ML18152A341
| ML18152A341 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/21/1994 |
| From: | Branch M, Tingen S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A342 | List: |
| References | |
| 50-280-94-17, 50-281-94-17, NUDOCS 9408090310 | |
| Download: ML18152A341 (17) | |
See also: IR 05000280/1994017
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.: 50-280/94-17 and 50-281/94-17
Licensee: Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted: June 5 through July 2, 1994
Inspectors:
- L.c.J ~
~
S. G. Tingen, ~Inspector
Accompanying Personnel:
D. M. Tamai
Approved by:
f )( k- ~
G. A. B~lisle, ~
Reactor Projects Section 2A
Division of Reactor Projects
SUMMARY
Scope:
?.-:J-1- Cf 'f
Date Signed
?- )-/-9r
Date Signed
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance and surveillance
inspections, and action on previous inspection items.
Inspections of
backshift, holiday, and weekend activities were conducted on June 6, 16, 24,
and 25 and July I.
Results:
Operations functional area
Command and control, use of procedures, and the quality of startup procedures
utilized during the Unit 2 startup were good {paragraph 3.4).
9408090310 940721
PDR .ADOCK 05000280
G
2
The failure to secure closed a Unit 2 makeup water isolation valve within 15
minutes after makeup as required by technical specification 3.2.F was
identified as a violation (paragraph 3.5).
Maintenance functional area
The Unit 2 steam generator chemical cleaning was well managed and the
contractor oversight provided by the licensee during this evolution-was
excellent (paragraph 3.3).
In the last 18 months, the Unit 1 and 2 turbine driven auxiliary feedwater
pumps have tripped on overspeed on 5 different occasions.
The corrective
actions for each of the overspeed trip events were considered reasonable.
Root Cause Evaluation 93-25 was being re-opened to further evaluate governor
valve binding (paragraph 4.1).
Actions previously implemented to correct deficiencies associated with foreign
material exclusion (FME) control did not preclude repetition. Three examples
where personnel did not maintain FME controls in accordance with the station
FME program were identified as a violation (paragraph 4.2).
Engineering functional area
Two accident analyses reviewed in conjunction with the Design Basis Document
for the Auxiliary Feedwater and Safety Injection Systems contained assumptions
that were not bound by operational practices.
An Inspection Followup Item was
identified to track resolution (Paragraph 5.2).
. *.*
~ ..
REPORT DETAILS
1.
Persons Contacted
I.I Licensee Employees
- R. Bartnikowski, Supervisor, Mechanical Maintenance
- W. Benthall, Supervisor, Licensing
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D. Christian, Assistant Station Manager
- J. Costello, Station Coordinator, Emergency Preparedness
- R. Cross, Coordinator, Nuclear Procedures
- J. Downs, Superintendent of Outage and Planning
- D. Erickson, Superintendent of Radiation Protection
A. Friedman, Superintendent of Nuclear Training
- S. Hall, Mechanical Maintenance
- W. Harrell, Vice President, Nuclear Engineering
B. Hayes, Supervisor, Quality Assurance
- D. Hayes, Superintendent of Administrative Services
- M. Kansler, Station Manager
C. Luffman, Superintendent, Security
J. McCarthy, Superintendent of Operations
- J. McGinnis, Station Nuclear Safety
A. Price, Assistant Station Manager
- R. Saunders, Vice President, Nuclear Operations
- K. Sloan, Supervisor, Operations Support
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- J. Swientoniewski, Supervisor, Station Nuclear Safety
- G. Thompson, Supervisor, Maintenance Engineering
G. Woodzell, Nuclear Training
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics,
security force members, and office personnel.
1.2
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingenj Resident Inspector
- D. Tamai, Intern
- Attended Exit Interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph .
2
2.
Plant Status
3.
Unit 1 operated at power for the entire inspection period.
Unit 2 was in cold shutdown at the beginning of the inspection period to
perform SG chemical cleaning. This chemical cleaning was necessary to
remove corrosion deposits/flow blockage from the SG tube support plate
area that was causing level oscillation problems in the C SG.
After the
chemical cleaning, the unit returned to power operations on June 25 and
operated at 100% power throughout the remainder of the period without
experiencing SG level oscillations.
