ML20140G829
| ML20140G829 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 06/04/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20140G777 | List: |
| References | |
| 50-295-97-02, 50-295-97-2, 50-304-97-02, 50-304-97-2, NUDOCS 9706170096 | |
| Download: ML20140G829 (27) | |
See also: IR 05000295/1997002
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION lli
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Docket Nos:
50-295, 50-304
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License Nos:
Report No:
50-295/97-02, 50-304/97-02
Licensee:
Commonwealth Edison Company
Facility:
Zion Nuclear Plant, Units 1 and 2
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Location:
101 Shiloh Boulevard
Zion, Illinois 60099
Dates:
February 6 through April 2,1997
Inspectors:
A. Vegel, Senior Resident inspector
D. R. Calhoun, Resident inspector
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E. W. Cobey, Resident inspector
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J. Yesinowski, Illinois Department of
Nuclear Safety (IDNS) Inspector
Approved by:
Michael E. Parker, Acting Chief
Reactor Projects Branch 2
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EXECUTIVE SUMMARY
Zion Nuclear Plant, Units 1 and 2
NRC Inspection Reports 50-295/9742; 50-304/97-02
This inspection included aspects of licensen operations, maintenance, engineering, and
plant support. The report covers an eight week period of inspection activities by the
resident staff.
Licensee performance during this inspection period was characterized by fNguent
operational events. Of particular concern was the licensee's continuing inability to
implement timely and effective corrective actions for identified deficiencies and preclude
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their recurrence. Also, operations' performance was characterized by poor control room
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operating practices and inadequate supervision, as demonstrated in both the reactivity
management event and the reactor coolant system loop flow instrumentation being taken
out-of-service without recognizing the Technical Specification (TS) implications. Recurring
1C containment spray pump starting problems were caused by equipment deficiencies, and
in one case,i.1 adequate maintenance activities. Engineering staff follow-up of the slow
start times was not thorough, as reflected in an operability issue assessment not being
performed within the required time frame, in addition, failure to follow radiation protection
procedures continued to be a problem, as evidenced by an unauthorized entry into a locked
Ooerations
The inspectors concluded that the February 21,1997, reactivity management
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event, occurred due to significant weaknesses in command and control, ineffective
communications, and poor reactivity management during shutdown activities. (NRC
Augmented Inspection Team Report 50 295/97-06)
The inspectors concluded that the failure of the control room operators to recognize
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the TS implications of removing safety-related instrumentation from service was
indicative of weak operations staff knowledge of TS requirements. In addition, this
event demonstrated similar weak operating practices, which included poor
command and control, and training deficiencies, that contributed to the occurrence
of the February 21,1997, reactivity management event. (NRC Augmented
Inspection Team Follow-up Report 50 295/97-07, 50-304/97-07)
An event concerning an unexpected high cooldown rate of the Unit 2 pressurizer
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surge line involved poor communications between operators and licensee
management. (Section 01.1)
An apparent violation was identified involving the failure to implement timely and
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effective corrective actions for a previous instance of undetected gas accumulation
h the reactor coolant system in September 1996. Several generic communications
existed which described similar industry events. (Section 01.5)
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An apparent violation was identified involving the failure to have procedures for
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extended operation in cold shutdown conditions and for operating procedures to
include measures to dia.gnose or prevent the undetected accumulation of gas in the
reactor coolant system. (Section 01.5)
Two apparent violations were identified involving the failure to make a four-hour
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non-emergency report and subm.t a written Licensee Event Report within 30 days,
for a condition that alone could have prevented the fulfillment of the safety function
to remove residual heat. (Section 01.5)
Maintenance
Poor electrical maintenance work practices resulted in a maintenance technician
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receiving an electrical shock. (Section M1.1)
The inspectors identified an example of a violation involving the failure to implement
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timely and effective corrective actions for NRC Violation 50-295/93023-01, 50-
304/93023-01, which pertained to the lack of requirements or acceptance criteria
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to evaluate the acceptability of 1C containment spray pump starting delays.
(Section M1.2)
The inspectors identified a violation concerning 1C containment spray pump testing,
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in that, both starting circuits were not tested to ensure that design requirements
were met. (Section M1.2)
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The inspectors identified an example of a violation involving the failure to implement
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timely and effective correctivo actions for a series of equipment failures caused by
over-torquing. (Section M1.3)
Enaineerina
The inspectors identified a violation involving the failure to address the operability
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of the 1C containmut spray pump for a slow starting condition in a timely manner.
(Section M1.2)
Plant Suooort
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The inspectors determined that a poor operating work practice contributed to the
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Unit 1 power reduction, since station personnel allowed the refueling water storage
tank boron concentration to trend toward the TS limit over a six-month period
without taking effective action to correct the trend. (Section R1.1)
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A violation was identified involving the failure to have direct oversight of and
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positive control over each personnel entry into a locked high radiation area.
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(Section R1.2)
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Report Details
Summarv of Plant Status
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Unit 1 was at or near 100 percent power at the beginning of this inspection period. On
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February 10,1997, power was reduced to approximately 45 percent in response to a
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Technical Specification (TS) action statement requirement for a high boron concentration
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in the refueling water storage tank. Power was maintained at approximately 40 percent
until February 21,1997, when the reactor was shutdown in accordance with a TS action
statement for an inoperable containment spray pump. During this shutdown evolution, an
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improper control rod manipulation occurred due to significant weaknesses in command and
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control, ineffective communications, and poor reactivity management during the shutdown
activities. As a result of this event, the plant was placed in a cold shutdown condition and
depressurized. On February 24,1997, an Unusual Event was declared due to the plant
exceeding a TS action statement requirement for reactor coolant system loop
instrumentation being removed from service. On March 11,1997, offsite power and
shutdown cooling was lost due to a trip of the Unit 1 system auxiliary transformer.
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Control room operators promptly restored shutdown cooling, but offsite power was not
restored until March 14,1997.
Unit 2 remained shutdown during the inspection period in support of the 14th refueling
outage. On February 28,1997, an Unusual Event was declared due to an unknown device
being entangled in the offsite feed for the Unit 2 system auxiliary transformer.
Licensee performance during this inspection period was characterized by frequent
operational events. Of particular concern was the licensee's continuing inability to
implement timely and effective corrective actions for identified deficiencies and preclude
their recurrence. Also, operations' performance was characterized by poor control room
operating practices and inadequate supervision, as demonstrated in both the reactivity
marmgement event and the reactor coolant system loop flow instrumentation being taken
out-of-service without recognizing the TS implications. Recurring 1C containment spray
pump starting problems were caused by equipment deficiencies, and in one case,
inadequate maintenance activities. Engineering staff follow-up of the slow start times was
not thorough, as reflected in an operability issue assessment not being performed within
the required ti ne frame. In addition, failure to follow radiation protection procedures
continued to be a problem, as evidenced by an unauthorized entry into a locked high
radiation area.
1. Ooerations
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Conduct of Operations
01.1 Pressurizer Surae Line Unexpected Cooldown Rate
a.
