IR 05000295/1989002
| ML20246L392 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 03/08/1989 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20246L381 | List: |
| References | |
| 50-295-89-02, 50-295-89-2, 50-304-89-02, 50-304-89-2, NUDOCS 8903240166 | |
| Download: ML20246L392 (22) | |
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J LU.S. NUCLEAR' REGULATORY COMMISSION
REGION III
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.. Report Nos.-50-295/89002(DRP); 50-304/89002(DRP)
Docket Nos. 50-295; 50-304
' License Nos. DPR-39; DPR-48 Licensee: Commonwealth Edison Company P..O. Box 767-Chicago, IL 60690 Facility Name: Zion Nuclear Power Station, Units 1 and 2 Inspection At:
Zion, IL Inspection Conducted: January 4, 1989 through February 17, 1989 Inspectors: _ M. M. Holzmer--
P. L. Eng D. J. Damon R. M. Lerch-L. P. Zerr
'J. M. Ulie
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MAR 0 81989 Approved B :
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.. Hinds, eactor Projects Section 1A Date Inspection Summary Inspection from January 4,1989.through February '17,1989 (Report Nos.
50-29.5/89002(DRP); 50-304/89002(DRP))
-Areas Inspected:
Routine, unannounced resident inspection of licensee action
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on previous inspection findings; summary of operations; January 15, 1989 Unit 2 shutdown.for steam generator tube leakage; January 27.- 1989, Unit i reactor trip; January 31,1989, Unit 2 manual reactor trip; February 6,1989, Unit i reactor' shutdown for heater drain' tank rupture disk repairs; operational safety verification and engineered safety feature (ESF) ' system walkdown; surveillance and maintenance observation; licensee event reports (LERs);
quality program effectiveness; January 26, 1989, site visit by NRC Regional Ad.ninistrator, allegations and CECO corporate and site organization changes.
Results: Of the 12 areas inspected, no violations or. deviations were identified in 10 areas, and two violations were identified in the remaining two~ areas [ failure to obtain as-found condtition during valve stroke time testing (Paragraph 9) and violation of Technical Specification 3.0.4 when changing modes with pressurizer power operated relief valve inoperable (Paragraph 10)]. While plant housekeeping and material generally improved, steam generator manway gasket and tube leakage and valve packing and seat leakage adversely affected' plant availability for the units.
In addition, there were two reactor trips which occurred during routine testing and troubleshooting.
8903240166 890310 I
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'PDR ADOCK 05000295
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DETAILS 1.
Persons Contacted G. Plim1, Station Manager i
+E. Fuerst, Superintendent, Production
'*T. Rieck, Superintendent, Services
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- W. Kurth, Assistant Station Superintendent, Operations R. Johnson, Assistant Station Superintendent, Maintenance
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J. Gilmore, Assistant Station Superintendent, Planning j
R. Budowle, Assistant Station Superintendent, Technical Services
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N. Valos, Unit 2 Operating Engineer M. Carnahan, Unit 1 Operating Engineer
- R. Cascarano, Technical. Staff Supervisor A. Ockert, Training Supervisor
T. Vandevoort, Quality Assurance Supervisor
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V. Williams, Station Health Physicist
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C. Schultz, Quality Control Supervisor i
+W. Stone. Regulatory Assurance Supervisor
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W. T'Niemi, Master Mechanic
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A. Bless, Regulatory Assurance Engineer G. Levy, Regulatory Assurance Engineer (Richardson and Estes)
- G. Olson, Quality Assurance Engineer
- P. Pawlak, Technical Staff Engineer
- P. LeBlond, Radiation Chemistry Supervisor
+T. Joyce, Station Manager
- Indicates persons present at the exit interview conducted on February 10, 1989.
+ Indicated persons present at the exit interview conducted on February 17, 1989. Mr. T. Joyce became the Station Manager effective February 13, 1989.
2.
Licensee Actions on Previous Inspection Findings (92701, 92702)
(Closed) Unresolved Item (295/81011-02; 304/81007-02):
Failure to provide each fire brigade member with annual practice sessions using j
actual fire extinguishing equipment and emergency breathing apparatus i
under strenuous conditions in accordance with Technical Specifica-tiens 6.1.E and NFPA Code-1975, Section 27.
Fire brigade members now attend quarterly classroom training and annual training using fire i
extinguishing equipment. Since 1984, the licensee has provided annual training using emergency breathing equipment in a " smokehouse" constructed on the site.
Fire drills are held quarterly, and attendance at a minimum of two drills per year for each fire brigade member is required and tracked using the attendance list on the Fire Drill Evaluation Form. All other training for fire brigade members is documented and tracked by the training department.
Since the specific concerns originally raised appear to have been addressed, this item is being closed.
Evaluation of the adequacy of the licensee's practical training sessions will be tracked as an Open Item (295/89002-01(DRS);
304/89002-01(DRS).
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(Closed)OpenItem(295/85011-01(DRS);304/85012-01(DRS)): Licensee review and incorporation of the manufacturer's current preventive maintenance instructions for the emergency lighting units (Teledyne).
A reference in the Zion Generating Station Maintenance Procedure Emergency Light Surveillance Numbered E041-1, Revision 0, dated November 3, 1987, included a reference to the Teledyne Operating and Maintenance Instructions. No other discrepancies were noted during this review. This item is considered closed.
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(Closed)OpenItem(295/85011-02(DRS);304/85012-02(0RS)):
Emergency lighting adequacy. During inspectors' discussions with the licensee's
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staff regarding the emergency lighting units, the licensee indicated that a walkdown of the emergency lighting units will be performed to determine that an adequate number of lighting units are installed and l
that sufficient illumination levels exist.in areas required by Section
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Ill.J of Appendix R.
By letter dated August 31, 1984, the licensee submitted a modified implementation schedule of work necessary to achieve compliance with 10 CFR 50, Appendix R.
Item No. 23 of this schedule indicated that the adding of additional emergency lighting units and aiming of their attached lamps is planned to be completed by January 1, 1986, to satisfy Section III.J of Appendix R.
During an inspection conducted during November 16-20, 1987, it was-
. identified that inadequate or no emergency lighting existed in five plant areas. This resulted in a violation being issued in Inspection Reports No. 50-295/87034-05; 50-304/87035-05. Therefore, to avoid duplication, Item 295/85011-02(DRS); 304/85011-02(DRS) is considered i
closed.