Operational Safety Verification (71707, 37551)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability. Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
3.1
Biweekly ESF Inspections
3.1.1 Unit 1 AFW System
The inspectors walked down the Unit 1 AFW piping located in
the safeguards building following maintenance performed on
the turbine driven AFW pump on June 15 and 16.
Valve
positions, piping temperatures, snubber oil levels and
general component conditions were inspected.
The inspectors
concluded that the system was operable and in good material
condition.
3.1.2 Unit 2 AFW System
An inspection of the AFW system was conducted.
The
inspectors walked down piping in containment and pumps and
piping in the safeguards building. Valve position, snubber
condition, and material condition of the equipment were
inspected. The inspectors concluded that the system was
operable and in good material condition .
3
3.2
Unit 2 RCS Draindown to 18.3 Feet
On June 6, the inspectors witnessed draining the Unit 2 RCS from a
level of 5% in the pressurizer (approximately 29.0 feet) to a
level of 18.3 feet in the reactor vessel. Draining the RCS system
to this level was required to support installing pressurizer
safety valve loop seal drain lines. This evolution was
accomplished in accordance with section 5.7 of 2-0P-RC-004,
Draining the RCS to Reactor Flange Level, revision 2.
During the
initial drain down phase, pressurizer level was monitored.
During
the draindown from 0% level in the pressurizer (approximately 27.5
feet) to the 24 foot level on the reactor vessel standpipe,
indication was not on scale and an inventory balance was utilized
to determine the amount drained from*the RCS.
Upon reaching the
24 foot level, the reactor vessel standpipe was utilized to
monitor RCS level. The inspectors monitored the rate of
increasing level in the boron recovery tank, seal injection flow
rate and letdown flow rate during the evolution where inventory
balancing was required.
The inspectors also verified that once
RCS level was in the range of the reactor vessel standpipe, main
control board indication of RCS level agreed with the local
standpipe indication.
No discrepancies were noted.
Prior to placing the reactor vessel standpipe in service, the
inspectors accompanied the system engineer and operations engineer
on a walkdown of the portion of the standpipe assembly that vents
the reactor head to the top of the pressurizer. The purpose of
this walkdown was to identify conditions that could create false
reactor vessel indication on the standpipe.
In a letter to the
NRC dated April 8, 1994, the licensee committed to review the
Unit 2 reactor vessel standpipe installation prior to placing it
into service. This commitment was generated due to perturbations
in Unit 1 reactor vessel standpipe level indication which were
discussed in NRC Inspection Reports Nos. 50-280, 281/94-02.
No
problems were identified during the walkdown and no perturbations
in the Unit 2 reactor vessel standpipe level indication occurred
while the system was inservice during the draindown evolution.
3.3
Unit 2 SG Cleaning Activities
The inspectors monitored activities associated with chemically
cleaning the secondary sides of the Unit 2 SGs.
SG cleaning
activities were accomplished by contractors. Chemical cleaning
involved a 3-step stage/process. Step 1 included injecting and
recirculating a copper solvent solution at 95 degree F followed by
a SG rinse. Step 2 included injecting and recirculating an iron
solvent solution at 195 degrees F followed by a SG rinse. Step 3
repeated the step 1 copper solvent process.
Following this
process, each SG was drained and refilled with water several times
to ensure that all chemicals were removed.
Throughout the
cleaning process, high pressure nitrogen was injected into the SG
to increase turbulence. After completing chemical cleaning, each
3.4
4
SG was drained and sludge lancing was performed.
The final
estimates, in pounds, of removed materials were:
Sludge
SG A
350
2600
1258
SG B
470
3050
984
SG C
500
3900
610
Once the actual cause of level oscillation in the C SG was known,
the licensee rapidly assembled a dedicated team of both plant and
contractor personnel for the project. This team completed the
project ahead of schedule and without impacting other scheduled
activities. Extensive briefings were held and video records were
assembled to share information gained with others in the industry.
The inspectors concluded that evolutions associated with the
Unit 2 SG chemical cleaning were well managed, and that the
contractor oversight provided by the licensee during this
evolution was excellent.
The inspectors also reviewed SE 94-115, Unit 2 Steam Generator
Chemical Cleaning.
