ML18152A225
| ML18152A225 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 05/30/1989 |
| From: | Fredrickson P, Holland W, Larry Nicholson, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A226 | List: |
| References | |
| 50-280-89-13, 50-281-89-13, NUDOCS 8906190159 | |
| Download: ML18152A225 (19) | |
See also: IR 05000280/1989013
Text
.*.
Report Nos.:
50-280/89-13 and 50-281/89-13
Licensee:
Virginia Electric and Power Company
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
Inspection Conducted:
April 2 - 29, 1989.
Inspectors: ~~
?'S(C
W. E. Holland, Seniorsidentlnspector
~~&~<<?
L. E. Nichols~Resident'nspector
Approved by:
V,,,.
~tJ,1~
a/
J. W. York, Resident Insp~
~~~-/b;
P. E. Fredrickson, Ac
ng Branch Chief
Division of Reactor
jects
SUMMARY
Scope:
§-2.1£-.P7
Date Signed
S*-..26-%7
Date Signed
s-2<!.'-57/
Date Signed
S"$cJ-8:9:
Date Signed
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, licensee event report
review, and followup on inspector identified items.
A special evaluation of
the licensee's program which was used to walk down selected systems prior to
unit(s) restart was documented in the last three resident reports and this
inspection effort continues in this inspection report.
Certain tours were conducted on backshifts or weekends.
Backshift or weekend
tours were conducted on April 3, 9, 15, 23, and 26, 1989.
Results:
During this inspection period, no violations were identified. The licensee's
ongoing ope rational readiness p_rogram appears to be addressing a 11 necessary
items for Un:t 1 restart .
890~190159
ADOCK
G
890530
05000280
PNU
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- R. Blount, Superintendent of Technical Services
D. Christian, Assistant Station Manager
D. Erickson, Superintendent of Health Physics
- E. Grecheck, Assistant Station Manager
M. Kansler, Station Manager
J. McCarthy, Superintendent of Operations
- G. Miller, Licensing Coordinator, Surry
J. Ogren, Superintendent of Maintenance
A. Price, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
- Attended exit int.erview.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Units 1 and 2 began the reporting period in cold shutdown.
The uni.ts
remained in cold shutdown for the duration of the inspection period while
substantial operational reviews and maintenance activities were being
conducted.
3.
Operational Safety Verification (71707)
a.
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, techni ca 1 speci fi cat i ans, and
limiting conditions for operations; examination of panels containing
instrumentation and other reactor protection system e 1 ements to
determine that required channels are operable; and review of control
room operator logs, operating orders, plant deviation reports, tagout
logs, jumper logs, and tags on components to verify compliance with
approved procedures .
. )
b.
2
Weekly Inspections
The inspectors conducted weekly inspections in the following areas:
verification of operability of selected ESF systems by valve
alignment, breaker positions, condition of equipment or components,
and operability of instrumentation and support items essential to
system actuation or performance. Plant tours were
conducted which
included observation of general plant/equipment conditions, fire
protection and preventative measures, control of activities in
progress, radiation protection controls, physical security controls,
plant housekeeping conditions/cleanliness, and missi"h:! hazards.
The
inspectors routinely monitored the temperature of the auxiliary
feedwater pump discharge piping to ensure steam binding was
prevented.
c.
Biweekly Inspections
The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagouts in effect;
review of sampling program (e.g., primary and secondary coolant
samples, boric acid tank samples, plant liquid and gaseous samples);
observation of control room shift turnover; review of implementation
of the plant- problem identification system; verification of selected
portions of containment isolation lineups; and verification that
notices to workers are posted as required by 10 CFR 19.
d.
Areas Inspected
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear rooms,
diesel generator rooms, control room, auxiliary building, Unit 1
containment, cable penetration areas, independent spent fuel storage
facility, low level intake structure, and the safeguards valve pit
and pump pit areas. Reactor coolant system leak rates were reviewed
to ensure that detected or suspected leakage from the system was
recorded, investigated, and evaluated; and that appropriate actions
were taken, if required.
The inspectors routinely independently
calculated RCS leak rates using the NRC Independent Measurements Leak
Rate Program (RCSLK9).
On a regular basis, RWPs were reviewed and
specific work activities were monitored to assure they were being
conducted per the RWPs.
Selected radiation protection instruments
were periodically checked, and equipment c*perability and calibration
frequency were verified.
e.
Physical Security Program Inspections
In the course of monthly activities, the inspectors included a review
of the licensee's physical security program.
The performance - of
various shifts of the security force was observed in the conduct of
',
f .
