ML20244C381
| ML20244C381 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 05/26/1989 |
| From: | Holler E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20244C372 | List: |
| References | |
| 50-498-89-11, 50-499-89-11, NUDOCS 8906140240 | |
| Download: ML20244C381 (14) | |
See also: IR 05000498/1989011
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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.NRC Inspection Rcport:
50-498/89-11
Operating Licenses:
50-499/89-11
Dockets:
50-498
50-499
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Licensee:
Houston Lighting & Power Company (HL&P)
P.O. Box 1700
Houston, Texas 77001
Facility Name:
South Texas Project (STP), Units 1 and 2
Inspection At:
Inspection Conducted:' April 1-30, 1989
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Inspectors:
J. E. Bess, Senior Resident Inspector, Unit.1
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Project Section D, Division of Reactor
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Projects
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J. I. Tapia, Senior Resident Inspector
Unit 2, Project Section D, Division of Reactor
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R. J. Evans, Resident Inspector, Unit 1
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Project Section D, Division of. Reactor
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D. L. Garrison, Resident Inspector, Unit 2
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Project Section D, Division of Reactor
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R. V. Azua, Reactor Inspector, Test Program
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Section, Division of Reactor Safety
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Approved:
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E. J. Holler, Chief, Project Section D
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Division of Reactor Projects
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890614o240 890607
POR
ADOCK 05000498
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Inspection Summary
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Inspection Conducted April 1-30, 1989 (Report 50-498/89-11; 50-499/89-11)
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Areas Inspected: Routine, unannounced inspection of plant status, followup of
events, operational safety verification, monthly maintenance observation, and
monthly surveillance observation.
Results: Within the areas inspected, one violation of NRC requirements was
identified regarding failure to establish environmental qualification of
certain auxiliary feedwater system valves with installed space heaters. Also,
paragraph 4)y of the space heaters did not meet the guidance of RG 1.75 (see
the circuitr
A weakness was noted in the controlling of instruction manuals,
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spare parts, history files, and housekeeping. A violation was noted but not
cited regarding maintenance activities (see paragraph 5). Discrepancies were
noted between the same procedures used in Unit I and in Unit 2 regarding
accumulator surveillance (see paragraph 6). Discrepancies regarding proper
maintenance of oil level in the essential chillers was also noted (see
paragraph 7).
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DETAILS
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1.
. Persons Contacted
- P. L. Walker, Senior Licensing Engineer
- J. E.. Geiger, General Manager, Nuclear Assurance
- A. W. Harrison, Supervising Licensing Engineer
- V. A. Simonis, Plant Operations Support Manager
- S. M. Head, Supervising Licensing Engineer
- M. R. Wisenburg, Plant Superintendent
- J. R. Lovell Technical Services Manager
- W. H. Kinsey, Plant Manager
- M. A. McBurnett, Licensing Manager
In addition to the above, the NRC inspectors also held discussions
with various licensee, architect engineer (AE), maintenance, and other
contractor personnel during this inspection.
- Denotes those individuals attending the exit interview conducted on
May 4, 1989.
2.
Plant Status
Unit 1 operated at full licensed thermal power for the duration of this
inspection period. The annual emergency preparedness graded exercise was
conducted on April 26, 1989. The results of the exercise are documented
in NRC Inspection Report 50-498/89-12; 50-499/89-12.
Unit 2 began this inspection period at 8 percent reactor power. After an
initial unsuccessful attempt to synchronize the Unit 2 main generator to
the offsite electrical distribution system, the licensee successfully
synchronized the generator on April 11, 1989. Toward the end of the
inspection period, the licensee shut down Unit 2 to find and correct a
noise essociated with the main turbine.
3.
Followup of Events - Units 1 and 2
(93702)
On April 6,1989, at 5:54 a.m. , with the Unit 1 emergency safety
features (ESF) Diesel Generator (DG) No.11 out of service for scheduled
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maintenance, ESF DG No.12 failed to start during an operability test
required by Technical Specification (TS) 3.8.1.1.
With two inoperable
DGs, Unit 1 entered a 2-hour limiting condition for operation (LCO) as
required by TS 3.8.1.1(f). Unable to return DG Nos.11 or 12 to
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operability status by 7:54 a.m., the licensee began a controlled shutdown
of Unit 1 as requireo by TS 3.8.1.1(f).
The problem with the DG No.12 was determined to be a failed resistor in
the governor assembly. The licensee had received information from the
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Palo Verde Nuclear Generating Station (PVNGS) that similar problems had
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existed with their DGs. Both the STP and the PVNGS DGs were manufactured
by Cooper Energy Services. The licensee contacted the manufacturer to
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discuss the problem and to pursue possible corrective measures that should
preclude recurrence of this event.
At 11:46 a.m., on April 6,1989, DG No.11 was returned to service. The
NRC inspector witnessed the performance of Procedure 1 PSP 03-DG-0001,
" Standby (S/B) Diesel Generator No.11 Operability Test." Following the
replacement of the failed resistor in the governor assembly and after
successfully completing the required operability test, the licensee
declared DG No.12 operable at 7:50 p.m. and exited TS 3.8.1.1.
On April 5,1989, Unit 2 tripped from 11 percent reactor power while
attempting to synchrntize the main generator to the offsite electrical
distribution system. The licensee determined the cause of the reactor
trip to be an electrical relay problem associated with the main generator
circuit breaker. The licensee determined that improper implementation of
changes to the wiring of the generator backup distance relay and negative
phase sequence relay by startup technicians, prior to turnover of the
generator system to plant operations, caused the Main Generator Circuit
Breaker to trip. The problem relsys were rewired and tested on April 7,
1989.
The loss of power to 13.8kV auxiliary buses, after the generator circuit
breaker tripped, resulted in a loss of power to Reactor Coolant Pumps 2A,
2B, 2C, and 2D. The undervoltage coils on the pump breakers actuated to
trip the breakers and generate a low flow reactor trip signal through the
Solid State Protection System, which tripped the reactor. All rods
inserted normally. The loss of power to ESF bus E2A caused Standby Diesel
Generator No. 21 to start.
ESF loads sequenced onto the bus as required.
After verifying stable conditions, the operators reenergized the auxiliary
buses from their respective standby buses which were supplied from the
Unit 2 Standby Transformer. When bus 2J was reenergized, RCP 2D restarted
because its breaker had failed to trip open on the loss of voltage. The
additional flow caused a drop in steam generator water level resulting in
an actuation of the Auxiliary Feedwater system. Average coolant
temperature continued to decrease due to lack of decay heat, lack of
coolant pump heat, and secondary steam loads. A main steam isolation was
manually initiated to prevent overcooling of the RCS.
Troubleshooting of the RCP 2D breaker revealed a broken lug on a cable
from the undervoltage coil to the breaker trip circuit. The wita
connected to the lug had caught on the breaker enclosure, apparently when
the breaker was racked in, because of the wire falling out of its harness.
The undervoltage coil functioned properly and sent a trip signal to the
Solid State Protection System to initiate a reactor trip; however, the RCP
breaker did not trip because of the broken lug. The broken lug on the
RCP 2D breaker was replaced and the other Unit 2 RCP breakers were checked
for other wires which may have fallen from their harnesses.
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. Plant restart was delayed by a packing leak on _a feedwater isolation
bypass valve. Mode I was achieved on April 11, 1989. On the same day, at
1:26 p.m., initial generator synchronization to the offsf te electrical
distribution system was achieved.
On April 15,1989, a Unit 2 reactor trip occurred when the Train S reactor
trip breaker opened without receiving a reactor trip signal from the solid
state protection system. All systems functioned normally after the trip.
The faulty breaker was subsequently replaced but reactor restart was again
delayed by necessary repairs to a worsening packing leak on the feedwater
isolation bypass valve. Mode 1 was again achieved on April 20, 1989.
On April 21, 1989, a metallic noise was discovered in the area near the
No. 8 main turbine generator bearing. HL&P commenced a reactor shutdown
to disassemble and inspect the low pressure turbine and bearings. On
April 27,1989, the licensee determined that a bore plug in the main
turbine generator jack shaft had backed out and fallen into the hollow
bull gear, causing a noise as it tumbled within the bull gear when the
turbine was rolled. The inspection period ended with reassembly of the
main turbine ongoing.
4.
Operational Safety. Verification - Units 1 & 2 (71707)
The objectives of this portion of the inspection were to ensure that the
facility was being operated safely and in conformance with regulatory
requirements, to er.sure that the licensee's management controls were
effective in discharging the licensee's responsibility for continued safe
operation, and te assure that selected activities of the licensee's
radiological protection program were implemented in conformance with plant
policies and procedures and were in compliance with the approved physical
security plan.
The NRC inspectors visited the control rooms on a daily basis when onsite
and verified that control room staffing, operator behavior, shift
turnover, adherence to TS LCOs, and overall control room decorum were
being conducted in accordance with NRC requirements.
Tours were conducted throughout various locations of the plant to observe
work and operations in progress.
Radiological work practices, posting of
barriers, ard proper use of personnel dosimetry were observed.
The NRC inspectors verified, on a sampling basis, that the licensee's
security force was functioning in compliance with the approved physical
security plan. Search equipment such as X-ray machines, metal detectors,
and explosive detectors were observed to be operational. The NRC
inspectors noted that the protected area was well maintained and not
compromised by erosion or unauthorized openings in the area barrier.
General housekeeping, cleanliness, and physical condition of
safety-related equipment were inspected with particular emphasis on
engineered safety feature (ESF) systems.
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During the inspection period, the NRC inspectors questioned the licensee
about the use of space heaters in safety-related motor operated valves.
The licensee identified seven safety-related valves per unit with space
heaters.. Three valves were associated with the Essential Cooling
Water (ECW) system and four were associated with Train D of the Auxiliary
Feedwater(AFW) system. Space heaters for the valves were provided by the
vendor for use during reinstallation storage and were not considered
safety related. After questioning by the NRC inspectors on the safety
classification of the motor space heaters, the licensee perfonned an
indepth review of the application of space heaters in the seven valves.
The licensee determined that the space heaters were incorrectly wired into
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the circuitry of the eight (four per unit) AFW valves but were correctly
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wired into the circuitry of the six (three per unit) ECW valves. The six
ECW valve space heaters were wired with dual circuit breakers, with one-
breaker designed to shunt trip open on an ESF signal. However, the eight
AFW valves had nonsafety-related space heaters wired in parallel to the
criteria established by Regulatory Guide (guration apparently did not meet
Class IE 125V DC motors. The wiring confi
RG).1.75,"Ph
The four AFW valves (per unit)ysical Independence
are: AF-MOV0143,
of Electrical Systems."
AFW turbine steam inlet valve; AF-MOV0514, AFW Pump 14 turbine trip and
throttle valve; AF-FV7526, AFW to steam generator ID regulating valve; and
AF-M0V0019, AF turbine Pump 14 isolation valve.
The eight AFW valves were located in the Unit 1 and Unit 2 isolation valve
cubicle (IVC) buildings. The area would be subjected to a harsh
environment if a design basis accident occurred. The eight AFW valves
were environmentally qualified because of their location. Vendor supplied
documents (Wyle Laboratories Report No. 47644-05) indicated that the motor
operated valves were tested for environmental qualification (EQ) without
the space heaters being energized. The licensee operated the eight EQ AFW
valves for several months with space heaters wired into the valve
circuits, even though the space heaters had not been shown to have been EQ
tested.
Paragraph (f) of 10 CFR 50.49 requires that qualification of each
component must be based on testing or experience with identical equipment,
or with similar equipment with a supporting analysis, to show that the
equipment to be qualified is acceptable. Paragraph (k) of 10 CFR 50.49
states that equipment previously required by the Commission to be
qualified to NUREG-0588, " Interim Staff Position on Environmental
Qualification of Safety Related Electrical Equipment," need not be
requalified. Section5(1)ofNUREG-0588, Revision 1,statesthatthe
qualification documentation shall verify that each type of electrical
equipment is qualified for its application and meets its 'specified
performance requirements. The basis of qualification shall be explained
to show the relationship of all facets of proof needed to support adequacy
of the complete equipment. Data used to demonstrate the qualification of
the equipment shall be pertinent to the application and organized in an
auditable form.
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The equipment qualification file (Wyle Laboratories Report No. 47664-05)
for the eight AFW valves did not adequately support the actual application
of the valves with the space' heaters installed and energized. The EQ
documentation' failed to adequately analyze for all possible effects of
energized space heaters used within the valve assemblies. Specifically,
the areas not analyzed included effect of premature aging of the valve
com)onents due' to: the additional heat supplied by the heater. .the effect-
of leater failure on the valve, and the effect of burn damage on.
electrical components due to close proximity to the heater elements.
Failure to properly qualify the eight AFW valves-with regard to their
~ application.in the field is an apparent violation of 10 CFR 50.49
requirements (50-498/8911-01;50-499/8911-01)._
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Train B of the Safety Injection (SI) system for Unit 2 was inspected to
ensure the system valves, control switches, and electrical power supplies
were in their correct positions, as required by the system operating
. procedure and plant drawings. The SI system Train B was compared to
Procedure 2 POP 02-SI-0002, Revision 2, " Safety Injection System Initial
Lineup," and the Piping and Instrument Diagram (P&ID) 5N129F05014 No. 2,
Revision.10 " Safety Injection System." All valves, power supplies, and-
control switches were found to be in the correct ' position for the mode of
operation on the day of inspection.
Items observed during the inspection
included:
Labelling discrepancies were observed throughout the system lineups.
.For example, in the Control Board Lineup 2 POP 02-SI-0002-5,
Valve 2-SI-FV-3957 was labelled "HHSI Tc Upstream" on the panel, but
was called "HHSI Pump Cold Leg Test Line Isolation Valv,
in the
procedure.
In the electrical lineup, the field label for
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Device E2B1-WIL was " Backup Breaker For Compt. C1," but E2B1-WIL was
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called 2-SI-M0V-0006B in the procedure.
In Train B Initial Lineup Procedure 2P0P02-SI-0002-5, the location of
Device 2-SI-0070B was missing the room number (fuel handling
building (FHB) RM-5).
During the review of SI System Vent Lineup 2 POP 02-SI-0002-16, two
Train B valves were noted to be missing from the lineup. The two
valves were the Test Vent Valves 2-SI-0138 and 2-S1-01018.
The SI System Vent Lineup 2P0P02-SI-0002-16 listed Valve 2-SI-0231,
which e s previously deleted. The valve was not shown on the system
P&ID, neither was the valve listed in the system initial lineup. A
review of documentation was perfomed to detemine if the valve was
shown to be deleted when operations performed the SI system vent
lineup. The licensee could not locate documentation to verify that
Train B of the SI system was vented per 2 POP 02-SI-0002-16. However,
Train B of the SI system was vented per 2 PSP 03-SI-0014, Revision 1,
"ECCS Valve Checklist " on February 13, 1989.
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During the inspection of the mechanical auxiliary building (MAB) in
Unit 2, Boric Acid Tank Room 076 was visited. The NRC inspectors observed
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local Sample Connection Valve 2-CV-0322 leaking excessively. This valve
was slowly draining boric acid from Boric Acid Tank 2B onto the floor of
the room. The Unit 2 shift supervisor was immediately notified. The
licensee fully shut the valve and generated a problem report.
The NRC inspectors observed control room operations, reviewed applicable
logs, and conducted discussions with control room operators. The NRC
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inspectors verified the operability of selected emergency systems,
reviewed tag-out records and verified proper return to service of affected
components, and ensured that maintenance requests had been initiated for
equipment in need of maintenance.
One apparent violation and no deviations were identified in this area of
the inspection.
5.
Monthly Maintenance Observations - Unit 1 (62703)
Portions of selected Unit 1 maintenance activities were observed to
ascertain whether the activities were conducted in accordance with
approved procedures. The activities included:
Maintenance Work Request (liWR) SY46861, Seismic Monitoring System
Preventive Maintenance (PM) IC-0-EM86007175, Revision 9A,
Meteorological Monitoring System Inspection
The NRC inspectors tried to determine through observations whether
approved procedures were being used, replacement parts were properly
certified, and housekeeping was being maintained. Specific items noted
during the observation of PM IC-0-EM-86007175 included:
Both the Primary and Backup Meteorological (Met) towers had
instruction manuals and drawings that were uncontrolled and out of
date. Having manuals available for use by the technicians in remote
locations, such as the Met towers, can be beneficial. However,
having uncontrolled or out-of-date copies of manuals for
troubleshooting or maintenance purposes may lead to problems. The
manuals and drawings have since been recalled for updating or
disposal by the licensee.
A box inside the primary Met tower contained what appeared to be
spare parts. The spare parts were inside zip-lock bags that provided
some identification as to what the parts were, however, there were no
material issue forms included in the box that identified the date or
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source of issue. The spare parts have since been returned to the
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Instrumentation and Control (I&C) shop for dispositioning.
An uncontrolled history file was being maintained at both Met towers.
The information that was gathered as part of the PM was being
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transferred to copies of out-of-date data sheets. These data sheets
were then being added to the history files. The history files have
since been returned to the I&C shop for review to determine their
usefulness.
The primary and backup Met tower electric generator batteries were
observed to have standing water on top of them. The potential
existed where the water could have shorted out the batteries. The
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batteries were cleaned by the licensee on the day of inspection.
The primary Met tower was noted to be in need of cleaning.
Housekeeping was not being maintained in an acceptable manner. Loose
paper, dirt, dead insects, and other items were noted throughout the
room. Prior to the end of this inspection period, the room was
cleaned by the licensee.
Observations noted during the review of MWR SY-46861 included:
Technicians were noted to be troubleshooting the circuitry of Seismic
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Monitor Channel Sensor XT0002A. Troubleshooting activities included
removing the. sensor for testing, lifting leads for a wire check and
meggering, and reterminating the lifted leads. All troubleshooting
activities were performed using verbal instructions provided by the
foreman of the task. A review of the MWR was performed.
Authorization to troubleshoot the circuitry was not a part of the MWR.
Instructions on troubleshooting activitim were provided in
OPGP03-ZM-0021, Revision 1, " Control of Configuration Changes During
Maintenance or Troubleshooting." Section 6.2.1 of the procedure
requires, in part, that troubleshooting is to be performed using
approved work instructions and as part of an MWR. The technicians,
following the instructions of their foreman, appeared to exceed the
authorization allowed for troubleshooting per OPGP03-ZM-0021 without
revising MWR SY-46861.
TS 6.8.1 requires written procedures to be established, implemented,
and maintained, including applicable procedures recommended in
Appendix A of Regulatory Guide 1.33, Revision 2, " Quality Assurance
Program Requirements (Operation)." Written procedures required per
Appendix A of RG 1.33 included procedure adherence and performing
maintenance.
Contrary to the above, on April 27-28, 1989, technicians apparently
violated TS 6.8.1 by performing maintenance activities that did not
adhere to requirements established by 0PGP03-ZM-0021. Although the
seismic monitoring system is considered nonsafety related, their
operability is required by TS 3.3.3.3.
Thisapparentviolation(498/8911-02;499/8911-02)ofTS6.8.1will
not be cited because the criteria specified in Section V. A. of the
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enforcement policy were satisfied. Corrective actions taken by the
licensee subsequent to the apparent violation included personnel
training and perfonning a teview of current procedures to detemine
and clarify the scope of troubleshooting activities.
During the performance of MWR SY-46861, an inspection ot the Unit 1
tendon gallery was performed. Housekeeping was not being maintained,
as indicated by grease on the floor of the tendon gallery.
Approximately 2-3 gallons of grease was located in the center of the
floor. A tendon in the tendon gallery was leaking grease
significantly. The sheathing filler grease cap was leaking grease on
Tendon V222. After the condition was reported to the licensee, a
second tendon (V209) in Unit 2 was noted by the licensee to be
leaking grease. Nonconformance reports were written for the two
tendons. The licensee advised that each unit has 96 vertical tendons
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and all will be inspected at least every 6 weeks for signs of
additional leakage. Containment structural integrity is required by
The licensee stated that the leakage of grease from the
two tendons did not affect the structural integrities of the two
reactor containment buildings.
The ladder area leading to the Unit 1 tendon gallery was inadequately
illuminated. The area from the top of the first ladder to the second
ladder was observed not to be illuminated, and was considered to be
an obvious safety hazard. The tendon gallery is an area of the plant
that is not traversed by plant personnel on a regular basis.
One apparent violation and no deviations were identified in this area of
the inspection.
6.
Monthly Surveillance Observations - Units 1 and 2 (61726)
An inspection of Unit 1 licensee surveillance activities was performed to
ascertain whether the surveillance of systems and components was being
conducted in accordance with TS and other requirements. The following
surveillance tests were cbserved and reviewed:
IPSP02-SI-0953, Revision 1, " Accumulator 1B Level Group 2 ACOT
(L-0953)"
IPSP02-SI-0963, Revision 1, " Accumulator IB Pressure Group 2 ACOT
(P-0963)"
The NRC inspector verified that testing was performed using approved
procedures, final test data was within acceptance criteria limits, and
test equipment was within required calibration cycles. A technical review
of the procedures was also performed.
During the review of IPSP02-SI-0963, Section 7.5 was noted to be
misnumbered. Section 7.5 had two steps numbered as 7.5.3.
Step 7.5.2
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instructed the technician to go to Step 7.5.4 if a computer point was
unavailable.
Due to the misnumbered steps, the potential existed of
referring a technician to, the wrong step (7.5.4). Verbatim compliance
with S'.ep 7.5.2 would have sent the technician to the wrong step.
Step 7.6.3 of IPSP02-SI-0953, instructed the technician to verify that an
annunciator alarmed when a comparator tripped. The comparator was reset
in the next step. Step 7.6.7 verified the same alarm energized when a
second circuit was tripped.
There were no steps between 7.6.3 and 7.6.7
that verified that the annunciator alarm cleared. The same procedure for
Unit 2 (2 PSP 02-SI-0953) included Step 7.6.6, which verified that the alarm
was clear. The same observation also applied to Procedure 1 PSP 02-SI-0963.
An inspection of Unit 2 licensee surveillance activities was performed to
ascertain whether the surveillance of systems and components _ were being
conducted in accordance with TS and other requirements. The following
surveillance tests were observed and reviewed:
2 PSP 02-SI-0931, Revision 0, "RWST Level Set 2 ACOT (L-0931)"
2 PSP 02-SI-0952, Revision 0, " Accumulator 2B Level Group 4 ACOT
(L-0952)"
During the review of 2 PSP 02-SI-0952, the procedure was compared to the
same procedure for Unit 1 (1 PSP 02-SI-0952, Revision 1). Differences were
noted between the two procedures. The differences inclutad:
The Unit 1 procedure additionally had Step 6.1 which referred the
technician to TS action statements for LC0 requirements. The Unit 2
procedure did not have a similar step.
The Unit 2 procedure had three additional steps in Section 7.6 to
verify that an annunciator was clear before, during, and after
testing. The Unit 1 procedure did not perform these steps.
Steps 7.7.1 (remove all test equipment) and 7.7.3 (ensure annunciator
deenergized) were double signoff steps for independent verification
of actions in the Unit 1 procedure. The same steps in the Unit 2
procedure were single signoff steps, with no independent verification
of the steps required.
Additionally, the NRC inspector noted the tenninal strips in the Unit 1
Relay Cabinet ZRR-012 had protective covers, but the terminal strips in
the Unit 2 Relay Cabinet ZRR-010 did not have protective covers.
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terminal strips were noted to be nonsafety related, however.
In conclusion, testing was performed using approved procedures, final test
data was within acceptance criteria limits, and test equipment was within
required calibration cycles. None of the observations were considered
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safety significant concerns. The discrepancies were referred to the
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licensee for resolution. No violations or deviations were identified in
this area of the inspection.
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7.
Monthly Maintenance Observations - Unit 2 (62703)
The NRC inspectors observed portions of selected Unit 2 maintenance
activities to ascertain whether the activities were conducted in
accordance with approved procedures. The activities included Work
Request CH-78095, " Add Oil to Essential Chiller 218." The essential
chillers provide cooling to selected safety-related equipment during upset
and faulted conditions.
The problem description on the work request was, " Essential Chiller 21B
upper oil sightglass is empty when chiller is running, add oil as
required." The work observed included postmaintenance testing of
Chiller 21B following maintenance. The following items were noted during
the inspection:
Procedure OPMP05-CH-0001, Revision 1. " York Chiller Inspection and
Maintenance," Section 6.5.5, provided instructions on how to check
the oil level with the chillers either operating or shut down. With
low oil level (as written on Work Request CH-78095), Addendum 4 was
required to be performed. Addendum 4 provided instructions to start
the chiller (Step 1), install a jumper to energize a solenoid
(Step 2), allow the solenoid to remain energized for approximately
5 days (Step 3), and monitor oil level every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (Step 4).
Step 3 was not completed in its entirety before Step 4 was performed.
The chiller did not run for 5 days prior to maintenance performing
Step 4 and postmaintenance testing. Steps 3 and 4 of Addendum 4
should be adhered to or revised by the licensee to clarify how long
the chiller is required to operate prior to performing oil level
. hecks.
Discrepancies were noted to exist between the essential chilled
water (CH) system operating procedures, maintenance procedures, and
the vendor manual with respect to proper chiller oil level.
Step 8.1.1 of Operating Procedure 2 POP 02-CH-0001, Revision 1,
" Essential Chilled Water System," stated " Verify the operating oil
level is above the top of the lower sight glass to the middle of the
upper sight glass for (Chillers) 22A, 22B, and 22C. The oil level is
visible in the sightglass for (Chillers) 2!A, 21B, and 21C.
If oil
level is out of range contact maintenance for correction."
Step 6.5.5.1 of OPMP05-CH-0001 stated " Verify operating oil level is
from the top of the lower sightglass to the middle of the upper
sightglass." Step 6.5.5.2 stated " Verify shutdown oil level to be at
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least at the top of bottom sight glass to the middle of upper sight
glass." Both steps applied to both sizes of essential chillers, the
300-ton units (22A-C) and the 150-ton units (21A-C).
The vendor manual for Chillers 21A-C indicates proper operating oil
level is from the lower sight glass to the middle of the upper sight
glass.
A vendor representative informed the NRC inspector that proper oil level
for all chillers exists when oil is visible in the upper sight glass with
the unit operating, and oil level can be reliably checked only during
chiller operation.
Discrepancies noted with the above statements included:
Step 8.1.1 of 2 POP 02-CH-0001 implied that Chillers 21A-C have only
one sightglass to verify oil level, but the chillers actually have
two sightglasses, an upper and lower one.
Vendor instructions were not located by the NRC inspector or licensee
personnel for proper oil level for the "open drive" type chillers,
22A-C. The oil reservoir is physically different between the "open
drive" and "hcrmetic" chillers. Vendor instructions were provided
only for hermetic chillers.
Step 6.5.5.2 of OPMP05-CH-0001 indicated shutdown oil level should be
no higher than the middle of the upper sight glass. Actual shutdown
level will vary, depending on purge drum (removes noncondensable
gasses from chiller) level at shutdown, length of shutdown and
chiller temperature. Also, actual shutdown oil levels for the open
drive chillers (22A-C) were noted to be above the top of the upper
sightglass (disagrees with requirements of Step 6.5.5.2).
Additionally, Step)6.5.5.2 disagrees with vendor instructions
(providedverbally that oil level could only be reliably checked
during chiller operation.
MWR CH-78095 was written to add oil to Chiller 218. Per wording of
the vendor manual, the chiller had sufficient oil, therefore, the MWR
was an unnecessary but conservative action.
Step 8.1.1 of 2 POP 02-CH-0001 instructed the operator to verify
operating oil le' vel of a chiller, but the chillers are not started
until Step 8.1.8 of the procedure.
Step 8.1.1 should be revised to
verify the oil level of a shutdown chiller is above a certain level,
or Step 8.1.1 should be placed after Step 8.1.8.
This subject area will be tracked as an open item (499/8911-03) until all
procedures in question have been revised to agree on how to check
essential chiller oil level, and operations personnel are trained on the
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proper way to check operating and shutdown oil levels.
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No violations or deviations were identified in this area of the
inspection.
8.
Preparation for Refueling Observations - Unit 1 (60705)
The NRC inspectors observed the testing of a carbon arc cutting device and
the generation of the basic requirements for a procedure to which it is
qualified and used. The device was tested on a mockup of the bottom half
shell of a steam generator; the shell included one primary loop nozzle and
the manway cover and flange.
The purpose of the equipment is to extract a broken bolt / stud in the
manway flange if that event' occurs during the first Unit I refueling
outage.
(The center of the bolt is cut out and the sides are collapsed.)
The overall unit encompasses: a fixture which can be bolted 'to the manway
flange, a positioner which will align the cutting head to the bolt hole, a
cooling unit, power control, and the graphite electrode cutting tool. The
unit is operated by positioning the device in the hole with the broken
bolt / stud, starting the cooling system (the system providns coolant to the
electrode and washes away the residue), end energizing the power unit to
the cutting electrode. When the cut has been made, the electrode is
withdrawn and the resultant "shell" of the bolt can be collapsed inwardly
and removed from the flange. Once set up, the operation can be performed
remotely, thereby reducing or keeping personnel exposure to penetrating
radiation to a minimum. The NRC inspectors did not have any concerns in
the development of the process.
No violations or deviations were identified in this area of the
inspection.
9.
Exit Interview
The NRC inspector met with licensee representatives (denoted in
paragraph 1) on May 4,1989. The NRC inspectors summarized the scope and
findings of the inspection. The licensee did not identify as proprietary
any of the information provided to, or reviewed by, the NRC inspectors.
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