ML20137J687
| ML20137J687 | |
| Person / Time | |
|---|---|
| Site: | Zion File:ZionSolutions icon.png |
| Issue date: | 03/24/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20137J668 | List: |
| References | |
| 50-295-96-20, 50-304-96-20, NUDOCS 9704040095 | |
| Download: ML20137J687 (26) | |
See also: IR 05000295/1996020
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U.S. NUCLEAR REGULATORY COMMISSION
REGION lli
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Docket Nos: 50-295, 50-304
Report No: 50-295/96-20; 50-304/96-20
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Licensee: Commonwealth Edison Company
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Facility: Zion Nuclear Plant, Units 1 and 2
Location: 101 Shiloh Boulevard
Zion,IL 60099
Dates: December 7,1996, through February 5,1997
Inspectors: A. Vegel, Senior Resident inspector
D. R. Calhoun, Resident inspector
E. W. Cobey, Resident inspector
J. Yesinowski, Illinois Department of
Nuclear Safety inspector
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Approved by: Marc L. Dapas, Chief
Reactor Projects Branch 2
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9704040095 970324
"DR ADOCK 05000295
O PDR
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EXECUTIVE SUMMARY
Zion Nuclear Plent, Units 1 and 2
NRC Inspection Reposts 50-295/96-20; 50-304/96-20
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This inspection included aspects of licensee operations, maintenance, and engineering. l
The report covers an eight-week period of inspection activities by the resident staff. )
Licensee performance during this inspection period was characterized by procedural non-
compliance and the acceptance of degraded or abnormal plant conditions. Operations and
engineering personnel failed to recognize and appropriately evaluate the degraded material
condition of the Unit 2 containment until prompted by the NRC. In addition, maintenance
workers did not inform operations personnel of unexpected changes in the configuration of
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' equipment observed during containment spray system maintenance activities.
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Operations 1
. *- The inspectors identified numerous material condition deficiencies involving safety-
related components in the Unit 2 containment. Lack of questioning attitudes and
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low standards by licensee personnel during both the post-maintenance restoration
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of equipment and plant walkdowns, contributed to the failure of the licensee to
identify these deficiencies. (Section 02.1)
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- The inspectors identified a violation involving the failure of operators to follow an
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abnormal operating procedure in response to a malfunctioning Eagle 21 process
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protection rack. The inspectors also determined that the procedure provided
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confusing guidance to operators which could make operator control of steam
- generator water level more difficult during some abnormal plant transients. The
licensee failed to identify these problems in the post-event review. (Section 03.1)
' * The inspectors identified that the licensee's review of open operability assessments
as part of the Unit 2 restart review function was not thorough. Licensee personnel
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did not identify the need to perform 10 CFR 50.59 safety evaluations for degraded
. equipment conditions for which an operability assessment was performed to allow
i continued operation until the next outage when the discrepant condition was to be
- rectified. in response to the inspectors' concerns, the licensee identified 15
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operability assessments requiring a 50.59 safety evaluation before Unit 2 startup.
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Maintenance j
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- - Poor work practices and an inadequate equipment out-of-service resulted in a
j persone.el safety hazard during containment spray system maintenance. The
acceptance of unexpected plant conditions by operations and maintenance
personnel prevented earlier identification of the hazard. A violation was identified
for the failure to follow an equipment control procedure. (Section M1.1)
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- _ The inspectors identified a violation involving the failure to determine the cause of ,
water intrusion into the 1 A auxiliary feedwater pump, turbine inboard beanng. !
(Section M8.1) !
EnginegIing
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- Engineering and maintenance personnel cMnged the spring tension on the Unit 2 ,
pressurizer power operated relief valves without using the appropriate design
change process. Consequently, the ability of the relief valves to perform their I
design basis function was affected. A violation was identified for the licensee's :
failure to use the site design control process. Corrective actions to address design
control configuration management deficiencies has not been effective as l
demonstrated by the inadequate control of the change to the PORV spring tension.
(Section E2.2)
} * The system engineer's troubleshooting of the Eagle 21 process protection system
was thorough. (Section E2.4)
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Report Details
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Summarv of Plant Status
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Unit 1 operated at or near 100 percent power during the inspection period, except on j
January 3 and 11, when power was reduced to approximately 40 percent to support ;
containment entries. Licensee personnel entered the containment for inspections of '
containment coatings and the recirculation sump cover. ,
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- Unit 2 remained shut down during the inspection period in support of the 14th refueling
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outage. On January 8, the licensee extended the outage to address numerous issues
including flaking and unqualified containment coatings, material condition deficiencies
} identified during containment and safety system walkdowns, and to conduct additional
reviews of programs, documentation, and commitments.
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Licensee performance during this inspection period was characterized by procedural non-
compliance and the acceptance of degraded or abnormal plant conditions. . Operations and
engineering personnel failed to recognize and appropriately evaluate the degraded material ,
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condition of the Unit 2 containment until prompted by the NRC. In addition, maintenance
I workers did not inform operations personnel of unexpected changes in the configuration of
- equipment observed during containment spray system maintenance activities.
4 1. Operations ;
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01 Conduct of Operations
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01.1 Ooerations Control of Plant Activities
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During this inspection period, the following two events occurred in which
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operations personnel did not demonstrate a questioning attitude or perform tasks !
p consistent with procedure requirements:
- Poor work practices and an inadequate equipment out-of-service resulted
in a personnel safety hazard during containment spray system maintenance.
A licensed operator failed to notify operations supervision promptly that
two valves in the containment spray system were in an abnormal position,
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delaying identification of the hazard. This event is discussed in
Section M1.1 of this report. l
- During the failure of an Eagle 21 process protection rack, the operators
responded promptly and stabilized the plant. However, the operators did not
respond in accordance with the approved abnormal operating procedure.
l The licensee did not identify, during its post-event review, this example of a
failure to follow procedure and other procedure problems later identified by
the inspectors. This event is discussed in Section 03.1 of this report.
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As previously documented in NRC Inspection Reports 50-29$/96-14; 50-304/96-14
and 50-295/96-17; 50-304/96-17, the inspectors continue to be concerned with ;
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examples of an insufficient questioning attitude and poor procedural compliance
- exhibited by the operations staff.