The SE required that each reactor coolant loop
be drained and isolated during the chemical cleaning process.
This was primarily because a SG temperature of 195 degrees F was
required to perform the iron removal phase and that TSs required
containment integrity to be established when RCS temperature
exceeded 200 degrees F.
With the loop drained, RCS temperature
could be maintained well below 200 degrees F and the SG could be
heated up to the desired temperature without the need to establish
containment integrity.
No discrepancies were noted with the SE.
Unit 2 Startup
On June 24 and 25, the inspectors witnessed the Unit 2 startup.
Evolutions monitored were taking the unit critical, opening the
MSTVs, turbine driven AFW pump testing, placing the turbine in
service and transferring control of FW regulating valves from
manual to automatic control. The only significant equipment
problem that occurred during the startup was that the A loop delta
T indication corresponded to 10% power when the reactor was at 2%
power.
The channel was declared inoperable and placed in trip as
required by TSs.
The startup was delayed while technicians
attempted to repair the channel. Technicians were unable to
repair the channel and the startup was resumed with the A loop
delta Tin trip.
An RTD lead imbalance was later identified as
.
the cause of the channel not indicating properly and was repaired
after the unit was placed on line. The inspectors concluded that
command and control, use of procedures, and quality of startup
procedure were good .
5
3.5
Isolating Makeup Water to the RCS During Cold Shutdown
On June 17, 1994, following a makeup evolution to the RCS, the
primary water isolation valve was not secured closed.
requires during cold shutdown and refueling conditions that valve
2-CH-223 or valves 2-CH-212, 215, and 218 be locked, sealed or
otherwise secured closed except during planned boron dilution or
makeup activities. Following a planned dilution or makeup
activities, the valve{s} must be secured closed within 15 minutes.
The licensee was operating with 2-CH-223 open and 2-CH-212, 215,
and 218 secured closed. At 12:11 p.m., makeup activities were
initiated. The control room operator notified the auxiliary
building operator to open 2-CH-212.
After terminating makeup
activities at 12:14 p.m., the valve was not closed. The incorrect
valve position was not discovered until 4:22 p.m. when the next
shift requested the valve to be opened for makeup activities.
Operations identified that a violation of TS 3.2.F had occurred.
They initiated a DR, and requested chemistry to measure the RCS
boron concentration to ensure that a dilution had not occurred.
The inspectors reviewed the event and concluded that the following
factors contributed to exceeding the 15 minute TS limit:
Two control room operators were overseeing a trainee
performing the makeup.
The control room operators failed to
control the trainee's actions and the makeup evolution.
A procedure did not exist for makeup activities during cold
shutdown conditions. This was considered a skill of the
craft evolution.
The purpose of the TS is to prevent an inadvertent boron dilution
of the RCS during cold shutdown or refueling conditions.
As immediate corrective actions, trainee manipulations of control
board switches were suspended, and the trainees were prohibited
from communicating instructions to the field operators. The
corporate fuels division performed an analysis to demonstrate that
an alarm would actuate early in the dilution allowing control room
operators adequate time to prevent a criticality. The inspectors
reviewed the analysis and concluded the results were satisfactory.
The licensee indicated that a procedure was being written for
makeup activities during cold shutdown and refueling conditions.
The licensee currently intends for the procedure to include a
pre-evolution briefing and logging of critical steps including
compliance with the 15 minute TS requirement.
On June 17, 1994, valve 2-CH-212 was open for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
and 8 minutes following makeup activities. This exceeded the 15
minute TS limit by 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> and 53 minutes.
The failure to close
and secure 2-CH-212 within 15 minutes following a makeup activity
while in a cold shutdown condition in accordance with TS 3.2.F was
6
identified as VIO 50~281/94-17-01, Failure to Close Unit 2 Makeup
Water Isolation Valve*Within 15 Minutes After Makeup.
Within the areas inspected, one violation was identified.
4.
Maintenance And Surveillance Inspections (62703, 61726)
During the reporting period, the inspectors reviewed the following
maintenance/surveillance activities to assure compliance with the
appropriate procedures.