3
daily activities to include: protected and vital areas access
controls; searching of personnel, packages, and vehicles; badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
Licensee 10 CFR 50.72 Reports
. *(1)
On April 6, 1989, the licensee made a report in accor~ance with
10 CFR 50.72 with regards to loss of the normal power supply to
the
11 F11 bus.
The power loss was caused by a failure in the
switchyard of the 500 KV stepdown transformer -which normally
feeds the
11 F11 bus.
The
11 F
11 bus was supplying normal power to
the Unit 1
11H11 bus and the Unit 2
11J
11 bus ( 4160 volt vi ta 1
buses). Loss of power to the Unit 1 11H11 bus resulted in loss of
power to the running (A) RHR pump for Unit 1. Operators started
the Unit 1
118
11 RHR pump within one minute of the loss of the
11A
11
pump.
RCS temperature did not increase during the time that RHR
cooling was lost.
The No. 1 EOG intentionally was not aligned
to automatically start due to potential vibration problems that
had been identified earlier.
However, after discussion with
station management, the diesel was started and the Unit 1
11H
11
bus was loaded onto the EDG.
Loss of power to the Unit 2
11J
11
bus resulted in an automatic start and load of the No. 3 EOG
onto th*e
11J
11 bus.
RHR was not lost on Unit 2 due to the
operating pump being powered from the Unit 2 11H
11 bus.
During the event, the Unit 1 reactor vessel level, as indicated
by standpipe, was 18.6 feet (approximately 2 to 4 inches above
the reactor ve s se 1 flange).
The Un it was. not in a reduced
inventory condition (3 feet below the vessel flange) as defined
by GL 88-17.
Loss of power to the 11 F
11 bus resulted in loss of
control room indicated standpipe level for the unit. Immediate
operator action was to dispatch an operator into the Unit 1
containment and locally monitor the standpipe level.
No loss of
RCS inventory was experienced during the event.
The licensee
took actions during the next four hours to restore offsite power
to the "F" bus and to transfer emergency busses back to the
11 F11
bus.
In view of the licensee's response to the event, the
inspectors believe that the operators are properly sensitized
to a loss of RHR condition.
(2)
On April 7, 1989, the licensee made a report in accordance with
10 CFR 50.72 as a result of an evaluation of main control room
habitability fo 11 owing a DBA.
The eva 1 uat ion stated that the
accident analysis assumed that the main control room air bottle
system would dump at the same time the OBA occurred. However,
the air bottle system is presently designed to be manually
initiated by the operators.
Using an allowance of ten minutes
for operator action, the licensee determined that a potential
4.
( 3)
4
exists for excessive cumulative radiation exposure to operators
during the 30 days following the accident.
Corrective actions
will include redesign of the actuation system *to allow for
automatic initiation.
On April 13, 1989, the licensee made a report in accordance with
10 CFR 50. 72 with regards to loss of the power supply to the
11 F
11
bus. The power loss was caused by a failure to properly conduct
a test by licensee personnel in the switchyard. The
11 F
11 bus was
supplying normal power to the Unit 1
11H
11 bus and the Unit 2 11J
11
bus (4160 volt vital buses). The No. 1 EOG gene~ator was tagged
out for repairs and was not available to provide emergency power
to the Unit 1 "H" bus.
Loss of power to the Unit 2 "J" bus
resulted in an automatic start and load of the No. 3 EOG on the
11J 11 bus.
RHR flow to both units was maintained throughout the
event with no increase in RCS temperature.
Ouri ng the event, the Unit 1 vessel level was 18. 3 feet
(approximately equal
to the reactor vessel flange), and
therefore the unit was not in a reduced RCS inventory.
Loss of
power to the 11 F11 bus resulted in loss of control room indicated
standpipe level for the unit.
Immediate operator action was to
dispatGh an operator into the Unit 1 containment and locally
monitor the standpipe level.
No loss of RCS inventory was
experienced during the event. The licensee took actions during
the next two hours to restore off site power to the II F" bus and
to transfer emergency busses back to the
11 F11 bus.
( 4)
On April 17, 1989, the 1 i censee made a report to the NRC in
accordance with 10 CFR 50.72 with regards to an ESF actuation of
the main control room ventilation dampers.
The dampers went
closed due to a spurious high spike on the chlorine monitor.
The chlorine monitors are no longer required to be installed at
the station and a design change to remove them is in progress.
The high alarm condition on the monitors was reset, the monitors
were removed from service, and the ventilation dampers were
realigned to their normal position.
Within the areas inspected, no violations were identified.
Operational Readiness Program Review (71710)
The inspectors continued to review the licensee's operational readiness
program as discussed in NRC Inspection Reports 280,281/88-51, 89-06, and
89-08.
This effort is being performed in accordance with EWR 88-584,
System Review For Startup, and includes both field walkdowns and a review
of outstanding issues by the system engineers.