No violations or deviations were identified.
3.
S_ummary of Operations Unit 1 The unit began the inspection period in Mode 1 and operated at power I
levels up to 100% until January 27, 1989, when the unit tripped while o
the licensee was troubleshooting a reactor protection and safeguards test light failure (see Paragraph 6). The unit was tied to the grid on January 29, 1989, and operated until February 6, 1989, when the unit was shutdown to repair a blown heater drain tank rupture disk and remained
shutdown for the remainder of the inspection period to repair steam
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generator manway leakage on the 1B and IC steam generators (see Paragraph 7).
Unit 2 The unit began the inspection period in Mode 1 and operated at power levels up to 90%. On December 27, 1988, shortly after startup from the October - December 1988 refueling cuta generator was identified (see Paragraph 4)ge, a leak in the 2A steam The leak rate was trended
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until January 15, 1989, when the unit was shutdown to investigate the
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cause of the leak. Seven tubes in the 2A steam generator were plugged and the unit was prepared for return to power. On Januar; 31, 1989, with the unit subcritical at normal operating temperature and pressure, six control rods fell into the core during troubleshooting activities on the control rod power supply cabinets. At the time, all four shutdown control rod banks and two control banks withdrawn from the core. The
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reactor was manually tripped (see Paragraph 6). The unit was made critical on January 31, 1989, and tied to the grid on February 1,1989.
The unit has operated at power levels'up tc 100% power for the remainder of the inspection period.
i No violations or deviations were identified.
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January 15, 1989 Unit 2 Shutdown to Repair Steam Generator,,"A" Primary to Secondary Leak (93702)
After startup from the October - December 1988, refueling outage, the licensee identified a steam generator tube leak. All four of the steam generators had undergone eddy current testing during the outage. The licensee monitored the leak by analyzing seccndary water for both sodium-24 and nitrogen-16 several times each day. The leak rate varied from 50 gallons per day (gpd) to about 250 gpd. On January 15, 1989, after the leak rate increased to 440 - 470 gpd, the licensee informed l
the senior resident that it intended to shut the unit down in order to
. locate and plug the leaking tubes. The unit was shut down the same day, and after the cooldown, the "A" reactor coolant system (RCS) loop isolated using the loop isolation valves. With the "A" RCS-loop drained, the
"A" steam generator level was held at approximately 70%
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wide range and the tube sheet was visually inspected.
Inspections
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revealed that the row 1, column 55 tube was leaking. While the level
in the "A" steam generator was slowly lowered, changes in the observed leak rate indicated that the tube crack was located near the cold leg
side of the apex of the U bcnd.
i The licensee then drained 2A the steam generator and pcrformed enhanced i
eddy current testing using a rotating pancake coil. Normal eddy current l
testing uses a bobbin coil. Enhanced eddy current testing results
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revealed a circumferential crack approximately.625 inches in length and approximately.1 inches wide.
The licensee noted that previous bobbin coil eddy current testing of the cracked tube revealed an indication which was considered to be acceptable.
The licensee reviewed previous bobbin coil eddy current testing results and plugged those tubes which had indications similar to that of the row 1, column 55 tube. Six row 1 tubes were plugged. A seventh tube was plugged due to rolled end indications.
On January 30, 1989, a conference call was held between licensee, NRR and
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Region III personnel. The licensee stated that according to Westinghouse (W), the SG manufacturer, the crack was not induced by fatigue, but was caused by stress corrosion cracking.
NRR individuals were concerned that i
if the. cracked tube was not stabilized af ter it was plugged, that the
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tube crack could propagate completely, severing the tube. The tube, even
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if plugged and not leaking, could thus move in the flow of the steam and damage adjacent tubes.
The licensee stated that they expected to receive
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a report from (H) within about three weeks which would provide technical justification for not stabilizing the leaking tube after it was plugged the licensee agreed to forward the results of the (g) report to NRC shortly after it was received.
The licensee also noted that they would continue to sample Unit 2 SGs daily until a few weeks after the unit reached full power and would then evaluate whether to return to the Technical Specification (TS) required frequency of weekly.
The licensee was asked if an administrative limit would be used until more was known about the failure. The licensee stated that the current limits in use for Unit 2 (500 gpd per SG as required in TS) were sufficiently conservative and would be adhered to.
NRC Region III asked that the licensee notify the resident inspectors or tie region in the event that the leak rate in any SG reached 200 gpd, and the licensee i
agreed to do so.
No violations or deviations were identified.
5.
January 27, 1989, Unit 1 Reactor Trip (93702)
On January 27, 1989, with the Unit 2 in hot shutdown, Unit I tripped from full power. Just prior to the trip, an electrical maintenance technician was troubleshooting a reactor protection and safeguards test light failure.
The technician had removed a test jumper when the 20-ET valve which controls the electro hydraulic control (EHC) fluid received
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an open signal. This allowed the EHC fluid to slowly drain down, causing I
the turbine stop valves to drift closed. When the steam supply could no i
longer meet the full power turbine demand, the turbine tripped. Since
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the reactor was above the 10% power setpoint, the reactor also tripped.
l All systems responded as designed.
i Review of the technician's actions and comparison between the as built wiring with the schematic diagrams did not identify the root cause for l
the trip. Review of the licensee's corrective actions will be performed
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as part of the review of the Licensee Event Report (LER).
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No violations or deviations were identified.
l 6.
Unit 2 Manual Reac_ tor Trip While in Hot Shutdown (93702)
j On January 31, 1989, with the unit subcritical, at normal operating temperature and pressure and all four shutdown control rod banks and two control banks withdrawn from the core, six control rods fell into the core during troubleshooting activities on the control rod power
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supply cabinets. The reactor was manually tripped to restore the plant to a known stable condition.
i Earlier in the day, a rod urgent failure had been received while operators were withdrawing the control rods during the approach to criticality. The shift engineer requested that members of the technical
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staff assist the shift in troubleshooting activities. The technical staff engineer identified the rod urgent failure alarm as caused by an
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' apparent phase control error in power cabinet 1 AC. The engineer
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successfully resolved the phase control error, and rod pulls were resumed. The operator received a multiplexing error upon attempting i
to pull rods and the technical staff engineer was sent-to investigate.
q During troubleshooting ' activities for the multiplexing error, the
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engineer attempted to exchange the error detector card for group A in power cabinet 1 SCD for the card associated with group A in power
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cabinet 1 AC. When the error detector cards were pulled, six control rods dropped into the core. The shift control room engineer decided to manually trip the remaining rods into the core rather than risk recovery of the dropped rods.
Preliminary investigation by the licensee revealed that the engineer performing the trouble shooting did not insure that the control rod stationary gripper coils would remain energized when removing the error detector cards. The cau'se of the rod urgent failure was identified as a failed signal processing card in power cabinet 1 AC. The unit was made critical on January 31, if'9, and tied to the grid on February 1, 1989.
The licensee has conducted a formal error evaluation for this event.
Review of the licensee's analysis and associated corrective actions will be performed as part of the NRC review of the Licensee Event Report (LER).
No violations or deviations were identified.
7.
February 6,1989, Unit 1 Reactor Shutdown to Repair Heater Drain Tank Rupturetisk_(93702)
On February 6, 1989, at approximately 9:47 a.m. Unit I was operating at approximately 99% power when the reactor operator received indications that the heater drain tank rupture disk had failed. At the time, Unit 2
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was operating at full power. The shift engineer ordered Unit 1 power
reduced to 50% at 10% per minute. The unit reached 50% power at 10:30 a.m..
At 6:18 p.m. the unit was ramped down towards hot shutdown.
The turbine was taken off line and repairs to the rupture disk were performed.
While preparing to return the unit to service, the licensee noted an abnormally high reactor coolant system leak rate and observed leakage from the IB and 1C steam generator (SG) primary manways. The unit was taken to the cold shutdown condition to perform repairs on all four SG manways.
No violations or deviations were identified.
O erational Safety Ve'ification and Engineered Safety Features System i
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,a down__(_71707 & 71710)
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The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators from January 4 through February 10, 1989. During these discussions and observations, the inspectors ascertained that the operators were alert, cognizant of plant conditions, attentive to changes in those conditions, and took
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prompt action when appropriate.
The inspectors verified the operability
of selected emergency systems, reviewed tagout records and verified
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proper return to service of affected corrponents. Tours of the auxiliary and turbine buildings were conducted to observe plant equipment i
conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated i
for equipment in need of maintenance.
I The inspectors, by observation and direct interview, verified that
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selected physical security activities were being implemented in
accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of. radiation protection controls.
From January 4, 1989 to February 10, 1989 the inspectors walked down the accessible portions of the component cooling system to verify operability.
These reviews and observations were conducted to verify that facility l
operations were in conformance with the requirements established under
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Technical Specifications, 10 CFR, and administrative procedures.
l Observations:
The inspectors observed the Unit 1 shutdown on February 6, 1989.
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The shutdown was performed in an orderly manner, using the appropriate procedures. Communications were complete and accurate, using appropriate repeat-back techniques.
While elevated xenon gas levels in the auxiliary building existed,
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access to the auxiliary building was restricted to minimize the potential for radioactive uptakes in excess of 10 CFR 20 limits.
The xenon gas was released to the auxiliary building from leakage from chemical and volume control system (CVCS) valves.
Efforts to locate the leaks required several days during which time access was restricted.
No violations or deviations were identified.
9.
Monthlyjiaintenance and Surveillance Observations (62703 & 61726)
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l Station maintenance activities on safety-related systems and components
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were observed or reviewed to ascertain whether they were conducted in accordance with approved procedures, regulatory guides industry codes or standards and in conformance with Technical Specifications. Consideration was given to:
the limiting conditions for operation while components or i
systems were removed from service; approvals prior to initiating the l
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work; use of approved procedures; functional testing and/or calibrations I
prior to returning components or systems to service; quality control I
records; personnel qualifications and training; certification of parts and materials; radiological and fire prevention controls.
In addition, work requests were reviewed to detemine status of outstanding jobs and
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to assure that priority is assigned to maintenance on safety-related equipment which may affect system performance.
Technical Specifications required surveillance testing on the reactor
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ventilation and containment isolation systems was reviewed or observed.
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Consideration was given to: procedures; calibration of test instrumen-i tation; limiting conditions for operation during testing; removal and
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restoration of the affected components; whether test results conformed with technical specifications and procedure requirements; review of
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test results by personnel other than the individual directing the test; I
and correction of any deficiencies identified during the testing.
The following maintenance activities were observed or reviewed:
Work Request Number Title Z77732 Unit 2 Letdown Isolation Valve 2 LCV RC-460 Z77441 Unit 2 Letdown Isolation Valve 2 LCV RC-459 276245 Unit 1 Purge Supply Valve 1 A0V RV-0002 277892 Unit 1 Turbine Trip Valve ET-20 Test Light The inspectors reviewed test documentation for the following tests:
PT-28 Containment Purge Valves /H M nitor Valves Stroke Time
Verification PT-78 Aux Feedwater Pumps Service Water Valves Operability Checks Findings a.
Performance Test, PT-78, " Aux Feedwater Pumps Service Water Valves Operability Checks," directs test personnel to apply "Neolube" to the stems for valves SW-101, SW-102, SW-103, SW-104 and SW-105 prior to stroke time testing.
These are the service water (SW) supply valves for the auxiliary feedwater pumps.
Lubricating the valve stems prior to measuring valve stroke time could have prevented obtaining the actual as-found valve stroke times.
Since early 1988, PT-78 test documentation included a precaution which stated, " Prior to operation of the service water supply to the aux feedwater pump M0Vs, apply neolube to the stem for lubrication."
PT-78 was revised on March 2, 1988 such that the precaution read,
" Prior to operation of the service water supply to the aux feedwater pump MOVs, apply neolube to the stem for lubrication per ZAP 10-52-9."
The ZAP specified that the valve be verified open with the threads (of the stem) exposed; after which, the stem is to be lubricated with Neolube. The March 2, 1988, PT-7B revision also added procedure step 5.2 which stated, "Have local operator j
'Neo-lube' valve stems for the following valves prior to stroking."
10 CFR 50, Appendix B, Criterion XI, as implemented by the Commonwealth Edison Company (CECO) NRC-approved Quality Assurance Topical Repcrt, i
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s CE-1A,' requires in part, that test procedures' include testing to
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demonstrate that equipment will perform satisfactorily-in service.
Quality Procedure (QP) 5-51, " Instructions, Procedures and Drawings for 0perations
. Station Procedures Manual," step A.1.a,: requires that procedures meet the requirements of ANSI N18.7-1972. ANSI-N18.7-1972, "American Naticnal Standard for Administrative Controls'
for Nuclear Power Plants," section 6.2.5, requires that test-procedures measure and record the as-found condition for. equipment being tested.
ZAP 10-53-1, " Inspection Plan - Surveillance,"
requires persons writing test procedures to include recording of-as-found condition for equipment being tested.
Failure to record:
the as-found valve stroke time using PT-78 as required by ZAP-10-53-1 is considered a violation (295/89002-02; 304/89002-02).
The licensee noted.that lubricating instructions in PT-7B did not agree with those of ZAP 10-52-9, " Station Lubrication Report."
The licensee stated the lubrication method specified in PT-78 was ineffective and therefore did not affect valve stroke time.
Consequently it believed that valve stroke times were indicative of valve condition. The licensee agreed to revise PT-78 to. require obtaining the as-found stroke time and to revise the valve stem lubrication: instructions to reflect the method defined in the ZAP.
b.
Regarding maintenance on 2 LCV RC-459 & 460, the Unit 2 letdown isolation valves:
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Although these valves are identical, the work packages differed in that the. work performed on 2 LCV.RC-460 required the use of.special procedure P/M003-7N, " Disassembly, Inspection-Reconditioning, Re-Assembly and/or Adjustment of Copes-Vulcan-Air Operated Control Valves," while the work package for 2 LCV RC-459 did not. The procedure.was applicable to both jobs.
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The copy of P/M003-7N used in the repair had two steps which j
were hand written in the margins but were partially cut off
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during the reproduction process.
Three procedure change requests were attached to the copy of
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P/M003-7N in the work package.
The three proc'edure changes were'nearly a year old being dated March 16, March 18, and
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March 19, 1988.
P/M003-7N was originally initiated as a new "special" procedure
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by change request number KM87-112, dated February 8, 1988; and, as of January 26, 1989, P/M003-7N had not been forwarded for final approval and typing. According to ZAP 5-51-4, " Procedure Control and Approval," a special procedure is:
... issued to direct operations or provide guidance in unusual. situations or to ensure orderly and uniform operations for short periods when the plant or equipment is performing in a manner that existing procedures do NOT apply. (emphasis added)
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Since P/M0003-7N applied to.all maintenance. work performed cn a
Copes-Vulcan valves, the' length of time between the' initial'
procedure request and issuance of a final station procedure-appears excessive.
Furthermore, the scope of P/M003-7N did-
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not fit the definition of a "special' procedure."
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.The training lesson plans and. learning objectives associated-
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with maintenance on Copes-Vulcan valves used P/M003-7N as training material for mechanical maintenance personnel.
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Theilicensee issued P/M003-7N as a final station procedure
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incorporating the three outstanding procedure changes on P
February 7, 1989.:
c.
Following completion of maintenance on the Unit I air operated
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purge supply valve, 1 A0V-RV-0002, the valve was returned,to service
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properly.
l d.. 'At the request.of the resident inspector the licensee initiated a review of work needing to be performed on the. fuel handling'and:
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transfer equipment. The request was made after equipment failures I
were noted during the October - December 1988 refueling outage, leading to a personnel injury and interruptions of fuel movements.
The licensee's review included a thorough examination of maintenance needed on the spent fuel pit bridge, fuel. transfer system,' rod control cluster change fixture, fuel manipulator' crane, tools and spare parts. The review included target dates for completion of action and consideration for keeping radiation doses during repair activities.as_ low as reasonably achievable'(ALARA). NRC review of progress made on'the licensee's action plan will be considered an Open Item (295/89002-03; 304/89002-03).
e.
Control room annunciators, instruments and. equipment were examined during routine' inspections. There were several annunciators, instruments, and valve indication and control devices in the control room which were found to have work request or defeat stickers, caution tags or out of service tags indicating some degradation of the associated equipment. During the inspection and at the exit meeting on February 10, 1989, the inspector stated that greater attention needed to be devoted to providing better equipment condition to control' room operators.
f.
Both trains of Unit 2 pressurizer power operated relief valves (PORVs) were repaired during the shutdown for the repair of the 2A steam generator leak.
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g.
Packing and seat leakage from several primary valves, which has gradually increased during Unit 1' operation, caused the unidentified reactor coolant system (RCS) leak rate to exceed the 1 gallon per minute (gpm) Technical Specification (TS) limit. The licensee entered the action statement associated with TS Limiting Condition for Operations (LCO) 3.3.3. A.
The high unidentified leak rate LC0 was exited after inspection by a technical staff engineer which i
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j revised the identified RCS leak rate upwards, bringing the
l unidentified leak rate below the 1 gpm limit. As of February 6, l
l 1989, the Unit 1 identified leak rate was.84 gpm. Gasket leakage j
forced Unit I to the cold shutdown condition to repair SG manways.
h.
On February 1,1989, leakage from chemical and volume control (VC)
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system valves resulted in elevated xenon levels in the auxiliary j
building (AB). Readings taken from the auxiliary building vent a
stack monitor (R-14) revealed a peak value of 4500 counts per I
minute (cpm) primarily attributable to xenon-133 and xenon-135.
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Air samples taken in the general access area of the 617' elevation l
l of the AB peaked at approximately 17% of the maximum permissible concentration as defined in 10 CFR 20, Appendix B.
The licensee's initial investigation suggested that the primary source of the leak was the volume control relief valve, 1 VC-8120.
Vent stack count rates dropped to approximately 1200 cpm following repair of 1 VC-8120.
Further investigation revealed that the letdown relief valve 1 VC-8119 was also contributing to the elevated
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xenon levels.
The letdown relief valve, 1 VC-8119 was repaired during the outage
associated with repair of the heater drain tank rupture disk l
described in paragraph 10 of this report. Xenon levels returned
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to normal following the Unit 1 shut down and repair of 1 VC-8119,
however, since the unit has remained shutdovin since 1 VC-8119 was l
repaired, the licensee will closely monitor gasecus radioactivity
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levels in the AB following the Unit I startup.
One violation and no deviations were identified.
One Open Item was
identified.
10.
LicenseeEventReports(,LE_Rs) Followup (92700).
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Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that deportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specifications. The LERs listed below are considered closed:
UNIT 1 LER NO.
DESCRIPTION 87008 Diesel Generator Vent Fan Fire Damper Failed Open in Violation of Technical Specification Due to Poor Communication
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87016 Inoperable Containment Isolation Valve 87017 Degraded Fire Retardant Material in Penetration Fire Barrier Due to Thermal Expansion i
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88008 Procedure Change Not Properly On-Site Reviewed Due to Deficient Administrative Procedures 88009-1L Failure to Test Safeguards Undervoltage Logic Due to Inadequate Review of Test Procedures.
l 88016 Invalid Samples Used to Calculate Release Rate and Activity Release due to Personnel Error 88017 Reactor Trip Due to Turbine Trip With Reactor Power Greater Than' Ten Percent 88022 Non-functional Fire Barrier Due to Personnel Error During Modification UNIT 2 LER N0.
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86020 Non-Functional Fire Barrier Without Fire Watch 86023 Service Water Area Vent Fan Outlet Damper Was Failed Open with the Fan Off
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87008 Containment Isolation Tech Spec Violation Due to Out of Service Auxiliary Feedwater Discharge Stop Valve 88001 Nuclear Station Operator Failure to Log Delta I with Nuclear Instrumentation Channel in Test 88003-Initiation of " Phase A" Containment Isolation During Safeguards Testing Due to Operator Error j
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88004 Missed Quadrant Power _ Tilt Surveillance Due to
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Deficient Procedure
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88006 Improper Installation of 28 Auxiliary Feedwater Pump i
Impingement Plate
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88018 Mode Change While Relying on Technical Specification
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Action. Statement for Inoperable PORV Block Valve
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Regarding LER 295/87008, a pneumatic t.ypass for the IB Diesel Generator room fan damper was removed without energizing the fan breaker that
maintains the damper in a closed position. This damper is part of the
area aircraft crash fire detection system and is required by Technical
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Specifications to be closed at all times except when the fan is running.
The area aircraft crash fire detection system is designed to prevent flames and fuel from entering the ventilation duct system after an aircraft crash near the ventilation ducts. The damper is also designed to close when the fan is tripped.
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The root cause of this event was poor communication between several departments which resulted in the fire damper being incperable. A
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l procedure was implemented in April of 1986 to assure that aircraft
crash fire protection dampers would remain close during maintenance.
l This LER is considered closed.
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Regarding LER 295/87016, containment isolation valve (CIV) 1 M0V SW0009
[the IC reactor containment fan cooler (RCFC) outlet isolation valve]
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was discovered open during power operations. The valve had been taken
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out of service and was blocked in the closed position for maintenance l
on the valve motor operator.
Blocking the valve closed fulfilled the l
l containment isolation function, since Technical specification 3.9.3 j
requires that penetrations with inoperable CIVs be isolated. Operations f
personnel noted both high flow and pressure indications to the RCFC; but they assumed that the flow and pressure instruments were in error because l
the valve was mechanically blocked closed. Further investigation by the l
licensee revealed that the instruments were indicating correctly and the
mechanical block had slipped.
Corrective actions included independent verification of system parameters l
resulting from taking equipment out of service and redesign of valve l
mechanical blocks. A similar event occurred in October, 1988, when
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mechanical blocks slipped on the Unit 2 pressurizer power operated
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relief valves during a refueling cutage. As a result, the licensee is conducting further investigations of valve blocking methods. Corrective actions for both events are already tracked by Open Item 295/88019-01; 304/88019-03.
This LER is considered closed.
Regarding LER 295/87017, degraded fire retardant material in penetration l
fire barrier due to thermal expansion, the licensee performed walkdowr.s of polyethylene filled gaps in walls used for fire protection barriers.
All gaps not meeting the licensee's engineering requirements for fire
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barriers were repaired. This LER is considered closed.
Regarding LER 295/88008, procedure changes being approved without review by an individual holding a valid Senior Reactor Operator's (SRO) license
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as required by Technical Specification 6.2.3, the affected procedures were chemistry procedures which were subsequently reviewed by an SRO.
fio changes were necessary. The procedure control and approval procedure, q
ZAP 5-51-4, was revised to verify SR0 reviews.
Failure to have these procedures reviewed by an individual holding a valid SRO license is a violation of Technical Specification 6.2.3 (295/89002-04(DRP)).
This violation meets the criteria specified in 10 CFR 2 Appendix C, Section V.A; consequently no Notice of Violation will be issued. This LER is considered closed.
Regarding LER 295/88009-1L, failure to test safeguards undervoltage icgic l
due to inadequate review of test procedures, the revision to this LER l
provides additional information regarding corrective actions taken in l
response to this event. Other corrective actions taken in response to l
this event are tracked by Violeticn 295/88012-09b and 304/88013-07b.
The additional items listed in this LER will be reviewed along with the licensee's violation response. This LER is considered closed.
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r Regarding LER 295/88016, this event involved a Technical Specification i
violation, in that invalid containn:ent atmosphere samples were used for j
a Unit I containment vent. The samples used to calculate the release i
rate and activity released were obtained prior to a reactor startup,and
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the containment vent did not take place until after the startup. A reactor startup changes radiological conditions in the containment and thus invalidates pre-startup samples.
The containment vent procedure, ZCP-304 was revised as indicated in the LER. This LER is considered closed.
Regarding LER 295/88017, reactor trip while Unit I was being shutdown, l
the root causes of the trip were procedural deficiency and personnel j
errors. The personnel errors were poor control of feedwater flow that j
caused reactor power to increase above the P-10 setpoint and the failing j
to recheck that power was below P-10 just prior to tripping the turbine.
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The corrective actions committed to by the licensee were to modify existing procedures to require that, prior to tripping the turbine,
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reactor power must be less than 10 percent and be stable or decreasing, i
In addition, a step was to be added to verify the P-7 block permissive annunciator is lit immediately prior to the turbine trip. The P-7 block l
permissive is lit when both reactor and turbine power are below 10%.
i This LER is considered closed.
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Regarding LER 295/88022, this LER discusses a 3-inch core hole penetration which degraded the functional integrity of a fire barrier.
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The event was caused by the failure to identify fire protection concerns
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during the preparation of an Engineering Change Notice for routing
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conduit.