4.1
Unit 1 Turbine Driven AFW Pump Maintenance/Testing
On June 15, the Unit 1 turbine driven AFW pump, l-FW-P-2, tripped
on overspeed while performing monthly test, l-OPT-FW-003, Turbine
Driven AFW Pump l-FW-P-2, revision 3.
The pump was declared
inoperable and a 72-hour LCO was entered in accordance with TS 3.6.F. Later that same day, the pump was restarted to investigate
the cause of the overspeed trip. The inspectors witnessed the
second start of the pump and noted.that the pump started and
operated satisfactorily.
WO 291712-01 was initiated to investigate/repair the turbine
governor valve.
The inspectors witnessed this maintenance which
was accomplished in accordance with procedure O-MCM-0401-01,
Valves & Traps in General, revision 2.
The governor linkage was
disconnected from the governor valve and mechanics manually
exercised the governor valve stem.
The stem was identified as
sticking/binding when manually exercised. The governor valve
bonnet was then disassembled and the bonnet components were
inspected.
The stem was slightly bent and approximately 80% of
the carbon packing bushings were broken into two or more pieces.
A hard deposit buildup was also identified *on the stem at the
pa~king area. A new bonnet, stem, and packing bushings were
installed.
Following the new bonnet, stem and packing bushing installation,
the inspectors under the supervision of the licensee manually
exercised the stem and noted that the stem moved freely with no
binding or sticking. The stem was then connected to the turbine
governor linkage and the turbine driven AFW pump was tested in
accordance with l-OPT-FW~003.
The inspectors witnessed this
testing and the pump operated satisfactorily. After completing
the test, the pump was declared operable and the TS 3.6.f 72-hour
LCO was exited.
Unit 2 was in CSD when the turbine driven AFW pump failure
occurred on Unit l; therefore, the Unit 2 turbine driven AFW pump
could not be started to verify operability. However, the Unit 2
turbine governor linkage was disconnected from the governor valve
and mechani~s manually exercised the governor valve stem.
The
-
7
stem was identified as stuck and could not be manually exercised.
The governor valve bonnet was then disassembled and the bonnet
components were inspected. A hard deposit buildup was also
identified on the stem at the packing area. A new stem and
packing bushings were installed. After the unit was restarted,
the inspectors witnessed the Unit 2 turbine driven AFW pump
testing in accordance with 2-0PT-FW-003.
The pump started and
operated satisfactorily during testing.
The inspectors reviewed the operational history for Unit 1 and 2
turbine driven AFW pumps and noted that since January 1993, these
pumps have oversped five times during surveillance testing.
On
January 15, 1993, the Unit 2 turbine driven AFW pump tripped on
overspeed after being started for a monthly surveillance test.
On
March 26, 1993 the Unit 1 turbine driven AFW pump tripped on
overspeed after being started for a monthly surveillance test.
The cause of these failures was attributed to failure of the steam
trap located in the turbine steam supply piping to each individual
turbine. These events and corrective actions were discussed in
NRC Inspection Report Nos. 50-280, 281/93-07.
On December 2, 1993, the Unit 1 turbine driven AFW pump tripped on
overspeed after being started for a monthly surveillance test.
The governor valve linkage was disconnected and the stem was
checked for freedom of movement.
The valve stem was found to be
stuck in the open position. The governor valve bonnet, stem and
packing were replaced. This event was discussed in NRC Inspection
Report Nos. 50-280, 281/93-26.
RCE 93-25 was performed in order
to determine the cause of the failure.
RCE 93-25 concluded that pitting corrosion and mineral deposits on
the valve stem caused the valve stem to bind with the packing
materials in the bonnet.
The RCE also concluded that the mineral
deposits were possibly the accumulation of mineral residue from
moisture carryover over a long period of time (five to six years).
The RCE referenced a report by the governor valve manufactures,
Dresser Industries, dated March 24, 1993, that stated that there
had been a few nuclear plants exhibiting corrosion related valve
stem binding. The report stated that the environment of the
governor valve was critical and that a dry environment for stem
and packing assembly was desired when the equipment was not
operating.
RCE 93-25 implemented modifications to enhance draining moisture
from the governor valve packing area and a PM item to periodically
inspect governor valves stems in each unit every refueling outage.