Insoection Scoce (71707)
The licensee observed an unexpected high cooldown rato of the Unit 2 pressurizer
surge line following a reactor coolant pump (RCP) swap. The inspectors
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interviewed engineering and operations personnel and reviewed applicable
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documentation including problem identification form (PlF) 97-0659.
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Observations and Findinos
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On February 6,1997, with the plant in Mode 5 (cold shutdown), the licensee
conducted a swap of RCPs to support maintenance activities on the "B" loop
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isolation valve,2MOV RC8002D. The control room (CR) operators started the 2D
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RCP and secured the 2B RCP. Approximately,25 minutes following this evolution,
the operators noted that the surge line temperature had decreased from 418 to
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216*F. The surge line temperature eventually stabilized at approximately 178'F,
which was the nominal reactor coolant temperature. The CR operators informed
operations management of the surge line cooldown and initiated an investigation
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into the cause of the event. Subsequently, the licensee determined that the cause
of the event was the initiation of backflow through the surge line due to the
switching of RCPs.
Following the occurrence of the event, the operators questioned whether the
unexpected cooldown rate was reportable, due to being a condition outside TS
requirements. Technical Specification 3.3.2, "RCS [ Reactor Coolant System]
Pressurization System Integrity," states that the RCS coo ldown rates shall be
maintained within the limits specified in the Pressure and Temperature Limits
Report, and the pressurizer cooldown rate shall not exceed 200*F per hour. The
licensee subsequently concluded that the TS cooldown limits were not exceeded
based on the following information: (1) the RCS temperature remained stable
throughout the transient; (2) the pressurizer bulk temperature initially decreased
only 3*F; and (3) the surge line temperature decrease of approximately 240*F was
within the design basis. Specifically, Westinghouse Standard 1.3, " Systems
Standard Design Criteria NSSS [ Nuclear Steam Supply System] Design Transients,"
dated April 5,1971, states that the pressurizer surge line nozzle was designed to
withstand a step change of 320*F six times per plant heatup; a total of 1200 plant
occurrences.
Following event occurrence, licensee management informed the inspectors that the
potential for a temperature transient was discussed by the CR operators during the
pre-evolutionary brief. The operators discussed their concem with the onsite
Westinghouse representative and the engineering staff. However, the operators did
not discuss the concern with licensee management until after the event,
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Conclusions
The inspectors concluded that based on the review of licensee's design basis
documentation, TS were not violated and the consequences of the observed high
cooldown rate was minimal. The failure of the CR operators to communicate to
licensee management their concerns with the potential for a temperature transient
to occur while switching RCPs, was reflective of poor communications and
inadequate command and control.
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01.2 Reactivity Manaaement Event
On Febrcry 21,1997, the operations staff performed an unplanned shutdown of
Unit 1 in response to the expiration of a TS limiting condition for operation action
statement concerning the 1C containment spray pump. During the shutdown, the
primary nuclear station operator manipulated control rods in a nonconservative and
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uncontrolled manner. The inspectors concluded that the improper control rod
manipulation occurred due to significant weaknesses in command and control,
ineffective communications, and poor reactivity management during shutdown
activities. An NRC Augmented inspection Team was dispatched to the site to
investigate the event. The results of the inspection were documented in NRC
Augmented inspection Team Report 50-295/97-06 and in NRC Augmented
Inspection Team Followup inspection Report 50-295/97-07, 50-304/97-07.
01.3 Declaration of Unusual Event Due to imoronerly Removina the RCS Loon
Instrumentation from Service
On February 24,1997, the licensee identified that the TS action requirements for
removal of all three RCS loop "A" flow instruments had been exceeded.
Specifically, CR operators removed the flow instruments from service on
February 22,1997, without recognizing the TS implications. As a result, the
licensee exceeded the 48-hour requirement for the plant to be placed in a cold
shutdown condition. The licensee subsequently declared an Unusual Event in
accordance with the General Station Emergency Plan. On February 25,1997, the
plant was placed in a cold shutdown condition and the Unusual Event was
terminated. inspector assessment of licensee performance with respect to this
event was documented in NRC Inspection Report 50-295/97-07; 50-304/97-07.
01.4 Unusual Event Declared for Unknown Device Entanaled in Offsite Feed for the Unit
2 System Auxiliarv Transformer (SAT)
On February 28,1997, the licensee identified an unknown device entangled in the
offsite feed to the Unit 2 SAT. As a result, the licensee declared an Unusual Event
due to the potential for the degradation of plant safety (unknown nature of the
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device) and the fact that outside agencies were called for assistance. The
inspectors concluded that plant management demonstrated the proper safety focus
in their declaration of an Unusual Event and the voluntary activation of the
Technical Support Center. The details of this event were discussed in NRC
inspection Report 50-295/97-08; 50-304/97-08.
01.5 Undetected Accumulation of Gas in the Reactor Vessel
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a.
Insoection Scone (71707 and 37551)
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On March 8,1997, the licensee identified the presence of a gas bubble in the
Unit 2 reactor vessel head. The inspectors interviewed licensee personnel,
reviewed applicable plant procedures and documentation, and evaluated the
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licensee's response to generic information on similar industry events and to a
previous Zion Station event in September 1996.
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Observations and Findinas
Seouence of Events:
On September 1,1996, the licensee identified a gradual decrease in reactor
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vessel water level on Unit 1 as indicated on the reactor vessel level
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indicating system (RVLIS) narrow range channels. The licensee
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subsequently determined that a bubble existed in the reactor vessel head.
On September 2,1996, the licensee vented the Unit 1 reactor vessel head
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and determined that approximately 1,028 gallons of water were required to
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refill the vessel. Subsequently, the licensee initiated a root cause
investigation of the event.
On October 30,1996, engineering personnel approved the root cause
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investigation, including recommended corrective actions, and forwarded it to
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operations for approval.
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On November 4,1996, Site Quality Verification (SOV) personnel initiated an
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unresolved issue corrective action record (CAR) on this event. The purpose
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of the CAR was to track the corrective actions.
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On December 14,1996, the operations manager postponed addressing the
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root cause investigation until following completion of the Unit 2 refueling
outage, which had been in progress since mid-September 1996. This was
due to the fact that Unit 1 was at power and Unit 2 was pressurized with
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reactor coo l ant pumps energized, and in these plant conditions the
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accumulation of gas in the reactor vessel was not an immediate concern.
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On January 8,1997, SOV personnel updated the CAR to recognize that the
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corrective actions were overdue (as of November 30,1996); however, no
action was initiated to address this issue.
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On February 16,1997, the licensee completed Unit 2 depressurization.
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On February 18,1997, the licensee took the Unit 2 reactor vessel level
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indicating system (RVLIS) out-of-service (OOS) per Maintenance Instruction
(MI) 1, " Draining the Reactor Coolant System for Refueling or Maintenance,"
for calibration. Since the Unit 2 refueling outage had been significantly
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extended, instrument maintenance (IM) department personnel wanted to
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zero the surve;!!ance clock on the RVLIS instrumentation prior to the plant
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conditions being thanged.
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On February 19,1997, IM department personnel released the OOS to be
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cleared on Unit 2 RVLIS.
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On February 20,1997, the licensee vented the Unit 2 reactor head.