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02 Operational Status of Facilities and Equipment
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02.1 Dearaded Material Condition of the Unit 2 Containment ,
a. .jnsooction Scone (71707)
The inspectors identified numerous material condition deficimcies in the Unit 2
- containment following the completion of major refueling outage maintenance
! activities. The inspectors discussed the deficiencies with licensee management and '
- engineering personnel, reviewed licensee corrective actions, and reviewed
documentation, including the applicable sections of the Updated Final Safety
Analysis Report (UFSAR).
b. Observations and Findinos ,
On December 16 and 24, during partialinspections of the Unit 2 containment while
accompanied by licensee m; wgement, the inspectors ideritified numerous material
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condition deficiencies including:
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- * boric acid buildup on flanges
- ' missing fasteners
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e loose cable tray covers ,
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- missing covers on electrical junction boxes
- damaged insulation on instrument wiring :
- bent, broken, and missing pipe supports I
- nylon straps supporting small bore piping l
1 * cracked weld'on 28 reactor coolant pump oil collection container ]'
I * miscellaneous debris located throughout the containment
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- containment recirculation sump screen damage ;
- peeling and flaking paint on containment surfaces
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The inspectors identified over 75 deficiencies during these inspections. The peeling
and flaking paint particularly concemed the inspectors. On December 16, the
inspectors communicated to licensee management that the potential existed for
paint flakes to possibly foul the containment recirculation sump screens which
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could impact emergency core cooling system (ECCS) operability. On December 31,
the licensee stated that all corrective actions for the identified containment material
condition deficiencies had been completed.
The inspectors later identified that the licensee had not evaluated the containment
paint issue with respect to the requirements of the UFSAR. Specifically, UFSAR
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- Section 6.3.2.1.3, " Recirculation Phase of Operation," required that containment ,
coatings not flake off, go into' solution, or otherwise provide interference with
cooling of the co.e following a loss-of-coolant accident.
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The inspectors discussed this concern with licensee management.' in response, the
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licensee stated that based upon an evaluation of the Unit 2 containment coatings
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completed by Systems Material Analysis Department (SMAD) personnel early in the
outage, the condition of the coatings, including paint, was acceptable. However, f
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- the inspectors' determined, through a review of this'avaluation, that the licensee's
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conclusion was not well supported.
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On Janbary 1, the licensee completed a walkdown of the Unit 2 containment to
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identify additiomi examples of containment coating deficiencies. Licensee
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personnel subse, uently scraped approximately 100 pounds of loose paint (and ,
other material) fn m the containment. Based upon the as-found condition of the
Unit 2 containment, the licensee's Plant Operations Review Committee members
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directed that an opwability assessment be conducted for Unit 1, the operating unit.
On January 3, the licensee determined that the Unit 1 containment recirculation
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sump could not be adysrsely affected by loose coating material and therefore it was !
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operable The liceensee indicated that this evaluation was based upon material
transport and " zone of influence" analyses. Specifically, the amount of unqualified
coatings in the vicinity of the sump was !9 sufficient to block the strainer and cause
- inadequate not positive suction head to the ECCS pumps.
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c. Conclusions
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. The inspectors concluded that: (1) lack of a questioning attitude and low standards )
by licensee personnel during both the post-maintenance restoration of equipment
and plant walkdowns, contributed to the failure of the licensee to identify the
i degraded material condition of the Unit 2 containment and equipment; (2) the i
licensee's conclusions regarding the ac.ceptability of the degraded containment I
i coatings, which were based upon the SMAD report, were not well-supported; and
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(3) licensee management did not recognize the significance of the centainment
coating deficiencies until after repeated prompting by the inspectors.
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The containment coating issue is considered an Unresolved item (50-295/96020-
01; 50-304/96020-01) pending NRC review of the licensee's " zone of influence"
'and transport analyses, evaluation of unqualified paints in the containment, and
review of net positive suction head loss calculations for the ECCS pumps. The
inspectors will address this issue further in NRC inspection Report 50 295/97-03;
50-304/97-03.
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03 Operations Procedures and Documentation
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03.1 Ooerator Resoonse to an Eaale 21 Process Protection Rack Failure
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a. Insoection Scone (71707)
A failure of the Unit 1 Eagle 21 process protection set 1, rack 1 resulted in a plant
transient. The inspectors interviewed operations personnel and reviewed Abnormal
l Operating Procedure (AOP) 7.5, " Eagle 21 Rack Failure Actions," Revision 8.
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b. Observations and Findmas '
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! On January 18, with ' Unit 1 operating at 99.8% power, a failure of the Eagle 21
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protection set 1, rack 1 occurred. The failure affected several instruments including
a "C" and "D" steam generator (SG) levels, reactor coolant loop flow, pressurizer
I level, and pressurizer pressure. Since the reactor coolant loop flow and pressurizer
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level instruments do not have a control function, their failure did not affect plant
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operation.
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!' When pressurizer pressure instrument channel 1P-455 failed high, the pressurizer
- control system responded by opening the pressurizer spray valve. Consequently,
e actual pressurizer pressure decreased to approximately 2100 psig before a control
! room operator terminated the pressure transient by manually closing the spray
! valve. Upon the failure of the SG level instrument channels, the associated
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feedwater regulating valves (FHVs) closed, causing actual water level in the !
- affected SGs to decrease. A control room operator took manual control of the
FRVs and opened the valves to restore water level to normal. The operators were )
able to restore the plant to a stable condition, including returning pressurizer
pressure to within Technical Specification (TS) 3.2.3.D.1 required parameters, in
- approximately six minutes, well within the TS action statement requirements.
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On January 21, after the licensee had reviewed the event, the inspectors identified
I that the operators did not follow AOP 7.5 while responding to the event. Abnormal
! Operating Procedure 7.5 directs the operators to first select an operable channel
when a failed instrument channel has a control function. Contrary to AOP 7.5,
upon failure of the pressurizer pressure channel, an operator manually. closed the
pressurizer spray valve without first attempting to select an operable instrument I
- channel. Although in this instance the safety consequence of the operator action l
was minimal, the inspectors were concerned with the failure of the operator to ,
follow the AOP. l
The inspectors also identified the following instances in which AOP 7.5 provided
confusing guidance to operators or could make operator control of steam generator
water level more difficult during some abnormal plant transients: l
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- Abnormal Operating Procedure 7.5 directed the operators to first select an
operable instrument channel and if an operable channel could not be !
