ML20056C851
| ML20056C851 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 06/30/1993 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML20056C849 | List: |
| References | |
| 50-528-93-12, 50-529-93-12, 50-530-93-12, NUDOCS 9307260029 | |
| Download: ML20056C851 (30) | |
See also: IR 05000528/1993012
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U. S. NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos.
50-528/93-12, 50-529/93-12, and 50-530/93-12
Docket Nos.
50-528, 50-529, and 50-530
License Nos.
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Licensee
Arizona Public Service Company
P. O. Box 53999, Station 9082
Phoenix, AZ 85072-3999
Facility Name Palo Verde Nuclear Generating Station
Units 1, 2, and 3
Inspection
Conducted
April 27 through May 31, 1993
Inspection
location
Wintersburg, AZ
Inspectors
J. Sloan,
Senior Resident Inspector
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H. Freeman,
Resident Inspector
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A. MacDougall, Resident inspector
F. Ringwald,
Resident Inspector
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B. Olson,
Project Inspector.
6// e/91
Approved By
Al N
Date Signed
Reactor Projects' Secti[o/
H.rWong, Chief
n II
Inspection Summary:
Areas Inspected: Routine, announced, onsite, regular and backshift inspection
by the resident and regional inspectors. Areas inspected included:
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review of plant activities
surveillance testing - Units 1, 2, and 3
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plant maintenance - Units 1, 2, and 3
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snubber testing - Units 1, 2, and 3
emergency diesel generator maintenance planning - Unit 3
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. reactor t' rip breaker post-maintenance testing - Unit 3
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charging pump testing - Units 1, 2, and 3
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essential battery seismic issues - Units 1 and 2
essential cooling water seismic issue - Units 1, 2, and 3
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shutdown cooling thermal overload bypass design error - Units 1, 2, and 3.
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core reload analysis - Units 1, 2, and 3
emergency operating procedures.- Units 1, 2, and 3
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containment isolation valve operability determination - Unit 3
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inspection of quality verification function - Units 1, 2, and 3
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Plant Review Board activities - Units 1, 2, and 3
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9307260029 9307o2:-=
$DR
ADOCK 05000529
PDR[
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accountability drill - Units 1, 2, and 3
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followup on previously identified items - Units 1, 2, and 3 -
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review of licensee event reports - Unit 3
During this inspection the following inspection procedures were utilized:
35702, 37700, 40500, 42001, 60710, 61726, 62703, 62705, 71707, 82301, 92700,
and 92701.
Safety Issues Management System (SIMS) Item:
None
Results:
General Conclusion:; and Specific Findings:
Sionificant Safety Matters:
None.
Strengths:
The Plant Review Board was aggressive, thorough, and focused on nuclear safety
in performance of its functions (Paragraphs 5 and 15). The licensee
identified some significant design and testing errors, and management response
-to the issues was sound (Paragraphs 2.d.(4), 8, and 10).
Maintenance /
personnel appropriately questioned guidance-provided in two work orders and
obtained guidance prior to continuing the performance of maintenance
activities on an emergency diesel generator in Unit 3 (Paragraph 6).
Observations of three QC inspectors demonstrated that the inspectors were
thorough and exhibited good technical knowledge (Paragraph 14.d).
Weaknesses:
Testing of snubbers was not performed as required by Technical Specifications
(Paragraph 5). One operability determination was not conservative or
consistent with generic NRC guidance, and another was not promptly confirmed
by continued troubleshooting (Paragraphs 13 and 17.b). On two occasions-
management expectations were not met when operators left the "at the controls
area" in the control room (Paragraph 2.d.(3)).
The inspectors noted'that work
planning involving an emergency diesel generator was not thorough
(Paragraph 6). An accountability drill did not actually demonstrate the
capability to perform personnel accountability within 30 minutes of the
initial notification of an event (Paragraph 16). Several personnel errors
resulted in the Unit I diverse auxiliary feedwater actuation system being
inoperable for nine days without operators being aware (Paragraph 4).
Corrective actions related to lifted leads were found to be ineffective
(Paragraph 14.c. (1) .
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- Summary of Violations and Deviations:
Of the 18 areas inspected. one cited violation.was identified regarding.
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snubber; testing.'(Paragraph 5), and one non-cited . violation was identified
regarding an operator not following procedures in response to a load reject
event (Paragraph 17).
Open Items:
Nine new followup items.were opened, six followup items were closed, and one
followup item was left open.
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DETAILS
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1.
Persons Contacted
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The below listed technical and supervisory personnel were among those
contacted:
Arizona Public Service Comoany (APS)
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R. Adney,
Plant Manager, Unit 3
J. Bailey,
Director, Site Technical Support
T. Bradish,
Manager, Nuclear Regulatory Affairs
R. Cherba,
Manager, Quality Systems
P. Coffin,
Engineer, Nuclear Regulatory Affairs
R. Flood,
Plant Manager, Unit 2
R. Fountain,
Supervisor, Quality Audits. and Monitoring
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R. Fullmer,
Manager, Quality Audits and Monitoring
D. Gouge,
Director, Plant Support
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W. Ide,
Plant Manager, Unit 1
J. Levine,
Vice President, Nuclear Production
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D. Mauldin,
Director, Site Maintenance and Modifications
R. Prabhakar, Manager, Independent Safety and Quality Engineering
T. Radtke,
Supervisor, Unit 3 Operations
C. Russo,
Manager, Quality Control
R. Schaller,
Assistant Plant Manager,_ Unit 1
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J. Scott,
Assistant Plant Manager, Unit 3
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R. Stevens,
Director, Nuclear Regulatory Affairs,
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M. Woloszyn,
Supervisor, Quality Audits Supervisor (Acting)
Others
J. Draper,
Site Representative, Southern California Edison
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R. Henry,
Site Representative, Salt River Project
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Denotes personnel in attendance at the Exit meeting held with .the
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NRC resident inspectors on June 1,1993.
2.
Review of Plant Activities - Units 1. 2. and 3 (71707)
a.
Unit 1
Unit 1 operated at essentially 100% power throughout this inspection
period with the exception of a reduction to 12% power on May 15,
1993, to repair a hydrogen leak from the main generator T4 neutral
bushing. The plant returned to 100% power- on May 20, 1993. On
April 29,1993, the plant had_ preliminary indications of reactor
coolant system (RCS) leakage greater than 10 gallons per minute.
Subsequent confirmation showed the leakage to be approximately 9.5
gallons per minute. A packing leak'was identified from the
pressurizer spray line bypass valve and was promptly: isolated. .The
RCS leak rate was then measured to be 0.15 gallons per minute. On
April 29,1993, at 2:21 a.m., an earthquake occurred with an
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epicenter approximately 30 miles south of the Grand Canyon which
measured 5.5 on the Richter scale. There was no indication of the
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earthquake from plant seismic monitoring equipment, and the licensee -
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did not observe any impact on the units during subsequent walkdowns.
b.
Unit 2
Unit 2 began the inspection period in the midst of a refueling
outage with the core off loaded. The unit entered Mode 6 and
commenced core reload on May 5,1993, and completed the reload on
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May 9.
The unit entered Mode 5 operations on May 20, 1993. The
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licensee continued to investigate the cause of the steam generator
tube rupture. At the end of the inspection period, the licensee had
completed 74 days of a projected 99 day outage.
c.
Unit 3
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Unit 3 operated the entire inspection period at 100% power. On
May 24, 1993, main turbine control valve number 4 began experiencing
position oscillations causing turbine and reactor power to lower
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approximately 1 to 1.5%.
Other oscillations were noted on May 28
and 30, and the licensee installed recorders to capture data for
further investigation. The licensee was formulating a
troubleshooting plan at the end of the inspection period.
d.
Plant Tour
The following plant areas at Units 1, 2, and 3 were toured by ~the
inspector during the inspection:
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Auxiliary Building
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Control Building
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Diesel Generator Building
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Fuel Building
Main Steam Support Structure
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Radwaste Building
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Turbine Building
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Yard Area and Perimeter
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Containment Building
The following areas were observed during the tours:
(1) Operating Logs and Records - Records were reviewed against
Technical Specifications and administrative control procedure
requirements.