The RCE also implemented a program to monitor and trend governor .
valve position and turbine speed ramp rate on a quarterly basis.
The RCE recommended that the turbine driven AFW pumps in both
units continue to be tested monthly because stroking the governor
valve might assist in reducing or controlling the mineral deposit
buildup on the stem.
8
The inspectors reviewed the surveillance tests completed after
December 2, 1993, on the Unit 1 turbine driven AFW pump.
On
December 3 and 29, 1993, the pump was satisfactorily tested.
On
January 22, 1994, Unit 1 was shutdown for a RFO and restarted on
March 24, 1994.
On March 25, 1994, the Unit 1 turbine driven AFW
pump tripped on overspeed after being started for the first time
since December 29, 1993.
The Unit 1 turbine driven AFW pump
operated satisfactorily on the second and third starts.
No
additional corrective action was performed and the pump was
determined to be operable. The failure was attributed to air
introduction into the governor during periodic maintenance
performed during the outage.
On April 21, and May 14 and 18,
1994, the Unit 1 turbine driven surveillance tests were
satisfactorily performed.
On May 11, the Unit 1 turbine driven
AFW pump automatically started and operated as designed after the
reactor was manually tripped. However, on June 15, the Unit 1
turbine driven AFW tripped on overspeed while performing the
monthly surveillance test.
The inspectors also reviewed the surveillance test performed on
the Unit 2 turbine driven AFW pump completed since January 12,
1994.
On January 12, February 9, March 10, April 6 and May 4, the
Unit 2 turbine driven AFW pump surveillance tests were
satisfactorily performed. There were no indication of the
governor valve binding subsequently discovered in June 1994.
At the end of the inspection period the licensee was in the
process of re-opening RCE 93-25 in order to reevaluate the root
cause of governor valve binding.
To ensure that the turbine
driven AFW pumps remain operable while correctives actions are
developed and implemented, the licensee was inspecting the
governor valve stems in both units weekly for a hard deposit
buildup and were continuing to perform surveillance testing at a
monthly frequency.
The inspectors concluded that the corrective
actions for each of the five Unit 1 and 2 turbine driven AFW pump
failures were reasonable.
The inspectors will continue to monitor
the licensee's actions in this area.
4.2
FME Control Deficiencies
VPAP-1302, Foreign Material Exclusion Program, rev1s1on 5,
specifies requirements to prevent foreign material, such as
maintenance residue, dirt, debris, and tools from entering open
systems or components.
During the inspection period, the
following examples were identified where VPAP-1302 requirements
were not adhered to during maintenance performance.
On June 10 the inspectors toured the Unit 2 containment.
When walking down the design change to install drain lines
on the pressurizer safety valve loop seals, the inspectors
noted that openings in the piping on the bottom of the A and
C pressurizer safety valve loop seal drain line penetrations
=..:=-..::=..:===-:==--=-=--=-=-=--=-=--=--==-=-=== ~-- - ----
9
did not have FME covers installed. Maintenance in the area
was not in progress when this condition was identified. It
appeared that at one time the openings had been taped over,
but the tape was not attached to the piping when the
inspectors walked down the area. The inspectors notified
the licensee of this condition and FME covers were
installed.
DR S-94-1232 was issued documenting that the FME
control boundary was violated.
During the Unit 2 outage, the A pressurizer safety valve was
removed and a wire mesh screen installed over the opening.
This configuration provided a vent path for the reactor
coolant system in accordance with TS 3.1.G.l.b.(5).
On
June 17 an operator noted that the FME cover installed over
the A pressurizer safety valve flange was not adequately
attached. Personnel had breached the cover to install a
purge hose for welding the loop seal drain line modification
and did not properly secure the cover following purge hose
installation. After this condition was identified the FME
cover was properly attached and DR S-94-1280 issued.
On June 21, the component cooling heat exchanger 1-CC-E-lA
was determined to be inoperable while performing
surveillance l-OSP-SW-002, Measurement of Macrofouling
Blockage of Component Cooling Heat Exchanger 1-CC-E-lA,
revision 4.
The procedure's SW flow rate acceptance
criterion would not be met.