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On February 21,1997, IM department pe sonnel completed the calibration
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of Unit 2 RVLIS instrumentation. However, the operators did not retum
RVLIS to service since Mi-2, " Reactor Coolant System Fill and Vent," which
was being utilized by the operators to provide guidance in the existing plant
conditions, did not require RVLIS to be in-service until after the reactor
coolant system was solid and pressurized.
On March 3,1997, the licensee completed Unit 1 depressurization.
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On March 7,1997, a Unit 2 nuclear station operator questioned the fact that
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the computer trend plots for pressurizer level and the volume control tank
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(VCT) were not trending in opposite directions as expected. Operations and
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engineering personnel identified that a void in the vessel head could have
been the cause. Subsequently, operators reduced VCT pressure to inhibit
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the transfer of nitrogen from the VCT to the reactor vessel on both units.
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On March 8,1997, the licensee vented the Unit 2 reactor vessel head and
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placed RVLIS in-service. The initial estimate of water to refill the void was
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6500 gallons. The licensee subsequently determined that approximately
6913 gallons were necessary to refill the reactor head void. The estimate
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for reactor vessel level was 588' 4.5" which was 2' 7.5" below the reactor
vessel flange.
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The licensee also vented the Unit 1 reactor head. Approximately 1090
gallons of water were required to fill the void. Review of RVLIS trend data
for Unit 1 indicated a decreasing reactor vessel level for several days.
However, since the operators were not required to monitor RVLIS in these
plant conditions, the declining trend had not been identified. Consequently,
the licensee initiated periodic venting (daily) of the reactor head on both-
units.
The licensee determined that a void would have continued to grow in the
reactor vessel until the surge line tap in the loop (approximately 584' 6"
which is 5' 8" above the top of active fuel) was exposed before pressurizer
levelinstrumentation would have revealed the presence of a void in the
vessel. Once the surge line tap was exposed, gas would have been able to
migrate to the pressurizer and would have resulted in an indicated dcctoase
on pressurizer level instrumentation. However, residual heat remova! (RHR)
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pump suction could have been affected at 584' 8", which would have been
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prior to reaching the point where pressurizer level would have provided
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direct indication of a void in the reactor vessel. In addition, the licensee
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subsequently determined that gas accumulation in the steam generators
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would have prevented the operation of the preferred alternate method of
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reactor coolant system (RCS) cooling due to the obstruction of natural
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circulation flow.
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On March 18,1997, independent Safety Engineering Group personnel
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submitted a revision to the unresolved issue CAR for the September 1996
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event to upgrade the CAR to a Severity Level I finding (a significant
condition which does affect safety).
On March 25,1997, system engineering personnel recognized the ongoing
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accumulation of gases in the Unit 2 reactor vessel and initiated a problem
identification form.
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On March 28,1997, the licensee approved the Level I CAR and initiated a
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troubleshooting plan to address the ongoing gas accumulation on Unit 2.
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On March 29,1997, the licensee sampled the gases being vented on Unit 2.
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The results indicated that air was a source: however, the licensee
questioned the validity of the sample due to the sampling methodology.
On April 3,1997, the licensee revised PT-0, Appendix E 3, " Operating
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Surveillance Checksheet," and issued an Operating Special Procedure (OSP)
!97-014, " Maintaining RCS Conditions in Mode 5."
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On April 4,1997, the licensee established a team to review the
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circumstances surrounding the voiding of both Unit 1 and 2 reactor vessels
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and evaluate the ongoing gas accumulation in Unit 2.
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On April 6,1997, the licensee sampled the gases being vented on Unit 2.
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The results indicated that the composition of the gases was consistent with
the composition of the gases in the VCT.
Untimely Corrective Action for a Previous Event
On September 1,1996, the licensee identified a gradual decrease in reactor vessel
water level on Unit 1, as indicated on the reactor vessel level indicating system
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(RVLIS) narrow range channels. The licensee subsequently determined that a
bubble existed in the reactor vessel head. On the following day, the licensee
vented the Unit 1 reactor vessel head and determined that approximately 1.028
gallons of water were required to refill the vessel.
As a result, the licensee initiated a root cause investigation. The investigation with
recommended corrective actions was approved by engineering and forwarded to
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operations for approval on October 30,1996. On December 14,1996, the
Operations Manager postponed addressing the investigation until following
completion of the Unit 2 refueling outage. This was due to the fact that Unit 1 was
at power and Unit 2 was pressurized with reactor coolant pumps running, and in
these plant conditions the accumulation of gas in the reactor vessel was not an
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immediate concern. However, when the units were subsequently depressurized,
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the investigation and corrective actions were not addressed. Had this investigation
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been aggressively pursued, the March 1997 event could have been prevented. As
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of April 9,1997, the root cause investigation and recommended corrective actions
had not been approved.
The failure to irnplement timely and effective corrective actions for a previous
instance of undetected gas accumulation in the reactor coolant system in
September 1996 is an apparent violation of 10 CFR Part 50, Appendix B, Criterion
XVI (Escalated Enforcement item (EEI) No. 50-295/97002-01, 50-304/97002-01).
Poor Evaluation and imolementation of Generic Industry information
Generic communications regarding similar industry problems and the licensee's
resulting actions are described below. The licensee failed to adequately evaluate
and address this information, and hence the licensee's program to review generic
industry information did not prevent the March 1997 event.
NRC Information Notice (IN) 94-36, " Undetected Accumulation of Gas in Reactor
Coolant Systern," was issued on May 24,1994. This IN described an event that
was similar to the events that occurred at Zion Station. The licensee's evaluation
of this IN in August 1994 was inadequate,in that, it did not address the following
aspects of the IN: (1) the susceptibility of monitoring reactor coolant system
inventory solely based on pressurizer levelinstrumentation; (2) operator knowledge
of RVLIS; and (3) a lack of thorough evaluation of previously published information
on similar events, in addition, the corrective actions that were designated were not
completely implemented as of April 9,1997.
Nuclear Safety Advisory Letter (NSAL)94-013, " Nitrogen Accumulation in RCS
During Mode 5 Operation," was issued on June 16,1994. The licensee's
evaluation of NSAL 94-013 was closed in reference to the evaluation being
conducted for NRC IN 94-36.
NRC IN 96-37, " inaccurate Reactor Water Level Indication and Inadvertent
Draindown During Shutdown," was issued on June 18,1996. This IN described an
event that was somewhat different from the subsequent gas accumulation events
at Zion. However, botr. were similar, in that, the loss of reactor coolant system
inventory went undetected due to the sole reliance on pressurizer level
irotrumentation, which in some cases provides inaccurate reactor vessel water level
indication. The licensee's evaluation of this IN on August 7,1996, stated that
RVLIS was not utilized for levelindication, and it did not address the susceptibility
of relying only on pressurizer levelinstrumentation to monitor the reactor coolant
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system inventory, in addition, the evaluation specified system engineering review
for concurrence; however, system engineering personnel never reviewed this IN.
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As a result, no corrective actions were designated.
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NRC IN 96-65, " Undetected Accumulation of Gas in Reactor Coolant System and
Inaccurate Reactor Water Level Indication During Shutdown," was issued on
December 11,1996. The licensee's evaluation indicated a lack of complete
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understanding of the reactor coolant system levelinstrumentation. Specifically, the
evaluation indicated that RVLIS was capable of providing actuallevelindication.