- selected, to place the controller in manual. This step in AOP 7.5 was
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confusing in that the step, although applicable to the other instrument
channels, was not applicable for a SG water icvel instrument channel. Duc
to the design of the SG water level control system, only one channel can be
used for SG water level control. The licensee subsequently issued a
temporary procedure change to clarify operator actions in response to a SG
water level instrument failure. ;
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level instability, directed the operator to place the FRV controller on the '
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affected SG in manual and to maintain SG water level in a wider then normal
band (i.e.,30% to 50%.) This guidance was appropriate for plant operation l
- at high power levels. However, at low power levels when SG water leval is
, being controlled with the feedwater regulating bypass valve, opening a neuch
, higher cs;:ccity FRV would make SG water level control more difficult for the i
I operattvs. The inspectors discussed this concern with the licensee. The j
i licensee & greed that a preferred method to stabilize SG wat6r level during a 1
j transient at low power was manual control of the feedwater regulating ]
bypass valve.
c. Conclusions
1 The inspectors concluded that: (1) control room operators failed to follow AOP 7.5 ;
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a in response to the Eagle 21 failure, in that,' pressurizer pressure control was not
i ' transferred to an operable channel; and (2) the licensee's post-event review was ,
not thorough, in that, the licensee failed to identify the operators' failure to follow i
AOP 7.5 and problems with the guidance in this procedure for controlling SG water i
level. l
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l Step 2 in Section C of AOP-7.5 requires that if the controlling channel of the
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pressurizer pressure instrument is inoperable, then an operable instrument channel
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is to be selected. The failure of the operators to select an operable channel in
response to the failure of the controlling channel on January 18, is considered a
violation of 10 CFR Part 50, Appendix B, Criterion V (50-2g5/g6020-02), as
described in the attached Notice of Violation. The inspectors did not consider the
of NRC requirements, since the procedure was not actually inadequate for the
intended purpose. Although the prescribed actions for controlling SG water level
- during a transient at low power was not the preferred method, operators could
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possibly stabilize SG water level by following the AOP.
07 Quality Assurance in Operations
07.1 ~ Licensee Oversiaht of Unit 2 Readiness for Restart
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a. inspection Scone (71707)
The inspectors observed several meetings of the Plant Operations Review
Committee (PORC) during which the readiness to restart Unit 2 was discussed,
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and reviewed selected portions of the pre-existing onsite review process used by I
the licensee to assess Unit 2 restart readiness,
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b. Observations and Findinas
Before implementation of the PORC concept, the onsite review function consisted
solely of independent reviews / evaluations by selected licensee managers as
described in the licensee's quality assurance manual. The licensee implemented the
PORC process to augment this onsite review function. The PORC process
consisted of onsite reviews in a group forum versus independent reviews by
selected managers. Once the PORC process is effectively implemented, the
licensee intends to replace the current onsite review process entirely with the
PORC.
Through observations of several PORC meetings and followup discussions with the
- licensee, the inspectors identified that the licensee had not determined, as part of
the Unit 2 restart review effort, whether existing open operability assessments
required a 10 CFR 50.59 safety evaluation. Specifically, the licensee did not i
identify the need to perform 10 CFR 50.59 safety evaluations for degraded I
equipment conditions for which an operability assessment was performed to allow
continued operation until the next outage when the discrepant condition was to be
rectified. In response to the inspectors' concerns, the licensee identified that 15 of
29 open operability assessments required a 50.59 safety evaluation before Unit 2 l
startup. The licensee had not recognized the need to conduct these safety i
evaluations until prompted by the inspectors.
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c. Conclusions
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The inspectors concluded that the implementation of the PORC process was a
positive step towards improving the licensee's safety focus, however, continued
process improvement is needed. The PORC did not identify that the review of open ,
operability assessments as part of the onsite restart review function, was not
thorough. Specifically, the onsite review did not recognize the need to perform
50.59 safety evaluations to determine if startup with open operability assessments
involved any unreviewed safety questions.
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ll. Maintenance
M1 Conduct of Maintenance
s - M1.1 Unexoacted Valve Actuation Durina Unit 1 Containment Sorav (CS) Svt ' 'n
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Maintenance
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o a. Inanection Scone (62707)
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On January 14, while performing maintenance activities on the "B" CS header
e isolation valve,1MOV-CSOO5, an electrical maintenance (EM) technician
inadvertently caused two other vaives in the CS system to open. The inspectors
interviewed operations, maintenance, and supervisory personnel; reviewed the
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applicable procedures; and reviewed the instructions in Work Request No.
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950082299-01, " Pump,1B Containment Spray Change Lubrication Pump / Motor
Coupling," and Work Request No. 950095411-01, "Limitorque,1B CS PP [ Pump)
Header Isolation Valve AdjustNerify Close Torque Switch Bypass."
b. Observations and Findinas
While performing an adjustment to a limit switch on 1MOV-CSOO5 with an
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uninsulated screwdriver, the EM technician unknowingly touched two contacts
which energized a relay. Due to the energized relay, the "B" CS pump discharge
i stop valve, IMOV-CSOO4, and the sodium hydroxide tank to "B" CS stop valve,
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1MOV-CSOO9, unexpectedly opened. The open CS pump discharge stop velve
established a flow path from the refueling water storage tank (R'NST) through the
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"B" CS pump to the CS piping downstream of 1MOV-CSOOS, which was also open.
The EM technicians involved in the work activity observed 1MOV-CSOO4 opening
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and heard flow noise, but they did not recognize that this was an abnormal
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condition, nor did they realize that one of the EM technicians had caused the valve
. actuation. Consequently, the EM technicians did not notify the contrc,1 room of the
valve movement.
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1 In parallel with the work on 1MOV-CSOO5, mechanical maintenance (MM)-
4 technicians were reassembling the 1B CS pump coupling. The EM and MM work
activities were both performed in the CS pump room. While attempting to recoupla
the pump, the MM technicians heard water flow and observed the pump impeller
rotate. The MM technicians did not recognize that uncontrolled rotation of the
pump impeller during lubrication of the impeller, constituted a significant personnel
safety hazard. As a result, the MM technicians continued with their work without
notifying the control room.
Subsequently, the EM technicians transferred administrative control of valve ,
1MOV-CSOO5 to the control room operators for post-maintenance testing. During
this testing, the control room operator noted that normally closed valves
1MOV-CSOO4 and IMOV-CSOO9 were open. The control room operator assumed
i the valves were opan to support CS system maintenance activities. Consequently,
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the control room operator did not communicate the changes in normal valve -i
r position to the unit supervisor (US).
