to the
NRC concerning the interlock setpoint for AMSAC.
The circuitry
automatically enables at 37 percent power as indicated by turbine first
stage impulse pressure.
The design basis of the system assumes that the
system is enabled at 40 percent reactor thermal power.
On November 2.
during the Unit 2 power ascension following a refueling outage the
AMSAC ci r,cui try enabled at 37 percent turbine first stage pressure but
reactor thermal power indicated greater than 40 percent (41~42 percent).
A DR was initiated to document the apparent discrepancy between the
actual thermal power level that the circuitry was enabled at and the
4
power referenced in the Updated Final Safety Analysis Report.
Subsequent review of the DR determined that the system was outside its
design basis.
Requirements for AMSAC are not contained in the TS.
The licensee
administratively controls AMSAC operability in accordance with Virginia
Power Administrative Procedure (VPAP) 2802. "Notifications and Reports."
Revision 7.
The VPAP requires that if AMSAC is inoperable for 30 days.
a special report shall be submitted to the NRC within the next 30 days.
The licensee is still reviewing the issue to determine corrective
actions to ensure that AMSAC enables within the design basis of the
system.
Further review of licensee actions to resolve the issue is
identified as IFI 50-280. 281/97010-02.
c.
Conclusions
Licensee actions to identify and report the AMSAC enable setpoint
problem exhibited a good questioning attitude and conservative approach
to operations.
An IFI was identified to review licensee actions to
resolve the issue.
01.6 Missed Surveillance Requirement
a.
Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding the failure to
perform a TS required .surveillance within the required time period.
b.
Observations and Findings
On October 28. the licensee determined that a TS required Periodic Test
(PT) on the diesel driven fire pump had not been performed within the TS
required frequency.
The pump was declared inoperable and the missed *
surveillance was performed satisfactorily that same day.
TS requires
that the PT be performed every 31 days.
With the TS allowed grace
period included. the surveillance frequency was exceeded by nine days.
The PT was scheduled to be performed within the required frequency by
the Operations Department. however. the PT was incorrectly initialed as
being completed by the operating shift on the PT work schedule due to a
personnel error. Subsequently, engineering notified operations that the
PT had not been received for final review and processing.* Review by
operations determined that the PT had not been performed and the TS
required frequency had been exceeded without declaring the diesel driven
pump inoperable.
The inspectors discussed this event with licensee personnel and reviewed
the corrective actions identified to prevent recurrence. Discussed
corrective actions for this matter included: satisfactorily completing *
the surveillance. initiating a DR (S-97-3132). counseling the involved
individual and adding an administrative enhancement to require
comparison of completed surveillance procedures with the surveillance
C.
5
work schedule. This non-repetitive. licensee identified and corrected
violation is being treated as a Non-cited Violation (NCV) consistent
with Section VII.B.1 of the NRC Enforcement Policy. This matter is
identified as NCV 50-280. 281/97010-03.
Conclusions
An NCV was i denti fi ed concer_ni ng the failure to perform a TS required
surveillance on the diesel fire pump within the required frequency.
01.7 Review of Shift Activities During Unit 2 Startup
a.
Inspection Scope (71707)
The inspectors reviewed shift logs and control room chart recorders and
observed shift activities during the Unit 2 startup from refueling.
b .. Observations and Findings
During October 27-31. the inspectors reviewed operation of the
control room chart recorders for both units to assure that pens were
marking properly and the recorders were timing correctly. The
inspectors verified that each chart had been checked by a licensed
operator each shift. Recorders not in use were cl early ma_rked as being
out-of-service.
The inspectors observed that shift logs were frequently reviewed by
control room operators. Additionally, operators maintained positive
control of the plant during pre-job briefings and during the performance
of periodic test procedures.
Preparations for reactor startup and plant operations while
transitioning from the refueling outage to power operations were
conducted safely with good control and communications.
Plant operators
demonstrated good knowledge and awareness of changing plant conditions.
The actions of the plant operators while taking the reactor critical
were conducted in accordance with approved procedures.
c.
Cone l us i ans
Control room charts were observed to be operating correctly and control
room logs were routinely reviewed by operators. Plant startup
evolutions were conducted in accordance with approved procedures.
01.8 Refueling Containment Integrity
a.
Inspection Scope (71707)
The inspectors reviewed containment integrity requirements during Unit 2
refueling activities.
6
b.
Observations and Findings
The inspectors verified that containment integrity was in place prior to
the off-load of fuel assemblies during the Unit 2 RFD.
The inspectors
reviewed applicable procedures and independently verified selected
portions of the containment isolation boundary.
c.
Conclusions
No problems were identified during a review of Unit 2 containment
integrity during fuel movement.
01.9 Unit 2 Containment Closeout Walkdown
a.
Inspection Scope (71707)
On October 27. the inspectors performed a containment closeout walkdown
to review containment conditions prior to unit restart.
b. * Observations and Findings
C.
The inspectors performed a walkdown of the Unit 2 containment prior to
the restart.
The station manager accompanied the inspectors on the
walkdown.
The walkdown encompassed all levels and rooms within the
containment.
Prior to the walkdown. the licensee stated that with the
exception of a few specific areas and items still staged for specific
tasks and tests. the containment was ready to support the return to
service of the unit.
In general. the overall condition of the
containment was adequate for the restart of the unit.
However. a number
of items were discovered during the containment inspection which
indicated that a more thorough walkdown should have been performed.
These items included the following:
Tywrap in the containment sump
Tape on the containment walls and on various pipes
A failed component cooling water pressure gauge on the "B" RCP
A refueling tool wrapped in a plastic sleeve
Numerous small hand tools. wire. nuts. bolts. and threaded 1/4"
stock
Upon exiting the containment. responsibl~ licensee personnel were
informed of the walkdown findings. A list of these deficiencies was
promptly drafted.
The items were corrected prior to the containment
closeout.
Conclusions
The licensee's preparation of the Unit 2 containment prior to restart
from the refueling outage was adequate.
Minor deficiencies were
identified and corrected prior to containment closeout.
7
01.10 Unit 2 Refueling Observations
a.
Inspection Scope (71707)
The inspectors observed the defueling of the Unit 2 Reactor.
b. Observations and Findings
Fuel handling evolutions were observed both in the containment and fuel
building. All observations indicated that the process was well
controlled and was adequately supervised. Technical Specification
requirements for refueling were being met. A monitor was posted at the
access to the refueling cavity to ensure all personnel entering the area
were trained in foreign material exclusion practices and were not taking
unnecessary items into the area.
The refueling evolution for the Unit 2
reactor was completed in accordance with specified requirements.
c.
Conclusions
Observations by the inspectors during the defueling of the Unit 2
reactor indicated a well controlled process being carried out in
accordance with Technical Specifications.
II.
MAINTENANCE
Ml
Conduct of Maintenance
Ml.1
Inservice Inspection (ISI)
a.
Inspection Scope (73753)
The inspectors reviewed ISI activities for the Unit 2 refueling outage.
The ISI review included fabrication and pre-service inspections for
piping welds made as the result of repairs. replacements. and
modifications.
b.
Observations and Findings
This was the first refueling outage in the second. 40-month period of
the third. 10-year. ISI interval. The third. 10-year interval started
May 10. 1994. and the ISI Code of record is ASME Section XI. 1989
Edition with no addenda.
The records for five VT3 component support inspections. eleven VTl
component inspections. sixteen piping component ultrasonic examinations.
twenty-eight piping component surface examinations. three reactor
coolant pump flywheel examinations. and seven reactor coolant isolation
valve stud examinations were reviewed by the inspectors. The licensee
was using computer software for the recording of ISI examination data
and examiner conclusions. and to generate required reports.
As a result
of using the computer. all reports were concise. complete. and legible.
8
During in situ ultrasonic examination (UT) of the 22.5-inch long, by
2.75-inch diameter studs in the "C" cold-leg, loop stop-valve, MOV2595,
several studs showed a reflector that appeared just beyond the back
reflection from the end of the stud. This reflector was of concern to
the UT examiners because it was similar to one of the reflectors
received from one of the notches in the calibration block.
The inspectors reviewed the _final disposition of the UT indications in
Stud No. 11, (the one with the largest signal) which was removed from
the valve and replaced.
The suspect Stud No. 11 was subjected to
visual, fluorescent liquid penetrant. and additional ultrasonic
examinations. The original ultrasonic signal was still present after
removal, but 1there were no indications found by the visual and surface
examinations.
Based on these additional examinations. the licensee
concluded that the signals were geometric or beam redirection signals.
and therefore the remaining studs were acceptable for continued service.
The inspectors agreed with the conclusions reached by the licensee.
The licensee's visual inspections of the reactor vessel head revealed
boron residue on the stalk of Spare Head Penetration Number 19.
The
residue emanated from the area of the welded seal canopy at the threaded
connection to the stalk. After reviewing available options for the
repair of the leaking seal canopy, the licensee elected to use a
mechanical fixture manufactured by ABB-Combustion Engineering (ABB-CE).
The inspectors monitored the licensee's decision process. and reviewed
the completed 10 CFR 50.59 analysis for this application of a mechanical
fixture to repair a reactor coolant pressure boundary leak.
By
definition. the welded seal canopy only provides a leak barrier for the
acme-threaded connection which is the reactor coolant boundary;
therefore. the inspectors agreed that the use of a mechanical fixture
would not require NRC approval.
The inspectors reviewed the radiographs associated with the replacement
of piping components in reactor coolant and secondary systems.
Particular attention was given to radiographs of welds involved with the
replacement of components in the reactor coolant letdown system and
steam generator feedwater piping inside containment.
The radiographs
reviewed were of acceptable quality.
The inspectors agreed with the
licensee's interpretation of weld quality.
c. * Conclusions
The licensee's inservice inspection results were well documented; and
the bases for conclusions were conservative. The decision to repair a
leaking spare reactor head penetration seal weld using a mechanical
fixture was fully supported by engineering analysis.
Radiographs of
replacement piping welds were in accordance with required codes and
standards .
9
Ml.2 Steam Generator Inspection
a.
Inspection Scope (50002) .
The inspectors reviewed procedures and documentation associated with the
eddy current examination of the Unit 2 "B" Steam Generator (SG).
b.
Observations and Findings
The Unit 2. Model 51 SGs were replaced with Model 51F SGs in 1980.
The
Model 51F SGs contain thermally treated Alloy 600 Inconel tubing with
stainless steel quatrefoil support plates. The tube ends were
hydraulically expanded for the full depth of_the tube sheet.
Since 1993. the licensee's SG inspection program required that one SG be
comprehensively inspected per outage.
The SG inspected during the
current outage was the "B" SG.
The inspection consisted of a bobbin
inspection of 100% of the tubes; a Motorized Rotating Pancake Coil
(MRPC) inspection of 20% of the tubes at the top of the tubesheet; and
an MRPC inspection of 20% of the Row 1. Li-Bends.
The licensee also
conducted a comparative study of eleven indications. found with their
standard 0.115-coil MRPC probe. using Plus Point eddy current ultrasonic
examinations.
As a result of the eddy current examinations. the licensee*elected to
plug five tubes. Three of the tubes. R37-C59. R36-C69. and R40-C70.
were plugged due to measured AntiVibration Bar (AVB) wear.
The measured
AVB wear was only approximately 20% through-wall. but conservative
growth rate calculations postulated growth to near 40% through-wall by
the end of three operating cycles. when SG "B" is due for its next
inspection.
The other two tubes. Rl-C34 and Rl-C35. contained
indentation restrictions at the top of the tubesheet.
The licensee
postulated that the tubes had been "dinged" during a past pressure
pulse/chemical cleaning operation in June 1994. and elected to plug the
tubes as a precautionary measure.
The inspection plan and results were discussed during a conference call
between NRC and the licensee on October 22. 1997.
c.
Conclusions
Consistent evaluations of eddy current inspection results and
conservative tube plugging decisions were strengths in the licensee's
steam*generator inspection program.
Ml.3
Flow Accelerated Corrosion (FAC) Program
a . Inspection Scope (49001)
The inspectors reviewed procedures. records. and documents related to
the monitoring of FAC in secondary piping and components.
10
b.
Observations and Findings
The inspectors reviewed the records associated with the inspection and
replacement of piping components in the steam and feedwater systems.
The records showed that the FAC program is a mature program. in that
predictions for the amount of wall loss in the piping systems were
generally accurate.
In the majority of cases with unacceptable wall
thicknesses. the program had predicted these results. and replacement
piping components were on hand.
The inspectors did note an exception to the FAC program predictions
occurred in a straight run of piping immediately downstream of a flow
control valve. This area of corrosion was not predicted by the computer
program. but was included for inspection because of the licensee's FAC
engineering personnel monitoring experiences at other plants. where FAC
in piping downstream of flow control valves had been observed.
Without
available replacement piping, the licensee was able to justify using a
weld buildup to restore the required wall thickness until the next
refueling outage.
c.
Conclusions
The licensee's flow accelerated corrosion monitoring program continued
to be a well-engineered and conservative program.
Ml.4 Emergency Diesel Generator (EOG) and Safety Injection (SI) Accumulator
Check Valve Testing
a.
Inspection Scope (61726)
The inspectors observed portions of surveillance tests performed on the
Number 3 EOG and Safety Injection Accumulator check valves.
b.
Observations and Findings
On October 5. the inspectors observed portions of Operations Periodic
Test (OPT) O-OPT-EG-001. "Number 3 Emergency Diesel Generator Monthly
Start Exercise." Revision 10-Pl. The inspectors considered that the
pre-job brief was thorough and the precautions were adequately
discussed.
The operators had the procedure at the job site and
constantly used it. The inspectors observed independent verification of
procedural steps. The operators were cautious and thorough.
The
results of the OPT were satisfactory.
On October 15. the inspectors observed portions of 2-0PT-SI-022. "SI
Accumulator Discharge Check Valve Test With Reactor Head Removed."
Revision 1-Pl. The test was modified to allow for performing the
surveillance with the Reactor Vessel Upper Internals not installed. The
core specimen access plugs were removed to prevent them from becoming
dislodged and falling to the bottom of the reactor vessel.
The upper
internals are normally placed in the reactor vessel for the performance
of this test and they rest on the access plugs which prevents them from
11
becoming dislodged.
The surveillance verifies by acoustic monitoring or
accumulator discharge flow that the check valves stroke full open.
The
check valves in each accumulator line are tested by acoustic monitoring
every third refueling cycle. Accumulator line "A" check valves, 2-SI-
107 and 2-SI-109, were acoustically monitored during RFO 14.
The
inspectors reviewed Safety Evaluation 96-045, Revision 3, which
evaluated the performance of the test with the upper internals removed.
The inspectors also reviewed completed Procedure 2-0PT-SI-022, Revision
1-Pl. All six SI check valv~s met the acceptance criteria as specified
in 2-0PT-SI-022.
c.
Conclusions
Surveillance activities associated with SI accumulator check valve
testing and Number 3 EOG testing were conducted in accordance with
approved procedures and met acceptance criteria.
Ml.5 Maintenance Activities
a.
Inspection Scope (62707)
The inspectors observed and reviewed maintenance activities to verify
that activities were conducted in accordance with TS, procedures,
regulatory guides, and industry codes or standards.
b.
Observations and Findings
The inspectors observed all or portions of the following Work Order (WO)
activities:
W0-368064 Perform protective relay maintenance and testing
W0-374842-01 Scrape, clean tubes and return "B" condenser water
box to service
The inspectors found that the maintenance activities were performed with
the proper tools on the correct equipment with the procedures and work
packages present and in use.
Pre-job briefings were accomplished with
appropriate personnel. Supervisory personnel were present to ensure
procedural adherence.
c.
Conclusions
The observed maintenance activities were performed satisfactorily.
Work
procedures were adequate and were being followed.
Ml.6 Surveillance Observations
a.
Inspection Scope (61726)
The inspectors observed and reviewed surveillance testing acti vi ti es to
verify that testing was performed in accordance with procedures, test
12
instrumentation was calibrated. Limiting Condition for Operations (LCOs)
were met. and any deficiencies identified were properly reviewed and
resolved.
b. Observations and Findings
The inspectors observed all or portions of the following surveillance
tests:
2-NSP-RX-014 "Control Rod Exercises." Revision 4
2-IPT-RP-AFW-001 "Under Voltage and Low-Low Steam Generator Logic
Start of the Steam Driven Auxiliary Feed Water Pump." Revision 6
2-PT-s:s "Consequence Limiting Safeguards Logic (Hi-Hi Train)
Verify Operability," Revision 9
2-IPT-RP-TM-001 "Turbine Trip Signal Input to Reactor Protection
System Functional Test." Revision 6
2-IPT-CC-MS-484 "Steam Line Flow Protection Loop F-2-484 Channel
Calibratioh," Revision 8
2-IT-CC-RC-412 "Delta T and TAvG Loop T-2-412 Channel Calibration."
Revision 16
2-PT-8.2 "Reactor Protection Logic Operability," Revision 10
2-0PT-FW-001 "Motor Driven Auxiliary Feedwater Pump 2-FW-P3A
Operability Test." Revision 5
2-0PT-FW-002 "Motor Driven Auxiliary Feedwater Pump 2-FW-P3B
Operability Test." Revision 6
2-NPT-RX-014 "Hot Rod Drive By Bank Operability," Revision- 4
2-NSP-RX-005 "RPI Calibration Data Collection." Revision 6
2-0P-RX-006 "Withdrawal Of Control Rods Banks To Critical
Conditions." Revision 6
2-IT-CC-RPI-001 "Analog Rod Position Indication System
Operability," Revision 4
The inspectors found that the work performed under these activities was
conducted* in a very professional manner.
All of the surveillances
observed were performed with the procedures present and in use.
Effective crew briefings were accomplished prior to performance of the
PTs.
-~-~--------------------~~--------------
13
c.
Conclusions
Thirteen observed surveillance tests were performed satisfactorily.
Ml.7 Refueling Surveillance Frequency Requirements
a.
Inspection Scope (61726)
The inspectors reviewed an issue involving surveillance frequency
requirements specified ih Section 4.1 of the TS ..
b.
Observations and Findings
During a routine inspection. questions were raised concerning the TS
surveillance frequency requirements specified in TS Section 4.1.
Specifically, Table 4.1-1, "MINIMUM FREQUENCIES FOR CHECK, CALIBRATIONS.
AND TEST OF INSTRUMENTATION CHANNELS," defines frequency "R" as "Each
Refueling Shutdown," while Table 4.1-2. "ACCIDENT MONITORING
INSTRUMENTATION SURVEILLANCE REQUIREMENTS," defines frequency "R" as
"Refueling." Table 4.l-2A. "MINIMUM FREQUENCY FOR EQUIPMENT TESTS,"
specifies a frequency of "Each refueling shutdown"* for line items 3, 6,
8, 14a and b. 15. 16. 17, and 18.
The licensee has interpreted the
frequency of terms "Each Refueling Shutdown" and "Refueling" to be any
time during the 18-month operating cycle.
If a surveillance test with a
specified frequency of "Each Refueling Shutdown" or "Refueling" can only
be accomplished during a unit shutdown. the licensee performs it at that
time.
However. if the licensee has determined that a test with these
specified frequencies can be performed with the unit on-line. they view
that the test can be performed at any time within the 18-month operating
cycle.
The licensee has an informal practice of accomplishing these on-
line tests 30 days or less prior to a unit refueling outage.
The validity of the licensee* s TS interpretation .is being reviewed by
the NRC.
Until this matter is resolved. this matter will be tracked as
Unresolved Item 50-280. 281/97010-04.
c. Conclusions
An unresolved item was opened to track resolution of an interpretation
of TS Surveillance frequency requirements.
Ml.8 Safety Evaluation of Relay Replacement/Engineered Safety Feature (ESF)
Actuation
a.
Inspection Scope (62707)
The inspectors reviewed the circumstances surrounding an ESF Actuation
during the replacement of a Consequence Limiting Safeguards (CLS) Relay .
14
b.
Observations and Findings
C.
On*October 11. at approximately 2:22 p.m .. during the replacement of
Relay 1812 in the "B" train of the Unit 2 Hi-CLS circuitry, an
inadvertent short circuit occurred while landing a lead which actuated
the "B" train of Hi-CLS.
At the time of the event. Unit 2 was in
refueling shutdown with the Residual Heat Removal System in service.
The actuation of the "B" train of Hi-CLS caused the actuation of the "B"
train of Safety Injection (SI).
All equipment expected to actuate on
the Hi-CLS and SI responded as designed (with the exception of equipment
removed from service). The Number 3 Emergency Diesel Generator auto
started but did not synchronize to its bus as power was never lost from
its associated bus.
At no time during the event was the residual heat
removal capability lost. Following verification that a valid Hi-CLS
signal was not present. the operators returned equipment to the normal
standby condition. This matter was reported to the NRC in accordance
with 10 CFR 50.72 and 50.73.
In preparation for the relay replacement. the licensee drafted Temporary
Modification S2-97-8 which provided instructions to install a jumper to
allow the replacement of Relay 1812. This Temporary Modification was
supported by Safety Evaluation 97-138 which stated that train "B" of
Safety Injection would be defeated during the evolution. The safety
evaluation further stated that a formal tracking mechanism would be used
to ensure that this condition was met.
Contrary to these specified
requirements. the Safety Injection signal was not defeated nor was a
formal tracking method used to ensure the condition was met due to
inadequate implementing instructions in the controlling work documents.
Specifically, Work Order (WO 00375660-02) and Procedure O-ECM-1801-01.
"Westinghouse Type BF or BFD Relay Replacement." Revision 10. the
procedures controlling the relay replacement activity, did not contain
specific instructions to ensure that the requirements specified in
Safety Evaluation 97-138 were implemented.
This failure represents a
breakdown in controlling plant configuration for a maintenance activity.
This is a violation of Technical Specification 6.4.A.7 and will be
tracked as Violation 50-281/97010-05.
Conclusions
A violation was identified for inadequate work instructions resulting in
the failure to implement the prerequisite requirements of a safety
evaluation during the replacement of a CLS relay. *
Ml.9 Unit 2 Pressurizer Power Operated Reli~f Valve (PORV) Maintenance
a.
Inspection Scope (62707)
The inspectors reviewed licensee activities involving corrective
maintenance of the Unit 2 pressurizer PORVs .
15
b.
Observations and Findings
Prior to the Unit 2 RFD, PORV 2-RC-PCV-2456 was inoperable with its
associated block valve closed due to valve seat leakage.
Pressurizer
PORV seat leakage has been an ongoing problem and was not successfully
addressed for the Unit 1 pressurizer PORVs during the previous Unit 1
RFD.
During the October. 1997, Unit 2 RFD. the licensee rebuilt both
pressurizer PORVs in accordance with procedure O-MCM-0419-01. "Copes-
Vulcan 2 Inch 1500 LB Reverse Acting Valve Overhaul." Revision 8.
During the overhaul of the valves .. direct oversight of the Virginia
Power Maintenance personnel was provided by a Copes-Vulcan vendor
representative. This maintenance overhaul included the replacement of
numerous valve parts (valve plug, cage, packing, stem and various
gaskets). The inspectors reviewed the associated documentation for the
pressurizer PORV overhaul and found no discrepancies.
Following the return of Unit 2 to service on October 31 and for the
remainder of the inspection period, no abnormal pressurizer PORV
tailpipe temperatures have been noted.
Monitoring tailpipe temperatures
for the remainder of the operating cycle will ultimately determine the
success of the pressurizer PORV repair.
c. {onclusions
The licensee rebuilt the pressurizer PORVs during the Unit 2 RFD.
Following return of the unit to service, no indication of seat leakage
was observed.*
Ml.10 Unit 2 C Reactor Coolant Pump (RCP) Flange Seal Replacement
a.
Inspection Scope (62707)
The inspectors observed and reviewed the licensee's actions to replace
the Unit 2 "C" RCP flange seal during the RFD.
b.
Observations and Findings
Prior to the Unit 2 RFD. the licensee determined that the "C" RCP flange
seal would be replaced due to observed flange leakage.
To gain access
to the seal, this evolution required removal of the RCP motor and lower
rotating unit including the 24 flange bolts.
While in the process of removing the 24 flange bolts. the licensee
experienced difficulty in the removal of bolt number 16.
Following the
removal of bolt number 16, inspection of the bolt hole revealed that the
majority of the threads were no longer intact (having been stripped
during bolt removal) .
The licensee determined that in lieu of repairing the damaged threads
during the present refueling outage, they would replace the RCP with
bolt number 16 as a "no load" bolt.
To support this decision, the
16
licensee obtained a detailed analysis from Westinghouse demonstrating
the acceptability of this option. This option recommended that during
the operating cycle. if the unit was to go to cold shutdown twice. the
pre-load on the remaining 23 bolts should be verified as acceptable
prior to restarting the unit.
The licensee also had two machining
vendors inspect the damaged bolt hole to provide permanent repair
options during a future refueling outage.
The inspectors followed this*issue in detail. A review of the
information provided by Westinghouse indicated that the "no load" bolt
option was viable. The inspectors wa~kdown of containment with RCS
pressure at 300 psig indicated no flange leakage. A licensee walkdown
with the unit at normal operating temperature and pressure also
indicated no pump flange leakage.
RCS leakage following the return of
Unit 2 to service was low and continued in this manner for the remainder
of the inspection period.
c.
Conclusions
The licensee successfully replaced the "C" Reactor Coolant Pump flange
seal. Installation of pump flange seal bolt number 16 as a "no load"
bolt was determined to be a viable option.
Ml.11 Unit 2 Pressurizer PORV Testing
a.
Inspection Scope (61726)
The inspector observed a portion of the setup and testing of the
pressurizer PORVs prior to the return to service of Unit 2.
b.
Observations and Findings
On October 24. the inspectors observed portions of the performance of
Procedure 2-0PT-RC-001. "PRZR PORV Refueling Test.* Revision 4.
This
test provides instructio.ns to perform a complete checkout of the Unit 2
pressurizer PORVs and their associated equipment. Testing was conducted
in a cautious and controlled manner and as specified by the procedure.
The Senior Reactor Operator supervising the test demonstrated superior
command and control over the evolution.
When problems were encountered.
the test was stopped and a well thought out course of action was taken.
The test was completed satisfactorily.
c.
Conclusions
Testing on the Unit 2 pressurizer PORVs was conducted in a cautious and
controlled manner and as specified by the procedure.
The Senior Reactor
Operator supervising the test demonstrated superior command and control
over the evolution .
17
III. Engineering
El
Conduct of Engineering
El.1 Unit 2 Letdown Line Orifice and Valve Replacement
a.
Inspection Scope (37551)
The inspectors reviewed the licensee's actions related to replacement of
the Unit 2 letdown line orifices and valves.
b.
Observations and Findings
On September 11. 1996. the licensee experienced the fourth socket weld
failure in the Unit 2 letdown line in 12 months.
The licensee
determined that the flow orifices (2-CH-R0-20RLD1-3). letdown orifice
block valves (2-CH-HCV-2200A-C). and some piping had to be replaced.
Design Change Package (DCP)96-040. "CVCS Letdown Piping Modification."
was issued to accomplish this work.
The licensee determined that the
modification would be accomplished in two phases.
They replaced some of
the piping and supports downstream of the orifices to change the
configuration and replaced, where practical. socket welds with butt
This work was accomplished during a December 1996 outage. This
effort was documented in more detail in Inspection Report Nos. 50-280 .
281/96-13.
The second phase was to replace the orifices and the orifice block valve
bodies and modify the valve supports during RFD 14.
The replacement
valve bodies required butt welds rather than the original socket welds.
WOs 357847-01 through -04. 357848-01 through -03. and 357850-01 through
-03 were issued to replace the valve bodies (2-CH-HCV-2200A-C).
The
- remainder of the work was accomplished by WOs 351999-02.-03. -16. and
-17.
The inspectors reviewed DCP 96-040 and the completed WOs and
verified that the work scheduled for RFD 14 had been completed. The
inspectors verified that DCP 96-040 has been completed.
c.
Conclusions
Letdown line modifications were performed during the Unit 2 RFD to
correct previous problems with weld leakage.
El.2 Appendix R Modifications
a.
Inspection Scope (37551)
The inspectors verified that the vital bus Appendix R modifications were
accomplished during the Unit 2 RFD.
b.
Observations and Findings
The inspectors observed portions of the work activities associated with
DCP 94-015. "Appendix R Vital Bus Modifications." and verified that the
18
associated WOs 38332754-01 and -02 had been completed.
The
modifications replaced the incoming feeder breakers in panels 2-I. 2-IA.
2:II. 2-IIA. 2-III. 2-IIIA. 2-IV. and 2-IVA with manual switches and
installed fuse blocks in Uninterruptable Power Supplies 2A-1 and 2A-2.
These modifications were implemented to meet the requirements of
Appendix R.
The licensee plans to implement the modifications on the
Unit 1 vital busses at the next scheduled refueling.outage.
c.
Cone l usi ans
The inspectors verified that the Unit 2 vital bus Appendix R
modifications had been implemented during the refueling outage.
IV. Plant Support
Rl
Radiological Protection and Chemistry (RP&C) Controls
Ri.1 Occupational Radiation Exposure Control Program
a.
Inspection Scope (83750)
b.
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program during the Unit 2 RFO.
The
review included observation of radiological protection activities
including pre-work briefings. personnel exposure moni tori n*g.
radiological postings, and verification of posted radiation dose rates
and contamination levels within the Radiologically Controlled Area
(RCA).
Those activities were evaluated for consistency with the
programmatic requirements. personnel monitoring requirements.
occupational dose limits. radiological posting requirements. and survey
requirements specified in Subparts B. C. F. G. and J of 10 CFR 20.
Observations and Findings
The inspectors conducted frequent tours of the RCA to observe radiation
protection activities and practices. Personnel preparing for routine
entries into the RCA were observed being briefed on the radiological
conditions in the areas to be entered. The briefings were given by
radiation control personnel before access was granted and covered the
dosimetry, protective clothing, and equipment required by the Radiation
Work Permit (RWP) for the entry.
The administrative limits for the
allowed dose and dose rate for the entry were emphasized during the
briefings. The briefings provided thorough descriptions of the existing
dose rates which could be encountered during the entry.
The inspectors
determined that personnel entering the RCA were adequately briefed on
the radiological hazards which could be encountered while in the RCA and
the radiological protective measures required to be taken during the
entry.
In addition to observing briefings for routine RCA entries. the
inspectors attended a briefing given specifically for work to be
performed under RWP 97-2-4102 in the Unit 2 "C" Reactor Coolant Pump
(RCP) Cubical.
Dose rates in that area were elevated and therefore
additional precautions were implemented. Those precautions included
.*
19
continuous Health Physics coverage, radiation and contamination surveys
of the equipment being worked on. and use of telemetric dosimetry.
In
addition to the radiological conditions and protective measures
addressed during briefings for routine entries-. the scope of work and
detailed discussions of how to accomplish each task were addressed
during this briefing. The inspectors determined that personnel were
adequately briefed on radiological hazards: protective measures and work
to be performed.
The inspectors observed the use of personal radiation exposure
monitoring devices by personnel entering and exiting the RCA.
Thermoluminescent Dosimeters (TLDs) were used as the priTT)ary device for
monitoring personnel radiation exposure.
In addition. Digital Alarming
Dosimeters (DADs) were used for monitoring the accumulated dose and the
encountered dose rates during each RCA entry.
The DADs were set to
alarm at administrative limits established for the specific RWP under
which the RCA entry was being made.
As the individuals exited the RCA.
the accumulated dose and encountered dose rate information was
transferred from the DADs to the Personnel Radiation Exposure Management
System (PERMS) data base in order to track individual exposures.
During
tours of the RCA the inspectors noted that the required dosimetry was
being properly worn by personnel when entering and while in the RCA.
The inspectors also noted that personnel exiting the RCA routinely
surveyed themselves for contamination using Personal Contamination
Monitors CPCMs).
The inspectors reviewed As Low As Reasonably Achievable CALARA) program
details. implementation. and goals for the current Unit 2 RFO.
Based on
the scheduled activities. daily and cumulative exposure projections were
established.
Individual exposures. based on data from DADs and PERMS.
were summarized by RWPs on a daily basis and allocated to the various
organizational departments.
Daily reports of the collective and
departmental exposures. along with their respective projected goals were
issued for monitoring purposes.
Plots of daily and cumulative exposure
vs. their respective projections were also distributed daily.
The
projected cumulative exposure for the planned 30 day Unit 2 RFO was 115
man-rem with a challenge goal of 100 man-rem.
As of day 11 of the RFO
(October 16) the daily and cumulative exposures were well within the
projected and challenge goals for the RFO.
The annual ALARA goal for
the site was established at 358 man-rem for the year 1997.
As of
October 16. the Year-To-Date (YTD) site collective dose was
approximately 52 man-rem above the projected YTD site collective dose.
The projected site collective dose was exceeded due to a 20 day
extension of the Unit 1 RFO. several unplanned outages. and other
emergent work.
The ALARA goal for the Unit 1 RFO. which occurred
earlier in the year. was 181 man-rem and the actual exposure was 222
man-rem.
The inspectors noted that the projected goals for the exposure
during the Unit 1 RFO and YTD site collective exposure were exceeded but
midway through the current Unit 2 RFO the projected goals for exposure
were being met.
The inspectors also reviewed records for individual
radiation exposures from the licensee's PERMS data base.
Those records
indicated that the YTD maximum individual exposures for Total Effective
C .
20
Dose Equivalent (TEDE). skin. extremity, and lens of the eye were 1.8.
4.2. 4.9. and 1.8 rem respectively.
The inspectors determined that
those exposures were well within the occupational dose limits specified
in 10 CFR 20.1202.
During the inspection the licensee was in the
process of an internal dose assessment for an individual that had
ingested a small amount of radioactive material. Preliminary estimates
indicated that the uptake was approximately 0.06 per.cent of the Annual
Limit on Intake CALI). or a Committed Effective Dose Equivalent (CEDE)
of 3 mrem.
Licensee records* indicated that this event occurred on
October 11. 1997. while the individual was performing a visual
inspection of the fuel transfer equipment in the Unit 2 Fuel Building
transfer canal.
During the time that the individual was performing the
work. the fuel transfer tube was open and the Fuel Building filtered
exhaust fans were started. Air flow from the Unit 2 Containment
Building through the transfer tube apparently swept radioactive
particles into the Fuel Building through the transfer canal where the
individual was working.
Deviation Report S-97-2844 was initiated for
this loss of contamination control event and the Operations Department
was assigned the responsibility for taking corrective actions.
During tours of th~ RCA the inspectors noted that general areas and
individual rooms were properly posted for radiological conditions.
Posted survey maps were used to indicate dose rates and contamination
levels at specific locations within rooms.
At the inspectors' request.
a licensee Health Physics staff member performed dose rate and
contamination surveys in several rooms and locations.
The inspectors
verified that the survey instrument readings were consistent with the
dose rates and contamination levels recorded on the posted survey maps.
The inspectors also noted that housekeeping was very good throughout the
RCA.
The inspectors also discussed with the licensee the primary coolant
chemistry controls used during reactor shutdown for the Unit 2 RFO.
Those controls included injecting additional boric acid into the coolant
during cooldown and injecting hydrogen peroxide after cooldown in order
to cause the release of radioactive material from the internal surfaces
of the Reactor Coolant System (RCS).
The radioactive material could
then be removed from the coolant by the filters and demineralizers in
the Chemical and Volume Control System (CVCS).
The licensee indicated
that approximately 176 curies (Ci) of cobalt-58 and 8.6 Ci of cobalt-60
were removed from the primary coolant. The overall effectiveness of
these shutdown chemistry controls would be evaluated based on the
reduction in the dose rates from specific locations in the plant and
from specific pieces of equipment.
The licensee indicated that the
results of that assessment would be documented in the ALARA report which
is scheduled to be issued 30 days after the RFO.
Conclusions
Based on the above reviews and observations. the inspectors concluded
that the licensee was properly monitoring and controlling personnel
21
radiation exposure and posting area radiological conditions in
accordance with lO*CFR Part 20.
Personnel entering the RCA were ad~quately briefed on radiological
hazards and protective measures.
Housekeeping in the RCA was very good during the Unit 2 RFD.
A significant amount of activity was removed from the RCS by Shutdown
Chemistry Controls in order to reduce exposure to workers during the
Unit 2 RFD.
Rl.2 Radiological Protection and Chemistry Controls (71750)
On numerous occasions during the inspection period. the inspectors
reviewed Radiation Protection (RP) practices including radiation control
area entry and exit. survey results. and radiological area material
conditions.
No discrepancies were noted. and the inspectors determined
that RP practices were proper.
Miscellaneous RP&C Issues (92904)
R8.1
(Closed) Violation 50-280. 281/97002-06: Multiple examples of failure to
foll ow radiation protection procedures.
RWP requ_i rements were not
fo 11 owed when i ndi vi duals failed to exit the RCA when thei'r DADs al armed
and individuals entered the RCA without DADs.
Licensee management
issued memorandums to station personnel stressing management
expectations for procedural compliance and personal accountability. A
Root Cause Evaluation of these events determined that the arrangement of
the area for in-processing to the RCA and the number of tasks required
for RCA entry were distracting to workers.
The flowpath for in-
processing to the RCA was rearranged to focus personnel on entry
requirements and. during periods of frequent entries. an individual was
posted at the RCA entrance to monitor compliance with dosimetry
requirements.
Sl
Conduct of Security and Safeguards Activities
Sl.l General Comments
On numerous occasions during the inspection period. the inspectors
performed walkdowns of the protected area perimeter to assess serurity
and general barrier conditions.
No deficiencies were noted and the
inspectors concluded that security posts were properly manned and that
the perimeter barrier's material condition was properly maintained.
Sl.2 Compensatory Measures
a.
lnspection Scope (81700)
Verified that the licensee employs compensatory measures when security
equipment has failed or performance has been impaired and that the
22
compensatory measures employed do not reduce the effectiveness of the
security system.
b.
Observations and Findings
Three compensatory measures were evaluated and observed_during the
inspection. Security officers were posted as compen$atory measures at
the containment personnel and equipment hatches.
Another security
officer was posted at the vehicle access door for the spent fuel vital
area.
The officers were equipped with appropriate dosimetry and were
aware of the procedural duties of their post. Appropriate security
measures compensated for the vital area access breaches in effect during
the ongoing outage.
None of the compensatory measures were due to
inoperable or malfunctioning equipment.
c.
Conclusions
Through observations. discussions with security force personnel. and
document review. the inspectors concluded that the licensee used
compensatory measures for vital area access breaches.
S2
Status of Security Facilities and Equipment
S2.l Protected Area Access Controls
a.
Inspection Scope (81700)
Evaluated the licensee's access control program for allowing packages.
personnel. and vehicles to enter the protected area to ensure compliance
with criteria in Chapters 2. 3. and 4 of the Physical Security Plan
(PSP).
b.
Observations and Findings
The inspectors reviewed appropriate access control procedures to. ensure
that the licensee provided appropriate access controls for the protected
areas.
Personnel. hand-carried packages or material. delivered packages or
material. and vehicles were searched before being admitted to the
protected area. Security personnel searched for firearms. explosives.
incendiary devices. and other items that could be used for radiological
sabotage.
These searches were either by physical search or by search
equipment.
Vehicle searches included a search of the cab. engine
compartment. undercarriage. and cargo areas.
The inspectors reviewed the following aspects of the personnel access
control program.
A coded and numbered picture badge identification
system was used for personnel who were authorized unescorted access to
the protected and vital areas. The codes corresponded to vital areas to
, which individuals had authorized access. Picture badges issued to
nonlicensee personnel indicated the authorized access areas and showed
23
that no escort was required.
Personnel displayed their badges while
within the protected area. Visitors authorized escorted access to the
protected area were issued a badge that showed an escort was required.
and were escorted by licensee-designated escorts while in the protected
area.
The licensee used biometric hand geometry to ensure
identification of individuals entering the protected area.
Access control program records were available for review and contained
sufficient information for identification of persons authorized access
to the protected area.
The licensee maintained access records of keys,
key cards. key codes. lock combinations. and other related equipment
during a person's employment or for the duration that these items were
used.
The inspectors reviewed the controls for entry and exit of packages and
material to and from the protected area.
Security personnel confirmed
the authorization of. and identified packages and material at access
control portals before allowing them to be delivered.
The licensee used
security force personnel and X-ray equipment to identify and confirm
that prohibited material was not entering the protected area.
The inspectors reviewed vehicle access control.
Individuals who
controlled the admittance control hardware that allowed vehicle access
to*protected areas were protected in a bullet resistant alarm station.
Armed security force personnel controlled the vehicle access search
area. Security force personnel escorted nondesignated vehicles while
within the protected area.
c.
Conclusions
The evaluation of the protected area access controls for packages.
personnel and vehicles revealed that the criteria of the PSP were being
followed.
S2.2 Alarm Stations and Communications
a.
Inspection Scope (81700)
b.
Evaluated the licensee's alarm stations and communication equipment to
ensure that the application of the criteria in Chapters 1. 4. and 6 of
the PSP and Security Plan Implementing Procedure (SPIP)-03.
"Central/Secondary Alarm Station Operation." Revision 3. dated
January 29. 1997, were implemented.
Observations and Findings
The inspectors verified that annunciation of protected and vital area
alarms occurred audibly and visually in the alarm stations. The
licensee equipped both stations with communication equipment and limited
closed circuit television (CCTV) assessment capabilities. Protected
area alarms were assessed by security officers in defensive positions
around the protected area. Alarm systems were tamper-indicating and
24
self-checking, and provided with an uninterruptable power supply. These
alarm stations were continually manned by capable and knowledgeable
security operators.
The stations were independent yet redundant in
operation.
The central alarm station's interior was not visible from
within or from outside the protected area. and no single act could
remove the capability of calling for assistance or otherwise responding
to an alarm.
The walls. doors. floors. and ceilings.of the alarm
stations were bullet-resistant .
. The licensee provided means for monitoring and observing, by human eye
or CCTV. persons and activities in the isolation zone and exterior areas
within the protected area. These means provided for assessing intrusion
alarms for possible threats occurring in the isolation zone and exterior
areas within the protected area.
The transmission and control lines
used in the CCTV intrusion alarm assessment system had line supervisibn
and tamper indication.
The inspectors evaluated the equipment. operation. and maintenance of
internal and external security communication links. and determined that
they were adequate and appropriate for their intended function.
Each
security force member could communicate with an individual in each of
the continuously manned alarm stations. who could call for assistance
from other security force personnel and from local law enforcement
agencies. The alarm stations had the capability for continuous two-way
voice communication with local law enforcement agencies through radio
- and the conventional telephone service. The licensee had compensatory
measures for defective or inoperable communication equipment.
Eight randomly selected Security Shift Blotters from October 22. 1994.
to October 20. 1997. were reviewed to verify that security plan and
procedure commitments in this area were being conducted and properly
documented.
c.
Conclusions
Based on this evaluation. the inspectors concluded that the licensee was
complying with the criteria in Chapters 1. 4. and 6 of the Physical
Security Plan and Security Plan Implementing Procedures for alarm
stations and communications.
S2.3 Protected Area Detection and Assessment Aids
a.
Inspection Scope (81700)
Inspected the licensee's protected area intrusion detection systems and
assessment aids to verify that they were functionally effective and met
licensee commitments in Chapters 2 and 4 of the PSP.
b.
Observations and Findings
The licensee had installed intrusion detection systems that could detect
attempted penetrations through the exterior isolation zones. and
C.
25
attempts to gain unauthorized access to the protected area.
The
licensee segmented the intrusion detection systems into enough alarm
zones to provide adequate coverage of the protected area perimeter
barrier and isolation zones.
The detection aids and alarm devices.
intluding transmission lines. were tamper-indicating and self-checking.
Sensors continued to function normally during loss of normal power.
The
licensee had compensatory measures to replace defective nr inoperative
detection aids.
The inspectors found through document review and
observation that the licensee had installed and tested detection and/or
surveillance subsystems for the protected areas.
The systems consisted
of motion. thermal. and volumetric detection equipment to discover and
assess unauthorized activities and conditions. These systems sent alarm
conditions to response force personnel through the alarm stations and
defensive positions allowing for response force personnel to assess and
correct the conditions.
The licensee used defensive positions (towers) to provide the initial
assessment and necessary response to the protected area alarms.
The
inspectors examined the licensee's defensive positions and found them to
be adequately placed.
They provided full fields of view and
unobstructed observation of the protected area barriers and is6lation
zones.
The licensee equipped these defensive positions with special
equipment as defined in the PSP.
Persons inside these defensive
positions were protected within the UL752 criteria .
Eight randomly selected Security Shift Blotters from October 22. 1994.
to October 20. 1997. were reviewed to verify that security plan and
procedure commitments in this area were being conducted and properly
documented.
Conclusions
Based upon the above evaluation. the inspectors concluded that the
licensee's intrusion detection systems and assessment aids were
functional. well maintained. effective for both covert and overt
penetration attempts. and met licensee commitments.
S3
Security and Safeguards Procedures and Documentation
S3.l Security Procedures
a.
Inspection Scope (81700)
b.
Reviewed a sample of implementing procedures to verify that the
procedures are consistent with plan commitments and practices.
Observations and Findings
The inspectors reviewed two Virginia Power Administrative Procedures and
twelve Security Plan Implementing Procedures.
Five procedures were
selected to verify commitments the licensee had made in the procedures.
The procedures selected pertained to all security areas inspected:
C.
26
procedural reviews. annual protected area perimeter and vehicle barrier
system walk downs. annual key core rotations. annual key card inventory,
and the vital area access authorization list.
Conclusions
The review and verification of commitments of selected security and
administrative procedures did not identify any inconsistencies or
noncompliance.
S3.2 Security Event Logs (SELs)
a.
Inspection Scope (81700)
Review a sample of event logs to verify that the licensee appropriately
analyzed. tracked. resolved. and documented safeguards events that the
licensee determined did not require a one hour report to the NRC.
b.
Observations and Findings
The inspectors reviewed quarterly SELs from the fourth Calendar Year
(CY) Quarter (QTR) 1996 to the second CY QTR 1997.
The total number of
events for each QTR was 12 for the fourth QTR 1996. 27 for the first QTR
1997. and 40 for the second QTR 1997.
The increases in the first two
QTRs of 1997 were mostly related to an outage.
The most significant
logged events during these two QTRs were unsecured vital area doors (14)
and lost badges (14).
The Deviation Reports for these events were
reviewed.
These events were licensee identified. human error. nonwilful
events with insignificant safety implications. The inspectors noted
eight computer hardware events logged in the second QTR 1997.
This
issue was discussed in paragraph 2.1 of Inspection Report 50-280.
281/96-06.
The security computer upgrade is still part of the key card
upgrade program that is scheduled for early 1998.
Noteworthy was that*
since January 1. 1996. to October 20. 1997. there have been only 16
security caused events documented in the SELs.
c.
Conclusions
The review of three quarterly SELs verified that the licensee was
appropriately analyzing, tracking, resolving, and documenting safeguards
events.
V. Management Meetings
Xl
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on November 25. 1997.
The
licensee acknowledged the findings presented .
_____ a:--____
_
27
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. _No proprietary information was
identified.
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Adams. Superintendent. Engineering
R. Allen. Superintendent. Maintenance
R. Blount. Assistant Station Manager. Nuclear Safety & Licensing
D. Christian. Station Manager
E. Collins. Director. Nuclear Oversight
M. ~rist. Superintendent. Operations
L. Hartz. Engineering Manager
B. Shriver. Assistant Station Manager. Operations & Maintenance
T. Sowers. Superintendent. Training
B. Stanley. Supervisor. Licensing
W. Thorton. Superintendent. Radiological Protection
H. Travis. Engineering NOE Manager
IP 37551:
IP 40500:
IP 49001:
IP 50002:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 73753:
IP 81700:
IP 83750:
IP 92904:
Opened*
INSPECTION PROCEDURES USED
Onsite Engineeri~g
Effectiveness of Licensee Controls in Identifying. Resolving, and
Preventing Problems
Inspection of Erosion/Corrosion Monitoring Programs
Surveillance Observation
Maintenance Observation
Plant Operations
Plant Support Activities
Inservice Inspection
Physical Security Program for Power Reactors
Occupational Radiation Exposure
Followup - Plant Support
ITEMS OPENED AND CLOSED
50-280. 281/97010-01
IFI
Review canal level probe RCE and corrective
actions (Section 01.3).
50-280. 281/97010-02
50-280, 281/97010-03
IFI
Review licensee actions to resolve AMSAC enable
setpoint issue (Section 01.5).
Failure to perform a required TS surveillance
(Section 01. 6).
50-280, 281/97010-04
50-281/97010-05
Closed
50-280, 281/97010-03
50-280, 281/97002-06
28
TS surveillance frequency requirement questions
(Section Ml. 7).
Inadequate work instructions resulted in the
failure to implement the requirements of a
safety evaluation (Section Ml.8).
Failure to perform a required TS surveillance
(Section 01. 6).
Multiple examples of failure to follow radiation
protection procedures (Section R8.1) .