On June 22 the SW side of the
heat exchanger was opened for inspection and a 14-inch by
64-inch piece of plywood, tape, and wire mesh used for
scaffolding were found in the tube sheet area. It was
concluded that the scaffolding material was left in the heat
exchanger after it was cleaned on June 16.
DR S-94-1323 was
issued documenting that materials were found in the heat
exchanger.
The materials were removed and the heat
exchanger was satisfactorily tested in accordance with
l-OSP-SW-002.
The first two examples involving improper FME controls involved a
design change performed in accordance with DCP 92-044, Pressurizer
Safety Valve And Loop Seal Modification - Surry Unit 2, dated
May 3, 1994.
DCP 92-044 invoked GMP-M-152, Fabrication and
Installation of Piping, revision 2. Step 6.1.4 of GMP-M-152
required that FME be established in accordance with VPAP-1302.
Paragraph 6.3 of VPAP-1302 requires that system openings be
covered with temporary covers when leaving the work area
unattended to prevent intrusion of foreign material.
Heat exchanger 1-CC-E-lA had been cleaned in accordance with
procedure MMP-C-HX-277, Tube Sheet and Channel Cleaning For
Bearing and Component Cooling Heat Exchangers, revision 1. Step
4.1 of MMP-C-HX-277 required that system cleanliness be maintained
and QC closeouts be performed prior to closing the system.
10
VPAP-1302 was invoked to maintain cleanliness and perform the QC
closeout. Step 6 of VPAP-1302 required that a FME control log be
maintained and that this log be reviewed prior to closing a system
to ensure that all articles introduced to the system during the
maintenance were removed and accounted for. Step 6.4 required
that the system be inspected for debris and tools prior to closing
the system.
The inspectors reviewed the completed copy of
MMP-C-HX-277 and noted that the FME Control Log was annotated that
all the material was removed from the heat exchanger prior to the
final closeout. After further investigation it was concluded that
the scaffolding material had not been removed.
On April 29, 1992, Violation 50-280/92-07-93 was issued for
failure to prevent foreign material from entering the SW system
during maintenance.
The corrective action for this violation
focused on issuing VPAP-1302 which established station-wide FME
controls applicable to implementing design change packages, as
well as, performing maintenance activities. The inspectors
previously reviewed VPAP-1302 and considered that it provided
adequate instructions but FME deficiencies have continued to
occur.
The inspectors reviewed DRs dating from December 1992 to
June 1994 and noted seven examples in addition to the ones
previously discussed where personnel did not follow station
procedures for maintaining FME control.
In addition, NRC
Inspection Report Nos. 50-280, 281/94-08 identified a weakness in
the area of FME control.
The inspectors concluded that the actions previously implemented
to correct deficiencies associated with FME controls did not
preclude repetition. 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action, requires that when a significant condition
adverse to quality is identified, the cause of the condition is to
be determined and corrective action taken to preclude repetition.
The failure to implement corrective actions to preclude FME
deficiency repetitions was identified as VIO 50-280, 281/94-17-02,
Failure to Implement Corrective Actions to Preclude Repetition of
FME Deficiencies.
Within the areas inspected, one violation was identified.
5.
Action on Previous Inspection Items (92701, 92702)
5.1
(Closed) URI 50-280/94-02-03, Evaluation of Pressurizer Hydrogen
Burn. This issue involved corrective actions taken to prevent the
hydrogen burn from recurring.
In a letter dated April 8, 1994 the
licensee responded to the URI and outlined corrective actions to
prevent recurrence. The inspectors verified that necessary
actions were taken during the Unit 2 outage to prevent hydrogen
burn during shutdown operations and pressurizer modifications.
The licensee procured new explosive meters to sample for explosive
gasses in an oxygen poor atmosphere. Training briefs for the new *
meters were given to the contractors performing the pressurizer
11
modification work. Training on using the new meters was
incorporated into the welder's craft training and is planned to be
included in the confined space entry training as well. Procedures
were updated for shutdown, pre-job briefs, PRT operations,
removing pressurizer safety valves, and welding and cutting
procedures for piping and instrumentation systems. Special work
instructions were written to address pressurizer modification
welding and cutting during the outage. The licensee continues to
evaluate the need for further enhancements on shutdown and
degasification procedures.