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Approximately an hour and a half later, an EM technician notified the US that
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IMOV-CS004 opened during work on 1MOV-CS005. As a result, the US initiated
an investigation. Approximately 30 minutes later, the control room operator
communicated to the US that 1MOV-CS009 was also open. Subsequently, a MM
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supervisor notified the US that the CS pump impellar unexpectedly began to rotate
during earlier maintenance activities. As a result, the US stopped all work on the >
CS system and notified licensee management of the event.
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i The licensee had established out-of-service (OOS) No. 960000673 to provide .
protection for maintenance personnel performing CS system work, which included
lubrication of the pump coupling. The OOS boundaries for the coupling work
included the CS pump motor and breaker. However, the pinnp suction and
discharge valves were not closed and tagged OOS. Consequently, when 1MOV-
i CS004 inadvertently opened, water from the RWST flowed through the pump and
- caused the impeller to rotate. Although no personnel were injured and no
1 equipment was damaged, the potential for significant personnel injury existed. The
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OOS did not adequately isolate the CS pump work area, in that, the pump was not
isolated from the RWST, a potential energy source.
The EM technician performing the work on 1MOV-CS005 used en uninsulated
screwdriver for work on energized equipment. Licensee personnel indicated that
! work on enorgized equipment was within the craft capability and that no specific
- requirements concoming electrical safety practices were violated. However, the
expectation of licensee management was that an insulated screwdriver be used and
, the equipment de-energized.
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The licensee concluded that the nuclear safety consequences of the event were
! system filled existing voided piping, and therefore, water did not actually spray into
containment. In addition, no discernable change in RWST level occurred.
- c. Conclusions
The inspectors concluded that: (1) maintenance personnel in the CS pump room
l and the involved control room operator demonstrated poor judgment by not
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promptly communicating the observation of abnormal plant conditions to plant
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management, (2) the OOS initiated to protect equipment and personnel associated
i with the 1B CS pump coupling work was inadequate, and (3) the EM technician
- performing work on 1MOV-CS005 exhibited poor work practices by performing
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adjustments on energized equipment with an uninsulated screwdriver. In addition,.
i some licensee personnel exhibited a poor questioning attitude and were insensitive
to a potentially hazardous plant condition during this event.
Zion Administrative Procedure (ZAP) 300-06, "Out-of-Service Process," Revision 9,
Appendix A, " Placing OOS Techniques," requires that when it is possible to add -
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energy to equipment from more than one source, then OOS cards be placed on all
isolating devices, including valves. The failure to isolate all potential energy sources
i to the 18 CS pump is considered a violation of TS 6.2.1.a, (50-295/96020-03), as
, described in the attached Notice of Violation.
M1.2 Emeroency Diesel Generator (EDG) Testina Deficiencias
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l The licensee identified two failures to conduct EDG surveillance testing. In
addition, while attempting to satisfactorily complete this testing, the licensee
experienced several EDG protective trips and equipment failures.
- * On January 17, during a review initiated to address questions raised by the
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NRC Project Manager, the licensee identified that hot restart testing had not
been performed as prescribed by the Technical Specifications for the EDGs.
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Flot restart testing is intended to verify that shortly after an operating EDG
has been shut down, it will restart and reach specified voltage and frequency
within the required time period.
- On January 17, the licensee identified that testing had not been properly
performed on the EDG starting air system discharge check valves.
- On January 18, the licensee completed hot restart testing on the 1 A,18,
and O EDGs. During initial testing of the 1 A EDG, the licensee aborted the
test due to an improperly installed strip chart recorder.
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- On January 18, during performance of hot restart testing, operators
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unloaded and manually tripped the 2A EDG due to indications of rapidly
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rising jacket water level. The abnormal indication was caused by the
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freezing of water in the indicator's sensing line due to an excessively cold
condition of the EDG room.
- * On January 19, during performance of hot restart testing, the 28 EDG
tripped on high turbocharger lubricating oil ratio due to an excessively cold
condition of the EDG room which affected the lube oil sensing line.
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Associated instrumentation compares lubricating oil pressure and
turbocharger discharge pressure and provides an EDG trip if oil pressure is
too high or low to ensure proper lubrication.
1- * On January 22, the licensee declared the 28 EDG operable and returned it to
service without successfully completing hot restart testing. Hot restart
testing'was subsequently ccmpleted later in the day.
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- On January 22, the licensee removed the 2B EDG from service to investigate
the cause of abnormally high lobe oil temperatures. On January 23, the
licensee discovered that the service water sides of the lube oil and }acket
water heat exchangers were fouled with debris.
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- On January 25, while attempting to perform hot restart testing, the 2A EDG
did not start due to a failure of the starting air system control valve to open.
The licensee successfully started the 2A EDG locally. During subsequent hot
restart testing, the 2A EDG tripped on high crankcase pressure due to
j blockage of the crankcase vent line. . .
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- On January 27, while attempting to perform hot restart testing on the 2A l'
EDG, the licensee aborted the test due to another incorrect installation of the
strip chart recorder. During the engine cooldown, the 2A EDG experienced a *
loss of lobe oil.
i The inspectors were concerned with the numerous material condition problems tint
cccurred during EDG testing activities. Follow-up inspection for these problems will .;
be the sub}ect of a special inspection which will be documented in NRC inspection
Report 50-295/97-05; 50-304/97-05.
' M2 Maintenance end Matedal Condition of Facilities and Equipme,!
.
'
M2.1 incorrect Oilin 2B CS Pumn
a. Insoection Scone (37551)
The licensee identified that the incorrect type of oil had been added to the 2B CS
, pump. The inspectors reviewed the oil sample results, and interviewed the involved
, system engineer, the lubrication coordinator, and a fuel handling supervisor.
.
b. Observations and Findinos
^
On November 25, the licensee determined that based on an oil sample drawn on
- October 28, the 2B CS pump motor outboard bearing contained Mobile heavy
i medium oilinstead of the required Mobile medium oil. The system. engineer
! determined that a fuel handler, who was responsible for adding the oil, added the
- wrong oil to the pump in March 1995. The licensee determined that the pump's
'
other bearings contained the correct oil.
!
The inspectors questioned the operability of the 2B CS pump. The system engineer
'
stated that there was no immediate operability concern because the condition was
I- corrected and the pump was not required to be operable at the time the wrong oil
was discovered. However, the inspectors were concerned that the licensee had not
evaluated past operability of the pump to ensure 10 CFR 50.72 and 10 CFR 50.73
reportability requirements were met. The system engineer, with the concurrence of
engineering management, initiated a problem identification form (PlF) to document
'
use of the incorrect oil and informed the inspectors that the PlF process would
address the reportability concern. The inspectors reviewed ZAP 700-08, " Problem
Identification Process," Revision _10, and noted that it did not require evaluation of a
degraded equipment condition to determine past operability.