However, the licensee concluded that the inaccurate reactor vessel level
instrumentation concern discussed in the IN was not on issue because refueling
level instrumentation (which indicates a level based on a reference to the
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pressurizer) was available. Although this evaluation was conducted on
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February 24,1997, when the plant conditions existed for the undetected
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accumulation of gas to occur on Unit 2, the licensee did not recognize or question
the need for immediate corrective actions. The resulting recommendations were
not implemented prior to the March 1997 event.
inadeouate Procedures
The inspectors determined that no operating procedure existed which provided
guidance on maintaining the plant in Mode 5 (cold shutdown) for an extended
period of time. Consequently, operators were using Maintenance Instruction (MI) 2,
" Reactor Coolant System Fill and Vent," to provide operating guidance for the
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existing plant conditions. The purpose of Mi-2 was to describe the operations
necessary to control the filling and venting of the primary system. As a result,
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operators did not place RVLIS in-service following completion of instrument
calibration on February 21,1997, since Mi-2 did not specify RVLIS to be placed in-
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service until after the plant was solid and pressurized. Without RVLIS in-service, no
direct indication of reactor vessel water level was available to the operators, which
prevented the timely identification of gas accumulation in the reactor vessel.
In addition, the inspectors noted that none of the operating procedures utilized
during cold shutdown conditions included measures to diagnose or prevent the
undetected accumulation of gas in the reactor coolant system. Specifically:
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PT-0, Appendix E-3, " Operating Surveillance Checksheet" (Nuclear Station
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Operator's shiftly surveillance while in Mode 5) did not include measures to
identify the accumulation of gas in the reactor vessel head, such as
monitoring RVLIS. Consequently, when RVLIS was trending downward on
Unit 1 in early March 1997, operators failed to identify that a void was being
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created in the reactor head.
Abnormal Operating Procedure (AOP) 6.3, " Loss of RHR [ Residual Heat
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Removal] Shutdown Cooling," relied on pressurizer levelinstrumentation for
determining reactor vessel water level. Pressurizer level was not an accurate
indication of reactor vessellevel under the voiding conditions.
Consequently, had the accumulation of gas continued to the point where
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reactor vessel level was below 584' 8" (the point below which shutdown
cooling could have been affected), Abnormal Operating Procedure (AOP) 6.3
would not have identified the cause of the loss of shutdown cooling to have
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been low reactor vessellevel. If shutdown cooling was not able to have
been restored, then AOP 6.3 would have directed alternate cooling to havo
been established. Alternate cooling methods were listed in order of
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preference beginning with RCS cooling using steam generators. However,
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the obstruction of natural circulation flow by the accumulation of gas in the
steam generator U-tubes could have prevented RCS cooling by this altcrnate
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method. As reactor vessel water level continued below 584' 6" (the point
below which pressurizer levelinstrumentation provided direct indication of a
gas bubble in the reactor vessel), AOP 6.3 would have directed the addition
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of inventory to raise reactor vessellevel. Therefore, due to the failure of
AOP 6.3 to utilize RVLIS for determining reactor vessel water level, the
recovery from a loss of shutdown cooling would have been significantly
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complicated.
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The failure to have procedures for extended operation while in cold shutdown
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conditions and for operating procedures to include measures to diagnese or prevent
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the undetected accumulation of gas in the reactor coolant system is an apparent
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violation of 10 CFR Part 50, Appendix B, Criterion V (eel No. 50-295/97002-02,
50-304/97002-02).
Lack of Ooerator/Encineerina Knowledae on the Ooeration of RVLIS
Based on review of the licensee's evaluation of several generic communications
that pertained to this issue and interviews of senior reactor operators, reactor
operators, operating procedure writers, and engineering personnel, the inspectors
concluded that the licenses staff lacked an understanding of the operation of
RVLIS. In addition, the licensee did not demonstrate an appreciation for the
importance of monitoring RVLIS while in cold shutdown conditions. The inspectors
determined that operators only received training on the operation of RVLIS during
the systems phase of initial license training. In addition, operator training had not
covered the use of RVLIS in cold shutdown conditions. During one training cycle,
NRC IN 94-36 and the associated revision of the Mi-1 series procedures were
covered. This revision included the addition of a precaution that indicated under
certain plant conditions nitrogen could have accumulated in the reactor vessel head
and steam generator tubes to the point where natural circulation was inhibited
and/or gas binding of ths RHR pumps may have occurred. However, this training
was not sufficient to raise the operators sensitivity to the importance of monitoring
RVLIS while in cold shutdown conditions.
Failure to Reoort Event
The inspectors identified that the licensee failed to make the appropriate prompt
report to the NRC following the identification of the undetected gas accumulation in
the reactor vessel head on March 8,1997. Specifically,10 CFR Part 50.72(b)(2)(iii)(B) requires a four-hour event report be made for any event or
condition that alone could have prevented the fulfillment of the safety function to
remove residual heat. Also,10 CFR Part 50.73(a)(2)(v)(B) requires a written
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Licensee Event Report be submitted within 30 days from the discovery of the event
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for any event or condition that alone could have prevented the fulfillment of the
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safety function to remove residual heat. This condition (undetected gas
[
accumulation in the RCS) could have potentially caused the loss of both trains of
shutdown cooling prior to the gas bubble reaching the size where pressurizer level
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would have provided direct indication of reactor vessel water level. Additionally,
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the accumulation of gas in the steam generators would have prevented the
preferred alternate method of RCS cooling due to the obstruction of natural
circulation flow.
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The failure to make a four-hour non-emergency report and submit a written
t.
!
Licensee Event Report within 30 days, for a condition that alone could have
prevented the fulfillment of the safety function to remove residual heat, are
apparent violations of 10 CFR Part 50.72(b)(2)(iii)(B) and 10 CFR Part
'
50.73(a)(2)(v)(B) (eel No. 50-295/97002-03, 50-304/97002-03 and eel No. 50-
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295/97002-04, 50-304/97002-04 respectively).
Site Quality Verification (SOV) and Manacement Oversiah!
SQV and management involvement in addressing the up iotected gas accumulation
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in the reactor vessel events was fragmented and protre aced, which resulted in
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untimely corative actions for significant conditions adverse to quality. The
untimely resp ose was reflected in: (1) the delay 'a reviewing and approving the
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root cause inn 'tigation and recommended corsctive actions for the September
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1996 event, wluch was not approved as o' April 9,1997;(2) SQV's acceptance
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that the root cause investigation and recommended corrective actions for the
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September 1996 event were overdue and were not being actively pursued in
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January 1997; (3) the delay in providing the operators an approved procedure
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governing plant operation in cold shutdown for an extended period of time; (4) the
ten day delay in reviewing and approving the Severity Leveli Corrective Action
Record submitted by the independent Safety Engineering Group; (5) the delay in
,
approving and implementing a troubleshooting plan to address the ongoing gas
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accumulation in the Unit 2 reactor vessel; and (6) the delay in establishing a team
of personnel to evaluate the circumstances surrounding the March 1997 event and
the ongoing gas accumulation on Unit 2.