The inspectors are
routinely monitoring all aspects of this readiness program.
The following
details some specific inspection areas and findings from this review .
'.
a.
5
Plant Configuration Confirmation
This portion of the program,
performed in
accordance with
Attachment II to the above EWR,
consisted of the station system
engineers conducting field walkdowns of the systems and noting
discrepancies for resolution. These discrepancies were evaluated to
determine if they should be corrected before unit startup and a
justification was written if deferral was recommended.
The inspector reviewed field change
11T11 to EWR 88-584, dated March 2,
1989, that identified and dispositioned discrepancies-as a result of
system walkdowns against 46 station drawings. This walkdown resulted
in the identification of 35 startup issues that were subsequently
added to the official startup list.
The inspector independently
verified that a 11 startup i terns are being tracked on the master
startup list.
In addition to an overall review of this extensive field change, the
inspector selected the following drawings for a more in-depth audit:
Drawing 11448-FB-46C, Sheet 1 of 2, Emergency Diesel Generator
Air Start System.
Drawing 11448-CBM-728, Sheet 2 of 3, Component Coo 1 i ng Water
System.
Drawing 11448-FM-87A, Sheet 1 of 2, Residual Heat Removal
System.
The inspector continued a review of the walkdowns documented via
field change
11U11 to EWR 88-584, dated April 13, 1989, to verify
adequate identification and disposition of discrepancies.
This
general review included the following:
Drawing 11448-FM-084A, Sheet 2 of 3, Containment Spray System
Drawing 11448-FB-0418, Sheet 1 of 1, Main Control Room Bottled
Air System
Drawing 11448-CBM-0848, Sheet 2 of 2, Outside Recirculation
Spray System
Drawing 11448-CBM-084, Sheet 1 of 2, Inside Recirculation Spray
System
Drawing 11448-CBM-0868, Sheet 2 of 3, Reactor Coolant System
The i11spector verified that each discrepancy identified was prop-erly
dispositioned and an appropriate mechanism was in place to require
adequate corrective actions.
For example, if a problem with the
b.
6
drawing was identified, the inspector verified that the drawing
discrepancies were formally submitted and tracked by the station
drawing update group.
No outstanding concerns were identified during
this inspection effort.
Assessment of Outstanding Issues
This item is covered in Attachment IV to EWR 88-084 and includes a
review of outstanding temporary modifications and/or jumpers, station
deviations, commitment items, outstanding safety-related work orders,
outstanding EWRs and open Type 1, 2, and 3 engineering evaluations.
The system engineers have been tasked with reviewing the above items
pertaining to their system and evaluating if closure of the item
should be performed prior to unit startup. For those items that will
not be closed prior to startup, a justification for not completing
the i tern must be written and approved by the Superintendent of
Technical Services.
(1) The inspector reviewed field change
11S11 to EWR 88-584, dated
March l, 1989, that addressed closed Type 1, 2, and 3
engineering reports.
No startup items were identified by the
licensee during their evaluation of the above field change. The
inspect.or reviewed each item of this field change with the
accompanying supporting documentation and justification and
concurred with the licensee's evaluations.
No
inspector
discrepancies were identified.
(2) The inspector reviewed parts of field changes J, K, P, W, and AA
made to EWR 88-584, that addressed commitments on which action
did not have to be taken before startup of the units.
Field
changes O and Z to EWR 88-584 were reviewed for commitments on
which action was necessary before startup. The following is a
list of 14 commitments that were reviewed on these seven field
changes.
Nine commitments were evaluated as not requiring
resolution before startup, and include:
Commitment No.
89-2089-001
85-5026-020
88-2168-001
Description
Inspect wiring on hydrogen analyzer
quarterly.
IE Bulletin 85-03, MOV Common Mode
Failure--Operators have been trained but
training documents have not been changed.
Batteries for security diesel to be placed
on preventive maintenanc~ program .
Commitment No.
(cont
1d)
88-2355-00i
88-1615-002
88-1377-001
87-0913-001
88-0811-001
.
88-0020-002
7
Description
Procedure deviation for permanent change
to operation procedure 1-0P-33A.
Deviation
is available to be used when this procedure
is required.
Independent verification (with regards to
station
tagging
program)
revision
to
administrative procedure.
-
Technical Specification change request
No. 204, procedure changes for future core
upgrade.
Future Predictive Analysis Group vibration
program
for
monitorjng
safety-related
equipment.
Westinghouse letter that deals with
outage related maintenance .
Pressurizer safety relief setpoint drift
( LER 88-016).
The following five commitments were evaluated by the licensee
as not requiring resolution prior to unit startup:
Commitment No.
