ML20211A812
| ML20211A812 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 01/29/1987 |
| From: | Stetka T, Tedrow J, Wilson B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20211A707 | List: |
| References | |
| 50-302-86-38, IEB-86-003, IEB-86-106, IEB-86-3, NUDOCS 8702190238 | |
| Download: ML20211A812 (21) | |
See also: IR 05000302/1986038
Text
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET,N.W.,
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ATLANTA, GEORGI A 30323
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Report No:
50-302/86-38
Licensee:
Florida Power Corporation
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3201 34th Street, South
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St. Petersburg, FL 33733
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Docket No:
50-302
Licensee No.:
DPR-I2'
Facility Name:
Crystal River 3
Inspection Dates: November 7,.1986 - January 7, 1987
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Inspectors:
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T. F. Stet , Senior Resident / Inspector
Date Signed
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J. E. Tedrow, Resident In@ector-
D~ ate Signed
Approved by
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B.A. Wilson, Section Chief
D' ate S'igned
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Division of Reactor Projects
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SUMMARY
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Scope:
This routine inspection was conducted by two resident inspectors in the
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areas of plant operations, security, radiological controls, Licensee Event
Reports and Nonconforming Operations Reports, review of IE Bulletins, and
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licensee action on previous inspection items.
Numerous facility tours were
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conducted and facility operations observed.
Some of these tours and observations
were conducted on backshifts.
Results:
Six Violations were identified: (Failure to adhere to posting require-
ments for radiation protection, paragraph 5.b(5);
Failure to have an adequate
procedure to perform shut down margin calculations, paragraph 5.b(E) b; Failure
to comply with the requirements of 10 CFR 50 Appendix J, paragraph 5.b(8).c;
Failure to perform surveillance requirements within the required time interval,
paragraph 6.a(3);
Failure to take adequate corrective action, paragraph 6.b(1);
Failure to issue a LER, paragraph 6.b(2) and 6.b(3)).
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8702190238 870204
DR
ADOCK 05000302
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REPORT DETAILS
1.
Licensee Employees Contacted
- J. Alberdi, Manager, Nuclear Site Support
- F. Bailey, Superintendent of Projects
- J. Brandely, Nuclear Security & Special Projects Superintendent
- P. Breedlove, Nuclear Records Management Supervisor
- J. Bpckner, Nuclear Security Superintendent
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- J. Cooper Jr. , Superintendent, Technical Support
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^J.lCibson, Nuclear Technical Specification Coordinator
q *V.'Hernandez, Senior Nuclear Quality Assurance Specialist
- B. Hickle, Manager, Nuclear Plant Operations
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- J. Lander, Director, Nuclear Projects & Outages
- M. Mann, Nuclear Compliance Specialist
R. Marckese, Nuclear Engineer I
- P. McKee, Director, Nuclear Plant Operations
R. Hurgatroyd, Nuclear Maintenance Superintendent
W. Neuman, Supervisor Inservice Inspection (ISI)
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W. Nielsen, Senior Nuclear Electrical /I&C Supervisor
- V. Roppel, Manager, Nuclear Plant Technical Support
- W. Rossfeld, Nuclear Compliance Manager
- P. Skramstad, Nuclear Chemistry / Radiation Protection Superintendent
- P. Small, Maintenance Department Coordinator
- S. Sullens, Senior Nuclear Electrical /I&C Supervisor
- K. Wilson, Manager, Site Nuclear Licensing
- R. Wittman, Nuclear Operations Superintendent
Other personnel contacted included off'ce, operations, engineering,
maintenance, chemistry / radiation and corporate personnel.
- Attended exit interview
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2.
Exit Interview
The inspector met with licensee representatives (denoted in paragraph 1) at
the conclusion of the inspection on January 7,1987.
During this meeting,
the inspector summarized the scope and findings of the inspection as they
are detailed in this report with particular attention to the Violations and
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Inspector Followup Items (IFI).
The licensee representatives acknowledged the inspector's comments and did
not identify as proprietary any of the materials provided to or reviewed by
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the ir.spectors during this inspection.
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3.
Licensee Action on Previous Inspection Items
(Closed) IFI 502/86-12-07:
The licensee has revised maintenance procedures
'MP-124 (revision 13, dated August 8,'1986) and MP-162 (revision 7, dated
October 1,1986) to include alignment specifications for the emergency
feedwater pumps.
Action on this item is considered complete.
(Closed) IFI 302/86-20-04:
The licensee has revised surveillance procedures
SP-354A (revision 15, dated November 7,1986) and SP-354B (revision 12,
dated October 24,1986) to require that both emergency diesel generator room
supply fans are returned to normal following diesel shutdown.
This item is
considered to be complete.
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(Closed) IFI 302/86-14-04: .The inspector reviewed documentation from the
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manufacturer which stated that Gulf Dieselmotive 471 was an acceptable
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oil _ for: use in the Woodward governor for the emergency diesel generators.
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The . inspector has no further questions on this matter and this item is
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' considered closed.
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(Closed) Violation 302/86-27-02:
The licensee has revised compliance
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procedure CP-115 (revision 58, dated November 28, 1986) to require the use
of the appropriate procedures for system restoration from an equipment
clearance.