Safety Consecuences
Although there were no actual consequences of these events on the health and
safety of the public or plant staff, the inspectors concluded that these events
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involved potential safety consequences. The identification of the gas accumulation
)
in the reactor vessel was an example of an operator's questioning attitude towards
unexpected, conflicting it'dications. However, it was fortuitous that the gas
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accumulation was detected prior to it reaching a size which could affect RHR
system operation. Specifically, given the appropriate plant conditions and the
operating practices at that time (not requiring RVLIS to be in-service while in cold
shutdown and, if in-service, not monitoring RVLIS), the potential existed for a void
i
to have been created in the reactor vessel that could have impacted decay heat
removal prior to being detected by pressurizer levelindication. Additionally, the
accumulation of gas in the steam generators would have prevented the preferred
2
altemate method of RCS cooling due to the obstruction of natural circulation flow.
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c.
Conclusions
The inspectors concluded that the undetected gas accumulation in the reactor
coolant system was due to: (1) untirnely corrective action for a previous event:
(2) poor evaluation and implementation of generic industry information; (3) lack of
procedural guidance for extended operation in cold shutdown conditions; (4)
operating procedures utilized during cold shutdown conditions did not include
measures to diagnose or prevent the undetected accumulation of gas in the reactor
coolant system; and (5) operations and engineering personnel did not have an
understanding of the importance of monitoring RVLIS while in cold shutdown
conditions.
II. Maintenance
M1
Conduct of Maintenance
M1.1 Electrician Received Electrica' Shock
a.
Insoection Scoce (62707)
A contractor electrician received an electrical shock while troubleshooting a service
building heating, ventilation,.and air conditionir,g unit (HVAC), OSV078. The
inspectors reviewed the licensee's documentation of the event including problem
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identification form (PlF) 97-0829.
b.
Observation and Findinas
On February 16,1997, a contractor electrician was performing troubleshooting of
the service building HVAC unit, OSV078. The electrician performed the work under
a personal out-of-service. While troubleshooting, the electrician placed his hand
into a control panel with exposed conductors and received an electrical shock. The
electrician was transported to a local hospital for examination and was
subsequently released.
c.
Conclusion
As previously documented in NRC Inspection Report 50-295/96-20; 50-304/96-20,
poor electrical maintenance work practices resulted in the inadvertent actuation of
two valves in the containment spray system. The occurrence of the electrician
receiving an electrical shock on February 16,1997, was another example of poor
electrical maintenance work practices which could have significant personnel safety
consequences. The inspectors were concerned that previous corrective actions to
address poor work practices in the vicinity of energized components have not been
effective in improving performance in this area. At the end of the inspection period,
,
the licensee was in the process of developing corrective actions to address the
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February 16,1997 event.
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M1.2 1C Containment Sorav (CS) Pumn Testino
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s.
Insoection Scope (627071
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The inspectors reviewed the circumstances related to problems encountered during
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1C CS pump testing. The inspectors reviewed relevant 1C CS pump surveillance
documentation, PlF 97-0798, and operability assessment #ER9701035. In
addition, the inspectors interviewed licensed operators, the system engineer, design
!
engineers, and licensee management.
'
b.
Qhservations and Findinas
During this inspection period numerous problems were experienced with the 1C CS
pump. The 1C CS pump is one of three CS pumps per unit, but, unlike the other
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motor driven pumps, the 1C CS pump is driven by a diesel engine. The diesel
engine is started by one of two independent starting circuits, with each circuit
receiving power from a dedicated battery. Each battery also has a dedicated
battery charger which maintains the associated battery' replenished.
On February 11,1997, the 1C CS pump was taken OOS for maintenance. Work
performed included motor control center (MCC) inspections and fuel oil day tank
level indication calibration. The maintenance on the level indication required fuel oil
day tank draining and refilling.
On February 12,1997, during performance of the post maintenance test in
accordance with PT-6C-ST, " Containment Spray C Pump System Test and
Checks," Revision 5, the operators noted a delay in the stort time of the pump.
The operators observed that the pump took more than five seconds to start.
However, since the surveillance procedure did not require the pump start to be
timed, the exact start time delay was not recorded. The delay in the 1C CS pump
start was caused by the engine not being able to start on the selected battery, in
this case, the #2 battery. The enginn subsequently did start on the alternate
battery (#1) due to an automatic ratcheting device in the start circuitry. The
automatic ratcheting device is designed such that when one battery has an
undervoltage condition, the circuit automatically transfers to the remaining battery
bank and locks out the degraded battery. The lockout can be manually reset using
a reset push button.
Following the observed slow start the operators secured the pump and started it a
second time as required by the surveillance procedure. Again, the operators
observed a similar start time delay. The diesel tried to start on the degraded
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battery again because an operator had apparently reset the locked out battery.
Operators eventually secured the pump and requested assistance from the system
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engineer in evaluating pump operability. The system engineer subsequently
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determined that the start delay was caused by the #2 battery being partially
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discharged and not capable of starting the diesel. The battery had been
inadvertently discharged during maintenance activities on the MCCs since the OOS
in support of the work de-energized the battery charger.
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After discussions with the system engineer, the shift engineer declared the 1C CS
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pump operable based on: (1) Zion Operability Determination Manual (ZODM)
CS-3.3, Revision 7, which required only 1 of 2 batteries to be operable, and (2)
PT-6C-ST, which did not have a starting time acceptance criteria. Therefore, since
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PT-6C-ST was satisfied, the 1C CS pump was considered operable.
t
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On February 14,1997, the system engineer determined that a formal operability
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evaluation was needed to address the time delay caused by the ratcheting of the
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starting circuit. Operability assessment #ER9701035 was initiated to document
engineering's conclusion that the 1C CS pump was operable based upon the results
!
of previously completed calculations. Specifically, engineering calculation 22S-B-
006M-080, which was performed to justify a slow start of the 2C CS pump,
allowed for a CS pump start delay of 18.3 seconds before the analyzed time
requirement to respond to a postulated loss of coolant accident (LOCA) would be
exceeded. On February 16,1997, based on re-evaluation of the operability
assessment, the licensee initiated an Operability Isex Form, Appendix B, to further
evaluate and conect the #2 battery degraded condition.
On February 19,1997, the licensee declared the 1C CS pump inoperable during
performance of PT-6C-ST when the pump required approximately 60 seconds to
start. Upon declaring the 1C CS pump inoperable, the licensee entered TS 3.6.1.C
and D limiting condition for operation (LCO) action requirements which required the
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pump to be restored within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the plant be placed in hot shutdown within
an additional four hours. The operators documented in the control room logs that
the pump was inoperable at 10:40 a.m.; however, the pump was actually
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inoperable at 10:20 a.m. The discrepancy was subsequently noticed on
February 21,1997, by the shift engineer and the discrepancy was corrected prior
to the LCO action requirements being exceeded.
The licenses subsequently determined that the cause for the slow start of the 1C
CS pump was clogging of the fuel oil filter. The licensee flushed the fuel oil day
tank and removed all debris from the tank. At the end of this inspection period, the
cause of the fuel oil filter fouling was still under investigation.