The inspectors reviewed the licensee's
committed corrective actions and consider this URI closed.
5.2
(Closed) URI 50-280, 281/93-07-01, Evaluation of DBD Program.
This issue involved a NRC concern that system DBDs at both Surry
and North Anna contained large numbers of open punchlist items
that may involve safety issues that should be promptly reviewed
and resolved.
On an average, 180 open punchlist items were
identified for each of the nine system DBDs developed as part of
the group 1 effort.
Meetings were held with the licensee to discuss the NRC concern
expressed above.
The licensee reviewed the specific issues
addressed in North Anna NRC Inspection Report Nos.
50-338, 339/92-32 associated with the RSS and determined that the
open items had been screened for safety significance in accordance
with the DBD program.
However, the licensee did realize from this
second review that documentation of their screening and decision
process could be improved. This realization prompted the licensee
to perform a more formal re-review of all open punchlist items.
The inspectors reviewed both the licensee's screening criteria for
open punchlist items and their re-review of all open punchlist
items for two of the nine Group 1 systems, which had completed
DBDs.
The systems selected by the inspectors for review were the
The licensee's screening criteria placed open items into 1 of 3
categories. The Immediate Category included both operability or
safety concerns which required prompt resolution as well as
missing critical calculations which required reconstitution within
30 days.
The Intermediate Term Category was defined as not an
immediate concern, but should be resolved in the interest of
having a quality body of design information.
The last category,
the Resolve If Needed Category included items that would be
resolved only if necessary to support future design or for
operational support. If properly applied and documented, the
criteria appeared to the inspectors to be appropriate. However,
it should be recognized that those items in the Resolve If Needed
Category may never be closed since they represent a low priority
for the licensee's DBD group.
The licensee is evaluating how the
DBD project can be closed with the low priority open items
remaining open.
12
The inspectors determined, based on a sampling of resolved and
remaining open items, that the licensee's re-review of the initial
open items from the Group 1 revision O DBDs was effective. This
additional effort resulted in both reducing the number of open
items, as well as, providing documented evidence that no safety
issues remain open fqr an extended period of time.
Based on
statistics provided by the licensee, approximately 33% of the 1670
initial open items were resolved leaving approximately 1092 still
open. Approximately 50% of the remaining open items are in the
Resolve If Needed Category.
The inspectors' review of the two DBDs above did however identify
two accident analyses that contained assumptions that were not
_bounded by operational practices. The item identified while
reviewing the SI system involved standard operating practices that
allowed the RWST temperature to go below the 40 degrees F value
assumed in the steam break analysis (Calculation SM-191, Main
Steamline Break Response Assuming No Boron in the Boron Injection
Tank for Surry Power Station with Offsite Power Available, Using
the RETRNPOl Code, dated July 1983}.
Based upon another issue,
the licensee had issued a standing order to operations to maintain
the RWST temperature above the 40 degree minimum temperature.
Based on the inspectors' concerns, the licensee issued a DR which
prompted performing a sensitivity study as to the impact of colder
RWST water on the steam break accident analysis. The result of
calculation SM-0942, Evaluate the Impact of Reducing the RWST
Minimum Temperature from 40 degrees F to 38 degrees Fon the MSLB
and LOCA Analyses for Surry Power Station, dated July 1994 were
summarized in a July 6, 1994, memo from K.L. Basehore (NAF} to
W.R. Benthall (Surry Licensing).
The July 6, 1994 memo indicated
that the MSLB calculation of record (SM-191) contained several
conservative assumptions.
The calculation assumed that a BIT full
of non-borated water was injected into the core. This is
impossible since the BIT no longer exists. The memo indicated
that conservatism in the calculation more than offset the minimal
effect of reduced RWST water temperature on core activity. The
inspectors will review calculation SM-0942 when available.
The item identified while reviewing the AFW system involved the
ability of one AFW pump's flow (350 GPM) to remove sufficient heat
with the RCPs operating. Safety analysis (NFE Technical Report
No. 204, Surry Loss of Normal Feedwater Analysis Using RETRANO 1,
dated July 1981) assumes that the RCPs are tripped.