The inspector has reviewed this procedure and considers this
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clarification adequate.
This item is considered closed.
(Closed) Violation 302/86-22-01:
The licensee has completed and the
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inspector has verified the completion of the following items:
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Revisions to the Operating Daily Surveillance Log, SP-300 (revision 89
dated July 22, 1986), and Shutdown Daily Surveillance Log, SP-301
(revision 65 dated October 24, 1986), have implemented the following
requirements:
i).
Checking the position of range selector switches on the hydrogen /
oxygen analyzer.
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ii)
Normal expected values of oxygen and hydrogen concentrations for
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comparison to logged values.
iii)
Check of the liquid nitrogen storage tanks to ensure an adequate
volume of nitrogen is available for dilution of the Waste Gas
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Decay Tanks (WGDT) if required.
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A permanent nitrogen addition system has been installed which allows
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nitrogen to be added directly from the plant's nitrogen header to the
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WGDT's.
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The range selector switches have been replaced with switches that have
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a spring return to the proper low scale position.
Operating Procedure OP-412, Waste Gas Disposal System, has been revised
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(revision 40 dated August 5,1986) to include instructions for opera-
tion of the permanent nitrogen addition system.
Action on this item is considered complete.
(Closed) Violation 302/86-22-02:
This violation was written to address
inadequate corrective action taken by FPC for Violation 302/84-33-01 and
Deviation 302/85-44-01 which resulted in Violation 302/86-22-01 discussed
above.
The corrective action taken in response to Violation 302/86-22-01
addresses the corrective action to this Violation and action on this item is
considered to be complete.
(Closed) IFI 302/86-12-08:
The licensee has completed the cleaning and
flushing of the lines suppling bearing flush water to the nuclear services
seawater pumps (RWP-2A, RWP-28) and decay heat seawater pumps (RWP-3A,
RWP-38).
The licensee has also completed an engineering analysis to
determine the necessary amount of flush water which these pumps need.
This
analysis concludes that as long as the pump bearings are kept flooded or
receive any amount of flush water flow, then the pumps should operate
satisfactory.
However, this analysis recommends that on any indication of a
loss of normal bearing flush water to these pumps, that RWP-2A or RWP-2B
should be started within ten minutes.
The licensee has revised the
appropriate annunciator response proce<~e to reflect this recommendation.
This item is considered to be closed.
(0 pen) IFI 302/86-35-07:
This IFI was written to review the licensee's
activities to determine the cause for the "B" main feetiwater pump overspeed
The licensee has done extensive troubleshooting on this pump
and has completed the following activities in an attempt to correct these
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Modified the Integrated Control System (ICS) input signal to the pump's
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governor electronic control assembly from a voltage signal to an
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amperage signal to reduce electrical noise.
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Shielded the ICS input signal cable.
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Replaced the governor's actuator.
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Tested the main steam supply line to the pump's turbine.
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Installed temporary recorders to monitor the ICS and governor
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operation.
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At this time the licensee has been enable to positively identify the cause
for the pump to overspeed and is continuing their investigation into this
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problem.
The licensee is considering replacement of the Woodward governor
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electronic analog controller with a new " state of art" digital controller
which should be immune to electrical noise.
Also the licensee plans to
install a high frequency filter on the ICS input signal to further reduce
electrical noise.
This item will remain open pending completion of the
licensee's investigation and corrective action.
4.
Unresolved Items
Unresolved items were not identified during this inspection period.
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5.
Review of Plant Operations
The plant began this inspection period in power operation (Mode 1).
On
November 11, at 1:21 p.m. , a control rod fell into the reactor core.
A
power reduction and reactor shutdown was initiated while troubleshooting
was conducted to determine the cause for the dropped control rod.
On
November 14, at 10:38 a.m. , the plant was cooled down to cold shutdown
(Mode 5) to replace a defective control rod d"ive stator.
After these
repairs were completed, a plant heatup was commenced and at 1:43 p.m. on
November 21 the hot standby condition (Mode 3) was reached.
On November 22,
at 2:10 a.m. plant operators observed an increase in reactor coolant system
leakage and a plant cooldown and depressurization was conducted to repair
the makeup and purification system letdown coolers, (see paragraph 9 of this
report for details).
After repairs had been completed to the makeup and
purification system letdown coolers, a plant heatup was commenced and Mode 3
reached at 10:09 a.m. on December 23, followed by the resumption of power
operation at 11:35 p.m. on December 24.
On January 2, at 9:20 a.m., plant
operators noticed that the first stage seal for the
"A" reactor coolant
pump showed degrading indications and a reactor shutdown and cooldown was
commenced to replace this seal package.
The plant remained in Mode 5 for
the remainder of this inspection period.
a.
Shift Logs and Facility Records
The inspector reviewed records and discussed various entries with
operations personnel to verify compliance with the Technical Specifica-
tions (TSs) and the licensee's administrative procedures.
The following records were reviewed:
Shift Supervisor's Log; Outage Shift Manager's Log; Reactor Operator's
Log; Equipment Out-0f-Service Log; Shift Relief Checklist; Auxiliary
Building Operator's Log; Active Clearance Log; Daily Operating Surveil-
lance Log; Work Request Log; Short Term Instructions (STIs); and
Selected Chemistry / Radiation Protection Logs.