.
13
.
9. y-,,... 3--,__., , ---- , , , , [ ~ . .
.
- - - - . . - --- - - - - -
_
t
,
u
i e-
.
-
.
The inspectors also noted that the licensee did not classify the problem with the
3
incorrect oil in the pump bearing as a nonconforming condition on the PIF. The
'
inspectors were concerned that this particular deficient condition would not be
captured by the PlF trerxling process and as such, a similar problem in the future
could be treated as an isolated incident. The licensee's initial response to the
. Inspector's concern was that the PIF was properly classified because the incorrect
i' oil was not considered a hardware failure. However, after further review, the 3
licensee agreed that the incorrect oil problem documented in the PlF should be i
'
- . classified as a nonconforming condition, and recognized the need to expand the
l / definition of a nonconforming condition to encompass this type of deficiency.
'
! ,
'
c. Conclusion I
l The inspectors determined that the system engineer was sufficiently involved in
evaluating the condition of the pump. ' However, the inspectors were concerned
that no formal mechanism existed to ensure that assessments were conducted to i
determine past operability of degraded equipment. The inspectors concluded that I
the definition of a nonconforming condition in ZAP 700-08 was too narrow in scope i
- to assure that all equipment deficiencies were adequately captured for appropriate i
'
l trending. This issue is considered an Unresolved item (50-304/96020-04) pending
NRC review of the licensee's evaluation to determine the impact of the incorrect oil ,
on operability of the 2B CS pump and to determine why the fuel handler added the !
! incorrect oil.
M8 Miscellaneous Maintenance issues
M8.1 (Closed) Unresolved item 50 295/96017-09: Resolve discrepancies in licensee's
root cause analysis for water in the 1 A auxiliary feedwater (AFW) pump turbine
- inboard bearing.
!-
! On November 26,1996, while replacing the oil in the 1 A AFW pump turbine
'
inboard bearing, the licensee identified the presence of approximately one-half
<
gallon of water in the bearing reservoir. The licensee initially concluded that the
water came from the oil cooler that was in service before December 1995 and that
i
the water had not been detected due to the manner in which the oil change
preventive maintenance (PM) task was performed. However, as discussed in NRC
inspection Report 50-295/96017; 50-304/96017, the inspectors identified that this !
root cause explanation was in conflict with statements by the fuel handlers
'
responsible for performing the PM activity.
On December 23,1996, in response to the inspectors' concerns, system
engineering and regulatory assurance personnel stated that PIF 96-4466, which
originally documented this condition, would be reopened and a root cause
- investigation would be conducted to determine the source of the water intn
- .bn.
However, the inspectors noted that as of the end of this inspection period, the
licensee had not reopened the PlF or attempted to determine the cause of the water l
intrusion.
l
14 ,
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. - . - _ _ _ _ _ _ _ _ ._ __ __ . _ ___ _ - __.._ _ ._ _ _._ _
"
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4 .
A de -
i. ;
'
The failure to determine the cause of a significant condition adverse to quality,
specifically, water in the 1 A AFW pump turbine, inboard bearing oil reservoir, is
i considered a violation of 10 CFR Part 50, Appendix B, Criterion XVI i
,
(50-295/96020-05), as described in the attached Notice of Violation. This >
- Unresolved item is closed.
111. Ennineering
)
E1 Conduct of Engineering
,
-
E1.1 Valves Not Tested as Raouired By the Inservice Test (IST) Prooram
a. insoection Scone (37551)
The licensee identified that several valves had not been tested as required by the l
i IST program. The inspectors interviewed the IST engineer and reviewed applicable 1
l procedures.
.
b. Observations and Findinas l
l
' )
On December 12 and 26, an IST engineer identified during a review of the IST !
'
program that the following valves had not been tested:
- .
- reactor coolant system (RCS) loop drain and fill valves 1(2)AOV-RC8035 A,
B, C, and D and 1(2)AOV-RC8034 A, B, C, and D,
'
- primary water injection to blender valves 1(2)FCV-VC111B l
!
!
- excess letdown heat exchanger stop valves 1(2)AOV-VC8381
. The licensee determined that an IST program change had not been properly
implemented. The IST program did not require remote position verification testing
for the RCS loop drain and fill valves and the excess letdown heat exchanger stop l
valves during the second ten year IST interval. However, this testing was required l
during the third ten year interval, effective May 1994. Although the licensee had !
- incorporated the valves into the IST program, procedures were not developed to
- accomplish this testing. The licensee determined that the primary water to blender
'
valves had never been incorporated into the IST program second ten year interval.
Consequently, the same valves were not included in the third ten year interval
! program.
i Upon discovery of this issue, the licensee revised appropriate procedures and tested
'
- the valves with the exception of valves 1(2)AOV-RC8034 A-D. The licensee
'
tagged these valves out-of-service and documented the valves' non-credit status for
remote po6ition indication in the degraded equipment log. The licensee plans to
continue a comprehensive review of the IST program to verify that every test listed
-
for each component in the IST program database is covered by a referenced
15
!
-- . < - - ,. _ . _ _
,__________..__.__.___I
-
~ _ . - . - - _ . _ . - _ .~.. _ _ _ _ . _ _ . _ ._ _ _ _ - ___-____ _ _ _ _
i
.
i - . ,
.
,.
procedure. The licensee stated that the review, which is scheduled to be complete
by March 31, will also verify that the IST procedures properly test each component
to applicable American Society of Mechanical Engineer (ASME) Code requirements.
- >
'
'
c. Conclusion
F
L
.The inspectors concluded that the licensee had identified some long-standing IST ,
'
program deficiencies. Although the IST review was still in progress at the
i conclusion of the inspection period, the initial effectiveness of this review was good
, as reflected in the identification of the missed tests.
The failure to test the RCS loop drain and fill, primary water to blender, and excess
- letdown heat exchanger valves, in accordance with the IST program, is considered .i
a violation of TS 4.0.5 which requires inservice inspection and testing of ASME ;
Code components (50-295/9602046; 50-304/96020-06). This licensee-identif'uni '
and corrected violation is being treated as a Non-Cited Violation, consistent with
'
l Section Vll.B.1 of the NRC Enforcement Policy.