88-1374-001
88-0040-003
84-0201-005
84-1152-004
88-0103-004
Description
Technical Specification Change No. 194(8),
heat up and cooldown curves necessary for
startup.
Commitment to NRC to perform full flow
test on inside recirculation spray pumps
during this outage.
Supplementary response to IEB 84-02 which
identifies additional AC energized relays
~hat must be replaced.
Design changes to feed data into the plant
status computer program for containment
spray fl ow, pressurizer heater status, and
pressure transmitters for the accumulators.
Containment spray system walkdown by NRC
resulting in two work requests and two
drawing changes.
~-j
. .
c.
8
A discussion with the liceosee on commitment 88-0020-002
concerning pressurizer safety relief setpoint drift revealed
that a TS change would have to be made. The acceptance band was
+/-1 percent of the pressure range, but the setpoi nt drifted
beyond this range. Calculations appear to show that +/-3 percent
is acceptable and the setpoint could be maintained within this
range.
The inspector's discussion with the licensee questioned
whether this should be a startup item. The licensee's decision
and action in this area will be evaluated prior to restart and
tracked as IFI 280,281/89-13-01, resolution of pressurizer
safety relief setpoint drift.
Inspection and Review Status
The overall status of the engineering work that pertains to Unit 1
(as of April 24, 1989) was as follows:
Wal kdowns
Total Items:
3341
Items Reviewed:
3341
Startup Items:
287
Commitments
Total Items:
1018
Items Reviewed:
770
Startup Items:
143
Closed Type 1
Total Items:
655
Items Reviewed:
556
Startup Items:
16
Total Items:
786
Items Reviewed:
370
Startup Items:
85
Open Type 1,2 & 3
Total Items:
261
Items Reviewed:
251
Startup Items:
56
Temp. Mods.
Total Items:
16
Items Reviewed:
16
Startup Items:
5
Within the areas inspected, no violations or deviations were identified.
5.
Maintenance Inspections (62703)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with
the appropriate procedures.
Inspection areas included the following:
a.
9
Evaluation of Maintenance/Modification On
The
Low Head Safety
Injection Pump (1-SI-P-lA)
The inspector continued the review of the maintenance activities
associated with replacement of replica parts in the LHSI pump
manufactured by Byron Jackson.
Initial maintenance activities were
discussed in NRC Inspection Report 280,281/89-08.
The licensee is currently working on the Unit 1 low head SI pump
(1-SP-P-lA) in order to replace the replica parts (non-original
equipment manufacturer parts) previously placed in 1'he pumps.
The
inspector reviewed procedure MMP-P-C-SI-090, Removal, Disassembly,
Inspection, Repair, Reassembly, and Reinstallation of Low Head Safety
Injection Pump "Safety Related" dated August 20, 1987. Completed and
signed off portions of this procedure were reviewed.
All of the parts have been removed from the pump well and wiped to
minimize any contamination.
The Byron Jackson -parts have a number
stenci 1 ed on them and if a number is not present it cannot be
verified as a vendor supplied item. The licensee is replacing all of
the carbon steel bearings, because carbon steel rusts and the
identifying number cannot be maintained.
One coupling out of five
did not have an identifying number and will be replaced.
A new
throttle bushing issued by the licensee's warehouse as a category 1
part for this pump was found to be a replicated part. (Station
deviation No. Sl-89-869).
The maintenance group, engineering, and the vendor are having
discussions concerning the difficulty of pressing the bearings back
onto the shafts.
The
bearings require a nine thousandths
interference fit and this causes an installation problem. The
inspectors will continue to monitor this maintenance activity.
b.
Regulator Replacement in Response to NRC IN 88-24
On April 7, the inspector witnessed replacement of the air supply
regulator on containment isolation valve 1-CC-TV-llOC in accordance
with EWR 89-003, Regulator Replacements In Response To NRC IN 88-24.
The subject NRC IN identifies a potential for overpressurization
failures of solenoid valves caused by an air system pressure greater
than the solenoid design maximum operating pressure differential. A
typical AC powered ASCO solenoid valve used at .;urry has an air
maximum operating pressure differential of 45 psi.
However, the
regulators that are used to reduce the instrument air supply down
from approximately 100 psi are not safety-related and their settings
are not controlled in the station setpoint document.
The licensee could not produce documentation that the maximum
supplied air pressure through the regulators is less than the maximum
operating differential operating pressure of the SOV, and therefore
10
stated that the qualification status of the S0Vs is indeterminate.
The corrective actions specified in the above EWR require replacement
of the upstream regulators with new regulators that are designated
safety-related with their setpoint officially controlled in the
station setpoint document.
This changeout is required on 51
containment isolation valves.