In Unit 1, the inspector noted an inconsistency between the
May 9,1993, unit log and the work order troubleshooting the
half-leg main steam isolation signal (MSIS) trip on May 9,
1993. The unit log stated that the fuse was found to have
oxidatica, while the work order stated that no oxidation was
present on the fuse. The system engineer concluded that
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oxidation was the cause of the half-leg MSIS trip, despite the.
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statement to the contrary in the work order. The inspector
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noted that a late entry was made to correct this log
discrepancy.
(2)
Monitorino Instrumentation - Process instruments were observed
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for correlation between channels and for conformance with
Technical Specifications requirements.
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(3)
Shift Staffina - Control room and shift staffing were observed
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for conformance with 10 CFR 50.54.(k), Technical
Specifications, and administrative procedures.
In addition,
operator (A0) performed a spot check of Unit 1 auxiliarystaffing over
the inspector
found that the commitment to staff at least four A0s per shift
was maintained.
The inspector observed two occasions in Unit 3 when for brief
periods of time (around 10 to 20 seconds) no operators were in
the "at the controls" area as defined in procedure 40AC-90P02,
" Conduct of Shift Operations." Although the requirements of
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10 CFR 50.54(k) were met, the expectations documented in the-
procedure were not met. The inspector noted that the operators
were in the control room in view of the panels, in the
" controls" area, also defined in procedure 40AC-90P02.
In one
case, the operator was standing at a desk just beyond the,"at
the controls" boundary, and in the other case the operator was
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standing at the Assistant Shift Supervisor's desk about 10 feet
from the "at the controls" boundary.
These occurrences
appeared to be caused by a lack of attention by the operators
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to assure that another operator was in the "at the controls"
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area prior to leaving that area. The inspector identified this
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matter to shift supervision who acknowledged the problem. The
inspector noted that 10 CFR 50.54(k) requires at least one
licensed operator to be "at the controls" at all times. The
licensee considered this requirement to be satisfied as long as
one operator was in the " controls" area. The inspector
concluded that this interpretation was consistent with
Regulatory Guide 1.114 and that the licensee met the
requirements of 10 CFR 50.54(k).
Licensee management issued a night order reemphasizing their
expectations and " Conduct of Shift Operations" training was
being revised to include a thorough review of this subject.
The inspector did not observe any further occurrences of this
problem and concluded that management's actions were
appropriate.
(4)
Eauipment Lineups - Various valves and electrical breakers were
verified to be in the position or condition required by
Technical Specifications and administrative procedures for the
applicable plant mode.
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The inspector noted a procedure change which resulted in Units
1 and 3 administratively relying on a boration flowpath which
included valves which had not been tested in accordance with
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ASME Section XI. The licensee identified and corrected the
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situation shortly after the change was implemented. An
alternate boration flowpath was available, although not
administrative 1y controlled; therefore, the safety significance
of this issue is considered to be low. Although the licensee
identified this deficiency, .the inspector was concerned that
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the normal procedure review process failed to identify the
problem prior to issuing the procedure change. The licensee
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acknowledged the inspector's comments.
(5)
Eouipment Taqqina - Selected equipment, for which tagging
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requests had been initiated, was observed to verify that tags
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were in place and the equipment was in the condition specified.
(6)
General Plant Eauipment Conditions - Plant equipment was
observed for indications of system leakage, improper
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lubrication, or other conditions that could prevent the systems
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from fulfilling their functional requirements.
During a plant walkdown in Unit 3, the inspector discovered
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that a ground wire was missing on valve SIB-HV-695, which is
the low pressure safety injection containment spray from the
shutdown cooling heat exchanger cross-tie valve. The licensee
concluded that the purpose of the wire was for personnel
protection and component operability was not affected. The
inspector concluded that the licensee's resolution of this
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problem was appropriate.
(7)
Fire Protection - Fire fighting equipment and controls were
observed for conformance with Technical Specifications and
administrative procedures._
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The inspector observed fire watch tours being performed in the
Unit I main steam support structure and Unit 2 auxiliary
building and found them to be consistent with licensee
procedures and management expectations.
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While touring the Unit 2 control building and auxiliary
building, the inspector noted several instances where fire
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extinguishers were left unsecured in an upright position,
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including one fire extinguisher that was left near the shutdown
cooling switchgear. An unsecured upright fire extinguisher
could be knocked over and become a missile hazard to both
personnel and equipment. While the licensee's safety manual
discussed the safe handling of compressed cylinders (oxygen,
nitrogen, etc.), it did not specifically address fire
extinguishers. The inspector discussed the issue with the
licensee's safety department. The licensee agreed with the
inspector's safety concerns and intends to incorporate fire
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extinguisher safety into the-safety manual and into -fire watch
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training. The inspector considered these actions to be
appropriate.
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(8)
Plant Chemistr_v - Chemical analysis results were reviewed 'for
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conformance with Technical Specifications and administrative
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control. procedures.
(9)
Security - Activities observed for conformance with regulatory
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requirements, implementation of the . site security plan,-and
administrative procedures included vehicle and personnel
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access, and protected and vital area integrity.
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(10) Plant Housekeeoing - Plant conditions and material / equipment
storage were observed to determine the general state of
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cleanliness and housekeeping.
(11) Radiation Protection Controls - Areas observed included control
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point operation, records of licensee's surveys within the
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radiological controlled areas, posting of radiation and high
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radiation areas, compliance with radiation exposure
permits, personnel monitoring devices being properly worn, and
personnel frisking practices.
(12) Shift Turnover - Shift turnovers and special evolution
briefings were observed for effectiveness and thoroughness.
No violations of NRC requirements or deviations were identified.
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3.
Surveillance Testina - Units 1, 2. and 3 (61726)
Selected surveillance tests required to be performed by the Technical
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Specifications were reviewed on a sampling basis to verify that:
1) the
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surveillance tests were correctly included on the facility schedule, 2) a
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technically adequate procedure existed for performance of the
surveillance tests, 3) the surveillance tests had been performed at the
frequency specified in the Technical Specifications, and 4) test results
satisfied acceptance criteria or were properly dispositioned.
Specifically, portions of the following surveillances were observed by
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the inspector during this inspection period:
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Unit 1
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Procedure
Descriotion
PPS Functional Test - RPS/ESFAS Logic
CEAC Number 2 Functional Test
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Unit 2
Procedure
Description
Eddy Current Testing of Tubing (Steam Generators)
Unit'3
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Procedure
Description
Auxiliary Feedwater Pump. AFB-P01 Operability
Test 4.7.2.A & C
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BDP ESFAS Functional Test
Radiation Monitoring Monthly Functional Test Procedure
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No violations of NRC requirements or deviations were identified.
4.
Plant Maintenance - Units 1. 2. and 3 (60710. 62703 and 62705)
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During the inspection period, the inspector observed and reviewed
selected documentation associated with maintenance and problem -
investigation activities listed below to verify compliance with
regulatory requirements, compliance with administrative and maintenance
procedures, required quality assurance / quality control department
involvement, proper use of safety tags, proper equipment alignment and
use of ,inmpers, personnel qualifications, and proper retesting.
The
inspector verified that reportability for these activities was' correct.
Specifically, the inspector witnessed portions of the following
maintenance activities:
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Unit 1
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Electrical determination of the spray chemical addition system
The inspector observed an electrician using the ." suggested resolution"-
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section of Engineering Evaluation Request (EER) 91-XE-34 (rather than.the
" engineering guidance" section). The electrician also did not. accurately
follow use the " suggested resolution" during wiring termination work to
remove the spray chemical addition system. . The electrician used plastic .
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sheeting, sealed with intermittent pieces of tape, to protect
Westinghouse ARD relays below the work area from debris. The EER
" suggested resolution" section called for complete sealing of the top
edge with tape, while the " engineering guidance" section did not specify
how to cover the relays. The inspector concluded that the actual work
performed was in accordance with the " engineering guidance" section. The
licensee initiated Condition Report / Disposition Request (CRDR) 1-3-0281-
to address the electrician's use of the EER. During a future inspection ~
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the inspector will review the CRDR evaluation and the licensee's
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determination of which portion of the EER should be used (Followup Item
50-528/93-12-01).
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On May 20, 1993, the inspector observed test leads with clip-on probes
attached to bare conductors on Unit 1 "A" High Pressure Safety Injection
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(HPSI) flow transmitter, FIT-303. Work Order 562936 was still open and
showed that no work had been performed on this equipment' since May 1,
1993. The inspector noted that leaving test leads installed when work
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was not in progress was contrary to the guidance issued on September 17,
1992, by the Maintenance and Work Control Newsflash. This Newsflash on
" Energized Equipment troubleshooting Expectations" stated, " Connections
made with clip-on type' connectors shall only be made for active
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troubleshooting - they shall be removed when work is not actually in
progress." The Newsflash was interim guidance promulgated while the
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licensee completed work to fulfill a commitment made in CRDR_080133,
which tracked actions resulting from the incident investigation for the
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ALERT (loss of all annunciators) that occurred on May 4,1992. _ According
to the Director, Site Maintenance and Modifications, MDG 24 and 25 were
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issued as the procedures to formalize management expectations in this
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area. The inspector noted that these MDGs did not include the
expectation stated in the Newsflash regarding clip-on connectors. The
Director, Site Maintenance and Modifications, committed to incorporate
this expectation into MDG 24. The licensee promptly removed the clip-on
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test probes and restored FIT-303. The licensee stated that this was
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contrary to management expectations and counselled the technicians
involved. The inspector concluded that the licensee's corrective actions
were appropriate. The inspector will review the revision of MDG 24 to
assure that the pertinent guidance is incorporated (Followup Item
50-528/93-12-02).
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On May 5, 1993, the licensee discovered that four of the eight bypass
keys were left installed in the auxiliary relay cabinet following .
maintenance of the diverse auxiliary feedwater actuation system (DAFAS).
This resulted in the DAFAS being unavailable from April 26, 1993, to
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May 5, 1993. DAFAS is not required to be operable under Technical
Specifications; however, the system was installed to respond to
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anticipated-transient-without-scram events. The licensee investigated
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this event under Condition Report / Disposition Request (CRDR) 1-3-0256,
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which was not closed at the end of the inspection period. The inspector
will review the completed CRDR during a future inspection (Followup Item
50-528/93-12-03).
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Unit 2
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Tube pulls
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Core Reload
Reinstallation of reactor vessel accelerometers
The inspector observed a portion of the activities to reinstall
accelerometers'on two reactor vessel studs. The accelerometers are used
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to provide signals to the vibration and loose parts monitoring system.
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Prior to entering containment to perform the reinstallation, the
instrument and control (I&C) technicians and inspector were briefed by
radiation protection personnel on dose rates, protective clothing
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requirements, and ALARA considerations. Radiation protection required
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. personnel in the work area to wear dosimetry on the head and the back, in
addition to dosimetry worn on the chest and an alarming dosimeter worn on
the arm.
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The work primarily consisted of: 1) torquing a mounting bolt on the
appropriate reactor vessel stud to 100 ft-lbs, 2) torquing a mounting
screw on the mounting bolt to 25 in-lbs, 3) torquing the accelerometer on
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the mounting screw to 18 in-lbs, and 4) connecting the electrical cable
to the accelerometer and lockwiring the connections.
The inspector
observed that the I&C technicians carried a copy of the procedure. and
used tools with current calibrations. Tape had been used to clearly
identify the appropriate studs for the accelerometers, and the stud holes
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in the reactor vessel head were numbered.
The technicians encountered
. difficulty with the removal of one of the mounting screws because the
screw had rusted to the mounting bolt.
Initial attempts to remove the
screw were unsuccessful because the bits of different screwdrivers would
slip out of the screw slot due to incorrect sizing.
The technicians
determined that a new mounting screw would be required after obtaining a
proper sized screwdriver and removing the screw.
Prior to leaving
containment, the technicians installed and torqued the mounting bolts and
demonstrated that sufficient torque could be developed with the torque
screwdriver to reinstall the mounting screws. The technicians also
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described the remainder of the installation process and indicated that
lockwiring the connections was difficult, but could be performed
especially when surgical gloves were worn. The inspector spoke with
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other technicians in the I&C shop who indicated that the use of surgical
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gloves improved the ability to perform the lockwire installation. The
installation of the accelerometers was completed on May 21, 1993, after a
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new mounting screw had been obtained.
Unit 3
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Emergency Diesel Generator "B" outage
calibrate jacket water high temperature switch
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replace shuttle valves
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replace governor oil
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test time delay relay on output breaker.
GE reactor trip breaker maintenance.
No violations of NRC requirements or deviations were identified.
5.
Snubber Testing - Units 1. 2. and 3 (40500, 61726. and 92701)
The inspector continued an inspection of snubber testing, previously
documented in NRC Inspection Report 50-529/93-11, and found several
deficiencies.
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The licensee's snubber testing program was defined in procedure 73AC-
9ZZ01, " Testing and Control of PVNGS Snubbers." After discussions with
Region V and NRR personnel, the inspector concluded that the licensee did
not meet the specific requirements of Technical Specification 4.7.9.
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However, the NRC staff determined that the licensee's program was
acceptable based on current testing standards and that the testing
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conducted during previous outages was acceptable.
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In letters to the Region V Regional Administrator, dated June 22, 1987,
August 31, 1987, and January 12, 1989, the licensee selected sample plan
No. 2 per Technical Specification 4.7.9 for Units 1,- 2, and 3,
respectively.
Sample plan 2 requires that "a representative sample of
each type of snubber shall be functionally tested in accordance with
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Figure 4.7-1."
Figure 4.7-1 plots the total number of snubbers of a type
found not meeting acceptance requirements verses the cumulative number of
snubbers of a type tested at the end of the day's testing.. The. figure is
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divided into three regions: Reject, Continue Testing, and Accept.
If the
plotted point falls into the " Reject" region, all snubbers of that type
are required to be functionally tested.
If the plotted point falls into
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the " Accept" region, functionally testing of that type of snubber may be
terminated. When the plotted point falls into the " Continue Testing"
region, additional snubbers of that type are required to be tested until
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the plotted point falls into the " Accept" or " Reject" regions or all
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snubbers of that type are functionally tested. With no failures,_the
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minimum number of snubber of a type that must be tested is 37. .
Technical Specification 4.7.9 defines the " type of snubber" to mean
snubbers of the same design and manufacturer, irrespective of capacity.
Licensee procedure 73AC-9ZZ01 further clarified this definition and
grouped the snubbers into five groups: 1) steam generator hydraulic
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snubbers, 2) reactor coolant pump hydraulic snubbers, 3) PSA-1/4 and PSA-
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1/2 "small" size snubbers, 4) PSA-1, PSA-3, and PSA-10 " medium" size
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snubbers, and 5) PSA-35 and PSA-100 "large" size snubbers._ With these
definitions, Technical Specification sample plan 2 requires that a
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minimum of 37 snubbers of each of the five types be tested or 100% of the
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snubbers if there are less than 37 snubbers of that type. Technical Specification 4.7.9 further requires "that the representative sample
selected for the functional test sample plans shall be randomly selected
from the snubbers of each type...."
As implemented, the licensee's testing program treated all mechanical
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snubbers (PSA) as one type and then selected a sample of 37.
Additionally, the program essentially used sample plan.1 (functionally
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test 10%) for testing the hydraulic snubbers by selecting one steam
generator snubber, and one reactor coolant pump snubber. The snubbers
were selected by a computer program from a data base containing a list of
snubbers. For the mechanical snubbers, the program selected a number of
small, medium, and large size snubbers proportional to the actual number
of snubbers of each size. Additionally, the program selected snubbers
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from different locations / systems based upon an algorithm. While the
snubber data base originally contained all the snubbers in the unit, each
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snubber was removed from the data base after it had been tested.
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According tu the licensee, this would ensure that each snubber would be
tested at some point,
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The inspector met with licensee management on April 20, 1993, and
discussed the program. The inspector questioned the licensee's method of
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snubber sample selection and the program's overall compliance with
Technical Specification 4.7.9 samole plan 2 requirements. The licensee
told the inspector that they had reviewed the questions of type and
sample size previously and believed that the program did' meet the
requirements of the Technical Specification. The licensee initiated CRDR-
9-3-0367 on April 30, 1993, to review procedure 73AC-9ZZ01 for compliance
with Technical Specification 4.7.9.