.
On February 21,1997, maintenance personnel overfilled the day tank causing a fuel
oil spill. The cleanup of the spill delayed restoration of the CS pump to service.
Following completion of maintenance activities, the pump was retested in
accordance with PT-6C-ST. Durin0 the test, the CS pump experienced a slow start
time of approximately 20 seconds. The licensee subsequently determined that the
I
start delay was caused by bumt contacts on a starter circuit relay. The licensee
replaced the affected relay and the starting solenoids.
The licensee subsequently retested the 1C CS pump satisfactorily at 1:58 p.m. on
February 21,1997. However, the pump could not be declared operable since the
system was stillin the test configuration. As a result, operators subsequently
tripped the reactor at 2:15 p.m., five minutes prior to the expiration of the LCO
action requirements. As discussed in the Augmented Inspection Team
(AIT)lnspection Report 50-295/97-06 and AIT Followup Report 50-295/97-07;
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50-304/97-07, the CS maintenance and testing activities directly contributed to the
plant shutdown and reactor trip in which the improper control rod manipulation
event occurred.
The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) for CS
start times with respect to main steam line break (MSLB) and LOCA analyses. The
UFSAR LOCA analysis requires the initiation of CS flow to the spray nozzles within
110 seconds after the containment high high pressure setpoint is reached. The CS
pump start time delay caused by the ratcheting of the starting circuit did not result
in the required 110 second actuation time being exceeded. Concerning the CS
system response time required in the MSLB analysis, the inspectors review of
supporting calculations was in progress at tne end of the inspection period.
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Pending inspector review of the licensee's MSLB analysis calculations to determine
the impact of the 1C CS ratcheting time delay on the ability of the CS system to
perform its design function, this item is considered an inspector Follow-up item (IFl
50-295/97002-05).
The inspectors reviewed the applicable CS pump test procedures including PT-6C-
ST-RT, " Containment Spray C Pump System Tests and Checks," Revision 8. The
inspectors determined that this test, which was utilized to obtain CS pump start
time data once every 18 months, was inadequate. Specifically, the test only
required response time data to be obtained for one of the two engine starting
circuits. As a result, the potential existed that the most conservative starting time
was not recorded. The starting time obtained by this test was used as an input for
Technical Staff Surveillance Procedure 15.6.136/146, " Matrix Procedure for Train B
Reactor Protection and Safeguards Response. Time Testing Un'it 1." This matrix
procedure was utilized to verify that the system response time was within the
I
bounds of the analyzed design limits.
Also during review of 1C CS pump test procedures PT-6C-ST and PT-6C-ST-RT, the
inspectors identified that acceptance criteria for the pump start time was not
delineated in the procedures. The inspectors were concerned that PT-6C-ST did not
require the starting time to be measured and neither procedure enntained
acceptance criteria for starting times. Consequently, starting time delays would not
have been identified or analyzed.
inspectors had previously identified the absence of starting time criteria in
procedure PT-6C-ST in Novumber 1993, as documented in Notice of Violation
50-295/93023-01, 50-304/93023-01. The licensee's corrective actions included
increased training of engineering personnel on operability daterminations and
revision of the ZODM. However, as reflected in the inspectors identifying the same
FT-6C-ST inadequecies on February 21,1997, the licensee's corrective actions
wero inadequate.
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During the course of inspection follow-up of the 1C CS pump failures, the
inspectors requested a copy of the Appendix B to operability assessment
- ER9701035 which was initiated on February 16,1997. During the month of
,
March, the inspectors made numerous additional requests for the completed
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Appendix .B without success. On April 3,1997, the inspectors were informed by
the licensee that the Appendix B had not been approved by the Operating Engineer
until March 25,1997. ZODM-0, " Operability Determination Manual," Revision 9,
requires that Appendix B, " Operability issue Form," shall be completed within five
days from initial discovery of the deficiency. The licensee exceeded the prescribed
completion time for the Appendix B operability assessment by approximately 36
days.
c.
Conclusiong
The inspectors concluded that the recurring 1C CS pump starting problems were
caused by equipment material condition deficiencies and poor control of
maintenance activities. ~ Spocifically, an OOS in support of maintenance activities
resulted in a battery being unexpectedly discharged, which caused the 1C CS slow
Wrt on February 12,1997. Once the starting delays were identified, investigation
ano P;1 solution of the problem.s were delayed by poor maintenance practices and
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untimely engineering evaluation of conditions. These ~ weaknesses were reflected in
the occurrence of the fuel oil spill and the significant delay in completing Appendix
B of the operabiHty assessment. In addition, the inspectors identified weaknesses
in the 1C CS test procedures, some of which were previously identified but never
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corrected.
As a result of the inspectors review of CS pump testing activities, several violations
I
of NRC requirements were identified. Periodic test PT-6C-ST-RT " Containment
Spray C Pump System Tests and Checks" was inadequate to demonstrate that the
CS pump would have performed satisfactorily in service; in that both battery
starting circuits were not tested, contrary to the requirements of 10 CFR Part 50,
Appendix B, Criterion XI, " Test Control" (50-295/97002-06, 50-304/97002-06).
In addition, the inspectors identified that licensee corrective actions were
inadequate for a previous NRC violation concerning PT-6C-ST not having any
requirements or acceptance criteria to evaluate starting time delays during CS
testing. The failure of the licensee to correct the previously identified testing
inadequacies was considered a violation of 10 CFR Part 50, Appendix, B, Criterion
XVI, " Corrective Actions" (50-295/97002-07a, 50-304/97002-07a).
The failure of the licensee staff to complete the Appendix B for the operability
assessment of the 1C CS pump starting time delay, that occurred on February 12,
within five days as required by ZODM-0, " Operability Determination Program," was
considered a violation of 1'O CFR Part 50, Appendix B, Criterion V, " Instructions,
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Procedures, and Drawings" (50-295/97002-08).
!
!
M1.3 Ineffective Corrective Actions for Several Over-torauino Events
a.
Insoection Scone (62707)
t
On February 11,1997, when the 2A emergency diesel generator (EDG) was
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returned to service following maintenance activities, the licensee discovered the
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lube oil cooler channel head was cracked. On February 28,1997, during
reassembly of the OB fire pump discharge piping, the piping connection between
the diesel engine fire pump and the discharge check valve cracked. The inspectors
reviewed the applicable work instructions and evaluated the licensee's corrective
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actions.
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b.-
Observations and Firidinas
On February 11,1997, when the 2A EDG was returned to service following
i
maintenance activities, the lube oil cooler channel head was discovered to have
been cracked. The licensee determined that during reassembly of the lube oil
cooler, the service water to lube oil channel head flange had been over-torqued.
Maintenance procedure P/DG002/3 3, " Diesel Generator Lube Oil Cooler
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Maintenance," Revision 4, specified the torque to have been 131 ft-lbs: however,
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since the flange was a cast iron raised face flange, the correct torque could have
been 47 ft-lbs. As a result of this event, the licensee replaced the cracked channel
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head, revised maintenance procedure P/D002/3-3, and reduced the actual torque on
the fasteners for both the jacket watet and lube oil cooler channel heads on each of
the other EDGs.