The inspector verified that the work
performed in the fie 1 d was being conducted and documented in
accorda~ce with the licensee's approved procedures.
No discrepancies
were identified.
c.
Emergency Diesel Generator No. 1
The inspectors followed the work being performed on the EOG No. 1 to
correct an excessive vibration problem and inspect for damage as a
result of lube oil contamination. Station deviation Sl-89-818, dated
April 6, 1989, identified excessive vibrations during performance of
the EOG monthly surveillance test.
The observed vibrations were
severe enough to cause the operators to perform an emergency shutdown
of the engine. Work Order No. 3800078912 authorized the removal and
retorquing of the EOG foundation anchor bolts.
The
inspector
witnessed portions of the removal and reinstallation of the anchor
nuts and discussed with the maintenance personnel their observation
that the as-found nuts were not tight.
Maintenance Engineering
inspected the as-found condition and recommended installation of jam
nuts.
In addition, plans were being made to inspect and retorque the
foundation bolts on the remaining two EOGs.
The problem of lube oil contamination was addressed in Work Order
No. 3800079985 and involved high zinc concentrations found in the
lube oil during normal sampling and analysis.
The EOG manufacturer
states that a zinc concentration in excess of 10 ppm in the lube oil
could damage the silver coating on the piston wrist pin bearings.
The samples of lube oil from the No.l EOG were determined to contain
15 to 17 ppm zinc. The samples from the remaining two EDGs were well
within specifications.
The inspector witnessed the removal and
inspection of four power assemblies from the EOG No.1 and concur with
both the licensee engineer and vendor representative that no damage
to the bearing surface had occurred.
The licensee was continuing to
search for the source of the zinc with speculation that the thread
lubricant may have been a contributor.
No discrepancies were
i dent ifi ed.
Within the areas inspected, no violations or deviations were identified.
6.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as
follows:
Test prerequisites were met.
11
Tests were performed in accordance with approved procedures.
Test procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test.
Test data were properly collected and recorded.
Inspection areas included the following:
a.
Emergency Diesel Generator Fuel Oil Supply
On March 4, the inspector witnessed testing of the emergency fuel oil
pump 1-EE-P-lA in accordance with test procedure PT-22.2, Emergency
Fuel Supplies. This pump supplies makeup fuel from the inground fuel
oil tank to the wall tanks in each EOG room.
The test verified that
the pump automatically starts and stops on specific levels in the
wan tank. The inspector discussed the test with station personnel
i nvo 1 ved and noted that severa 1 prob 1 ems were *; dent i fi ed with the
level indication in the wall tanks. The licensee agreed that further
testing of the diesel pumps that transfer fuel from the wall tank to
the skid tank is warranted and stated that a test procedure is being
prepared.
N9 discrepancies were noted.
b.
Functional Test of the Low Head Safety Injection System
The inspector reviewed the recently developed surveillance test,
1-PT-18.3E, Refueling Test Of LHSI Lines To Charging Pumps, which
ensures that an operable flowpath exists from the LHSI pumps to the
charging pumps via the recirculation mode transfer piping.
The
licensee discovered during
an
investigation of a previously
identified valve labeling and power supply problem (ref. IR 280,281/
88-45) that they had never functionally tested the flowpath from the
LHSI
pumps to the charging pumps.
The inspector verified the
fl owpath specified in the test procedure and discussed the test
method with the appropriate system engineer.
No discrepancies were
i dent ifi ed.
c.
Emergency Diesel Generator No. 3
The inspector reviewed periodic test 2-PT-22.3C, Diesel Generator No.
3 Test, dated February 22, 1988.
This survei 11 ance procedure
implements the requirements of TS 4.6.A.1.a that each emergency
diesel generator has a manually initiated start followed by
synchronization with other power sources and assumption of load by
the diesel generator up to 2750 kw.
This is a monthly test and
requires a minimum duration of 30 minutes.
On April 7, the __inspectors attended the pre-briefing with the SROs
and ROs to discuss the running of the No. 3 EOG.
On this date-,
observations were made of the RO taking oil samples, running the air
d.
12
compressor diesel, making valve alignments, recor.ding proper level of
cooling water, etc.
In the main control room, the inspectors
observed the starting and manual synchronization of the diesel with
other power sources. The periodic test instructions suggest running
the diesel for approximately two hours; however, the test was
terminated after approximately 35 minutes because rainwater was
entering the air louvers in the close vicinity of the electronic
control cabinets, with some water hitting the cabinets. The licensee
terminated the test to evaluate any adverse effects the rain might
have on the electronic controls. This condition was identified as a
deviation report in the licensee's corrective actiol't program.
No
discrepancies were observed during the performance of the periodic
test.