However, EPs
1,2-E-O, Reactor Trip or Safety Injection, revision 14 and ES-0.1,
Reactor Trip Response, revision 12 do not instruct the operator to
trip the RCPs to preclude a loss of heat sink.
Upon loss of the
heat sink, the EPs do provide steps to shutdown the RCPs.
At the time of the analysis the action statements of the Surry TS
allowed unit operations with only I operable AFW pump.
A TS
.
amendment was requested to no longer allow unit operations with I
The amendment was approved by NRC letter dated
.
.*
~-------
-~ -__ .,,:,. -------~~
13
April 27, 1982.
The inspectors reviewed the data provide by the
licensee and found it acceptable.
However, the safety analysis of
record did not reflect the licensee's efforts since the safety
analysis was performed and the DBD also did not provide a complete
record of issue resolution. The licensee is reviewing the basis
for the values and the information contained in the EPs to
determine if earlier RCP tripping with only one AFW pump operating
would be prudent. The inspectors will continue to follow this
item.
Resolution of these two specific items, as well as, reviewing
other analyses for unverified assumptions was identified as
IFI 50-280, 281/94-17-03, Followup on Unverified Assumptions in
Accident Analyses.
5.3
(Closed) IFI 50-280/94-12-0l, Interpretation of TS 3.6.D. This
issue involved TS requirements for CST MCR level indication.
The
NRC staff review of TSs 3.6.D and 3.6.B.2 concluded that CST level
indication was not required by TSs.
TSs only require MCR
indication for AFW system valve alignment for feedwater flow to
the SGs.
Within the areas inspected, no violations or deviations were identified.
6.
Exit Interview
The inspection scope and findings were summarized on July 6, with those
persons indicated in paragraph 1.
The inspectors described the areas
inspected and discussed in detail the inspection results addressed in
the Summary section and those listed below.
Item Number
VIO 50-281/94-17-01
VIO 50-280, 281/94-17-02
URI 50-280, 281/93-07-01
URI 50-280/94-02-03
IFI 50-280/94-12-01
Status
Open
Open
Closed
Closed
Closed
Description/(Paragraph No.}
Failure to Close Unit 2 Makeup
Water Isolation Valve Within
15 Minutes After Makeup
(paragraph 3.5).
Failure to Implement
Corrective Actions to Preclude
Repetition of FME Deficiencies
(paragraph 4.2).
Evaluation of DBD Program
(Paragraph 5.2).
Evaluation of Pressurizer
Hydrogen Burn (paragraph 5.1).
Interpretation of TS 3.6.D
(paragraph 5.3).
_cc_--..c-"-- --
Item Number
IFI 50-280, 281/94-17-03
14
Status
Open
Description/(Paraqraph No.}
Followup on Unverified
Assumptions in Accident
Analyses {paragraph 5.2).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
7.
Index of Acronyms and Initialisms
BIT
CFR
CSD
DR
F
GPM
IFI
LCO
MSTV
NAF
NRC
BORON INJECTION TANK
CODE OF FEDERAL REGULATIONS
COLD SHUTDOWN
CONDENSATE STORAGE TANK
DESIGN BASIS DOCUMENT
DESIGN CHANGE PACKAGE
DEVIATION REPORT
EMERGENCY PROCEDURES
ENGINEERED SAFETY FEATURE
FAHRENHEIT
GALLONS PER MINUTE
INSPECTION FOLLOWUP ITEM
LIMITING CONDITIONS OF OPERATION
LOSS OF COOLANT ACCIDENT
MAIN CONTROL ROOM
MOTOR OPERATED VALVE
MAIN STEAM LINE BREAK
MAIN STEAM TRIP VALVE
NUCLEAR ANALYSIS & FUELS
NUCLEAR REGULATORY COMMISSION
PREVENTIVE MAINTENANCE
PRESSURIZER RELIEF TANK
PERIODIC TEST
QUALITY CONTROL
ROOT CAUSE EVALUATION
REACTOR COOLANT PUMP
REFUELING OUTAGE
RECIRCULATION SPRAY SYSTEM
RESISTANCE TEMPERATURE DETECTOR
REFUELING WATER STORAGE TANK
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SAFETY EVALUATION
SAFETY INJECTION
15
T
TEMPERATURE
TS
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
VIOLATION
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER