ML18152A128
| ML18152A128 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 05/19/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A129 | List: |
| References | |
| 50-280-97-03, 50-280-97-3, 50-281-97-03, 50-281-97-3, NUDOCS 9705290349 | |
| Download: ML18152A128 (24) | |
See also: IR 05000280/1997003
Text
..
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9705290349 970519
ADOCK 05000280
G
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280, 50-281
50-280/97-03, 50-281/97-03
Virginia Electric and Power Company (VEPCO)
- Surry Power Station, Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
March 9 - April 19, 1997
R. Musser. Senior Resident* Inspect,- ....
K*. Poertner, Resident Inspector
P. Byron, Resident Inspector
J. Coley, Jr., Reactor Inspector (Section M2.l, M2.2,
and M2.3)
B. Crowley, Reactor,. Inspector (Assisted J. Coley with
inoffice review, Section M2.3)
D. Jones, Sr. Radiation Specialist (Section Rl.l,
Rl.2, Rl.3, and Rl.4)
G. Belisle. Chief, Reactor Projects Branch 5
Division of Reactor Projects
Enclosure 2
..
- - - - - - - - - -
EXECUTIVE SUMMARY
Surry Power Station, Units 1 & 2
NRC Inspection Report Nos. 50-280/97-03, 50-281/97-03
This integrated inspection included aspects of licensee operations.
engineering, maintenance. and plant support.
The report covers a 6-week
period of resident inspection; in addition, it includes the results of
announced inspections by a regional radiation specialist and regional projects
inspectors.
Operations
- .
During the Unit 1 Refueling Outage (RFO), the licensee failed to
properly maintain refueling containment integrity which constituted a
violation of Technical Specification (TS) 3.10.A.1 (Section 01.2).
The inspectors concluded that the licensee could have exhibited a more
conservative approach by providing an additional method to monitor spent
fuel pit temperature during the period of high pit heat load (Section
01.3).
Maintenance
Maintenance personnel failed to follow the reactor disassembly procedure.
in that they did.not place RTV along the entire circumference of the
inner J-Seal resulting in the cavity seal leak during post installation
testing. This is a. Violation of TS 6.4.D. The inspectors consider that
work practice is the only causal factor described in Deviation Report
(DR) 97-0795 to be valid. The procedure is clear and explicit. The
inspectors concluded that the response to DR 97-0795 should have been
more explicit in that it did not detail the work practice/failure to
follow procedure issue. The proposed corrective actions involving
revising the-procedure are enhancements and will likely not prevent
recurrence. The inspectors discussed this with plant management and
plant manageme.nt stated that they would review the issue (Section Ml.1).
The work performed to install 1-SW-MOV-105B was performed properly and
in accordance with the specified work instructions. Providing more
detailed instructions in the design change and work order was discussed
with plant management as a potential enhancement for future tasks of
this type (Section Ml.2).
The inspectors determined that the licensee performed the appropriate
actions to correct a number of longstanding equipment problems.
The
effectiveness of these activities will be determined during the next
operating cycle (Section Ml.3).
The Inservice Inspection (ISI) period plan, personnel certifications,
weld examination, and the ultrasonic examination procedure were in
accordance with Code Requirements (Section M2.l) .
The drawing for the upstream elbow weld on Pressurizer Line No. 4"-RC-
34-1502 (weld adjacent to Weld No. 3-02) was not depicted on ISI reactor
2
coolant isometric sketch No. 11448-WKS-0124Al-1.
The licensee took
actions to have the !SI drawing revised (Section M2.l).
The review of procedures, personnel certifications and the evaluation of
recorded eddy current data for tubes in the A steam generator revealed
that Westinghouse personnel were very knowledgeable of the eddy current
examination and data analysis process (Section M2.2).
Virginia Power Company has approximately 5000 components in the Unit 1
flow accelerated corrosion program. Approximately 110 to 121 of these
components are scheduled each outage to be examined. A concern was
expressed when high component replacement rates were experienced from
the small sample of components examined.
The licensee issued DR .
S-97-0895 to address flow accelerated corrosion concerns.
Licensee
actions planned in response to this deviation were considered good
(Section M2.3).
Engineering
The modification activities revi~wed by the inspectors during the RFO
should correct two longstanding equipment deficiencies (Section El.I).
Based on the deterioration seen in the Unit 1 letdown orifices. the
licensee prudently replaced these orifices and associated downstream
piping during the 1997 Unit 1 RFO (Section El.2) .'
The inspectors identified a violation .involving an inaccurate Licensee
Event Report (LER) submittal. The licensee addressed this matter and
the associated corrective actions in their response to Violation
50-280, 281/97002-04 (Section EB.I).
Plant Support
During the Unit 1 RFO, the licensee was properly monitoring and
controlling personnel radiation exposure and posting area radiological
conditions in accordance with 10 CFR Part 20 (Section Rl.1).
The licensee was maintaining radioactive effluent monitoring
instrumentation in an operable condition and performing the required
surveillances to demonstrate their operability. The Radiation
Monitoring Upgrade Program was considered to be a significant program
improvement (Section Rl.2).
The onsite meteorological measurements program was implemented in
accordance with the Updated Final Safety Analysis Report (UFSAR)
(Section Rl.3).
The licensee was maintaining the .Control Room Emergency Ventilation
System in an operable condition and performing the required
surveillances to demonstrate operability of the system (Section Rl.4) .
I,
Report Details
Summary of Plant Status
Unit 1 was in a RFO the entire reporting period.
Unit 2 operated at power the entire reporting period.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707, 40500)
The inspectors conducted frequent control room tours to verify proper
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
safety system lineups were periodically reviewed from control room
indications to assess operability. Frequent plant tours were conducted
to observe equipment status and housekeeping. DRs 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.
01.2 Loss of Refueling Containment Integrity
a.
Inspection Scope (71707)
The inspectors reviewed instances which resulted in a loss of refueling
containment integrity during the Unit 1 RFO.
b. Observations and Findings
On March 20, with Unit 1 in refueling shutdown and fuel movement
underway, a *1 i censee manager performing a wa l kdown of refueling
containment integrity penetrations discovered that the blanks on the
main steam safety valve flanges were not properly secured.
Fuel
movement was stopped. A subsequent investigation revealed that the
blank installed in the position of main steam safety valve l*MS-SV-103C
had a gap of approximately one-eighth inch between the .sealing surfaces.
The licensee developed and implemented a containment integrity
verification plan which involved checking other penetrations and
properly securing the blanks on the main steam safety valve flanges.
No
additional problems were identified. Fuel movement resumed
approximately three and one-half hours after being stopped.
The fo 11 owing day at approximately 10: 54 a. m. . during a tour of the Unit
1 containment, a member of the licensee's Nuclear Oversight Department
discovered that the containment equipment hatch blank flange was not .
properly closed. Light from outside containment could be seen through
the flange seating surface.
Fuel movement was again stopped. A more
2
detailed and effective containment integrity verification plan was
implemented. Operations performed a detailed walkdown of all
containment penetrations.and identified another leakage path.
Main
Steam Trip Valve, 1-MS-TV-lOlC, had drifted from the full closed
position and was no longer serving as a containment barrier as required.
Instrument air had leaked past an isolation*valve to the trip valve's
actuator causing the valve to partially open.
These* matters were
corrected prior to the resumption of fuel movement.
This matter was reported to the NRC in accordance with 10 CFR 50.73 (LER
50-280/97006-00).
In this report, the licensee stated that the
requirements of 10 CFR 100 would not have been exceeded in regards to
this matter if a postulated fuel handling accident had occurred with the
containment conditions as stated. The inspectors reviewed the
licensee's evaluation and concurred with the licensee's conclusion.
The failure to maintain all penetrations which provide a direct path
from containment atmosphere to the outside atmosphere closed is a
violation of TS 3.10.A.l. Th~ failure to maintain refueling containment
- integrity during fuel movement will be tracked as Violation
50-280/97003-01.
c. Conclusions
Duri.ng the Unit 1 RFO, the licensee failed to properly maintain
refueling containment integrity during fuel movement which constituted a
violation of TS 3.10.A.1.
01.3 Spent Fuel Pit Temperature Monitoring (71707)
On March 23, the day folJowing the completion of the Unit 1 full core
offload, the inspectors reviewed the licensee's methods of monitoring
spent fuel. pit temperature.
Normally, a temperature indicator on both
the Unit 1 and 2 control panels displays the spent fuel pit temperature.
Additionally, two alarms for spent fuel pit high temperature (high and
high-high temperature) are normally available through the control room
annunciator system.
On the date of this review and for the previous
five days, only the temperature indicator on the Unit 2 panel remained
operable. The remainder of the equipment was out of service due to an
ongoing modification involving a portion of the non-safety related
instrument racks.
To compensate for this condition, operations
.
personnel were logging spent fuel pit temperature on an hourly basis and
were well aware of the equipment status. The inspectors concluded that
the licensee could have exhibited a more conservative approach by
providing an additional method to monitor the spent fuel pit temperature
during this period of high spent fuel pit heat load.
08
Miscellaneous Operations Issues (92901)
08.1 (Closed) LER 50-281/95001-00:
pressurizer heatup exceeded TS limit due
to lack of procedural control.
On February 4, 1995, the Unit 2
operators noted that the pressurizer cooldown rate was close to the
3
200° Fahrenheit per hour (F/hr) cooldown allowed by TS 3.1.B.3. The
operators slowed the cooldown rate and submi.tted DR 95-0206. A review
of the data taken during the performance of General Operating Procedure
2-GOP-2.6, "Unit Cooldown, Less Than 205° F to Ambient," revealed that
the TS specified cooldown rate had not been exceeded.
However, the data
indicated that the pressurizer temperature increased from 254° F to
400° Fin a one hour period which exceeds the TS specified limit of
100° F/hr.
DR 95-0218 was issued to describe this event. This event is
described in detail in Inspection Reports (!Rs) 50-280, 281/95003 and
50-280, 281/95006.
The licensee attributed the event to inadequate procedural c9ntrols for
pressurizer in-surges and out-surges during the Reactor Coolant System
(RCS) cooldown which was due to lack of operating experience.
In
addition the operators did not anticipate a heatup during RCS cooldown
evolutions. The licensee initiated training on the event and revised
Procedure 1/2-GOP-2.6. Westinghouse performed an analysis of the
effects of the transient on the pressurizer. The analysis revealed that
the transient had no detrimental structural effects on the pressurizer.
The Westinghouse Owners Group (WOG) created a task team on pressurizer
in-surge and out-surge transients. The team collected data on
. pressurizer heatup and cooldown rates. The WOG completed their review
and on February 3, 1997, issued a set of guidelines to mitigate these
events. The results of the review were documented in WCAP-13588,
"Operating Strategies for Mitigating Pressurizer Insurge and Outsurge
Transients," dated March 1993 and WCAP-14717, "WOG Evaluation of the
Effect of Insurge/Outsurge Out of Limit Transients on the Integrity of
the Pressurizer (Program MUHP-5063 Summary Report)," dated August 1996.
The licensee plans to evaluate the results and recommendations of the
task team.
The following procedures were revised as a result of the
guidelines:
OSP-RC-001. "RCS and Przr Heatup/Cooldown Verification,"
Revision 1
GOP-1.1. "Unit Startup, RCS Heatup From Ambient to 195° F,"
Revision 9
GOP-1.2, "Unit Startup, RCS Heatup From 195° F to 345° F,"
Revision 9
GOP-2.4, "Unit Cooldown; Hot Shutdown to 351° F." Revision 9
GOP-2.5, "Unit Cooldown, 351° F to 201° F," Revision 7
GOP-2.6, "Unit Cooldown, 201° F to Ambient," Revision 7
The inspectors verified that the changes had been made to the
procedures.
The inspectors reviewed the heatup and cooldown data of February 4,
1995, contained in GOP-2.6: Westinghouse evaluation RM06-1566, dated
February 13, 1995; and the training lesson plans. Tr*aining records were
reviewed and the inspectors verified that training had been given. The
licensee has completed their planned corrective actions.
4
08.2 (Closed) Violation 50-281/95006-02: pressurizer heatup rate exceeded TS
limits of 100° F/hour. This violation was written against the event
described in Section 08.1 CLER 50-281/95001-00).
The inspectors
reviewed the licensee's*response dated June 15, 1995, and determined
that it was acceptable. The closure of the LER 50-281/95001-00 also
closes this item.
08.3 (Closed) LER 50-280/97006-00: loss of refueling integrity due to an
inadequate containment closure process.
The corrective actions related
to this LER will be tracked by Violation 50-280/97003-01.
IL Maintenance
Ml
Conduct of Maintenance
Ml.1 Reactor Cavity Seal Ring
a.
Inspection Scope (62707)
On March 16, 1997, following installation of the cavity seal ring, the
licensee performed the cavity level air drop test. The test failed
because of excessive leakage. The inspectors reviewed the DRs and
verified the licensee's corrective actions .
b. Observations and Findings
The licensee installed the cavity seal ring in accordance with O-MCM-
1150-01. "Reactor Disassembly And Reassembly," Revision 4, Section 6.11,
"Reactor Cavity Seal Ring And Strongback Installation." A visual
inspection of the seal ring following the failed test revealed that
there were two areas, each about 10 inches long, where the inner J-Seal
was not touching the re~ctor vessel (1/8" gap). Additionally, the
licensee determined that they had failed to place RTV along the entire
circumference of the inner J-Seal. The licensee also identified that
six of the 20 capscrews in the diaphragm plate manway nearest the cavity
ladder were loose (not even hand tight). The outer J-Seal had been
sealed to the diaphragm plate foam using RTV, but the RTV had migrated
under the seal ring standoffs which did not allow the seal to settle
into position. These items caused the seal to leak by when the
inflatable seal was deflated. The seal ring was removed from the cavity
and one inner segment ring was found to be bent.
The bent segment was
removed, straightened, and reinstalled.
RTV was placed as required by
procedures. The air drop test was successfully repeated.
No leakage
was observed and both seals inflated and deflated as designed.
Two DRs.
97-0782 and*97-0975, were issued by Engineering and Maintenance
respectively to track this issue.
The causal factors of the event that were listed in DR 97-0975 *were
written communicati~n. work practices. and resource management.
The
licensee attributed the lack of a sign off for the procedural step which
controlled the event and this was the first time the crew had performed
the activity as contributors to the event. Although O-MCM-1150-01 Step
5
6.11.6 had a sign off blank, the proposed corrective actions were to add
a sign off to its substep, Step 6.11.6.c, and revise Figure 13 of the
procedure to show additional detail.
DR 97-0795 was closed on the basis
that 0-MCM-1150-01 had been revised to include the sign off for Step
6.11.6.c and the figure revision was being tracked by Procedure Manager
Tracking Number. MEFB 97-0031 and the revision would be completed prior
to the Unit 2 RFD.
The inspectors discussed their inability to find the
procedure revision with the licensee. The licensee provided the
inspectors with a one time only procedure action request which added the
sign off step*to Step 6.11.6.c and a change to Section 6.9. This action
changed the procedure for work during the RFD. but did not revise the
procedure.
The proposed corrective actions for DR 97-0782 were to add the sign off
as described above, add a "Caution" so that RTV is not applied under the
standoffs, and add a step after Step 6.9.7 to check the manway fastener
torque. The DR was closed out by stating that the MEFB-97-0031 had.been
issued to track the procedure revision, which will incorporate these
(and other) changes.
Both DRs were approved for closure by the Station
Nuclear Safety a_nd Operating Committee (SNSOC) on April 10; 1997.
On April 22, 1997, the inspectors reque~ted a copy of Procedure O-MCM-
1150-01 from the licensee's Document Control and received O-MCM-1150-01.
Revision 4.
The inspectors reviewed O-MCM-1150-01, Revision 4, and did
not observe a sign off for Step 6.11.6.c as indicated by the closure
document. Step 6 .11. 6. c states, "Apply a sma 11 bead of RTV seal ant
along the entire circumference of the inner J-Seal where the seal
contacts the reactor flange. (The bead should be at least 1/8 inch
thick ..... )" The inspectors consider that this step is very clear as
to what is required when applying RTV to the inner J-Seal.
MEFB-97-0031
was also reviewed and the inspectors noted that it only states under
comments that the procedure needs to be revised after the current RFD.
It references DR 97-0795 but there is no reference to the proposed
procedure revisions contained in DR 97-0782.
c. Conclusions
Maintenance personnel failed to follow the procedure in that they did
not place RTV along the entire circumference of the inner J-Seal
resulting in the cavity seal leak during post installation testing.
This is a Violation (50-280/97003-02) of TS 6.4.D. The inspectors
consider that work practice is the only causal factor described in DR
97-0795 to be valid. The procedure is clear and explicit. The
inspectors concluded that the response to DR 97-Q795 should have been
more explicit in that it did not detail the work practice/failure to
follow procedure issue. The proposed corrective actions involving
revising the procedure are enhancements and will likely not prevent
recurrence. The inspectors discussed this with plant management and
plant management stated that they would review the issue
6
Ml.2 Replacement of Service Water Valve 1-SW-MOV-105B
a.
Inspection Scope (62707)
The inspectors monitored maintenance activities involving the
replacement of service water valve 1-SW-MOV-105B.
b. Observations and Findings
On April 12, the inspectors observed portions of the replacement of
service water valve 1-SW-MOV-105B.
The work was being performed in
accordance with Work Order (WO) 00363165-03 and Design Change 97-016.
The valve was replaced because it would not satisfactorily pass a local
leak rate test. In this instance, a valve of the type previously
installed was no longer available, thereby requiring a new type valve to
be installed in accordance with an approved design change (97-016). All
work observed by the inspectors was performed properly and in accordance
with the specified work instructions. The inspectors reviewed the
associated documentation and found it satisfactory with one minor
exception. Specifically, neither the design change nor the WO provided
detailed instructions for the installation of a flange insulation kit.,
This kit was required to be installed to eliminate any galvanic
corrosion concerns due to the dissimilar metals of the new valve and the
existing piping. The inspectors questioned the maintenance personnel
performing the task about the methodology for installation of the
insulation kit. The maintenance personnel indicated that they had
received appropriate oral instructions from ~heir supervision and
engineering personnel concerning the installation of ~he insulation kit
and were cognizant of the proper installation procedure.
The inspectors
discussed with plant management that providing more detailed
installation instructions would enhance future tasks of this type*.
c. Conclusions
The work performed to install l-SW-MOV-105B was performed properly and
in accordance with the specified work instructions. Providing more
detailed instructions in the design change and WO was discussed with
plant management as a potential enhancement for future tasks of this
type.
Ml.3 Unit 1 Outage Activities
a.
Inspection Scope (61726. 62707)
The inspectors reviewed a number of activities during the Unit 1 RFO.
7
b. Observations and Finding
1.
Unit 1 Safety In,iection Accumulator lC. Change In Boron
Concentration
2.
The licensee observed that the boron concentration in Safety
Injection (SI) accumulator lC was decreasing while the level
remained constant. The accumulator is connected to the cold leg
of the C loop by a 12-inch line. The line goes from the cold leg
to the accumulator through two check valves (1-SI-147/145) and an
open motor operated gate valve (1-SI-MOV-1865C).
The check valves
are oriented to allow flow from the accumulator to the reactor
coolant cold leg. The system engineer theorized that check valve
l-SI-147 leaked by allowing the 2200° F reactor coolant to flow to
the accumulator. Thermal mixing caused the reactor coolant with a
lower boron concentration to dilute the coolant in the
The system engineer believed the constant level was
the result of valve 1-SI-MOV-1865C packing leakage being equal to
the 1-SI-147 inleakage.
The licensee replaced the seat ring in l~SI-147 and this was
accomplished by WO 00328809-01.
WO 00359031-01 was issued to
repack valve l-SI-MOV-1865C.
The inspectors noted during their WO
review that both check valves were overhauled on September 23,
1995, because of boron dilution in the C accumulator.
In
addition, l-SI-MOV-1865C was previously repacked on December 9,
1994. The inspectors verified that the licensee completed their
corrective actions for the boron dilution in the C accumulator.
The effectiveness of the corrective actions can not be determined
until the unit has been at power.
Primary Power Operated Relief Valve (PORV) Maintenance
During the last Unit 1 operating cycle, primary PORV 1-RC-PCV-
1455C was isolated because its associated block valve was shut due
to leakage through the PORV.
To correct this problem. the
licensee performed a complete rebuild of the valve. This included
replacement of the valve's plug, cage and stem.
The inspectors
reviewed the associated work documentation and considered that the
maintenance performed was satisfactory.
3.
Pressurizer Spray Valve Maintenance
During the last Unit 1 operating cycle, pressurizer spray valve 1-
RC-PCV-14558 was isolated due to faulty operation and seat
leakage. During the current Unit 1 outage, the valve body and
internals were replaced.
The inspectors reviewed the associated
work documentation and considered that the maintenance performed
was satisfactory.
4.
8
Pressurizer Instrumentation Nozzle Visual Inspections
During the previous Unit 1 RFO, an inspection of the pressurizer
instrumentation nozzles revealed evidence of leakage. The nozzles
in question were removed and replaced. This matter was reported
to the NRC in LER 280/95007-00.
An action to prevent recurrence
for this event was to perform a visual inspection of the nozzles
during the unit's next RFO.
The licensee performed a visual
inspection of the Unit 1 pressurizer instrumentation nozzles and
noted no leakage. The inspectors reviewed the visual examjnation
report and considered that the licensee's inspection was
satisfactory.
'
c. Conclusions
The inspectors determined that the licensee performed the appropriate
actions to correct a number of longstanding equipment problems.
The
effectiveness of these activities will be determined during the next
operating cycle.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Observation of Unit 1 ISI Work Activities
a.
Inspection Scope (73753)
This is the first outage, of the second inspection period. of the third
ISI interval. The applicable code for Unit 1, for the third ISI interval
was the American Society of Mechanical Engineers (ASME) Code Section XI.
1989 Edition, no Addenda.
The inspectors reviewed documentation and
observed work activities to determine whether the ISI activities were
performed in accordance with TS, the applicable ASME Code, and/or
requirements imposed by NRC/industry initiatives.
b. Observations and Findings
The inspectors reviewed the Inservice Inspection (ISI) outage
examination plan and the component examination schedule for the current
inspection period. The reviews were performed to determine if changes
to the component examination schedule for the current inspection period
had been properly documented. Certification records for examiners
performing ISI examinations this outage were reviewed. Virginia _Power
Procedure No. NDE*UT-601, "Ultrasonic Examination of Piping Welds,"
Revision 0, was also reviewed for technical content.