The inspector observed a special Plant Review Board (PRB) convened on
May 10, 1993. The PRB met to discuss the implications of not having
performed surveillance testing on snubbers in accordance with Technical
Specification 4.7.9.
The PRB critically addressed safety concerns
regarding snubber testing that was required by the Technical
Speci fications. The PRB members reviewed the functional testing that was
performed during the previous outages in all three units to determine the
technical significance of not performing the testing in accordance with
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the Technical Specifications.
The PRB determined that the testing that.-
was performed was equivalent to the testing required by the Technical
Specifications and did not represent a safety concern. The inspector
concluded that the special PRB met the requirements of Technical Specification 6.5.1 related to PRB responsibilities, and that the PRB was
!
thorough and effective in addressing this matter.
-
Upon further evaluation, the NRC concluded on May 6, 1993, that the
licensee did not meet the requirements of Technical Specification
~
Surveillance Requirement 4.7.9.e sample plan 2 and had not met these-
requirements during any of the previous testing periods. Speci fically,
the licensee had not randomly selected the representative sample and had
.
not tested the minimum number of snubbers of each type as required by
l
sample p_lan 2 (Violation 50-528/93-12-04).
In addition to not meeting the surveillance requirement, Technical
t
Specification 4.0.3 stated that failure to perform a surveillance
requirement within the prescribed interval constituted noncompliance with
the operability requirements for the Limiting Condition for Operation
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(LCO). This would require all snubbers in all three units to be declared
,
inoperable and the appropriate action statement be taken. The LCO for
Technical Specification 3.7.9 stated that, if one or more snubbers were
--
inoperable on a system, the inoperable snubber (s) be replaced or repaired
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the associated system be declared inoperable and the
ACTION specified for that system be followed. This would have led to-the
shut down of 'Jnits 1 and 3 which were operating at the time.
In a letter to the NRC dated May 14, 1993, the licensee described that
,
the snubber testing that had been performed, for the most part, met the
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requirements intended by the NRC when it issued generic guidance for
snubber testing and that other nonconformances were minor deviations.
The licensee additionally requested enforcement discretion for Units 1
and 3 to prevent unnecessary shutdowns and for Unit 2 to allow mode
changes (Mode 6 to Mode 5) until emergency Technical Specification
,
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changes could be processed. The NRC determined that the course of action
taken involved minimal or 'o safety impact and that the exercise of
,
enforcement discretion was warranted when considering the public health
4
and safety. Therefore, on May 14, 1993, the NRC exercised discretion not
to enforce compliance with the ACTION statement of Technical Specification 3.7.9.
,
The licensee continued to examine the snubber failures. The small size
snubbers generally have failed due to bent shafts. The licensee believes
that some of the small size snubber failures were due to a water hammer
'
event. Other snubbers failures were due to-insufficient or degraded
lubrication, corrosion products, installation problems or excessive force
.
applied. The licensee did not find a root cause of failure which would
l
raise an operability concern for the snubbers in Units 1 and 3.
One violation of NRC requirements was identified.
6.
Emergency Diesel Generator (EDG) Maintenance Planning - Unit 3 (62703)
The inspector observed portions of a scheduled maintenance outage on the
"B" EDG which started on May 4, 1993. The inspector noted a mechanic
investigating leakage from the attached fuel oil booster pump identified
i
in work arder (WO) 846422. The inspector noted that the WO called for
.
replacing fittings on the pump that were recently replaced and did not
appear to be leaking. The craft did not believe that the WO specified
the correct location of the leak and notified the shop foreman.
The work
was deferred and the leak was subsequently found to be from the pump
packing during the post-maintenance run. Although craft personnel
appropriately questioned the work order and obtained guidance before
-
continuing, the inspectors were concerned that the work planning for this
'
activity was deficient in that the planner did not adequately evaluate
-
the scope of the work to ensure the WO was for the leaking component.
,
!
The inspector also observed replacing the oil in the overspeed governor,
in accordance with WO 043764. The inspector noted that the WO included a
description of one component needing oil (UG-08); however, a description
of the other component was not available. The mechanics were unclear
what the other component was and had to refer to the vendor technical
manual (VTM) in the shop for clarification. After looking at the VTM,
!
'
they were able to identify the other component and completed the oil
i
replacement. Again, this showed appropriate consideration by the craft
to obtain clarification prior to continuing work; however, the work
planning was deficient in that the WO did not contain sufficient
information to allow the work to be performed.
The inspector also observed the post-maintenance run of the EDG and noted
good support in the field from the shop foremen,
2
The inspector concluded that the mechanics acted properly in stopping
work to resolve their questions, and that the shop foreman provided good
support. The inspector further concluded that work planning was not
thorough for these activities.
11
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No violations of NRC requirements or deviations were identified.
7.
Reactor Trio Breaker (RTB) post-Maintenance Testina - Unit 3 (62703)
During post-maintenance testing of RTB 3JSBAC03, operators misunderstood
'
a note posted by the breaker that described the proper position of the
undervoltage (UV) coil. The note said " verify proper UV position.after
i
each breaker close operation." The reactor operator and auxiliary
operator noted that after the breaker was tripped manually the UV coil
i
was not reset. The operators did not recognize that this was not the
correct position of the coil. The operators used pictures near the
,
breaker which showed both the proper and improper position. However, the
operators incorrectly reasoned that since the note said to verify the
proper UV coil position after each closing operation, and since they had
,
just opened the breaker, the proper position for the UV coil. should be
the opposite as shown in the pictures. Therefore, the control room
believed the UV coil was properly reset and suosequently attempted to
close the breaker, which immediately tripped because the UV coil was not
reset.
i
The inspector concluded that there was an appropriate level of management
attention during the testing; however, the inspector also noted there was
still confusion in the field concerning the identification of proper UV'
coil operation despite the attention which has been focused on reactor-
trip breaker and UV coil operation. Unit 3 operations personnel informed
the other units of the confusion surrounding the training aid and'
recommended that all licensed and non-licensed operators attend refresher
training on the operation of the UV coils. Additionally, the licensee
,
identified an inconsistency between the operations and maintenance
procedure concerning the actions to take if the UV coil does not reset.
This problem was being addressed by a procedure change to ensure all RTB
,
operations are controlled by the operations procedure and Condition
,
Report / Disposition Request (CRDR) 3-3-0237 was written to evaluate the
'
problem.
The inspector concluded that the licensee's response to this situation
was adequate.
No violations of NRC requirements or deviations were identified.
,
8.
Charoina pumo Testina - Units 1. 2. and 3 (71707)
!
On May 20, 1993, the licensee determined that testing of the charging
,
pumps had been performed with flow instruments with an instrument range
i
not meeting the requirements of Section XI of the ASME Code, Article IWP
!
4120. The ASME Code requires the flow instruments to have a range of.
!
less than or equal- to three times the reference flow value. The
,
reference flow value was 44 gallons per minute (gpm), so the maximum
!
allowed range was 0-132 gpm.
Flow instrument CHN-FL-212, which was used
for the tests in all three units, had a _ range of 0-150 gpm. The accuracy
'
of CHN-FL-212 was
1.0%, while the ASME Code only required an accuracy
-
of i 2.0%.
As a result of this concern, the licensee entered Technical
12
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Specification 4.0.3 and reperformed the' tests within the allowed time
period after adjusting the range of the instrument. 'The licensee also
notified NRC personnel of the condition and discussed its intentions in
-
parallel with its prompt actions. The licensee stated that it intends to
thoroughly review compliance of its inservice. testing program with
,
surveillance requirements. This issue is unresolved pending the
licensee's evaluation of the inservice testing program (Unresolved Item
50-528/93-12-05).
No violations of NRC requirements or deviations were identified.
9.
Essential Battery Seismic Issues - Units 1 and 2 (37700)'
a.
Essential Batterv Seismic Clearance - Unit 2 (37700)
In response to licensee-identified cracks near the terminal post of
Unit.1 essential (PK) batteries, the licensee modified the design
,
prior to replacing the Exide batteries. in-Unit 2 with AT&T round
-
cell batteries. This modification consisted of using more flexible
,
cables (to reduce. cable. relaxation stresses) and installing
horizontal support. brackets. The inspector noted that there was
less than 1/2" of clearance between the horizontal supports and the
battery cabinets in the battery "A" installation. Because the
horizontal brackets were fastened .to support structures which would
move independently from the battery rack during a seismic event, the
inspector was concerned about potential. damage to the batteries
during such an event. The licensee agreed with the. inspector's -
>
concern and promptly modified the installed supports so that there
was approximately 3" of clearance between the supports.and the.
battery rack. The "A" PK battery had been declared inoperable for
the modification installation and was.still in this status when the
concerns were identified. The inspector reviewed the installation
of the supports in Units 1 and 3 and determined that similar
conditions did not exist.
-
The licensee's design modification will be reviewed in a future
inspection to determine if the details were adequate (Unresolved
Item 50-529/93-12-06).
b.
Batterv Rack Partial Thread Engagement - Unit 1
"
While inspecting the essential batteries in Unit.'1, the inspector
noted that the bolts that fasten the retainer assembly' bars to the
i
foundation did not extend fully through the 1/2". steel plate. Th_e
essential batteries are held in place by 1/2" threaded rods which
extend from brackets at the top of the battery cabinet to the
-
foundation. The threaded rods are connected to retainer assembly
bars which in turn'are~ fastened to the foundation by 5/8" bolts.
The inspector estimated that the 5/8" bolts had approximately 3/8"
i
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of thread engagement with the foundation.
Drawing 13-E-ZJP-001,
,
sheet 2, required that the bolts have full thread engagement .into
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the 1/2" plate. This condition had been previously identified by
the licensee in CRDR 1-3-0095.
i
!
The licensee's generic procedure on fastener tightening /preload,
!
30DP-9MP02, Revision 01.08, required that "where the bolted
i
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connections attach to a tapped and threaded hole in the mating part,
the bolt length shall be sufficient to assure an engagement of at
.
least one bolt diameter. . . ." The observed condition, S/8" bolts
!
with 3/8" thread engagement, did not meet the generic criteria. The
'
inspector questioned if the condition was seismically acceptable and
'
if the condition had been previously documented.
Licensee personnel
'
determined that the seismic requirements of the installation
-
required approximately 3/8" of thread engagement, but that the
'
evaluation had not been documented at that time.
The licensee documented evaluation of the condition on material
nonconformance report (MNCR) 93-PK-1017. The resolution of the MNCR
s
stated that the bolts met the requirements of calculation 13-MC-XM-
204, " Thread Engagement for Partially Engaged Fasteners." However,
the inspector noted that the calculation stated that if the specific
materials were not addressed in the calculation,- a case specific
calculation should be prepared that considered the materials, the
application, and the design loading conditions. The specific
materials used in this application, ASTM A307 bolts and ASTM A36
}
foundation plate, were not specifically covered in the calculation.
The inspector will review the licensee's technical justification for
i
resolution of this MNCR in a future inspection (Unresolved Item
i
50-528/93-12-07).
No violations of NRC requirements or deviations were identified.
10.
Shutdown Coolino (SDC) Thermal Overload BYDass Desian Error - Units 1. 2.
and 3 (71707)
~
On May 5,1993, during post-modification testing of a design change to
remove the auto closure interlock on SDC isolation valves (S1-651 through
,
656), the licensee found that the thermal overloads on the valve motor
operators were only bypassed when system pressure was greater than 480
psi. Since the interlock circuit is closely related to the bypass
feature, the inspector concluded that licensee missed an opportunity to
identify the design error during the design review of the interlock
design change. Technical Specification (TS) 3.8.4.2 requires these
overloads to be bypassed continuously or under accident conditions
whenever the valves are required to be operable.
Since the accident
'
analysis and TS 3.7.11 require SDC to be available for entry into long
term cooling in Modes 1 through 3, the licensee determined that the
valves needed to be operable and the overloads bypassed when pressure is
a
less than 480 psi in Units 1 and 3.
Consequently, the valves and the SDC
J
systems in Units 1 and 3 were declared inoperable and the appropriate TS
3
action statements were entered. The thermal overloads were promptly
)
bypassed and the SDC systems were declared operable on the morning of
1
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May 6, 1993. Additionally, the licensee made a one-hour notification per
10 CFR 50.72 for being outside their design basis, and initiated
Condition Report / Disposition Request 9-3-0369 to determine the root cause
of the design error.
i
At the time of the discovery, Unit 2 was in Mode 6 and had commenced
'
refueling operations, and one SDC loop was in operation with the
isolation valves open.
In Modes 4 through 6 the purpose of the SDC
system is to provide decay heat removal per Appendix A to 10 CFR Part 50,
,
General Design Criterion 34, and is not required as part of accident
mitigation.
In Mode _6, TS 3.9.8.1 required one SDC loop to be operable
and one SDC loop in operation. The licensee's TS Interpretations
3.4.1.4-13-02-00 and 3.9.8.1-13-01-00 defined an operable SDC loop in
,
Modes 5 and 6 as a pump and an associated flow path but did not 'specify
that the isolation valves must be operable. Therefore, the licensee
determined that bypassing the thermal overloads in Unit 2 was not
-
immediately required. The licensee subsequently bypassed the thermal
!
overload protection in Unit 2 on May 25,1993, while in Mode'5.
,
The licensee is evaluating its interpretation of TS 3.8.4.2 to determine
!
whether proper accident conditions have been evaluated and the need for
-!
bypassing of the thermal overloads for these and other valves.
The
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licensee submitted Licensee Event Report (LER) _50-528/93-06 on this
issue. The inspector concluded that the licensee's initial
,
interpretation of the requirements and actions to correct the situation
'
were conservative. Additionally, the inspector concluded that it 'was
!
commendable that the licensee discovered this problem during post-
.,
modification testing although it appears that the error could have been
identified earlier in the design change process.
This issue will be
,
further reviewed during the review of LER 50-528/93-06.
-t
No violations of NRC requirement or deviations were identified.
.
11. Core Reload Anal _vsis - Units 1. 2. and 3 (37700)
The Office of Nuclear Reactor Regulation (NRR) and Region V personnel
'
conducted an inspection of the core reload analysis process in
preparation for the licensee performing independent reload analyses. NRR
,
will issue a special report (Safety Evaluation Report) describing this
review and its conclusions.
.
No violations of NRC requirements or deviations were identified.
12. Emergency Operatina Procedures (EOPs) - Units 1. 2. and 3 (42001)
The inspector reviewed the status of licensee actions regarding E0P-
~
related comments resulting _ from the Unit 3 Human Performance Study Report
!
performed by the NRC Office for Analysis and Evaluation of Operational
Data (AE00) as a result of the February 4,1993, reactor trip event in
.
Unit 3 (see NRC Inspection Report 50-530/93-04). The AE0D report was
,
issued on April 22, 1993, and Region V determined that the following
issues from the report warrant additional followup-
15
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a.
Several difficulties with the E0Ps occurred during recovery,
b.
Procedures did not quickly restore the electrical system and did not
consider using the main feedwater system to feed the steam
generators.
f
The licensee reviewed procedural guidance and determined that the
E0Ps should be changed to allow use of main feedwater, if available,
and that guidance for restoration of the switchyard electrical-
lineup should also be included. These changes are planned to_.be.
incorporated in October 1993.
c.
The procedure directed manual control of the pressurizer spray valve
,
which could result in excessive reactor operator task workload in
y
other emergency conditions.
The AEOD report described that operators may be unnecessarily tasked
with administrative and monitoring responsibilities as the result of
being required to operate some systems, such as pressurizer spray,
in the manual mode, instead of automatic control. The licensee
i
reviewed this issue for pressurizer spray only. Th'e reason-that the;
E0Ps require manual operation of the spray valve is that operators
>
are required by a Technical Specification surveillance requirement-
to log spray line -temperature every time the valve cycles, when less
than four reactor coolant pumps are operating. The licensee stated
that placing the controls in manual actually reduced the burden on -
-
the operators, because they would know when the valve is . cycled and
can log required information appropriately. The licensee considered
l;
and rejected reliance on computerized monitoring of the spray line
temperature to meet the surveillance requirement because operators
might not notice spray line temperature changes and:therefore might
allow continued automatic spray operation that might be detrimental
,
to the spray nozzle. The licensee did not think that monitoring in .
>
this fashion was consistent with the intent of the surveillance
requirement,- even though it would allow continued operation in the
i
'
automatic mode. .The licensee does not plan to revise the E0Ps as a
result of this issue.
j
,
d.
The E0P prolonged the time from automatic initiation to shutdown,of
,
the emergency diesel generators.
,
The licensee determined that the E0Ps should be revised.to' allow
_
operators to move the step forward to secure the emergency diesel
generators when. appropriate and time permits. This change is
scheduled for October 1993.
.
.I
e.
The current computer system is not able to adequately display fast ~
.
f.
Auxiliary feedwater and safety injection system flows do not have a
,
recorder to readily identify the amount of water injected.
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g.
The emergency diesel generators were run unloaded for about four.and
'
one-half hours.
,
,
After the unloaded run, operators followed the carbon burnout
guidance of abnormal operating procedure 43A0-3ZZ52, " Diesel
l
Generator Operations After ESFAS Actuations " . This procedure
l
required the generator to be run at greater than or equal to 4.2 MW
!
for greater than or equal to 15 minutes, if the generator was
!
operated unloaded for more than six hours since its last loaded'
I
operation. The diesels had not been run unloaded for more than six
hours, and the operators did not perform a carbon burnout run.
}
(
During a future inspection, the inspector will review the procedural
<
guidance with industry and vendor recommendations.
,
h.
The audible alarm for computer alarms (system RJ) was intentionally
disabled.
These items will be further reviewed during a future inspection (Followup
Item 50-530/93-12-08 for items a, b, c, d, and h; and Followup Item
50-530/93-12-09 for items e, f, and g).
I
No violations of NRC requirements or deviations were identified.
13.
Containment Isolation Valve Operability Determination - Unit 3 (71707)
_
The inspector reviewed the operability determination of 3HPB-UV-004, the
'
Unit 3 containment hydrogen control downstream isolation valve (normally
closed), which tripped its thermal overloads when responding to a close
-
signal on a containment isolation actuation signal (CIAS) on February 4,
!
1993. The inspector reviewed Condition Report / Disposition Request (CRDR)
3-3-0136, the unit logs and control room logs, and interviewed line
,
management concerning the operability of the valve. The CRDR discussed
i
'
troubleshooting on February 6 which verified that the motor currents were
normal and the overloads were the proper size. There was no discussion
!
in the CRDR or logs concerning what actions were done on February 4 to
verify the operability of the valve. The operations manager informed the
inspector that the valve was successfully stroked several times as part
i
ef ASME Section XI testing and the thermal overloads had' been tested,
j
without identification of the root cause of failure. The licensee
subsequently determined the valve to be operable based on these results
!
and the fact that the overloads that tripped are bypassed during a CIAS.
l
The valve was initially determined to be operable with'out fully
f
understanding why the overloads tripped, because the information
i
available supported the determination that the valve could perform its-
safety function. Additional troubleshooting.was not started until
~
March 9,1993, contrary to the guidance in Generic letter 91-18,
l
Technical Guidance 9900, Section 5.4, for continuous attention in the
decision making process. The inspector concluded that--these additional
efforts were comprehensive and led to eventually determining the cause of
the failure to be relaxation of the torque switch due to a gear ratio
i
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insufficient to ensure that relaxation did not occur. HPB-UV-004 was-
1
declared inoperable when troubleshooting commenced'again on March 9.
As-
a result of testing on similar Rotork actuators, HPB-UV-002 in Unit 3 was
i
also declared inoperable.
The licensee corrected these deficiencies by
-
installing a contact in the CIAS circuit that would open when the valve
-
was shut and prevent the valve from cycling. Although the licensee
stated that the delay was due to -scheduling conflicts, the inspector
,
concluded that the licensee did not aggressively pursue confirmation of-
the initial operability determination as described in Generic Letter 91-
18 in that troubleshooting to determine the root cause of the failure was.
t
delayed for over one month. .
,
No violations of NRC requirements or deviations were identified.
14.
Inspection of Quality Verification Function - Units 1. 2. and 3 (35702)
The inspector assessed the effectiveness of the licensee's quality
verification (QV) organizations in identifying safety significant
problems and in ensuring timely and effective corrective action.
In
conducting the review the inspector focused on the following areas:
performance assessment program, corrected on-the-spot (C0TS) program,
safety significant technical issues, and observation of quality control
(QC) inspectors.
a.
Performance Assessment Procram
,,
The inspector reviewed the following documents associated with the
assessment of plant performance:
Performance Assessment Trend
-
Report, Performance Assessment Annunciator Report, Trend Analysis
Coding Manual, and the current Issues Report.
The inspector
concluded that these programs were effective in focusing' appropriate
management attention on performance ' issues. The inspector also
observed that the documents reviewed provided a longer term summary
4
of plant performance (3 months and greater), and that the areas
described were generally broad in nature (site maintenance, human-
'
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performance,etc). The inspector concluded that the long term
,
nature of these documents was expected and that more real time
identification and trending was addressed using the COTS program.
b.
COTS Procram
,
t
The inspector reviewed the QC monthly reports for March and April
_
.
1993 and selected various COTS from these reports to review. The-
l
inspector interviewed line management and . supervisors to determine
.
how they respond to COTS issued in their areas. This inspection
1
evaluated the licensee's process, but did not include an in-depth
look at the corrective actions identified by the supervisors.
In
general, the supervisors were informed within a few days by the QC
supervisor issuing the COTS that there was a-problem. This
notification was either verbal or written. The line supervisors
would then perform some type of counseling and/or training and were
t
sensitive to monitoring trends in individual performance.
l
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The inspector concluded that the QC. organization was identifying
'
good issues and that they were appropriately documented. The
-
inspector also noted that work center supervisors were sensitive to
trending problems and to taking appropriate corrective action to
help prevent problems from becoming more serious.
c.
Technical Review of Safetv Issues
(1)
Lifted / Landed Leads
The inspector conducted a search in the corrective action
.
tracking system (CATS) for all documents associated with
"
lifted / landed leads. There were approximately twenty various
documents in the data base in the last two years on this
subj ect. The inspector reviewed the following corrective-
action documents: Condition Report / Disposition Requests
(CRDRs) 3-1-0014, 3-1-0018, 1-1-0130, 1-2-0355, and 1-2-0584;
Material Nonconformance Reports (MNCRs) 92-SQ-1010 and. 92-SQ-
1011; and Quality Control Reports (QCRs) 00450879-012 and
00562561-002. The inspector noted that there were-four CRDRs
written on this subject from May 1991 until May 1992. The
first three CRDRs did not require a formal root cause analysis
(RCA) and were designated for trend only or apparent cause.
evaluation. CRDR 1-2-0355, written on May 19,.1992, required a-
formal RCA that concluded the cause of the improper landing of
leads was inadequate procedures.
The inspector was concerned that the CRDRs were not being
effectively used to determine the underlying cause of the
personnel errors associated with lifted / landed leads.
'
Specifically, the failure to screen the first four CRDRs for a
formal RCA may have contributed to continued errors involving
lifted / landed leads.until a trend of over one year was
ebserved. The inspector was also concerned that the initial
RCA did not address broader generic maintenance issues, such as
inattention to detail and continued personnel errors.
In June 1992, Corrective Action Report (CAR) 92-0123 was
,
written to investigate the continued problems in this area.
The inspector noted that six additional CRDRs and several
QCRs/ COTS were issued in the area of lifted / landed leads after
the CAR was issued. This problem was identified by the
,
licensee in the fourth quarter 1992 Current Issues Report, and
!
a more comprehensive corrective action plan was initiated to
1
correct the broader generic' maintenance issues associated with
-
these personnel errors. The inspector noted-that lifted / landed
leads was a top priority for each of the unit QC shops, and
that the broader personnel performance issues were being
addressed by upper management. The inspector concluded that
the licensee's current actions appeared to be appropriate and
will review this item further in a future inspection (Followup
Item 50-528/93-12-10) .
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(2) Heat Exchancer Pluaaino Events
The inspector searched the CATS system for all reports related
'
to heat exchanger work. There were five MNCRs, one CRDR, and
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two Plant Inspection Reports (PIR) written concerning essential
cooling water heat exchanger work. One of the PIRs was for
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incorrectly installing plugs (00545315-M-02) and the other was
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for using the wrong plug map (00545315-M-03). The inspector _
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noted that these problems were immediately corrected.
The inspector reviewed all the events related to mis-plugging.
y
of steam generator (SG) U-tubes.
In 1990 during refueling
4
outage (RF0) 2R2, the licensee discovered that a tube in SG 22
was mis-plugged during the previous RF0, 2RI. The corrective
actions for this event . included developing a lessons-learned
folder for QC inspectors involved with verification of tube
plugging and a second party independent verification using a -
videotape of the tube sheet.
By using the videotape, the
licensee subsequently identified two tubes that were
incorrectly plugged prior to restarting from RF0 2R2.
The
licensee determined that the cause of the mis-plugging was-a
transposition error from the eddy current data to the MNCR.
In
March 1993 during RF0 2R4, the licensee identified another tube '
in SG 22 that had been mis-plugged during the previous outage,
4
2R3. A violation was issued in Inspection Report 50-529/93-11
for the licensee's failure to plug the proper tube despite
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similar failures in the previous outage. The inspector also
noted that the same process of transposing the eddy current
data to the MNCR was used during the current outage and that an
additional problem with properly controlling the tube sheet
maps was identified by licensee QC personnel during the current
Unit 2 outage.
QC personnel identified this problem then they
were performing a review of the circumstances surrounding the
latest mis-plugging incident.
The inspector participated in training course QMZAC-00 for QC
inspectors on independent verification of SG U-tube plugging.
'
This was a new training module developed as part of the
corrective action for the mis-plugged _ tube identified in the
current Unit 2 outage. The inspector noted the training was
positive and helped trainees understand the difficulties of
identifying the proper location of SG tube plugs. The
4
inspector also concluded that the lack of similar training in-
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the past may have contributed to plugging errors.
For example,
all five inspectors'that participated in the training quickly
identified the mis-plugged tube that was discovered during the
current outage. The licensee initiated CRDR 2-3-0222 to
determine the root cause of the latest mis-plugging event. The
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licensee's evalu'ation was not complete at the end of this
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inspection period.
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In summary, the inspector concluded that the previous mis-
plugging events involving the essential cooling water heat
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exchanger were appropriately reviewed by licensee personnel,
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and as discused in Inspection Report 50-529/93-11, the
licensee's previous corrective actions for SG tube mis-plugging
were ineffective.
d.
Observations of OC Inspectors
The inspector observed the conduct of three QC inspectors-during-the
following evolutions and the adequacy of the-associated QCR:
Installation of LDCP 03-LE-HP-042 on valve 3J-HPB-UV-0002, QCR
00603791-002; installation of Raychem in line kit on motor leads to
HPSI "B" pump, QCR 00601082; and installation of multi-stud
tensioner on the Unit 2 reactor vessel, QCR 00584537-002. The
inspector concluded that the QC inspectors were thorough and showed
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good technical knowledge. The inspection efforts included various ,
areas 'and not only the specific hold point / witness points. The
inspector noted that some items identified during the inspection
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activity were not discussed in the associated QCR. The inspector
discussed this with the QC inspector and his supervisor who agreed
that the items should have been noted.
In summary, the inspector concluded that the performance of the
three QC inspectors observed was a strength. However, some QCRs
should have included a discussion on observations that may no't meet-
the criteria of a COTS but warrant documentation so they ca.n be
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evaluated for potential enhancements or problems.
No violations of NRC requirements or deviations were identified.
!
15.
Plant Review Board Activities - Units 1. 2. and 3 (40500)
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The inspector reviewed Plant Review Board (PRB) activities as part-of an
overall evaluation of the effectiveness of the licensee's self-assessment
capabilities.
The inspector examined'PRB meeting minutes from four randomly-selected
meetings. Additionally, the inspector attended several PRB meetings
,
during the last year, including the May 10,'1993, special PRB which met
to address snubber issues (Paragraph 5). The PRB was-found to be focused
on nuclear safety. Members demonstrated good understanding of the issues-
)
and were thorough in their evaluations. The inspector noted that in May
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1993, only six action . items were being tracked by the PRB, 'and that these
items were being closely managed. The inspector also noted that the'PRB
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met much more frequently than required-by licensee procedures or NRC-
regulations.
In the meetings: attended and meeting minutes reviewed, the
PRB addressed most of. the items over which the PRB is required to
'
maintain oversight. The inspector reviewed the membership and determined
that the members met the minimum qualification requirements. The
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inspector concluded that the PRB met regulatory requirements regarding-
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its oversight responsibilities and that it contributed substantially to
nuclear safety.
No violations of NRC requirements or deviations were identified.
16.
Accountability Drill - Units 1. 2. and 3 (82301)
The inspector observed an accountability drill on May 26, 1993, conducted
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to verify the licensees ability to account for all personnel within 30
minutes of declaring a site area emergency (SAE) or above. The inspector
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observed the drill from the Unit 3 operations support building, Unit 2
operations support center, and the central alarm station.
'
The inspector noted that the drill started at approximately 8:00 a.m.
with the announcement of an Alert in Unit 3.
The announcement stated
that there was an alert and that all personnel were to report to their
assembly location. The event was not upgraded to a SAE until
approximately 9:00 a.m., when an announcement was made that
accountability was required and the 30 minute clock was started.
However, security personnel had been working toward-accountability since
the start of the alert and had a significant head start when the actual
call for accountability was made. The report of accountability to the
emergency response coordinator was made at 9:25 a.m., and met the
administrative requirement for a report within 30 minutes of declaring a
SAE.
However,' the inspector concluded that the drill did not adequately
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demonstrate the ability to account for all personnel within 30 minutes of
the initial event notification, since security had been working toward
the accountability report for over an hour. The inspector noted that
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there is no regulatory requirement covering this drill and the failure to
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demonstrate the capability to meet assembly and accountability
requirements is not a violation of regulatory requirements.
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The licensee agreed with the inspector's observations, and committed to
conduct another drill which would start as a SAE and immediately require
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accountability within 30 minutes,
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No violations of NRC requirements or deviations were. identified.
17.
Followup on Previously Identified Items - Units 1. 2. and 3
a.
(Closed) Followup Item 50-528/92-41-01. Reactor Trio due to Known
Defective Neoative Seauence Relay - Unit 1 (92701)
,
3
This item involved weaknesses in the vendor information program
which were identified following the reactor trip on December 8,
1992. CRDR 9-2-0743 was still open as a result of additional
actions which were identified by. the licensee to address these
program weaknesses. The licensee evaluation was completed on
,
March 1,1993, and corrective actions were identified. The
corrective actions are scheduled to be complete.by November 11,
1993. These actions include expanding the scope of vendor technical
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documents, contracting with General Electric for vendor technical
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information support for non-quality related components, revising.
design change procedures to incorporate _ vendor technical manual
requirements, completing the search for missing model numbers,
superseding the first 500 old vendor manuals, and sampling vendor
contacts to determine the adequacy of these corrective actions. One
licensee action taken to address the program vulnerability
identified by the inspector regarding the quality of information:
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obtained by the vendor has been the implementation of a Vendor
Technical Information Exchange computer bulletin board system to
share vendor _ contact information among nuclear utilities. - The
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inspector considered the use of the bulletin board system to- be a
creative application to address the identified weakness. This item
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is closed.
b.
(Closed) Unresolved item 50-528/93-11-01. Feedwater' Isolation Valve
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Doerability Determination - Unit 1 (92701)
This item involved an evaluation of the operability determination of
SGB-UV-132 performed on June 9,1992, after the valve failed to
stroke during a surveillance test designed to demonstrate that the
valve would stroke. The inspector noted that after the second
surveillance test failure, operators considered the valve operable
because the pressure in the accumulator increased to above 5000
psig, and valve could have failed to move because of a failure of-
the logic circuitry, rather than the "M"
four-way valve.
Thq
inspector noted that a portion of the logic ' circuitry is shared by
the test circuit and must function correctly for the valve to
perform its safety function. A review of the history 'of the logic
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circuitry revealed that no failures had been recorded. A review of
the history of the. "M" four-way valve revealed numerous failures.
The inspector concluded that with the evidence available at the time
of the operability determination at 4:16 p.m., the operators no
longer had a basis to have confidence that the' vaive would perform
its safety function. The inspector acknowledged that there was
insufficient information available to conclusively demonstrate the
location of the failure; however, in accordance with Technical
Specifications, a component is only operable when it is " capable of
performing its specified function." Generic Letter 91-18 guidance
states that "the licensee's process should call for immediately
declaring equipment inoperable when reasonable-expectation of
operability.does not exist or mounting evidence suggests that the
final analysis will conclude that the equipment cannot perform its
specified' safety function (s) ."
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During an interview with the shift. supervisor, the inspector noted
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that one aspect of the decision to not declare the valve inoperable
following the second failure of the valve to stroke resulted from
the fact that surveillance testing was deemed to still be in
progress because steps had been added to the surveillance. test
procedure to test the valve separately from the logic circuitry.
The shift supervisor stated that the valve would have been declared
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inoperable if those steps were not present in the surveillance test
procedure and the additional actions had been in a troubleshooting
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work order. The inspector concluded that the operators focused so
closely on following good troubleshooting practices that attention
was diverted away from the operability consideration.
The inspector.
further concluded that the operability determination made at 4:16
i
p.m. on June 9,1992, was incorrect; however, the Technical.
[
Specification Limiting Condition for Operation was met as described
below. Therefore, Technical Specifications were not violated.
1
The licensee declared the valve inoperable at 3:56 p.m. to conduct
the second stroke test. Although the licensee determined that the
valve was operable at 4:16 p.m., the inspector concluded that the
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valve was not operable which resulted in the valve not being made
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operable within four hours as required by Technical Specifications.
However, the valve was restored to an. operable status within the
next six hours (at 1:50 a.m.), just six minutes before the Action
Statement would have required further action to reduce power and
change modes. The inspector further noted that this compliance _ was
not as a result.of planned actions.
The licensee agreed with the inspector's conclusions and committed
to adding additional FWIV technical training and troubleshooting
separate from operability determination training for all licensed
operators during continuing training. .The inspector concludgd that
1
this appeared appropriate. This item is closed.
c.
(Closed) Unresolved Item 50-529/93-11-03. Snubber Testing - Unit 2
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(40500, 61726. and 92701)
3
a
This item was left unresolved in a previous inspection to review the
snubber testing program, the causes of the failures, and the
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licensee's consideration of the Unit 2 snubber failures on Units.1
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and 3.
This item is closed based on the inspector's review,
documented in Paragraph 5.
d.
(Closed) Followup Item 50-530/93-04-03. Reactor Trio Breaker (RTB)
Documentation - Unit 3 (92701)
This item involved the identification of RTB undervoltage trip
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attachment (UVTA) binding. The vendor resolution of this issue was
to modify the UVTA design. When the licensee was asked which
breakers still-had the old style UVTAs installed, the response did
not include the Unit 2 "B"
RTB.
Later this breaker was noted to
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have the old style UVTA. Followup questions revealed the need for
,
the licensee to determine whether this was a material tracking
deficiency or an document review deficiency. -The licensee
investigation determined that the documentation existed; however,
the reviewers did not take sufficient time to thoroughly review the
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existing documentation. Since the most recent work order associated
with this UVTA showed warehouse requisition documentation, the
reviewer assumed that the UVTA obtained from the warehouse was a new
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style device when it was actually an old style device which had been
returned to the warehouse and later reissued. The inspector agreed
with the licensee's conclusion. This item is closed.
,
e.
(0 pen) Followup Item 50-530/93-11-05. Macne-Blast Breaker
!
Inoperability - Close Latch Sprina Interference - Unit 3 (92701).
1
This item involved the inoperability of a safety-related General
Electric (GE) Magne-Blast breaker due to interference of the close
1
latch spring.with the close latch monitoring switch. The inspector
concluded that licensee immediate actions were appropriate.
Condition Report / Disposition Request (CRDR) 3-3-0152 was issued to
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evaluate the inoperability. Three long term actions were
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recommended for consideration by this CRDR. The first was to issue
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a Plant Change Request to annunciate any failure of the breaker
closing springs to charge in the control room. The second was~to
issue an Engineering Evaluation Request to permit the use of torsion
springs on Magne-Blast breakers. The third was for the licensee to
obtain Service Advice and other information regarding the spring
changes from GE. The inspector concluded that these actions
appeared appropriate. This item will remain open pending a review
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of licensee plans with regard to these recommendations.
f.
(Closed) Unresolved Item 50-530/93-11-06. Operator Response to
Turbine Trio - Unit 3 (92701)
,,
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During the response to a turbine trip on April 21, 1993, the ;eactor
operator (RO) tripped one of the reactor trip breakers. -The
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inspector conducted interviews with the R0, control room supervisor
(CRS), operations supervisor, and operations training supervisor to
determine whether the R0's response to the event was appropriate.
'
The inspector noted that procedure 41A0-1ZZ02, " Load Rejection,"
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included steps to verify if. a reactor power cutback (RPCB) has
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occurred.
If a RPCB has occurred, the operators are directed to
monitor pressurizer pressure and to manually trip the reactor if the
high pressure setpoint is approached.
In this. event, the R0
announced he had a RPCB and observed reactor power-decreasing, but
he was'not monitoring pressurizer pressure.
Instead, when a low
departure from nucleate boiling ratio pre-trip on channel
"C" was
H
received (due to the rod motion and change in local neutron flux),
the R0 announced he was trippi.ng the reactor and placed his fingers
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on the manual trip push buttons. The R0 did 'not fully press' the-
.
buttons because he was waiting for concurrence from the CRS. When
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he did not get verbal concurrence, he realized that a trip was not
R
required and withdrew his hand from the push buttons. However,
during this time he inadvertently pressed one of the buttons enough
to trip the breaker.
The inspector discussed this event with the operations training
supervisor.
During simulator training on load rejection, operators
were expected to monitor reactor power (to verify whether a RPCB
occurred) and pressurizer pressure.
If a RPCB did not occur, they
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were expected to manually trip the plant.
Since the simulator did
not model a RPCB at this time, the simulator scenarios had always
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led to a reactor trip. The inspector concluded that the training in
this area was consistent'with the actions directed by the abnormal
operating procedure.
!
The inspector acknowledged that it was noteworthy that numerous
plant systems responded as designed during the event which prevented
a reactor trip. Also, the fact that the. R0 did not trip the plant.
because he waited for concurrence from the CRS demonstrated
excellent teamwork and command and control. However, the inspector
concluded that the R0's response to the event was not consistent
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with the direction in the load rejection procedure to monitor
1
pressurizer pressure, a violation of plant procedures.
The failure to follow plant procedures is not being cited because
the criteria specified in Section VII.B of- the enforcement ' policy
.
were satisfied (NCV 50-530/93-12-11). This event had relatively low
safety significance in that it was conservative to trip the reactor,
'
although an unnecessary reactor trip would have represented a'
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challenge to plant safety systems. The licensee promptly issued
night orders that emphasized the need to be aware of differences
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between the plant and simulator.
In addition, the licensee
subsequently installed the software to model the RPCB in the
simulator, reflecting the restoration of RPCB capability in 1.he
!
Units which was performed on February 3,1993 (see NRC Inspection
Report 50-530/93-04).
Based on this review, this unresolved item is closed.
!
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One non-cited violation of NRC requirements was identified.
18.
Review of Licensee Event Reports (LER) - Unit 3 (92700)
'
Through direct observations, discussion with licensee personnel, or.
review of the records, the following LER was closed.
t
Unit 3
i
92-05,
Revision LO
" Train B Low Pressure-Safety Injection Pump.
Breaker Inoperable"
[
.
This LER reported the Magne-Blast breaker failure ~ discussed in
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Inspection Report 50-530/92-92-31, Paragraph 8.. No additional'
issue were identified in the~ LER. 'This LER is closed.
No violations of NRC requirements or deviations were identified.
19.
Exit Meetino (71707)
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An exit meeting was held on June 1,1993, with licensee management and
resident inspectors during which the observations'and conclusions in this
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report.were discussed. The licensee had no additional comment's. to the '
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inspector's findings. The licensee did not _ identify as . proprietary any
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materials provided to or reviewed by.the inspectors during the
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inspection.
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