Functional Testing of Unit 1 IRS Pumps.
The inspector reviewed the test procedure which was used to conduct
operability testing of the Unit 1 IRS pumps 1-RS-P-lA and 1-RS-P-18.
Test procedure 1-ST-214, Operability of IRS Pumps for Unit 1 was
conducted on 1-RS-P-lA on April 3, 1989, and on 1-RS-P-18 on April 4,
1989.
The
inspector verified that the procedure adequately
documented the conduct and results of the testing.
The procedure
copy that was reviewed had three procedure deviations which were
incorporated* prior to or during testing.
The deviations received
required reviews for 10 CFR 50.59 compliance and were approved by the
station safety committee as required by TS.
No discrepancies were
identified.
Within the areas inspected, no violations or deviations were identified.
7.
Licensee Event Report Review (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC
reporting requirements were being met and to determine appropriateness of
the corrective actions. The inspector's review also included followup on
implementation of corrective action and review of licensee documentation
that all required corrective actions were complete.
LERs that identify violations of regulations and that meet the criteria of
10 CFR, Part 2, Appendix C,Section V are identified as LIVs in the
following closeout paragraphs.
LIVs are considered first-time occurrence
violations which meet the NRC Enforcement Policy for exemption from
issuance of a Notice of Violation.
These items are identified to allow
for proper evaluations of corrective actions in the event that similar
events occur in the future.
(Closed) LER 280/87-14, Inadequate Review of AFW Supply Following
Safeguards.
The issue involved a scenario in which AFW could be
an operating unit due to a HELB in the main steam valve house.
single active failure of the opposite unit's available AFW pump
HELB in
lost to
With a
a total
13
loss of AFW to the affected unit would result. Corrective action included
immediate administrative control to ensure that when a unit is above 350
degrees/450 psig, two AFW pumps are available from the other unit.
The
licensee also submitted a TS change to require this action. The inspector
reviewed the corrective action and verified that the TS change was
submitted.
This LER is closed.
(Closed) LER 280/87-38, Increased Off-Site Thyroid Dose Calculations from
Steam Generator Tube Rupture due to Post Trip Steam Generator Tube
Uncovery.
The issue involved determination of a condition in which a
potential exists for uncovering of a tube break after a ~team generator
tube rupture event. This issue was identified after the North Anna steam
generator tube rupture event which occurred on July 15, 1987.
The
licensee's initial evaluation concluded that the additional thyroid dose
would be below regulatory limits.
However, the issue has been assigned
for additional generic review by a Westinghouse program.
The program was
proposed to the WOG and is expected to be completed in 1989.
The
inspector reviewed the LER and also determined that the issue resolutions
will be reviewed by other technical NRC groups.
This LER is closed.
8.
Action on Previous Inspection Findings (92701, TI 2515/100 & 101)
a.
(Closed) !Fi 280,281/87-13-02, Followup on Licensee Performance for
Decay Heat Removal Evolutions during Low Reactor Coolant Level
Operation.
The issue involved the licensee's evaluation and
implementation of lessons learned from NRC IN 87-23, Loss of Decay
Heat Remova 1 During Low Reactor Coo 1 ant Leve 1 Operation.
After
issuance of the IN, the licensee took actions to implement design
changes to both units for the installation of permanent level
instrumentation to monitor
level during reduced inventory
operation. This level instrumentation was installed for both units
during their respective refueling outages in 1988.
On October 17, 1988, the NRC issued GL 88-17, Loss of Decay Heat
Removal.
The GL requested that each 1 i censee respond to act i ans
taken with regard to implementation of eight recommended expeditious
actions which are discussed below, and to respond to actions taken
with regard to six programmed enhancement recommendations discussed
in the attachment to the GL.
The licensee submitted their response
to the GL expeditious actions request by letter dated January 6,
1989, and responded to the GL programmed enhancement recommendations
request by letter dated February 3, 1989.
The inspectors reviewed the licensee I s responses to GL 88-17 and
conducted specific reviews of the eight recommended expeditious
actions as outlined in the licensee's January 6, 1989 reply.
The
following is a brief description of the recommended actions of the
licensee's response and the inspectors' fi~dings.
14
TRAINING - Discuss the Diablo Canyon event, related
lessons learned, and implications with appropriate
personnel.
Provide training shortly before entering
inventory condition.
events,
plant
reduced
The licensee's response stated that the event had been discussed
with operations personnel including specific evolutions involved
in
cooldown/draindown operation.
The
inspectors verified
through discussions with operators that they had received
training on specific evolutions involved in cooldown/draindown
operations and that they were sensitized to pot'ential loss of
OHR.