In addition to these record reviews, the inspector independently
verified clearance order tagouts.
No violations or deviations were identified.
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b.
Facility Tours and Observations
Throughout the inspection period, facility tours were conducted to
observe operations and maintenance activities in progress.
Some
operations and maintenance activity observations were conducted during
backshifts.
Also, during this inspection period, licensee meetings
were attended by the inspector to observe planning and management
activities.
The facility tours and observations encompassed the following areas:
security perimeter fence; control room; emergency diesel generator
room; auxiliary building; intermediate building; reactor building;
battery rooms; and electrical switchgear rooms.
During these tours, the following observations were made:
(1) Monitoring Instrumentation - The following instrumentation was
observed to verify that indicated parameters were in accordance
with the TS for the current operational mode:
Equipment operating status; area atmospheric and liquid radiation
monitors; electrical system lineup; reactor operating parameters;
and auxiliary equipment operating parameters.
During these plant tours, the inspector noted the continuing
licensee activities to locate and repair minor leaks in the waste
gas system which has caused increased gaseous activity in the
atmosphere of the auxiliary building (AB).
While this increased
activity has been minor in nature, it has been recurring and as
a result, the licensee established a task force to locate the
sources of these leaks.
As the result of this task force's investigations, the licensee
has identified minor radioactive gas leaks around the make-up tank
(MUT).
It is postulated that these leaks were caused by the
following:
Valve stem leaks out of nitrogen and hydrogen addition
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diaphragm valves MUV-141 and MUV-143;
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A pipe union leak from a pressure transmitter instrument
fitting; and,
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A weep hole in the weld securing a reinforcing saddle for a
pipe connection located at the top of the MUT.
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The licensee has repaired valves MUV-141 and MUV-143 and the pipe
union leak but is unable to repair the weld weep hole at this
time.
The hole appears to be sufficiently small enough so that a
special ventilation system the licensee has installed in the MUT
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room, which includes an independent filter system, can mitigate
this leakage.
The independent filter system exhausts to the
normal AB ventilation stack so that all releases are adequately
monitored.
This . filter system has been effective since no
increases of radiation levels in the AB atmosphere have been
detected.
It is planned to repair this weep hole during the next
refuel outage.
IFI (302/86-38-01):
Review the licensee's activities to repair
the weld weep hole in the MUT.
(2) Safety Systems Walkdown - The inspector conducted a walkdown of
the Core Flood (CF) system to verify that the lineup was in
accordance with license requirements for system operability and
that the system drawing and procedure correctly reflect "as-built"
plant conditions.
No violations or deviations were identified.
(3) Shift Staffing - The inspector verified that operating shift
staffing was in accordance with TS requirements and that control
room operations were being conducted in an orderly and profes-
sional manner.
In addition, the inspector observed shift turn-
overs on various occasions to verify the continuity of plant
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status, operational problems, and other pertinent plant informa-
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tion during these turnovers.
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No violations or deviations were identified.
(4) Plant Housekeeping Conditions - Storage of material and components
and cleanliness conditions of various areas throughout the
facility were observed to determine whether safety and/or fire
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hazards existed.
No violations or deviations were identified.
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(5) Radiation Areas - Radiation Control Areas (RCAs) were observed to
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verify proper identification and implementation.
These observa-
tions included selected licensee conducted surveys, review of
step-off pad conditions, disposal of contaminated clothing, and
area posting.
Area postings were independently verified for
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accuracy by the inspectors.
The inspectors also reviewed selected
radiation work permits and observed the use of protective
clothing, respirators, and personnel monitoring devices to assure
that the licensee's radiation monitoring policies were being
followed.
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On November 18, while' observing maintenance activities within
the -Reactor Building (RB), the inspector noted three -licensee
personnel that were not wearing glasses that provide beta protec-
tion for the eyes.
The posting for the RB required beta protec-
tion for all personnel within the building.
When a' roving health physics (HP) technician, that was in the
immediate area, was notified of this observation, the technician
immediately corrected the situation.
The licensee's radiation protection procedure, RSP-101, defines
posting as a radiological control in paragraph 2.3.26 and requires
adherence to radiological controls -in paragraph 3.1.3.4.
Failure
to adhere to the requirements of procedure RSP-101 is considered
to be contrary to the requirements of TS 6.11 and is considered to
be a Violation.
Violation (302/86-38-02):
Failure to adhere to the posting
requirements of radiation protection procedure RSP-101 as required
by TS 6.11.
(6) Security Control - Security controls were observed to verify that
security barriers were intact, guard forces were on duty, and
access to the Protected Area (PA) was controlled in accordance
with the facility security plan.
Personnel within the PA were
observed to verify proper display of badges and that personnel
requiring escort were properly escorted.
Personnel within vital
areas were observed-to ensure proper authorization for the area.
No violations or deviations were identified.