- E2 Engineering Support of Faciuties and Equipment
'
E2.1 Residual Heat Removal (RHR) System Samole Valve Wirina Discrepancy '
i
- a. Insoection Scone (37551)
The licensee identified that the RHR sample valves for Unit 2 were wired
-
incorrectly. The inspectors reviewed applicable procedures and drawings and
interviewed operations, chemistry, system engineering, and electrical maintenance
personnel. !
4
b. Observations and Findinos
'
On January 6, with Unit 2 in Mode 5 (Cold Shutdown), licensee personnel opened
the 2B RHR loop sample valve but did not observe flow at the sample panel.
2-
Chemistry personnel initiated PlF No. 97-0097 to document the event.
- Subsequently, the licensee determined that the wiring from the RHR sample valves'
electrical junction boxes to the valves' control switches was reversed. As a result,
i the loop "A" sample valve control switch operated the loop "B" sample valve and
,
the loop "B" sample valve control switch operated the loop "A" sample valve. The
,
actual wiring configuration in the field did not match the configuration specified in
drawing 22E 2-4668," Wiring Diagram, Nuclear Sampling System & Miscellaneous
!.. Valves." The licensee subsequently corrected the wiring configuration problem.
The inspectors noted that on December 13,1996, the licensee obtained a TS
required sample from the operating RHR loop. Technical Specification 4.2.1.A.2
j 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. Due to the wiring configuration discrepancy described in the
16
~
.
- e
,. 4 -.
.v ,e..--, ,. ... , , . . . .,, . , , . _ , , , . , _ _ _ _,c - ,-
_ _ _-. _ _ ,. . . _ _ . _ . . . _ _ _ _ __. _ _ __ _ _ . _ _.
.
. .
t y
.
preceding paragraph, the licensee may have obtained a non-representative sample.
The inspectors were concerned that the TS requirements may not have been met.
c. Conclusion
The Jicensee took prompt action to determine the cause for the inability to sample
the RHR loop. However, this issue is considered an Unresci4ed ihm
(50 295/96020-07, 50-304/96020-07) pending NRC review of the consequences
,
of the wiring discrepancy relative to obtaining TS required boron concentration
j samples.
I
E2.2 Modification of the Pressyrizar Power Ooerated Relief Valves (PORVs) Without
i Usina the Desian Control Process
2'
a. Inspection Scone (37551)
4
On November 22,1996, licensee personnel changed the spring tension on the
l Unit 2 pressurizer PORVs without using the appropriate design change process.
, The inspectors reviewed licensee documentation including maintenance procedures,
,
work packages, and operability assessments, and interviewed maintenance and
4 system engineering personnel.
.
'
b. Observations and Findinos
To stop seat leakage from Unit 2 pressurizer PORVs 2PCV-455C and 2PCV-456,
the licensee made spring tension adjustments to these valves per Work Package
r No. 960041517 and Work Package No. 960018157, respectively. Subsequently,
. pressurizer PORV 2PCV 455C failed its stroke time surveillance test. During review
'
of the test failure, the involved system engineer identified that a change to a
pressurizer PORV's spring tension could potentially affect the valve's ability to
operate. After further evaluation, the licensee determined that PORV 2PCV-455C
would operate correctly with the new spring tension and associated accumulator
'
capacity provided that personnel maintained instrument air system header pressure
at greater than or equal to 105 psig. The licensee normally maintained instrument
air system pressure at 106 psig. On January 20, instrument air system pressure
i dropped below 105 psig and the licensee declared 2PCV-455C inoperable.
. Instrument air system pressure did not drop low enough to impact the operability of
i PORV 2PCV-456. The licensee subsequently restored instrument air system
pressure to 106 psig and declared PORV 2PCV-455C operable.
c. Conclusion
i
The inspectors were concerned that the spring tension change was implemented
during corrective maintenance without a proper evaluation of the impact on PORV
- operability. The licensee failed to use the design control process, and as a result,
l- the ability of a safety-related component to perform its design basis function was
affected.
17
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. - - --, i._ ._ -- ~.
- - - - . _ ~ .- .. . .. - .-. _ . . . . . - _- - -. . - .
-
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t.
l Zion Administrative Procedure 510-02, " Plant Modification Program," Revision'6,
<
establishes requirements for assuring design control during the modification
process. It defines a " design change" as any change in design that may affect ,
functional requirements, operating conditions, or safety, regulatory, reliability, and !
! ASME Code-related requirements, and that would require that affected
, documentation be changed. The failure to use design control measures prescribed
in ZAP 510-02 for a change to the safety related functional requirements of the
PORVs is considered a violation of 10 CFR Part 50, Appendix B, Criteria Ill (50-
-
304/96020-08), as described in the attached Notice of Violation.
1
As provicusly documented in Inspection Report 50-295/96011: 50-304/96011,
implementation of the modification process was an area of inspector concern. i
Corrective actions to address design control configuration management deficiencies :
I
has not been effective as demonstrated by the inadequate control of the change to
the PORV spring tension.
E2.3 Missina Ventilation Holes on Contalomant Recirculation Sumo Covers
i
a. Insoection Scone (37551 and g3702)
On January 10, the licensee identified that two holes specified in design drawings
were missing from the Unit 2 recirculation sump cover. On January 11, the
'
- licensee identified that the same holes were missing on Unit 1. The inspectors
reviewed the applicable drawings and interviewed station management, operations,
, and engineering personnel.
b. .Qbservations and Findinas
! During an engineering review of the containment recirculation sump drawings in
7, support of the licensee's evaluation of the containment coating issue (see l
'
Section O2.1), the licensee identified that two one-inch ventilation holes were
missing on the Unit 2 containment recirculation sump cover. The licensee
determined that the cover plate holes were designed to allow air to escape from the i
!.
sump as it fills with water from the containment floor. In the absence of venting l
j through these holes, flow to the ECCS pumps could be hindered during the l
recirculating phase of a postulated low-of-coolant accident.
The licensee decided to reduce power on Unit 1 to approximately 40 percent to
facilitato a containment entry to determine whether the ventilation holes existed on l
l the Unit 1 sump cover. However, the normal letdown and charging flow path was > l
isolated to support corrective maintenance for a stem packing leak on the low
pressure letdown control valve,1PCV-VC131. This plant configuration temporarily
prevented power reduction through boron concentration changes. 't.icensee
- management decided not to use control rods to effect the power reduction due to !
concerns with unnecessarily increasing the complexity of the evolution and the :
'
potential for operator error. The licensee decided to postpone the power reduction )
- until the maintenance was cornpleted and normal letdown was restored, which was '
!
m
.