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A similar event occurred on the 2B EDG lube oil cooler channel head in
February 1995 following replacement of the lube oil cooler service water isolation
valve,2SWOO33. The valve was replaced in accordance with Work Request No.
!
950006910-01. The licensee attributed the cause of the failure to have been
flange misalignment, .but did not recognize that the flange was over-torqued.
l
Consequently, the licensee's corrective actions were not sufficient to preclude the
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subsequent failure of the 2A EDG lube oil cooler channel head on February 11,
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1997.
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In addition, the inspectors noted that during the past year, the licensee experienced
i
at least two other equipment failures due to the equipment having been over-
torqued. On June 20,1996, the 1 A condensate pump discharge flange cracked
during reassembly; and, on July 31,1996, the OC cribhouse sump pump discharge
check valve flange cracked during reassembly. In both of these instances, the
joints were raised face cast iron, The licensee repaired the equipment and
incorporated each uf the instances into mechanical maintenance lessons learned in
the case of the 1 A condensate pump, the licensee subsequently revised the
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procedure to include the correct torque value,
On February 28,1997, during reassembly of the OB fire pump discharge piping in
accordance with Work Request No. 940037310-01, the piping connection between
the diesel engine fire pump and the discharge check valve cracked due to being
over-torqued. The licensee's investigation concluded that the flange had been
torqued to 370 ft-lbs; however, since the flange was raised face cast iron, it should
have been torqued to 76 ft-lbs.
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In response to a series of equipment failures on February 29,1997, caused by
over-torquing, the licensee issued a stop work for mechanical maintenance on
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February 28,1997, pending the development and implementation of corrective
actions. Prior to allowing the mechanical maintenance department to return to
work, the licensee completed short-term corrective actions which included:
(1) training on maintenance procedure P/M014-1N, " Safety Related and Section XI
Code Mechanical Closure Report"; (2) the verification of correct torque values in
mechanical maintenance procedures; and (3) the implementation of a torque
verification form to be completed by the first line supervisnr for each work activity
prior to reassembly. Additional long term corrective actions included the
verification of torque values for all maintenance procedures and work packages
conducted during the current Unit 2 outage (scheduled completion date of April 30,
1997) and the completion of a training course for mechanical maintenance
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personnel on the identification of flange and fitting materials, flange configurations,
closure procedures, and the use of torque wrench adapters and extensions
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(scheduled completion date of December 31,1997).
c.
Conclusions
The inspectors concluded that in the case of the 2B EDG failure in February 1995, a
significant condition adverse to quality, the causes were not effectively determined
i
and corrective actions taken to preclude recurrence were inadequate, as evidenced
l
by the subsequent failure associated with the 2A EDG on February 11,1997. This
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is considered an example of a violation of 10 CFR Part 50, Appendix B, Criterion
XVI, " Corrective Actions" (50-295/97002-07b, 50-304/97002-07b). In addition,
the corrective actions taken for several failures of nonsafety-related equipment with
!
the same cause (over-torquing of cast iron raised face flanges) were not effective at
preventing a subsequent failure of a safety-related piece of equipment.
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III. Enoineerina
l
E1
Conduct of Engineering
E1.1
Notification of inocerable Enaineered Safety Feature Busses Due to Breakers in an
Unaualified Seismic Position.
On February 13,1997, the station made a one hour non-emergency report in
accordance with 10 CFR Part 50.72(b)(1)(ii)(A) after determining that several 4KV
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and 480V buses were inoperable because their associated breakers were not in a
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seismically qualified position. The licensee's breaker operating practices allowed
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the breakers to be in a removed / racked out position, which is an unqualified
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position. The licensee's immediate corrective actions included placing all breakers
!
in a seismically qualified position. This issue is considered an Inspection Follow-up
item (50-295/97002-09, 50-304/97002-09) pending NRC review of the licensee's
long-term corrective actions.
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E8
Miscellaneous Engineering issues
1
E8.1
(Closed) Unresolved item 50-295/96020-07. 50-304/96020-07: Review the
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consequences of the TS required boron concentration samples with the residual
heat removal (RHR) sample valves wired incorrectly.
,
Technical Specification 4.2.1.A.2 requires that when reactor coolant system
pressure is less than 200 psig, boron concentration in the operating RHR loop be
used to verify shutdown margin at least once a shift. The inspectors reviewed the
licensee's root cause investigation report, No. 304-200-97-CAOS-0097, the RHR
system configuration, and the previous year's boron concentration sample results.
The inspectors concluded that even though the RHR sample valves had been wired
incorrectly since original construction, the configuration of the RHR system was
such that both trains were normally cross-connected and sufficient mixing was
available for a boron concentration sample from either train to be a representative
sample for the operating loop. In addition, the inspectors reviewed previous sample
results and did not identify any abnormalities. This Unresolved item is closed.
IV. Plant Suonort
R1
Radiological Protection and Chemistry (RP&C) Controls
R 1.1 Hiah Boron Concentration in the Refuelina Water Storaae Tank (RWST)
a.
Insnection Scoce (71750)
On February 10,1997, the licensee reduced power on Unit 1 after entering a
shutdown LCO as a result of RWST in. con concentration being greater than the TS
limit. The inspectors reviewed RWST boron sample results over the last nine
months and interviewed personnel from the operations and chemistry departments.
b.
Observations and Findinas
On February 8,1997, RWST boron concentration sample results indicated 2600
ppm. Technical Specification 3.8.1.F specifies RWST boron concentration to be
between 2400 and 2600 ppm. Operators added approximately 9000 gallons of
primary water to the RWST and placed the RWST on recirculation for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior
to obtaining a subsequent sample. On February 10,1997, the post recirculation
sample indicated a boron concentration of 2605 ppm, which was greater than the
TS limit. As a result, the licensee commenced actions to place Unit 1 in hot
shutdown as required by TS. After recirculating the RWST a second time using one
of the containment spray pumps, the licensee obtained acceptable boron sample
results and terminated the plant shutdown.
The licensee subsequently determined that the cause for the high boron
concentration samples was stratification of the water in the RWST. As a result of
insufficient circulation, the boron tended to concentrate on the lower portions of
the tank, which resulted in the high sample results, even after significant dilutions.
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The inspectors were informed by the licensee that the RWST boron concentration
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sample results had been trending toward the upper TS limit since October 1996.
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However, actions taken were ineffective to stop the trend.
C.
Conclusion
i
The inspectors concluded that the poor operating practice of allowing the boron
concentration to trend towards the upper TS limit without taking appropriate action
resulted in the licensee unnecessarily placing Unit 1 in an LCO and contributed to
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the occurrence of the Unit 1 power reduction. Station personnel did not effectively
address the cause for the unexplained rise in boron concentration sample results
until the TS limit was exceeded.
R1.2 Unauthorized Entry into Locked Hiah Radiation Area (LHRA.]
a.
Insoection Scoce (7125.Q1
The licensee identified that s maintenance mechanic made an unauthorized entry
into a locked high radiation area. The inspectors interviewed licensee personnel and
reviewed applicable procedures and documentation.
b.