(7) Fire _ Protection - Fire protection activities, staffing and equip-
ment were observed to verify that fire brigade staffing was
appropriate and that fire alarms, extinguishing equipment,
actuating controls, fire fighting equipment, emergency equipment,
and fire barriers were operable.
No violations or deviations were identified.
(8) Surveillance - Surveillance tests were observed to verify that
approved procedures were being used: qualified personnel were
conducting the tests; tests were adequate to verify equipment
operability; calibrated equipment was utilized; and TS require-
ments were followed.
The following tests were observed and/or data reviewed:
- SP-104, Hot Channel Factors Calculations;
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- SP-113, Power Range Nuclear Instrumentation Calibration;
- SP-154, Functional Testing and Calibration of the
Triaxial Time-History Accelographs and
Triaxial Seismic Switch;
- SP-177, Local Leak Rate Test of AHV-1A thru
AHV-10;
- SP-179, Containment Leakage Test-Types "B" & "C";
- SP-181, Containment Air Lock Test (only a
procedure review was conducted, no data
was reviewed);
- SP-317, RC System Water Inventory Balance;
- SP-326A, Toxic Gas Detection System (Weekly);
- SP-333, Control Rod Exercises;
- SP-335, Radiation Monitoring Instrumentation
Functional Test;
- SP-363, Fire Protection System Tests;
- SP-404, Fire Deluge & Sprinkler System
Surveillance;
- SP-421, Reactivity Balance Calculations;
- SP-422, RC System Heatup & Cooldown Surveillance;
- SP-455, Functional Test of Vital Bus Redundant
Transformers & Static Transfer Switches;
- SP-510, Weekly Battery Check (Units 1&2);
- SP-512, Battery Inspection & Charger Test (Units 1
& 2); and,
- SP-513, Battery Service Test (Units 1 & 2).
As the result of these reviews, the following items were
identified:
(a) The inspector observed the performance of SP-513 on the newly
installed battery at Unit 2.
This procedure has been
rewritten to test the 'Jnit 1 and Unit 2 batteries under a new
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load profile.
The licensee has been requested
to provide
information regarding the DC loads that these batteries
must supply so that a correct battery load profile can be
verified.
IFI (302/86-38-03):
Review the information to verify the new
load profiles for the Unit 1 and Unit 2 batteries.
(b) On November 12, while reviewing completed data for procedure
SP-421, the inspector noted that Data Sheet II (Enclosure 4)
which is used to compute the shutdown margin with an
inoperable control rod, was incorrectly completed.
The
shutdown margin computed on the day shift of November 11
was computed as -1.5768% delta-k/k whereas the correct
value should have been -2.468% delta-k/k.
Furthermore data
completed on the 4:00 PM to 12:00 AM shift of November 11 and
on the 12:00 AM to 8:00 AM shift of November 12, had to have
numerous corrections made to arrive at a reasonably correct
answer.
Further review of this procedure by the inspector indicated
the following procedure inadequacies:
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Step 6.3.1 of the procedure determines the shutdown
margin available based upon existing core conditions.
This shutdown margin is calculated on Worksheet I
(Enclosure 1) with the resultant shutdown margin
recorded in Step 6.b of the worksheet and on Data
Sheet II.
To assure that the calculations are performed
correctly, the procedure requires in Step 4.3.5, that
all algebraic signs be correctly maintained.
Step 6.b
also states "If the shutdown margin is <1% delta-k/k
during Modes 1,
2,
3,
4,
or 5, notify the shift
supervisor," which means that any positive value greater
than +1% delta-k/k (e.g. , +1.5% delta-k/k) would be
acceptable.
Since a positive number would result if the
reactor being in a critical condition, the intent of
this step, i.e. to assure that the reactor is shutdown,
is not accomplished.
Step 6.3.3 of the procedure determines the shutdown
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margin that would be required to insure a shutdown
reactor with an inoperable control rod.
This margin is
obtained by summing the rod worth of the inoperable
control rod which is obtained from rod worth curves and
recorded in Step 6.3.2 and the TS required shutdown
margin of 1% delta-k/k.
Since the rod worth reactivity
is a positive number, when this number is added to 1%
delta-k/k (as required by Step 4.3.5) the result is a
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positive number which-is in excess of 1%.
The procedure
then goes on to say in Step 6.3.4 that "The value
obtained in Step 6.3.1 must be greater than the value
obtained in Step 6.3.3."
Since this would provide a shutdown margin value that is
always greater than the value obtained in Step 6.3.1, it
appears that there is no way to insure that the required
shutdown margin is met.
Personnel utilizing this procedure realized that the intent
was to end up with a result that was a negative number that
was less than -1% delta-k/k (e.g. , -1.5% delta-k/k).
In
their attempts to arrive at a reasonable result, numerous
corrections had to be made and in all these cases the
procedure required answers were not obtained.
There was no
evidence that an actual improper shutdown margin was not
being maintained.
The error made on the November 11 data sheet and the number
of corrections that had to be made to the following
November 11 and 12 data sheets provided strong evidence that
the procedure was inadequate.
Written procedures must be adequate to assure that the intent
of an evolution is completed correctly.
Failure to have
an adequate procedure is contrary to the requirements of
TS 6.8.1 and is considered to be a violation.