18
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4
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expected to be approximately five hours. However, the restoration of normal
, letdown took approximately 11.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> due to delays in completion of the -
j maintenance activities. -
'
After entering the Unit 1 containment, the licensee determined that ventilation
holes were also missing in the Unit 1 recirculation sump cover, in evaluating this
condition far operability and reportability purposee, the licensee assumed that an :
,
expected gap between the sump and the cover plate would provide an adequate
.
vent path. However, the licensee found that the gap did not exist on Unit 1 and
- through a later evaluation, that the gap was not of sufficient size on Unit 2. The
inspectors were concerned that the licensee had initially taken credit for the
existence of a gap in determining operability of the ECCS without verifying the
actual sump configuration. The licensee drilled holes in the Unit 1 and 2 sump
covers to provide the required vent path.
- c. Conclusions
The inspectors concluded that: (1) due to a material condition deficiency on the
'
normal letdown and charging flow path, the licensee delayed action to determine if 1
the Unit 1 sump cover had the required ventilation holes; and (2) the licensee did l
'
not determine if a gap existed in the Unit 2 containment ECCS sump before taking !
'
credit for this gap in the associated sump operability and reportability evaluations.
! -
i
,
. The missing ventilation holes for the Unit 1 and 2 containment recirculation sumps '
is considered an Unresolved item (50-295/96020-09; 50-304/96020-09) pending
l
"
NRC review of the licensee's design change package for drilling the sump cover
l. oles and final assessment of ECCS operability with the holes missing.
, E2.4 Enole 21 Failures
- a. IDADection Scone (37551) -
,
Durirsg this inspection period, several failures of components in the Unit 1 Eagle 21
process protection system occurred. The inspectors reviewed licensee actions in
j response to these failures. The inspectors interviewed engineering and operations
- personnel and reviewed applicable documentation.
b. Observations and Findinas ,
j I
'
Dioital Filter Processor (DFP) Board Failure
.
On December 29,1996, an annunciator alarmed in the control room indicating a
problem with the Eagle 21 protection set 1, rack 1. The licensee determined
through diagnostic testing that a DFP board was faulty. Maintenance technicians
replaced and satisfactorily tested the DFP board. '
,
I
'
19
.
, ,
w- aye-, ,-. -m y -
+ - - - .-- e -
-- - - - -- ----- -
. _ . . . _ _ .. _ . _ _ . . ._ . - . _ _ _ _ . ._ . . . _ . . _ _ ___ ~ . _ . _
,
1
. . .
'
.
.
Hiah AC Rinole Identified on Primary Power Sunolv
1
3'
'
On January 1,1997, Eagle 21 annunciators alarmed for "RCP [ reactor coolant
pump) low flow or RCP breaker trip" for loops A, C, and D and for "PZR
.
[ pressurizer) pressure deviation." The licensee determined that the actuations were 1
4
not caused by an actual plant event, but could not identify a failed component l
, through diagnostic testing.
1-
'
instrument mechanics determined that there was high AC ripple,450mVs, on an i
l Eagle 21 system's 15V primary power supply. However, system engineering ,
personnel determined that the ripple amplitude was within vendor specifications and . j
,i
not of sufficient magnitude to impact equipment operability. After replacing the ,
power supply and completing tests on the channels that had tripped,' the licensee "
returned the affected protection set to service.
On January 6, control room operators noted that indication 1F1-414 (RCS loop "A" l
!
_
flow) was approximately four percent lower than the highest redundant flow
'
.
Indication. The licensee declared the channel inoperable and tripped the associated
bistable. Engineering personnel determined that all outputs from protection set 1,
.
- rack 1 had dropp6d approximately one percent due to the removal of the high AC
l ripple. The vendor subsequently determined through testing that the faulty power
- supply was not the cause of the control room alarms, but that it did affect the
outputs from protection set 1, rack 1. The licensee calibrated the control room
indication on January 7 and restored the bistable to service on January 10.
Low Flow on 1 A Reactor Coolant Loon
L
.On January 15, the licensee tripped the bistable for 1FC-414 again because the
indication was four percent lower than the highest redundant indication. The
system engineer believed that the transmitter for 1FC-414 may have drifted
out-of-tolerance and the licensee, therefore, initiated an action request to calibrate
the transmitter durity 'he next Unit 1 outage.
Faulty DFP Board
l On January 18, the Eagle 21 protection set 1, rack 1 failure annunciator alarmed l
l Four of 20 bistables automatically tripped and cleared. The bistable actuation
resulted in a plant transient which is discussed in Section 03.1 of_ this report. The
licensee could not identify a failed component with the Eagle 21 oystem self-
,
diagnostic feature. I
!
In response to the event, the licensee initiated the following troubleshooting
activities to identify the cause of the alarms and actuations:
7
. adjusted the voltage on the input card to determine the effec l % the output, !
f i
, *
replaced the primary power supply with the backup secoDtary power supply,
20
.
1
. - . . . . -. .. - . . _ . .
, _ _ _ _ - ._ ___ ._ _ .._ ..__. ._ _ _ _ _ ._ _ _
.
'
,
,.
.
- - . ,
- verified the configuration of the DFP board, and
- checked connections to the DFP board and the primary power supply to
J verify electrical contact.
!
!- The licensee did not identify any problems during the troubleshooting activities.
4 However, based on the results of troubleshooting, the system engineer concluded
{ that the most likely cause of the actuation was a faulty DFP board, since all
. Instrument inputs feed into the DFP board and the same board was in place during
i both the January 1 and January 18 events. The system engineer assumed that the
analog portion of the DFP board had failed. The syatem engineer sent the suspect
DFP board to Westinghouse for analysis. Since replacement of the DFP board on
January 22, no other problems with the Eagle 21 process protection system have
- occurred.
t
- c. Conclusion
i'
The inspectors were concerned with the numerous problems exhibited by the
! Eagle 21 system, some of which adversely impacted plant operation. The
- inspectors determined that the involved system engineer was proactive in pursuing
..
resolution of the Eagle 21 system actuations. In response to the Eagle 21 failure on
January 18, the licensee's troubleshooting plan was thorough and well
implemented. ,
E3 Engineering Procedures and Documentation
l
"
E3.1 Review of UFSAR Commitments
The discovery of a licensee operating its facility in a manner contrary to the UFSAR
, description highlighted the need for a special focused review that compares plant
practices, procedures, and/or parameters to the UFSAR descriptions. The
inspectors reviewed the applicable portions of the UFSAR that related to the areas
,
inspected. The inspectors noted the following inconsistencies between the plant
- practices, procedures, and/or parameters:
a. Containment Coatinas Did Not Comolv with the Raouirements of the UFSAR
The inspectors identified that the Unit 2 containment coatings did not meet the
requirements of UFSAR Section 6.3.2.1.3, " Recirculation Phase of Operation."