Observations and Findinas
On April 1,1997, radiation protection personne! issued maintenance contractors
the key for the Unit 1 vertical pipe chase (VPC) room which was posted as a LHRA,
an area with a dose rate greater than 1,000 mrem /hr. Radiation protection
personnel briefed the contractors on the LHRA access requirements before issuing
the key to one of the contractors who was designated as the key custodian.
Subsequently, custody of the key was transferred to another contractor, who was
also trained on LHRA access controls. In addition, the contractors had also been
informed of the LHRA access requirements by their foreman during a pre-job
briefing.
Upon aniving at the job site, the contractors propped open the VPC room door to
accomplish welding activities. In accordance with Zion Administrative Procedure
(ZAP) 610-02, "High Radiation Area Access Control," Revision 3, the key custodian
was required to provide direct oversight of and positive control over each personnel
entry into the area. However, he became involved in other work activities which
distracted him from providing continuous control over entrance into the VPC. As a
result, a maintenance mechanic entered and exited the VPC without being observed
by the key custodian. The mechanic was in the VPC for approximately five minutes
and received a dose of 2 mrem.
The maintenance mechanic had previously been in the Unit 2 VPC, which was not
posted as a LHRA, and was entering the Unit 1 VPC to verify valve packing
information. The maintenance mechanic entered the VPC area since the door was
open and he did not see the radiological postings which would have prevented him
from entering.
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On April 2,1997, the maintenance mechanic contacted the radiation protection
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(RP) department to question the Unit 2 VPC access controls. As a result, the
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mechanic's unauthorized entry into the Unit 1 VPC was identified. Radiation
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Protection personnel informed RP management of the problem; however, RP
management failed to inform senior plant management of the unauthorized entry
until April 3,1997. The licensee's immediate corrective actions included: (1)
initiating a PlF; (2) performing a preliminary investigation; (3) restricting the key
custodian from the radiological controlled area; and (4) issuing a standing order on
April 3,1997, which required RP personnel to be the key custodian and control
access to locked high radiation areas.
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c.
Conclusion
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The inspectors concluded that the licensee's preliminary investigation was
appropriate; however, RP management did not notiny senior plant management of
.
the unauthorized entry into a LHRA in a timely manner.
ZAP 610-02, "High Radiation Area Access Control," Revision 3, requires that
entrances to accessible high radiation areas with radiation levels greater than
1,000 mrem /hr be locked or be controlled by a key custodian who has direct
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oversight of and positive control over each personnel entry into the area. The
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failure of the key custodian to have direct oversight and positive control of
personnel entry into the Unit 1 VPC, which was a locked high radiation area, is
considered a violation of Technical Specification 6.2.2.B (50-295/97002-10).
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V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on April 9,1997. The licensee
acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
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X3
Management Meeting Summary
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The Deputy Executive Director for Regulatory Programs and the Director for Nuclear
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Reactor Regulation toured the Zion facility and met with licenseo management on
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March 26,1997.
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Partial List of Persons Contacted
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J. Mueller, Site Vice President
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K. Dickerson, Executive Assistant
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R. Godley, Regulatory Assurance Mainager
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M. Weis, Support Services Director -
R. Zyduck, Site Quality Verification Director
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T. Patterson, Unit 1 Plant Manager
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R. Starkey, Unit 2 Plant Manager
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K. Hansing, Unit 1 Operations Manager
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G. Vanderheyden, Unit 2 Operations Manager
M. Schimmel, Unit 2 Maintenance Manager
B. Giffin, System / Component Engineering Manager
R. Budowle, Site Quality Verification
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M. Madigan, Site Ouality Verification
W. Stone, Regulatory Assurance Supervisor
C. Allen, Regulatory Assurance
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D. Beutel, Regulatory Assurance
NaC
M. Dapas, Chief, Reactor Projects Branch
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List of Insoection Procedures Used
Engineering
lP 62707
Maintenance Observation
Plant Operations
Plant Support Activities
List of items Ooened, Closed, and Discussed
Onened
50-295/304-97002-01
EEi
Failure to imp!ement timely and effective corrective
action for a previous instance of undetected gas
accumulation in the reactor coolant system in
September 1996
50-295/304-97002-02
eel
Failure to have procedures for extended operation while
in cold shutdown conditions and for operating
procedures to include measures to diagnose or prevent
the undetected accumulation of gas in the reactor
coolant system
50-295/304-97002-03
eel
Failure to make a four-hour non-emergency report, for a
condition that alone could have prevented the
fulfillment of the safety function to remove residual
heat in accordance with 10 CFR Part 50.72(b)(2)(iii)(B)
50-295/304-97002-04
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Failure to submit a written Licensee Event Report within
30 days, for a condition that alone could have
prevented the fulfillment of the safety function to
remove residual heat in accordance with 10 CFR Part 50.73(a)(2)(v)(B)
50-295/97002-05
IFl
Review the MSLB analysis to determine the impact of
the 1C CS pump ratcheting time delay on the ability of
the CS system to perform its safety function
50-295/304-97002-06
Failure to test both battery starting circuits for the "C"
containment spray pumps to ensure that the design
starting time requirements were met
50-295/304-97002-07a
Failure to implement timely and effective corrective
actions for NRC Violation 50-295/93023-01, 50-
304/93023-01
50-295/304-97002-07b
Failure to determine the cause and implement effective
corrective actions to preclude recurrence for the
cracked lube oil cooler channel head on the 2B
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50-295/97002-08
Failure to complete appropriate operability assessment
within five days of discovery of the slow starting time
on the 1C CS pump
50-295/304-97002-09
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Review of long-term corrective actions for breaker
position seismic qualification
50-295/97002-10
Failure to have direct oversight und positive control
over each personnel entry into a locked high radiation
area
Closed
50-295/304-96020-07
Review the adequacy of boron concentration samples
with the RHR sample valves wired incorrectly
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list of Am. .. ...s
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AOP ' Abnormal Operating Procedure
CAR Corrective Action Record
CR
Control Room
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Escalated Enforcement item
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HVAC Heating, Ventilation and Air Conditioning
IDNS lilinois Department of Nuclear Safety
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inspector Follow-up Item
IN
information Notice
IM
instrument Maintenance
LCO
Limiting Condition for Operation
LHRA Locked High Radiation Area
LOCA Loss of Coolant Accident
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MI
Maintenance Instruction
MCC Motor Control Center
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MSLB Main Steam Line Break
NRC- Nuclear Regulatory Commission
NSAL Nuclear Safety Advisory Letter
NSSS Nuclear Steam Supply System
OOS Out-of-Service
OSP Operational Special Procedure
Public Document Room
PlF
Problem identification Form
Reactor Coolant Pump
Radiation Protection
RP&C Radiological Protection & Chemistry
RVLIS Reactor Vessel LevelIndicating System
RWST Refueiing Water Storage Tank
System Auxiliary Transformer
SQV Site Quality Verification
TS
Technical Specifications
UFSAR Updated Final Safety Analysis Report
Unresolved item
VCT Volume Control Tank
Violation
VPC
Vertical Pipe Chase
ZAP
Zion Administrative Procedure
ZODM Zion Operability Determination Manual
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