The inspector also determined that the training included
reviews of all procedural and administrative changes implemented
as a result of the licensee's response to GL 88-17.
CONTAINMENT CLOSURE -
Implement procedures and admi ni strati ve
controls that reasonably assure that containment closure will be
achieved prior to the time at which core uncovery could result
from a loss of OHR coupled with the inability to initiate
alternate cooling or addition of water to the RCS inventory.
The licensee's response stated that procedures require that the
status of the containment configuration be established and
verifiea prior to entering a reduced inventory condition (water
level lower than 3 feet below the vessel flange).
In addition,
the AP for loss of RHR capability directs containment closure
action to be initiated and continued until the RHR system is
returned to service and core conditions are verified normal.
The
inspectors verified that the licensee has
prepared
procedures and administrative controls to reasonably assure that
containment closure will be achieved prior to the time at which
core uncovery could occur.
This was done by reviewing OP-lG,
Refueling Containment Integrity and RCS Mid-Loop Containment
Closure Checklist; Standing Order No. 7, Operation When the RCS
Is Partially Drained; and AP 27.00, Loss of Decay Heat Removal
Capability.
RCS TEMPERATURE - Provide at least two independent, continuous
temperature indications that are representative of the core exit
conditions whenever the RCS is in a mid-loop condition.
The licensee's response stated that procedures for draining the
RCS will be revised to ensure at least two incore temperature
indicators are operable prior to draining the RCS to a reduced
inventory condition.
The incore temperature will continuously
indicate in the control room and will be periodically monitored
by the operators.
The temperature readings are periodically
recorded on the control room shutdown logs by the control room
operators.
The inspectors verified that controlling procedures
.,
15
for draining the RCS were revised to ensure at least two incore
temperature indicators are operable prior to draining the RCS to
a reduced inventory condition. The inspector also verified that
the
contra l
room
operators peri odi ca lly recorded these
temperature readings in their logs. Also, it was verified that
RCS temperature curves were incorporated into AP 27.00, Loss of
Dec~y Heat Removal Capability.
RCS WATER LEVEL - Provide at least two independent, continuous
RCS water level indications whenever the RCS is in a reduced
inventory condition.
The licensee's response stated that one continuous means of
level
indication has
been
installed which
provides for
continuous readout in the control room.
This system also
provides for an alarm for loss of shutdown cooling at a level of
12 feet, 4 inches.
The second means of level indication is
still under review.
The inspectors verified that the licensee
has a permanently installed water level
instrument with
continuous readout in the control room whenever the RCS is in a
reduced inventory condition. This instrument alarms when water
level decreases to 12 feet, 4 inches (approximately 7 inches
above mid-nozzle).
This system is currently operable on both
units.* The licensee has committed to installing a second
independent channel during the next respective unit refueling
outages.
PERTURBATION -
Implement procedures and administrative
controls that generally avoid operations that deliberately or
knowingly lead to perturbations to the RCS and/or to systems
that are necessary to maintain the RCS in a stable and
controlled condition while the RCS is in a reduced inventory
condition.
The licensee's response stated that an operations procedure for
assessing maintenance activities that could potentially cause a
loss of RCS inventory, is being developed.
The inspectors
verified that the licensee had prepared a procedure, OC-28,
Assessment of Maintenance Activities for Potential Loss of
Reactor Coolant Inventory, which allowed for assessment of work
on systems for potential loss of reactor cool ant inventory
during reduced RCS inventory conditions. This procedure allows
for operator evaluation of work to be performed based on
guidelines for the assessment.
The procedure also established
additional controls to assure that maintenance activity will not
adversely affect RCS inventory.
RCS INVENTORY ADDITION -
Provide at least two availdble or
operable means of adding inventory to the RCS
that are in
addition to pumps that are part of the OHR systems.
These
should include at least one high pressure injection pump.
J
16
The licensee's response stated that procedures will be revised
to require that one high head and one low head safety injection
pump with appropriate flowpaths be provided prior to RCS
dra i ndown into a reduced inventory condition.
The inspectors
verified that the 1 i censee has a procedure which requires at
least two available or operable means of adding inventory to the
RCS in addition to the RHR system.
This requirement is
accomplished by OC-6, Boric Acid Flow Paths and Tech Spec Heat
Trace Circuit Verification.
The procedure requires that in a
reduced inventory condition, one CHG/SI pump and one LHSI pump
must be available with appropriate flowpaths to the core.
NOZZLE DAMS - Implement procedures and administrative controls
that reasonably assure that all hot legs are not blocked
simultaneously by nozzle dams unless a vent path is provided
that is large enough to prevent pressurization of the upper
plenum of the reactor vessel.