Ultrasonic examination of reactor coolant welds Nos. 3-0lDM and 3-02
were observed. These ASM~ Code welds were four-inches in diameter and
were located on top of the pressurizer. Although the examinations were
conducted satisfactorily, one discrepancy was noted by the inspectors.
The ISI drawing for the upstream elbow weld on the elbow (Pressurizer
L-ine No. 4"-RC-34-1502). which was attached to the reducer on the
pressurizer nozzle, was not depicted on ISI Drawing No. 11448-WMKS-
,-
9
0124Al-1.
The licensee subsequently stated that, when insulation was
removed, it was not unusual to find a weld that was previously not
identified in the program.
However, the program contained an adequate
surplus of welds, which were examined in the event that additional welds
were identified during inspection activities. The licensee also stated
that as welds were found, the ISI drawings were revised to depict the
locations of the new welds.
In addition to the above, the inspectors also observed two ultrasonic
examinations (Welds Nos. 1-02 and 1-03) on the 14-inch diameter
feedwater piping running to steam generator A and one ultrasonic
examination (Weld No. 1-01) on the 16-inch diameter. feedwater piping
running to steam generator B.
The feedwater piping examination was
performed in accordance w.ith t_he requirements of NRC Bulletin No. 79-13.
c. Conclusions
The ISI period plan, personnel certifications, weld examinations, and.
the ultrasonic examination procedure were in accordance with Code
requirements.
One discrepancy*was noted, in that, the drawing for the
upstream elbow weld on Pressurizer Line No. 4"-RC-34-1502 (weld adjacent
to Weld No. 3-02) was not depicted on the ISI reactor coolant isometric
sketch. The licensee took actions to have the ISI drawing revised .
M2.2 Observation of Unit 1 Steam Generator A Eddy Current Data Analysis
Activities
a.
Inspection Scope (73753)
The inspectors reviewed the Surry Power Station Unit's 1 & 2 Steam
Generator Monitoring and Inspection Program Plan, the Surry Site
Specific Eddy Current Data Analysis Guidelines (Procedure No. SRY-SGPMS-
002.2, Revision 0), the Westinghouse Electric Corporation Nuclear
Services Division Steam Generator Primary Maintenance Services Data
Analysis Technique Procedure No. DAT-GYD-001, Revision 7, and personnel
certification records for all of the Westinghouse examiners and
analysts.
In addition. tube evaluation and data analyst activities were
. inspected.
b. Observations and Findings
The licensee's single steam generator inspection program was initiated
on Unit 1 in 1994.
During each outage, 100 percent bobbin coil
inspections of all open tubes in one steam generator are examined.
In
addition, a 20 percent sample of hot leg tube sheet transitions in one
steam generator are examined each outage using a Motor Rotating Pancake
Coil (MRPC).
Based on this program, 100 percent of all steam generator
tubes are bobbin coil examined within a rolling 60 month schedule.
Under ASME Section XI, 1989 Edition, the extent and frequency of
examination is governed by the plant TSs. Surry Unit 1 TS, Section 4.19.C requires 3 percent of all tubes be examined (301 tubes): however,
3336 tubes were bobbin coil examined in A Steam Generator (100 percent
10
of all tubes in A).
In addition. 669 hot leg tube sheet transitions (20
percent sample) will be MRPC examined this outage.
The inspectors'
review of documentation delineated in the scope paragraph above and
observation of the online evaluation process revealed that the approved
data analysis guidelines were being followed: the data analysts were
very knowledgeable of-the requirements and operation of their equipment:
and the 100 percent bobbin coil examinations were complete with no
reportable pluggable indications identified at this point in the outage
examinations.
c. Conclusion
The review of procedures. personnel certifications. and evaluation of
recorded eddy current data for tubes in the A steam generator revealed
that the Westinghouse personnel (including their contractors) were very
knowledgeable of the eddy current examination and the data analysis
process.
M2.3 Unit 1 Flow Accelerated Corrosion (FAC) Program
a.
Inspection Scope (49001)
The licensee has approximately 5000 components in the Unit 1 FAC
program.
Approximately 110 to 121 of these components are scheduled
each outage to be examined.
The inspectors held discussions with the
licensee's erosion/corrosion engineers to determine the scope of FAC
examinations scheduled for this outage, the condition of the plant
piping as revealed by inspection: the extent of pipe replacement
required; and whether proper examination expansion was performed when
defective components were found.
b.
Observations and Findings
The licensee's initial sample of components scheduled for ultrasonic
examination this outage was 113.
The licensee had also planned to
replace 22 components without further examination. based on corrosion
growth rates confirmed last outage.
However, discussions with cognizant
personnel revealed that ultrasonic thickness examinations had identified
20 additional components that had to be replaced.
The licensee would
now have to replace 48 total components this outage.
In addition. the
sample of components was expanded to 140 total components.
The high
rejection rate of components in relationship to the average sample of
components scheduled for examination during this outage concerned the
inspectors. Therefore, discussions were held with cognizant licensee
personnel to determine the results of previous outage operations. This
review revealed that a significant number of components had been
repaired or replaced as the result of inspection for Unit 1 in both the
1994 (13) and 1995 (21) outages.
However. the inspectors found that the
licensee has not experienced any recent leaks and no sealant cans were
installed on either units. The inspectors also verified a portion of
the licensee's component expansion inspections and found that they had
been conducted properly.
11.
During a meeting with senior management. the inspectors expressed
concern over the high component rejection rate. The inspectors were
informed by senior management that they were also concerned over the
number of components requiring replacement.
Therefore, as soon as the examinations of components were completed, and
the total replacements determined, Virginia Power would review this
problem in detail, and determine an appropriate course of action. The
actions to be taken would be sent to the inspectors for review.
DR S-97-0895 was written by. the licensee to address these issues.
On April 4, 1997, a response was provided to the inspectors in Region
II. This response addressed the high rejection level issue raised by*
the inspectors. The response also addressed wear-rates seen on the
feedwater components, which were somewhat higher than predicted either
by previous evaluation or by the CHECWORKS modeling: and that
conservatism currently utilized in the prediction of component life may
not be sufficient enough to consistently prevent the violation of code
minimum wall thickness.
As a result of these concerns, an action plan
was implemented by the licensee.
On April 9, 1997, the licensee
clarified the engineering positions relative to inspection scope.
expansion and the safety of the unit's piping systems in light of the
recent FAC findings. *On April 10, 1997, a conference call was held with
representatives from Virginia Power, at both the Surry Power Station and
the Innsbrook Technical Center, and the NRC to discuss the licensee's
submittal and their action plans. The NRC agreed that the licensee was
taking appropriate action at this time.
As part of their action plan for DR S-97-0895, the licensee had
contacted the Electric Power Research Institute (EPRI) to conduct a site
visit (tentatively May 5, 1997) to perform a technical engineering
review of the Virginia Power Secondary Piping Component Inspection
Program.
CHECWORKS databases, system models and outage data have
already been transmitted to EPRI for review.
NRC personnel considered
this was a good action taken by the licensee. However, the licensee was
notified that when the EPRI assessment of the Unit 1 FAC program was
comp 1 eted, Region II wi.11 conduct an inspection at the Innsbrook
Technical Center to review the licensee's progress on each of the action
items addressed in the response,to DR S-97-0895.
c. Conclusions
Virginia Power Company has approximately 5000 components in the Unit 1
FAC program. Approximately 110 to 121 of these components are scheduled
each outage to be examined. A concern was expressed when high component*
replacement rates were experienced from the small sample of components.
examined.
The licensee issued DR S-97-0895 to address FAC concerns.
Licensee actions planned in response to this deviation were considered
good.
12
III. Engineering
El
Conduct of Engineering
El.1
RFO Modifications to Correct Long Standing Issues
a.
Inspection Scope (37551)
The inspectors reviewed two modifications which addressed longstanding
issues.
b. Observations and Finding
1.
2.
Unit 1 Steam Generator Channel Head Drain Replacement*
The licensee had experienced leakage from the Unit 2 steam
generator channel head drain. The corrective action was to remove
the drain line at the steam generator and replace it with a
stainless steel plug. Engineering developed Design Change Package
(DCP)95-046, "SG Channel Head Drain Isolation," to remove the
drain lines from the Unit 1 steam generators. The inspectors
reviewed DCP 95-046 including the safety review and the proposed
changes to UFSAR. Section 4.2.2.3.2.3. The work was controlled by
WOs 00337078-01, 02, and 03 for steam generators lA, 18, and lC
respectively. The inspectors reviewed completed WO 00337078-03
and procedure O-MCM-1801-01, "Piping, Components Repair and
Replacement," Revision 4.
The inspectors verified that applicable
sections of the procedure had been signed off and the WO closed
out.
Source Range Nuclear Instrumentation (NI) Detector Cabling
Replacement
The cables for both the intermediate and source range NI detectors
were replaced to reduce extraneous "noise" in the detectors. The
change was controlled by DCP 96-007.
On March 12, 1997, the N-31
detector was declared operable at 7:45 a.m., after completion of
post maintenance testing. However. the Raychem protector had not
been applied. At 12:30 p.m., a technician disconnected the cable
as he believed it would be easier to install the Raychem with the
cable disconnected. The control room was unaware that the N-31
cable would be disconnected.
The technicians notified the control
room of their actions and the detector was declared inoperable.
The Raychem was installed and the N-31 detector was declared
operable at 1:09 p.m., following satisfactory performance of
1-PT-1.1, "NIS Trip Channel Test Prior to Startup." The
technicians did not install the Raychem prior to acceptance
testing in the event that problems occurred during testing and the.
Raychem had to be removed.
The licensee determined that the
technician had not been briefed that the detector was energized.
DR 97-0709 was issued to follow the event .
13
The inspectors.reviewed DCP 96-007 and noted that the modification
was performed by Westinghouse. Westinghouse.procedures were used
to control the cable changeout.
The inspectors did not find any
cautions or directions relating to the sequence of installing the
1
Raychem.
The inspectors concluded that the event was caused by
poor communications.
c. Conclusions
The modification activities reviewed by the inspectors during the RFO
should correct two longstanding equipment deficiencies.
El.2 Unit 1 Letdown Line Orifice and Piping Replacement
a.
Inspection Scope (37551)
The inspectors reviewed the licensee's actions related to the
replacement of the Unit 1 letdown line piping and orifices.
b. Observations and Findings
On March 15, the licensee performed radiographic examinations on the
Unit 1 letdown orifices to check for a similar erosion condition
previou$ly seen on the B Unit 2 letdown orifice. Vibration testing of
the Unit 1 letdown lines performed at hot shutdown exhibited values
higher than those normally expected, but less that allowable.
The
results of the Unit 1 exam were as follows:
A 45 gpm Orifice: This orifice exhibited the most extensive
deterioration with its nominal 0.212 inch diameter being eroded to
an inside diameter of approximately one-inch over the last five
inches of the orifice. A microscopic examination of the sectioned*
orifice indicated the damage was caused by cavitation.
B 60 gpm Orifice: This orifice exhibited only minor erosion.
C 60 gpm Orifice: This orifice exhibited deterioration with its
nominal 0.242 inch diameter being eroded to. an inside diameter of
approximately one-half inch over the last one and one-half inches
of the orifice.
Based on the results of these examinations, the licensee replaced all
three orifices during the ongoing Unit 1 RFO.
In addition, the licensee
replaced the piping downstream of the orifices and inspected the letdown
isolation valves. The piping was fabricated with butt welds in lieu of
the existing socket welds.
The inspectors monitored the piping replacement act~vities. The
licensee has theorized that the erosion in the orifices in Unit 2 led to
increased vibration and ultimately cracking of the lines. Although Unit
1 has not experienced any letdown line cracking like those seen on
14
Unit 2, the licensee's action to replace the orifices and piping were
prudent.
c. Conclusions
Based on the deterioration seen in the Unit 1 letdown orifices following
radiographic examination, the licensee prudently replaced the orifices
and associated downstream piping during the 1997 Unit 1 RFO.
EB
Miscellaneous Engineering Issues (92902)
E8.1
(Open) LER 50-280/97001-00:
shutdown due to steam drain line weld leak.
This LER discussed the January 24, 1997, Unit 1 shutdown due to a
pinhole leak on a main steam drain line in the main steam valve house.
During the unit shutdown, both source range Nis failed after
energization. Section 4 (Immediate Corrective Actions) of this report
stated that the plant was borated to the cold shutdown condition. The
inspectors questioned the accuracy of this statement. The unit was
borated to hot shutdown conditions and shutdown margin was verified as
required by TSs.
Licensee management made a conscious decision not to
borate to cold shutdown conditions during the event. This item was
discussed with plant licensing personnel and plant management.
The
licensee agreed that the statement was not accurate and initiated a
revision to the LER to correct the matter. The inspectors identified an
example of an inaccurate LER submittal in the previous IR (50-280,
281/97002). This item is identified as Violation 50-280/97003-03. The
licensee incorporated corrective actions for this violation in their
response to the previous violation. This LER will re.Jin open pending
revision.
IV. Plant Support
Rl
Radiological Protection and Chemistry (RP&C) Controls
Rl.l Occupational Radiation Exposure Control Program
a.
Inspection Scope (83750)
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program during a segment of the Unit 1
RFO.
The review included observation of radiological protection
activities including pre.-work briefings, personnel exposure monitoring,
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.
15
b. 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 and the 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.
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 primary 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 a Personal Contamination
Monitor (PCM).
The inspectors discussed with the licensee the special procedures
implemented for releasing personnel from the RCA when xenon
contamination was suspected. The licensee provided the inspectors with
the following general description of the release process. Routine
decontamination procedures and release criteria were followed if an
individual alarmed the PCM at the RCA exit portal and the contamination
was determined to have been localized. If the PCM alarm was determined
to have been caused by generally uniformly distributed activity, then
additional surveys were performed to determine which radionuclides were
present. If the activity was found to be other than xenon, such as
cesium or cobalt. then additional decontamination was performed. If the
activity was found.to be xenon. the individual was surveyed with a hand
frisker to assure that the routine release criterion of 1000 dpm was
met. A release permit was then provided to the individual in the event
that the more sensitive portal monitor at the protected area exit point
were to alarm. Overall. the routine and special procedures assured that
any individual who alarmed the PCM was required to meet the routine
release criteria established for surveys by a hand frisker. The
16
licensee indicated that the special procedures were in effect for less
than two weeks due to the short half-life of xenon.
The inspectors reviewed As Low As Reasonably Achievable (ALARA) program
details. implementation. and goals for the Unit 1 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
inspectors noted that daily and cumulative projections were exceeded
early in the outage but by day 29 of the scheduled 39 day outage the
cumulative exposure was below the projected value.
During tours of the 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 licensee provided for the inspectors' review a copy of the Five-Year
Exposure and Low-Level Radwaste Management Plan .. The inspectors noted
that the plan consisted of the following four objectives: increase and
expand efforts in innovative technology application; continue source
term reduction efforts; continue waste generation reduction efforts; and
continue high worker awareness and improved job and outage planning: A
list of activities and implementing schedules for achieving those
objectives was also delineated in the plan.
c. Conclusions
Based on the above reviews. the inspectors concluded that the licensee
was properly monitoring and controlling personnel radiation exposure and
posting area radiological conditions in accordance with 10 CFR Part 20.
Rl.2 Radioactive Effluent Monitoring Instrumentation
a.
Inspection Scope (84750)
The inspectors reviewed licensee's procedures and records pertaining to
surveillances and"alarm setpoints for selected radioactive effluent
monitors.
The surveillance procedures and established alarm setpoints
were evaluated for consistency with the operational and surveillance
requirements for demonstrating the operability of the monitors. Those
requirements were specified in Sections 6.2.2 and 6.3.2 and Attachments
3 and 16 of VPAP-2103, "Offsite Dose Calculation Manual (ODCM)."
17
b. Observations and Findings
The inspectors toured the Control Room and relevant areas of the plant
with a licensee representative to determine the operational status for
the following effluent monitors:
RM*RRM-131
.l-GW-RM-102
1-VG-RM-110
RRM-101
Radwaste Facility Liquid Effluent Line
Process Vent Noble Gas Activity Monitor
Ventilation Vent Noble Gas Activity Monitor
Radwaste Facility Vent Noble Gas Activity
Monitor
The above monitors were found to be well maintained and operable at the
time of the tours.'
The inspectors reviewed the 14 procedures related to channel checks,
source checks, channel calibrations, channel functional tests, and alarm
setpoints for the above listed monitors.
The ir:spectors determined that
the procedures included provisions for performing the required
surveillances in accordance with the relevant sections of the ODCM and
at the specified frequencies. The inspectors also reviewed the most
recently completed surveillances for the above listed monitors. Those
records indicated that the surveillances were current and had been
performed in accordance with their applicable procedures. The
inspectors also verified that the alarm setpoints for the above listed
monitors were consistent with procedure HP-3010.040 and ODCM
requirements. The licensee indicated that effluent monitor percent
availability was not routinely tabulated, therefore, the inspectors
reviewed the licensee's 1996 maintenance history records for the above
listed monitors. Those records indicated that the monitors were very
seldom out of service except for scheduled preventive maintenance and
surveillance testing. The inspectors also discussed the licensee's
Radiation Monitoring Upgrade Program with the cognizant Project
Engineer.