In addition, contrary to the station's Housekeeping / Fire Protection procedure, the Shift Engineer was not notified prior to core hole drilling and therefore, failed to implement non-functional penetration fire barrier surveillance.
Immediate corrective actions were appropriate and sufficient. Similar events have occurred over the past'several years involving missed firebarrier surveillance (see LERs 295/86015, 024, 027, 030, and l
304/86020). Station procedures were revised many times in order to
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prevent recurrence of similar events.
Procedure revisions following this event included a checkoff list that included fire protection concerns.
In addition, controlled Fire Protection drawings (P& ids)
are in the process of being approved which will identify all fire protection walls and barriers. The Licensee's corrective actions are
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tracked under conunitment #295-200-88-2200. This LER is considered closed.
Regarding LER 304/86020, a non-functional fire barrier without a fire watch being posted, the barrier was the wall between the 2A and 2B charging pumps in which a 1 x 2 ft construction hole had been cut.
During the time the fire watch was supposed to have been posted, a roving fire watch was touring the area on a hourly basis for unrelated reasons.
Fire watches are now performed by the onsite security force, and more strincjent administrative procedures now exist. No recurrences have been noted. This LER is considered closed.
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Regarding 304/86021, the service water area vent fan outlet damper was failed cpen with the fan off. This damper is an area aircraft crash derrper that is required by Technical Specifications.
A cover plate was found loose on the Miller air control valve to the damper actuator. This allowed control air pressure to bleed off and the spring loaded control valve opened the damper. The corrective actions included tightening the cover plate, closing the damper, and then cycling the fan to verify proper damper operation. This LER is considered closed.
Regarding LER 304/87008, the licensee reported that on September 8, 1987, at 2:45 pm, with Unit 2 in Mode 1, auxiliary feedwater (AFW) pump discharge motor-operated valve 2M0V-FWO55 was taken out of service (00S)
and de-energized in its throttled position. This made the valve unable to perform its containment isolation function which was in violation of TS 3.9.3.
TS 3.9.3 requires the valve to be restored to operability within four hours or the affected penetration must be isolated. The valve was returned to operability at 1230 pm on September 9, 1987, after being inoperable for 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> and 45 minutes.
The Shift Control (SCRE) who authorized taking the valve 00S referred to TS 3.7.2 on the AFW system which required the valve to be opened in the throttled positior, as part of the AFW flowpath but would have permitted closure of the valve. The AFW function was left operational and the valve was capable of being operated locally. The valve does not receive
a containment isolation signal to close in order to provide an AFW
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flowpath under reactor trip or accident conditions.
Consequently, there were nc immediate concerns for public health or safety. The licensee is in the process of submitting a TS amendment that will allow the valve to be considered operational for containment isolation purposes, if it can be manually closed.
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A similar event occurred on August 25, 1987 (Reference LER 295/87015)
when the IB Residual Heat Removal (RHR) pump suction isolation valve
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was de-energized without meeting the TS operability requirement for a I
secondary RHR system function. As corrective action, the licensee
changed the administrative procedure for taking equipment out of service
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ZAP 14-51-2 and the " Inoperable Equipment Surveillance Test," procedure, PT-14 to require operators to consider immediate and subsequent requirements when taking equipment out of service. These changes were made in October, after the September AFW event.
It is likely that these changes would have prevented this event.
The failure to maintain feedwater isolation operable or its penetration isolated within four i
hours is a violation of TS 3.9.3 (304/89002-04(DRP)). This violation meets the test of 10 CFR 2 Appendix C, Section V.A; consequently no tiotice of Violation will be issued, and this matter is considered closed.
Regarding LERs 304/88001 and 304/88004, on January 8, 1988, during a
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functional test of one channel of power range nuclear instrumentation (fil), hourly manual logging of delta flux was not performed as required by Technical Specification (TS) 4.2.2.A.S.
This occurred over approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 45 minutes and was found by the relieving
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operator. The licensee also reported in LER 304/88001 that a Quadrant-
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Power Tilt Ratio (QPTR) surveillance was also missed during NI calibrations. The LER was not complete in that it addressed neither the time period for which this' surveillance was required but not performed nor the safety significance of the missed QPTR. The licensee committed to revising the LER. This is an Open Item (304/89002-05(DRP)) pending l
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issuance of the revision and review by the NRC.
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On April 14, 1988, during a NI channel function test, the hourly performance of a QPTR calculation was not performed as required by TS 4.2.2.C.2.
The surveillance was not performed for approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
when the discrepancy was discovered. At the time this occurred, the
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procedure changes that were proposed as corrective action for LER 304/88001 had not been issued. These changes in all likelihood would
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have prevented this even.t.
l The corrective actions included operator training and the addition-
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acknowledging a caution on the TS surveillance requirements.
Instrument
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Maintenance procedures 1N-41 through 44 and 2N-41 through 44 were checked, and the change had been made which also added a Shift Engineer signoff for this requirement. The delta flux data retrieved from the process computer remained-within the allowable band.
Failure to perform i
QPTR during NI calibrations was also covered in operator training, and
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Standing Order 88-02 was written to clearly delineate the TS surveillance l
requirement and the signcffs added to the Instrument Maintenance
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procedures included reference to this TS requirement.
In addition, the
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administrative controls of surveillance during NI calibrations were
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moved from an Abnormal Operating Procedure to Periodic Test Procedure,
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L PT-14C, to more appropriately control this activity.
i Failure of the licensee to manually log the delta flux hourly while
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channel testing temporarily disabled flux deviation alarms and to perform QPTR calculations every hour with an excore detector channel inoperable are exam (304/89002-06(DRP))ples of violations of TS 4.2.2.A.5 and TS 4.2.2.C.2 This violation meets the test of 10 CFR 2
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Appendix C,Section V.A; consequently, no Notice of Violation will be issued, and these LERs are considered closed.
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i Regarding LER 304/88003, the licensee reported the events surrounding an
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inadvertent initiation of Phase A containment isolation.
The licensee's l
investigation found the isolation to have been initiated when the unit i
operator depressed the wrong test switch during a routine surveillance.
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Subsequently, the 2 Control Rod Drive Mechanism vent fan tripped and
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repeatedly tripped when restarted.
The cause of the fan trip was L
determined to be a cracked relay case, causing intermittent malfunc-l tioning. The relay was replaced and the part identification was
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L reported.
However, investigation into the initial fan trip signal is still in progress and results will be issued in a supplemental report.
Since this fan is not required by TS for safe shutdown of the plant, j
there are no further concerns with this event. The licensee is
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considering the installation of plastic covers over the test switches
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to help prevent recurrence of an operator hitting the wrong switch.
This LER is considered closed.
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Regarding LER 304/88006, improper installation of the 28 auxiliary feedwater (AFW) pump impingement plate, the installation error resulted from an-inadequate design review during initial. construction.
Corrective actions included relocation of the impingement plate in the correct orientation, and a review to determine if other necessary equipment was improperly protected from a high energy line break.
No additional problems were identified. This LER is considered closed.
Regarding LER 304/88018, the licensee reported that on December 21, 1988, with Unit 2 in Mode 3 (hot shutdown), a power operated relief valve (PORV) block valve, EMOV-RC8000B, was declared inoperable,
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manually closed and de-energized in accordance with TS Action i
I Statement 3.3.1.F.b.
Technical Specification 3.3.1.F requires that two PORVs and their associated block valves be operable in Modes 1, 2, and 3.
Technical Specification 3.0.4 also requires that entry into an' operational mode shall not be made while relying on provisions in
the action statements. Contrary to TS 3.0.4, the unit was placed in i
Mode 2 on December 26. 1988 and in Mode 1 on December 28, 1988.
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The decision to change modes with the inoperable block valves was caused l
by senior cperator-improperly applying TS 3.0.4 in the belief that since i
the action statement set no time limit, entry into operational modes was permitted. With no time limit on the action statement, for example, if the block valve became inoperable in Mode 1, operation could continue indefinitely once the action statement is met. This erroneous applica-l tion of TS 3.0.4 developed in spite of the issuance of Generic Letter J
87-09 " Sections 3.0 and 4.0 of the Standard Technical Specification i
(STS) on the Applicability of Limiting Conditions for Operation and i
Surveillance Requirements" which describes the' restrictions of TS 3.0.4
and recommends TS changes to be made to alleviate this.
Taking the
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unit to Mode 1 and 2 while relying on the action statement of TS 3.3.1.F l
1s a violation of TS 3.0.4 (304/89002-07(DRP)).
This LER is considered
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closed.
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One violation and no deviations were identified. Three licensee identified violations and one Open Item were identified.
11. Quality Pr_ogram Effectiveness (40500)
A previous instance involving a test procedure that did not obtain i
as-found conditions was noted in PT-210, " Aircraft Fire Detection System l
Test." PT-210 incorrectly required energization of the heat trace for the diesel generator room ventilation intake isolation dampers prior to stroke testing. This finding was identified as an example of a four part violation identified as 295/88012-01c; 304/88013-01c. The licensee noted that PT-210 test methodology did not assess the operability of the dampers in cold weather conditions and believed that the instance identified in inspection report 295/88012; 304/88013 was an isolated Case.
The inspectors noted that the licensee has concitted to conduct a review
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of its policy and guidance regarding the administration, control and documentation related to test activities as discussed in open item i
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l 295/88023-02; 304/88023-04; however, the licensee should take care to scrutinize ongoing surveillance activities in parallel with the review.
I The inspector noted that the timeliness of issuarce of station procedures has been previously discussed as noted in IR 295/88012; 3C4/88013 (paragraphs 4, 5). The inspectors also noted that the licensee was informed of concerns regarding use of temporary procedure changes as
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discussed in IR 295/87015; 304/87018 (paragraph 7).
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t The inspectors noted that in response tc the violation identified in l
paragraph 9 of this report, the cognizant Assistant Technical Staff l
Supervisor provided in depth, comprehensive information in an objective
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and timely manner. Although the information did not prevent issuance of a violation, his investigation was thorough, well thought out and effectively addressed identified concerns.
No violations or deviations were identified.
12. January 26, 1989, SiteVisitbyRegiona,1 Administrator (3Q7031 On January 26, 1989, Messrs A. Bert Davis, Regional Administrator, Region III; Julian M. Hinds, Jr., Chief, Projects Section 1A; Robert M. Lerch, Technical Assistant to the Branch Chief, Branch 1A; and Lloyd P. Zerr, Backup Project Manager, NRR, met with Messrs. Cordell Reed, Senior Vice President, Nuclear Operations, Commonwealth Edison; George Pliml, Station Manager, Zion Station and members of the Zion plant staff.
Mr. Davis' visit included a site tour by the senior resident inspector and a meeting with members of the Zion plant staff. Mr. Davis stated that the material condition of the Zion plant was much improved since his last visit in October, 1988; bcwever the plant could improve the material
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condition by performing " deep cleaning". Mr. Davis also noted that the number of temporary alterations and open modifications seemed high; bcwever, the number of non-outage work reovests looked gcod.
q No violations or deviations were identified.
13. AllegationRIII-88-A-0176_(99024)
The Zion Senior Resident Inspector (SRI) reported that on December 8, 1988, a nuclear station operator (NS0) while on duty and being questioned about specific plant status, declined to answer further questions indicating that he had been criticized for talking with the NRC. He stated that he was told by two individuals that the Production Superintendent made derogatory remarks, criticizing NS0s for pointing out problems to the Senior Resident Inspector. The NS0 also stated that he spoke with the Production Superintendent and he denied having made critical remarks.
During the SRI's Unit 2 outage inspection activities, an additional concern was developed.
It appeared that schedule pressures to complete the cutage may have an ur. desirable impact on individual performance.
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I Inspection With regard to scheduler pressures, this concern was discussed in telephone conversations on Decctber 9, 1988, between T. Maiman, Commonwealth Edison Company Vice President for Operations and E. Greenman, Director, Division of Reacter Projects (DRP) Region III (RIII), and also in a call between G. Plim1, Zicn Plant Manager, E. Furst, Zion Production Superintendent and W. Forney, Deputy Director, DRP, RIII and B. Clayton, Acting Chief, Branch 1, DRP, RIII. Subsequently, startup activities were observed by B. Clayton and R. Lerch, Reactor Engineer, Branch 1, DRP, RIII, over a weekend shift and followed by the resident inspection staff with assistance from the Senior Resident Inspector from Dresden.
(See Inspection Report 295/88023(DRP);304/88023(DRP)). Activities at an increased L
pace due to the startup were observed.
No violations or deviations were identified although a licensee identified violation was reported regarding a safety injection event on December 11, 1989.
With regard to criticism of NS0s by plant management for bringing problems to the attention of NRC inspectors, interviews were conducted specifically about plant conditions on December 8, 1988, with the Plant Manager, the Production Superintendent and seven NS0s.
Impressions were requested from other NRC inspectors who had recently conducted inspections and from the NRC resident inspection staff., The Production Superintendent (PS) denied making any derogatory remarks criticizing NS0s for pointing out problems to the NRC. The Plant Manager and Production Superintendent also stated that the licensee's policy was that problems should be brought to plant managers first, but if the staff was not satisfied with management's response, they could go to the NRC. The Production Superintendent's alleged use of derogatory language in a meeting of plant operations supervisors to describe NS0s relaying problems to the NRC was regarded by plant staff niembers interviewed as a rumor which was generally known through the plant grapevine. Although specifically asked, none of the plant staff interviewed during this inspection could attribute the source of the rumor to a specific person.
Interviewees could not say whether these remarks were reflective of management's desire to have problems brought to their attention first or of management's attitude towards all problems brought to the NRC.
They appeared to believe that the Production Superintendent did make the derogatory statement as stated in the original allegation.
All interviewees agreed that there is no " policy" written or stated which prevents licensee personnel from talking to the NRC. The need for NRC inspectors to discuss plant status with NS0s was clearly
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understood. Some NSO interviewees described how they felt caught in i
the middle in that problems with procedures found by the NRC on their reactor unit / shift, would be attributed to them by managers and potentially held against them in some subsequent personnel action.
No specific actions taken against operators in this context were identified but the NS0s made clear their concerns for maintaining a l
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good relationship with a management for whom they expected to work for a long time.
Thus, they felt that their future may depend on the extent to which they bring ccncerns to NRC's attention or confirm NRC inspector's findings.
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Conclusions The plant management does not have any policy, written or stated, to prevent or punish individuals bringing problems to the NRC. The remarks attributed to the Production Superintendent were not confirmed as fact, but as a rumor in the plant. The remarks, although denied by the Prcduction Superintendent, may or may not have been made or may have been taken out of context. As a rumor, the remarks have some credibility with operators due to the Production Superintendent's management style and personality. Based on the inspectors observations and discussions with plant staff members, it appears the willingness of NS0s to believe the remarks and to repeat them is indicative of a more adversarial relationship between management and plant staff than is seen at other sites. Any actions taken by plant management to counteract the perception of the truth or intent of these rumors have had little or i
no effect.
Interviewees described the predicament of any licensee individual who, when talking to the NRC, has a problem identified to them by the NRC or identifies a problem to the NRC. While interviewees recognized the importance of identifying safety concerns, they felt that a price may be exacted by a supervisor or manager in some subtle way. Thus they feared " making waves" or drawing attention to themselves. The examples used by some NS0s, of being associated with problems for which they were not responsible, also indicated a distrust of management's ability or i
desire to accurately assign root causes and apply appropriate corrective I
actions.
l Although no cases of employment discrimination were identified, the l
perceptions conveyed to inspectors by plant staff as described above j
could prevent the identification of safety issues. These perceptions, on the part of the plant staff, should be addressed by the licensee
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in order to assure that safety concerns are identified and corrected.
No violations or deviations were identified.
14. Changes To Plant and Corporate Management _(30703)
On February 7,1989, the licensee announced that as a result of a review of their corporate organization, referred to as Introspect, major changes would take place in the CECO corporate and nuclear station organizations.
The restructuring would eliminate approximately 660 middle management and supervisory positions.
At the Zion Station, the following changes were implemented on y
February 14, 1989:
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Name From P_osition
--..P..o s i t.i o n To G. Plimi Station Manager, Zion Nuclear Quality Programs Manager, GO T. Joyce Prcduction Superintendent, Station Manager, Zion Byron E. Fuerst Production Superintendent, Project Manager, Engineering
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Zicn and Construction Services, Zion W. Kurth Assistant Superintendent, Production Superintendent,
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Operating, Zion Zion
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P. LeBlond Radiation Chemistry Assistant Superintendent, Supervisor, Zion Operating. Zion T. Reick Services Superintendent, Technical Superintendent,
Zion
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Zion R. Budowle Assistant Superintendent, Services Director, Technical Services, Zion Administration, Zion I
The following changes became effective on February 21, 1989:
i V. Williams Lead Health Physicist, Health Physics Supervisor, i
Zion Zion P. Zwilling Nuclear Services Group, G0 Chemistry Supervisor, Zion
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i On February 27, 1989, the following change was announced:
G. Kassner SRO License Training Class Lead Health Physicist, Zion Zion No violations or deviations were identified.
15. Open Items l
Open Items are matters which have been discussed with the licensee which will be reviewed further by the inspector and which involve some action on the part of the NRC or licenvee or both. Three Open Items disclosed i
during this inspection are discussed in paragraphs 2, 9 and 10.
16. Licensee Identified Violations In accordance with 10 CFR Part 2, Appendix C, General Staten'ent of Policy and Procedure for NRC Enforcement Actions, the NRC will not generally issue a notice of violation for a violation that meets all of the following tests:
1)
It was identified by the licensee; 2)
It fits in Severity Level IV or V; 3)
It was reported, if required; (4)
It was or will be corrected, including measures to prevent recurrence, within a reasonable time; and
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It was not a violation that could reasonable be expected to have l
been prevented by the licensee's corrective action for a previous violation.
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Three licensee identified-violations disclosed in this inspection are discussed in paragraph 10 of this report.
17.
ExitInterview(30703],
The inspectors met with licensee representatives (denoted in Paragraph
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1) thrcughout the inspection period and at the conclusion of the l
inspection on February 10, 1989, to sumarize the ' scope and findings
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.of the inspection activities. An additional exit meeting was held on February.17, 1989, to discuss flRCs findings pertaining to followup of
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allegations as described in paragraph 13. The licensee acknowledged the inspectors' coments. The inspectors also discussed the likely informational content of the inspection report with regard to documents
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or processes reviewed _ by the inspectors during the' inspection.
The i
licensee did not identify any such documents or processes as proprietary.
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