Violation (302/86-38-04):
Failure to have an adequate
procedure for computing reactor shutdown margin.
c)
During a review of procedure SP-181 on November 21, the
inspector noted that step 1.3 had a notation regarding the
surveillance frequency which stated in part:
" Air locks opened during periods when containment
integrity is not required by Technical Specifications
shall be tested at the end of such periods at not less
than Pa.
The 'end' of Mode 5 outages is defined
as..."30 days prior to Mode 4 and 15 days following
ascension to or beyond Mode 4."
Subsequent discussions with licensee personnel indicates that
this notation represented the licensee's interpretation of
10 CFR Part 50, Appendix J, paragraph III.D.2(b)(ii).
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Additionally the licensee believed that an exemption had
been granted by the NRC for relief from this paragraph of
Appendix J.
Further review of this issue by the inspector indicated the
following:
Paragraph III.D.2(b)(ii) of Appendix J requires air
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locks to be tested at the accident pressure (Pa) prior
to entering a mode of operation where containment
integrity is required.
Since the TS require containment
integrity in Modes 1 thru 4, this meant that such
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testing had to be accomplished in Mode 5 (cold shutdown)
and prior to entering Mode 4 (hot shutdown).
The plant changed operational modes, from Mode 5 to
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Mode 3 (hot standby), on November 21-22 and no air lock
test at pressurc Pa had been performed.
The licensee had not received an exemption from the NRC
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that exempted them from the requirements of Appendix J,
paragraph III.D.2(b)(ii).
Failure to comply with the requirements of 10 CFR Part 50, Appendix J is considered to be a Violation.
Violation (302/86-38-05):
Failure to comply with the
air lock testing requirements of 10 CFR Part 50,
Appendix J.
(d) During a review of the completed data for procedure SP-154
performed on October 17, 1986, the inspector noted in step
10.2 of data sheet Enclosure 3, that the vendor performing
the procedure recommended that the acceleromater package
located on the top of the Reactor Building (RB) be inspected
for humidity or desiccant monthly.
The licensee has
developed a Preventative Maintenance (PM) procedure to
accomplish the inspection but has not, pt implemented the
procedure.
The procedure will be implemented within a few
weeks.
Inspector Followup Item (302/86-38-06):
Review PM program
implementation of the humidity / desiccant inspection on the RB
accelerometer.
(9) Maintenance t.ctivities - The inspector observed maintenance
activities to verify that correct equipment clearances were
in effect; work requests and fire prevention work permits, as
required, were issued and being followed; quality control
personnel were available for inspection activities as required;
and TS requirements were being followed.
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Maintenance was observed and work packages were reviewed for the
following maintenance activities:
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Replacement of safety valve RCV-8 in accordance with
maintenance procedures MP-102 and MP-122;
Replacement of the Power Operated Relief Valve (PORV),
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RCV-10, and associated block valve RCV-11 in accordance with
Repairs on the
"0"
vital inverter in accordance with
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procedures MP-531, PM-119 and PM-130;
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Troubleshooting and repair of the
"D" Vital Bus fransfer
Switch (V3XS-10), in accordance with procedures MP-531 and
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Troubleshooting and replacement of a power range neutron
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detector NI-5 in accordance with procedures MP-531 and
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Troubleshooting and repair of auxiliary steam supply valve
ASV-26; and,
Troubleshooting and repair of the Emergency Feedwater
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Initiation and Control (EFIC) channel
"C" main steam line
isolation in accordance with procedure MP-531.
As the result of these reviews, the following items were
identified:
(a) While observing maintenance activities on the vital inverter
the inspector noted that the licensee does not have formal
maintenance procedures (MP) to address repairs to certain
electrical equipment such as inverters or the generator end
of the emergency diesel generators (EDGs).
Maintenance on
this equipment is presently conducted using a Work Request
(WR) and detailed work instructions that receive the same
level of review and approval that a MP would receive.
This observation was discussed with licensee personnel at
which time it was determined that the licensee had not
developed formal MPs for this equipment since it has not
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(until recently on the inverter) required any corrective
maintenance.
The licensee also stated that chey have begun
development of MPs to cover these types of electrical
equipment.
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Inspector Followup Item (302/86-38-07):
Review the
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licensee's progress in developing MPs to cover certain
electrical equipment.
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(b) While reviewing documentation following completion of work on
the inverter, the inspector noted an t.pparent discrepancy
between the post-maintenance testing listed on the WR and the
- testing that was actually performed.
The WR listed procedure
PM-130, Static Inverters, as the procedure to be used for
post-maintenance testing.
However, while reviewing the work
package, the inspector noted that only a portion of PM-130
was performed and that this portion did not appear to provide
-
!
adequate testing.
Subsequent discussions with licensee personnel and review of
additional documentation provided assurance that an adequate
post-maintenance- test had been performed.
The inspector
noted, however, that a potential problem which could result
in incorrect or improper post-maintenance testing may exist
due to improper or incomplete documentation on the WR.
The licensee acknowledged the inspector's remarks and is
2
reviewing the post-maintenance testing area to determine what
'
improvements can be made.
!
Inspector Followup Item-(302/86-38-08):
Review the
licensee's progress to improve the post maintenance testing
.
specification on WRs.
,
j
(10) Radioactive Waste Controls - Solid waste compacting and selected
liquid and gaseous releases were observed to verify that approved
,
procedures were utilized, that appropriate release approvals were
t
obtained, and that required surveys were taken.
No violations or deviations were identified.
(11) Pipe Hangers and Seismic Restraints - Several pipe hangers and
seismic restraints (snubbers) on safety-related systems were
2
observed to insure that fluid levels were adequate and no leakage
i
was evident, that restraint settings were appropriate, and that
'
anchoring points were not binding.
,
4
No violations or deviations were identified.
,
6.
Review of Licensee Event Reports and Nonconforming Operations Reports
j
a.
Licensee Event Reports (LERs) were reviewed for potential generic
1
impact, to detect trends, and to determine whether corrective actions
j
appeared appropriate.
Events, which were reported immediately, were
-
reviewed as they occurred to determine if the TS were satisfied.
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14
LERs 85-34, 86-17, 86-19, 86-20, 86-21, 86-22 and 86-24 were reviewed
in accordance with current NRC policy.
LERs 85-34, 86-17, 86-19, 86-21
and 86-24 are closed.
(1) (0 pen) LER 86-22:
This LER reported that the weekly Unit 1
battery surveillance test required by TS 4.8.1.1.1.C.1 was not
performed within the required time interval.
The LER stated
that the plant status was in Mode 5 with no core alterations in
progress.
The LER further stated that the applicable action
statements of the-TS were complied with.
The inspector reviewed
this matter and determined that during the time period in which
the surveillance test time interval had expired (November 21 -
November 24), a plant heatup to Mode 3 was being performed when a
letdown cooler failure occurred and forced the plant to shutdown
and cooldown to Mode 5.
This action would not have complied with
the TS action statement (TS 3.8.1.2) to suspend all operations
involving positive reactivity additions.
The licensee plans to
issue a supplement to this LER to provide additional information
regarding the plant status and compliance with the TS action
statement.
This LER will remain open pending NRC review of the
supplemental response.
(2) (Closed) LER 85-34:
This LER reported that the core flood tank
isolation valves (CFV-5 and CFV-6) were not verified to be
operable as required by TS 4.5.1.d prior to ascending from Mode 4
to Mode 3.
This action violated TS 4.0.4 which prohibits entry
into an operational mode unless the surveillance requirements
associated with the limiting condition of operation are satisfied.
The licensee has revised surveillance procedure SP-402, Core
Flood System Isolation Valve Alarms Actuation (revision 8 dated
November 15, 1986) to specify that the valves must be checked'
prior to ascending from Mode 4.
This matter is considered to be a
licensee identified violation in which adequate corrective action
was taken to prevent recurrence.
(3)
(0 pen) LER 86-20:
This LER reported that the surveillance
frequency on the Reactor Vessel Vent Valves (RVVVs) and several
other surveillances exceeded the maximum combined interval time
for any three consecutive tests that is required by TS 4.0.2.
Review of this event by the inspector identified the following:
SP-140, Incore Neutron Detector System Calibration, due
-
by August 17, 1986, was not completed as of January 7,
1987;
SP-154, Functional Testing & Calibration of the Triaxial
-
Time-History Accelographs and Triaxial Seismic Switch,
due by August 17, 1986, was not completed until
October 17, 1986;
.
.
.
i
_.
_
_ _ _ _ _ _ _ _ _ _ - _ _ _ _ _
~
.
15
-
SP-202, Inservice I1spection Vent Valve Internals,
due by September 9,1986, was not completed as of
September 30,1986 (however NRC has issued an exemption
to this requirement on November 7, 1986);
SP-363, Fire Protection System Tests, due by October 5,
-
1986, was not completed until November 13, 1986;
-
SP-404, Fire Deluge & Sprinkler System Surveillance, due
by August 29, 1986, was not completed until November 20,
1986;
SP-411, Fire Protection Deluge & Sprinkler Systems Test,
-
due by October 11, 1986, was not completed until
December 14, 1986;
SP-512, Battery Inspection & Charger Test (Units 1 & 2),
-
due by October 4,
1986, was not completed until
November 14, 1986; and,
SP-513, Battery Service Test (Units 1 & 2), due by
-
October 22, 1986, was not completed until November 14,
1986.
Failure to meet the total maximum combined interval for any
three consecutive tests of 3.25 times the specified interval
is contrary to the requirements of TS 4.0.2 and is considered
to be a Violation.
Violation (302/86-38-09):
Failure to perform surveillance
requirements within the maximum combined interval time
specified in TS 4.0.2.b.
While it is recognized that this Violation was identified by
the licensee, it is being cited due to the failure of the
licensee to identify and correct the Violation in a timely
manner.
This LER remains open pending issuance of the supplementary
LER.
b.
The inspector reviewed Nonconforming Operations Reports (NCORs) to
verify the following:
compliance with the TS, corrective actions as
identified in the reports or during subsequent reviews have been
accomplished or are being pursued for completion, generic items are
identified and reported as required by 10 CFR Part 21, and items are
reported as required by TS.
_ _ _ _ _ _ _ _ _ _ _ _ _ _
'
.
16
All NCORs were reviewed in accordance with the current NRC Policy.
As
the result of these reviews, the following items were identified:
(1) NCORs86-224 and 86-228 reported problems which affected the 230
kv switchyard supplying the offsite power source for Unit 3.
NCOR 86-224, dated December 10, 1986, reported that the Unit 1 and
Unit 2 battery load profiles were actually higher than that tested
for during the 18 month battery service tests required by TS 4.8.1.1.1.C.4.
These batteries provide the independent 125 volt
DC control power for protective relaying schemes and breaker
switching for the 230 KV switchyard as described in the Final
Safety Analysis Report (FSAR) section 8.2.3.3.a. Since December,
1976, several modifications have been performed on these batteries
to supply other DC loads for the non-nuclear coal plants.
Therefore the DC loads which these batteries must supply have
changed.
These changes were not reflected in the battery service
test which proves that these batteries can supply actual emergency
loads for one hour.
NCOR 86-228, dated December 15, 1986, reported that three breakers
(numbers 3230, 3233 and 3234) in this switchyard did not comply
with the FSAR section 8.2.3.3.
Specifically, these breakers did
not have the two electrically independent sets of tripping coils
supplied from separate DC supplies.
These breakers were installed
during Unit 4 and Unit 5 coal plant tie-ins to this switchyard in
1981 and 1982.
The licensee has experienced ongoing problems with non-nuclear
modifications to the switchyard and switchyard interfaces which
affect the regulatory basis for the nuclear unit.
LER 85-32 was
issued in January 1986 and reported that an auxiliary transformer
installed in the 230 KV switchyard for the coal plants did not
have the diverse DC control power for the primary and backup
protective relaying as described in the FSAR section 8.2.3.3.
The
corrective action as stated in this LER included a check of the
Unit 4 and Unit 5 interface with the 230 KV substation to assure
that no deficiencies of this type existed there.
None were found.
In addition a review of other interfaces as described in the FSAR
was conducted and no deficiencies were identified.
It appears
that if this review had been adequate, the events discussed in
NCOR's86-224 and 86-228 would not have occurred.
Failure to take adequate corrective actions thereby preventing the
occurrence of the problems identified by NCOR's86-224 and 86-228
is considered to be contrary to the requirements of 10 CFR Part 50
Appendix B Criterion XVI and the FPC Quality Program section
1.7.1.16, Corrective Action, and is considered to be a violation.
-_ _ _
_ _ _ -
I-
!
'
..
17
Violation (302/86-38-10):
Failure to take adequate corrective
action to identify and correct problems in the 230 KV switchyard.
(2) NCORs86-204 and 86-205 reported that procedure SP-351, Nuclear
Services Flow Path Operability, was not adequately implementing
TS ' 4. 7. 3.1. a and 4. 7. 4.1. a.
These TS require that each valve
servicing safety related equipment in the Nuclear Services Closed
Cycle Cooling (SW) and Nuclear Services Seawater (RW) systems
which is not secured in position be verified in its correct
position at least every 31 days.
The inspector reviewed these NCORs for reportability and noticed
that. at least two- of the seven valves listed on an attachment to
the NCORs were manual isolation valves which serviced safety
related equipment.
These two valves (SWV-305 and RWV-26) supplied
the safety related portion of the Domestic Water (DO) system to
supply bearing flush water to the safety related nuclear services
and decay heat seawater pumps.
Procedure SP-351 should have
included these valves to comply with the TS but did not.
The
licensee identified this problem on November 14, 1986 and is going
to revise procedure SP-351 accordingly.
However, this matter was
not reported to the NRC via an LER within thirty days as required
by 10 CFR Part 50.73.a.2.i.B.
FailuretoreportviaanLERanyoperationorconditionprohibited
by the plant s TS is contrary to the requirements of 10 CFR 50.73.a.2.i.B and is considered to be a violation.
Violation (302/86-38-11)i
Failure to issue a LER.
(3) NCOR 86-188 reported that normally closed inboard containment
isolation valve AHV-1C was discovered off its seat during the
performance of a type B leak rate test in accordance with
procedure SP-177, Local Leak Rate Test of AHV-1A thru AHV-10.
The
inspector reviewed this NCOR and on December 9,1986, discussed
the results of the leak rate test with the leak rate examiner who
performed this test.
This test is accomplished by pressurizing
the air space between AHV-1C and AHV-10 (the associated outboard
containment isolation valve)' to Pa (the postulated post accident
reactor building internal pressure - approximately 60 psig) and
measuring the leakage rate from the two containment isolation
valves.
Since AHV-1C was not properly seated, the leakage rate
exceeded the test equipment capacity to pressurize this air space
and Pa could not be achieved (only approximately 25 psig could be
obtained).
Therefore the leak rate of this penetration could not
be determined.
The licensee was unable to obtain the as found
leak rate for the downstream valve AHV-1D due to plant conditions
but did perform a soap check of the seating surfaces of this valve
at the 25 psig pressure that was obtained.
The results of this
check revealed that this valve appeared to be seated properly.
- _ _ _ _ _ _ _ _ _ _
.
.
18
TS 3.6.1.2 requires containment leakage rates be limited to a
combined leakage rate of less than .6 La (maximum allowable
leakage rate at pressure Pa) for all valves and penetrations
subject to type B and C tests.
The inability of the licensee to
show that the limits of this TS were not exceeded (since the
leakage rate for the AHV-1C, AHV-1D penetration could not be
determined) placed the plant in a condition prohibited by the TS.
This situation should have been reported to the NRC via an LER
as required by 10 CFR 50.73.a.2.i.B and is considered to be a
violation.
This violation is another example of the violation
discussed in the preceding paragraph of this report (paragraph
6.b(2)).
(4) NCOR 86-226 reported that an engineering evaluation to verify
control room habitability, conducted on November 3,
1986,
identified that in June,1984, a sulfur dioxide tank had been
installed at the Unit 1 coal plant.
Due to the close proximity of
this tank to the nuclear unit, the licensee performed a conserva-
tive accident analysis for this tank and has determined that
unacceptable levels of sulfur dioxide could accumulate in the
nuclear unit's control room should a catastrophic failure of the
tank occur.
The licensee is pursuing additional protective
measures to ensure that a catastrophic failure to this tank does
not occur.
In a letter to the NRC dated December 18, 1986, the licensee
outlined the corrective action that was being performed to protect
the tank and provided justification to continue operating the
nuclear unit.
The low probability of a catastrophic failure of
the tank and a more probable accident analysis showed little
detriment to the safe operation of the nuclear plant.
However,
this letter stated that the following short term corrective
actions would be accomplished:
A sulfur dioxide monitor would be installed in the nuclear
-
unit's control room by January 30, 1987.
,-
A sulfur dioxide monitor would be installed at the sulfur
dioxide tank and this monitor would provide input to an alarm
in the nuclear unit's contral room.
This action would be
completed by February 15, 19o7, and,
Air breathing apparatus (air packs) would be provided in the
-
control room.
These air packs would be included in the
preventive maintenance program for air packs.
IFI (302/86-38-12):
Review the completion of the licensee's short
term protective measures for the sulfur dioxide tank.
- - __ _ _-
_ _ _ _ _ _ _
'
.
19
This letter further stated the following long term corrective
actions to be taken:
Complete permanent protective measures for the sulfur dioxide
-
tank by June 30, 1987.
Complete a report for 'the control room habitability review
-
by June 30, 1987 to determine if additional actions are
required, and,
Complete the control room habitability modifications in
-
Refuel 6.
IFI (302/86-38-13):
Review the completion of the licensee's long
term protective measures for the sulfur dioxide tank.
7.
Review of 10 CFR Part 21 Evaluations
An evaluation of NCOR 86-96 regarding the design nozzle loading on the steam
turbine of the emergency feedwater pump (EFTB-1) was reviewed to verify
compliance with 10 CFR Part 21.
No violations or deviations were
identified.
8.
Review of IE Bulletins (IEB) and IE Information Notices (IEN)
(Closed),IEB 86-03:
The inspector reviewed the licensee's response to IEB 86-03, Potential Failure of Multiple Emergency Core Cooling System (ECCS)
Pumps Due to Single Failure of Air-0perated Valve in Minimum Flow Recircula-
tion Line.
The licensee determined that the problem described by this
bulletin did not apply because of the design of these recirculation lines
at this facility.
Licensee action on this bulletin is considered to be
complete.
(Closed) IEN 86-106:
The inspector reviewed the licensee's activities with
respect IEN 86-106, Feedwater Line Break.
Upon notification of the line
break event that occurred at the Surry Nuclear Plant, the licensee formed a
" Pipe Rupture Task Force" to determine what pipe examination activities
could be accomplished while in their current outage.
The task force
identified 22 areas within the feedwater system that had similar flow
characteristics (i.e., elbows, high turbulence areas, etc.) to the area that
failed at the Surry plant and began Ultrasonic Testing (UT) on these areas.
This testing is expected to be completed prior to the end of the current
outage.
The results of the UT remain to be reviewed.
Inspector Followup Item (302/86-38-14):
Review the results of the UT on the
main feedwater piping performed due to the Surry event.
.-
-.
.
20
9.
Nonroutine Event Followup
On November 22, at 2:10 a.m.
the plant was in the hot standby (Mode 3)
condition.
Plant operators observed an increase in the Nuclear Services
Closed Cycle Cooling (SW) system activity with a corresponding increase in
thissystem'ssurgetanklevel.
Monitoring of the makeup and purification
.
system s makeup tank revealed that a reactor coolant system to SW system
leak had occurred.
The leakage rate was estimated at four gpm.
An unusual
event was declared and a plant cooldown was commenced in accordance with TS 3.4.6.2.b.
The leak was determined to be from the "A" makeup and purifica-
tion letdown cooler (MUHE-1A).
This leak was isolated and the unusual event
terminated at 7:50 a.m.
A NRC welding specialist inspector observed the cooler replacement and weld
repairs.
The results of this observation are documented in NRC inspection
report 50-302/86-40.
Further information on this matter can be found in
that report.
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