The project included installation of new digital
display/controllers in the Control Room, installation of new detectors,
and wiring upgrades.
The licensee indicated that the project was 80
percent complete for Unit 1, 100 percent complete for Unit 2, and 50
percent complete for common systems.
The planned completion date for
the project is year end 1997.
During a tour of the Control Room the
licensee demonstrated for the inspectors the enhanced capabilities of
the new digital display/controllers. The inspectors determined that the
radiation.monitor upgrade project was a significant program improvement.
c. Conclusions
Based on the above reviews and observations, it was concluded that the
licensee was maintaining radioactive effluent monitoring instrumentation
in an operable condition and performing the required surveillances to
demonstrate their operability .
18
Rl.3 Meteorological Monitoring Program
a.
Inspection Scope (84750)
The inspectors evaluated implementation of the licensee's onsite
meteorological measurements program for consistency with the program
description contained in Section 2.2.1.2 of the UFSAR.
b. Observations and Findings
The inspectors reviewed meteorological surveillance procedures and
determined that they included provisions for performing daily channel
checks and semiannual channel calibrations. The inspectors also
reviewed the records for the.most recent instrument calibrations for
wind speed, wind direction, and air temperature which were performed
during November and December 1996. These records indicated that the
calibrations were current and had been performed in accordance with the
applicable procedures. During a tour of the Control Room, licensee
personnel displayed on a monitor the computerized log of the daily
channel checks performed for the previous 2 days.
The inspectors also
noted that the meteorological monitoring instrumentation was operable at
the time of the tour.*
c. Conclusions
Based on the above reviews and observations, the inspectors concluded
that the onsite meteorological measurements program was implemented in
accordance with the UFSAR.
Rl.4 Control Room Emergency Ventilation System
a.
Inspection Scope (84750)
The inspectors reviewed the licensee's procedures and records for the
surveillances required to demonstrate operability of the Control Room
Emergency Ventilation System (CREVS).
Those procedures and records were
evaluated for consistency with the operational and surveillance
requirements delineated in TSs 3.23 and 4.20.
b. Observations and Findings
The inspectors toured the Turbine Building, Control Room, Emergency
Switchgear and Relay Room, and Mechanical Equipment Rooms in which the
CREVSs were located. The licensee's cognizant system engineer
accompanied the inspectors on the tours. during which the major
components of the systems were located and identified. The emergency
ventilation systems included four independent units consisting of fans,
dampers, pre-filters, High Efficiency Particulate Air (HEPA) filters,
and charcoal adsorber filter beds.
The inspectors verified that the air
flow paths and arrangement of the system components within those paths
were consistent with the system diagram (Figure 9.13-3) referenced in
Section 9.13.3.6 of the UFSAR.
The inspectors observed that the
J
19
components and associated ductwork were well maintained structurally and
that there was no physical deterioration of the equipment or ductwork
sealants.
The inspectors reviewed selected ventilation system surveillance
procedures and determined the they included provisions for performing
functional tests, filter leak testing, air flow measurements.
differential pressure measurements. and charcoal adsorption efficiency
testing. The surveillance frequency and acceptance criteria for the
test results specified in those procedures were consistent with the TS
requirements.
Review of selected records of those tests, generally the
most recently completed, indicated that they had been performed in
accordance with the testing procedures and that the acceptance criteria
had been met.
c. Conclusions
Based on the above reviews and observations, the inspectors concluded
that the licensee was maintaining the CREVS in an operable condition and
they were performing the required surveillances to demonstrate
operability of the system.
Sl
Conduct of Security and Safeguards Activities (71750)
On numerous occasions during the inspection period, the inspectors
performed walkdowns of the protected area perimeter to assess security
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.
V. Management Meetings
Xl
Exit Meeting SU11111ary
The, inspectors presented.the inspection results to members of licensee
management at the conclusion of the inspection on April 25 and May 14, 1997.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
identified.
,J
20
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Blount, Superintendent, Maintenance
D. Christian, Station Manager
M. Crist, Superintendent, Operations
J. McCarthy, Assistant Station Manager, Operations & Maintenance
B. Shriver, Assistant Station Manager, Nuclear Safety & Licensing
T. Sowers, S~perintendent, Engineering
B. Stanley, Director, Nuclear Oversight
W. Thorton, Superintendent, Radiological Protection
NRC
N. Diaz, Commissioner, Nuclear Regulatory Commission
L. Reyes, Regional Administrator, Region II
IP 37551:
IP 40500 :.
IP 49001:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 73753:
IP 83750:
IP 84750:
INSPECTION PROCEDURES USED
Onsite Engineering
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
Occupational Exposure
Radioactive Waste Treatment and Effluent and Environmental
Monitoring
ITEMS OPENED, CLOSED. AND DISCUSSED
Opened
50-280/97003-01
Loss of refueling containment
integrity (Section 01.2).
50-280/97003-02
50-280/97003-03
Closed
50-281/95001-00
LER
Failure to follow maintenance
procedure (Section Ml.l).
Failure to meet the requirements of
10 CFR 50. 9 (a) for LER 50-
280/97001-00 (Section E8.l).
Pressurizer heatup exceeded TS limit
due to lack of procedural control
(Section 08.1).
50-281/95-06-02
50-280/97006-00
Discussed
50-280/97001-00
LER
LER
21
Pressurizer heatup rate exceeded TS
limits of 100° F/hour (Section
08.2).
Loss of refueling integrity due to
inadequate containment closure
process (Section 08.3).
Shutdown due to steam drain line
weld crack (Section E8.l) .