The licensee's response stated that RCS* 1oop isolation is
obtained by the use of loop isolation valves. Therefore, nozzle
dams are not used.
The inspectors verified that the licensee
does not presently use steam generator nozzle dams.
LOOP STOP
VALVES -
Implement procedures and administrative
controls that reasonably assure that all hot legs are not
blocked simultaneously by closed loop stop valves unless a vent
path is provided that is large enough to prevent pressurization
of the reactor vessel
upper plenum or unless the
configuration prevents vessel water loss if reactor vessel
pressurization should occur.
The licensee's response stated that this condition will be
contro 11 ed by procedures to assure that one 1 oop remains
unisolated with the respective loop bypass valve open.
The
inspectors verified that the licensee has implemented procedure
and administrative controls that reasonably assure that at least
one 1 oop remains uni so 1 ated with the respective 1 cop bypass
valve open.
This is accomplished by Standing Order No. 7,
Operation When the RCS Is Partially Drained.
The
inspectors consider that the licensee has satisfactorily
implemented the eight recommended expeditious actions responses to GL 88-17 as outlined in their January 6, 1989 reply.
This item is
closed.
b.
(Closed)
IFI
280,281/88-33-0l,
Followup
on
Sequence of Data
Collection for Testing AFW Pumps. This issue involved the adjustment
of the turbine-driven AFW pump speed prior to collection of data*for
the monthly surveillance. The licensee agreed that clarification of
the test procedure was warranted and issued a revision to periodic
..
17
test 1 and 2-PT-15.lC dated March 23, 1989.
The inspector reviewed
the revised test procedure and noted that an engineering evaluation
is now required before proceeding if the as found pump speed is
outside an allowable range.
This item is closed.
c.
EDG Fuel Oil Handling and Storage (TI 2515/100)
On January 16, 1987, the NRC issued IE Information Notice 87-04
alerting lice~sees of potentially significant problems pertaining to*
long-term storage of EDG fuel oil.
The inspector reviewed the
licensee 1s program for storage and handling of EDG .fuel oil as a
result of information provided in the Notice.
Discussions with the
licensee revealed the following:
New procedures are being put into place for sampling the fuel
oil in the tanks for oxidation and biological contamination.
Additional fuel sampling ports are being added to some of the
tanks.
Fuel oil filters and strainers are in the preventive maintenance
program.
No violations or deviations were identified.
9.
Exit Interview
The inspection scope and findings were summarized on May 2, 1989, with
those individuals identified by an asterisk in paragraph 1. The following
new items were identified by the inspectors during this exit:
One IF! (paragraph 4.b) was identi°fied for followup on resolution of
pressurizer safety relief setpoint drift (280, 281/89-13-01).
The licensee acknowledged the inspection findings with no dissenting
comments.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
10.
Index of Acronyms and Initialisms
cc
ccw
CFR
CHG
ABNORMAL OPERATING PROCEDURE
COMPONENT COOLING
COMPONENT COOLING WATER
CODE OF FEDERAL REGULATIONS
CHARGING
DESIGN BASIS ACCIDENT
~ ,
DPI
DR
EOG
EMP
GL
GPM
IFI
IN
IR
IRS
LER
LHSI
LIV
NRC
OP
sov
TS
18
DELTA PRESSURE INDICATORS
DEVIATION REPORT
ELECTRICAL MAINTENANCE PROCEDURE
ENGINEERED SAFETY FEATURE
EMERGENCY SERVICE WATER
ENGINEERING WORK REQUEST
GENERIC LETTER
GALLONS PER MINUTE
HIGH PRESSURE SAFETY INJECTION
INSPECTION AND ENFORCEMENT
INSPECTOR FOLLOWUP ITEM
INFORMATION NOTICE
INSPECTION REPORT
INSIDE RECIRCULATION SPRAY
INSERVICE INSPECTION
LICENSEE EVENT REPORT
LOW HEAD SAFETY INJECTION
LICENSEE IDENTIFIED VIOLATIONS
LOSS OF-COOLANT ACCIDENT
MOTOR OPERATED VALVE
NUeLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
OPERATING PROCEDURE
PREVENTATIVE MAINTENANCE
PARTS PER MILLION
POUNDS PER SQUARE INCH
POUNDS PER SQUARE INCH GAUGE
PERIODIC TEST
QUALITY ASSURANCE
QUALITY CONTROL
REGULATORY GUIDES
REACTOR OPERATOR
RECIRCULATION SPRAY SYSTEM
RADIATION WORK PERMIT
REFUELING WATER STORAGE TANK
SAFETY INJECTION
SOLENOID OPERATED VALVE
SENIOR REACTOR OPERATOR
TECHNICAL SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
WESTINGHOUSE OWNER 1S GROUP