'
Specifically, the UFSAR required that containmer,t coatings not flake off, go into
- solution, or otherwise provide interference with cooling of the core following a loss
-
of coolant accident. This issue is discussed in Section 02.1 of this report.
,
21
l
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y ,- ,m----- - - ,
, . . . -, w
- . - - - -. -. . - - . - .... .. . ~ . . . - ... ... .. . _ , - _ - - - . _ . - - - - . . ,
l
"
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,
E8 Miscellaneous L@::-bg issues
E8.1 Pressurizer Relief Pinina Stresses and Pine Suonort Loads Optside of the Desian .)
- Basis 1
On January 21, while evaluating a discrrn ancy in the design temperature and -
pressure used in the analysis of pressuri.or relief piping, the licensee identified that, !
j based on preliminary results of the computer analysis, piping stresses and pipe i
support loads could exceed design limits. The licensee subsequently concluded that
the piping stresses and pipe support loads were within operability limits. At the end
a of the inspection period, the licensee was finalizing calculations and implementing a
j design change to ensure that piping stresses and support loads are within design .
limits. This issue is considered an Unresolved item (50-295/96020-10;
4. 50-304/96020-10) pending NRC review of the final calculations and the completed
j modification documentation.
4
E8.2 Pinino Svstems in Containment Possibiv Outside the Deslan Basis Durina a
Postulated Main Steam Line Break (MSLB)/ Loss-of-Cool, ant Accident (LOCA)
On January 24, the licensee notified the NRC regarding its proposed response to
Generic Letter (GL) 96-06, " Assurance of Equipment Operability and Containment
l
'
Integrity During Design Basis Accident Conditions." The licensee indicated that
isolated sections of liquid filled piping which penetrate the containment could
-
experience thermally induced over-pressurization during s postulated MSLB/LOCA,
3
and as a consequence, both units would be outside their design bases.
'
After discussions with the inspectors on January 29, the licensee notified the NRC
that there was also a potential to experience hydraulic transients in service water
piping in containment during postulated accident conditions and consequently,
design stress limits would be exceeded. These issues are considered an Unrusolved
item (50 295/96020-11; 50 304/9602011) pending NRC review of the licensee's
i response to GL 96-06.
i
.
V. Manacoment Meetinaa
X1 Exit Meeting Summary
.
'
The inspectors presented the inspection results to members of licensee
. management at the conclusion of the inspection on February 5,1997. 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.
,
i
22 .
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= , .- . . _ - - . .-. . -.. . . . - . - - - - - - _ _ - _ - - _ _ - - - - - - _ - _ _ - - _ - - - - - - _ _ - -
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- - X3 Management Meeting Summary
The Acting Deputy Director of the Office of Nuclear Reactor Regulation toured the
, Zion facility and met with licensee management on December 18 and 19,1996.
On December 23,1996, and January 3,1997, the NRC bold management meetings .
which were open to the public, with Commonwealth Edison in the NRC Region lii
'
office. Participants discussed the results of the licensee's independent Safety
- Assessment (ISA) at both the LaSalle and Zion Stations. The meeting on January 3 6
2 siso included a discussion of the Zion containment coating deficiencies described in
.i Section 02.1 of this report. The NRC issued meeting minutes for the January 3 ,
i, meeting which were placed in the NRC public document room. During the
l-
'
December 23 meeting, the licensee described the (GA process and emphasized the ;
'
high experience level of the ISA team members. The license > J-*cribed various
plant performance and personnel deficiencies identified durir:; % ISA and ;
discussed the initiative to develop improvement plans. The licensee planned to !
'
'
make the ISA report available to the public.
i
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Partial Ust of Persons Contacted
'
Licensee
J. Mueller, Site Vice President
'
S. Lacey, Plant General Manager
R, Godley, Regulatory Assurarme Manager
T. Patterson, Unit 1 Plant Manager
R. Starkey, Unit 2 Plant Manager
K. Hansing, Unit 1 Operations Manager
G. Vanderheyden, Unit 2 Operations Manager
D. Bump, Unit 1 Maintenance Superintendent
C. Schultz, Training Supervisor
j B. Schramer, Chemistry Supervisor
- T. Kirwin, Work Control Manager
P. Garda, Maintenance Engineering Supervisor ,
K. Moser, Operations Supervisor. l
!
G. Ponce, Electrical Maintenance Supervisor l
W. Stone, Regulatory Assurance Supervisor
.
D. Beutel, Regulatory Assurance
,
n
M. Depas, Chief, Reactor Projects Branch
4
(
f
1
1
1
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i
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24
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- _.- - - - . - .- -. . . .-..-. - - - .- - . - . - - - _ . _ . - -
- -
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[* Ust of inanaction Prae =A=es Used
,,
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IP 37551 Engineering
.i IP 62707 Maintenance Observation
IP 71707 Plant Operations
- IP 93702 Prompt Onsite Response to Events at Operating Power Reactors
List of items Onaned. Closed, and Diann==M
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4 Onened
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i 50-295/304-96020-01 URI Review of the " zone of influence" analysis, transport I
j analysis, evaluation of unqualified paints in the
containment, and not positive suction head loss
calculations for the emer9ency core cooling system j
l pumps
- 50-295/96020-02 VIO Failure to follow abnormal operations procedure for the
- failure of an Eagle 21 protection rack *
50 295/96020-03 VIO Failure to follow the OOS procedure resulted in
inadequate isolation of CS work area , ,
. 50-304/96020-04 URl . Review of the impact of incorrect oil on the operability
{ of the 2B CS pump
50-295/96020-05 VIO Failure to determine the cause of a water intrusion into
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the 1 A AFW pump turbine inboard bearing reservoir
, 50-295/304-96020-06 NCV Failure to test valves as required by the IST program ;
50 295/304-9602047 URI Review the adequacy of boron concentration samples
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with the RHR sample valves wired incorrectly '
l 50-304/96020-08 VIO Failure to implement appropriate design control
measures when conducting a design change on the Unit
i 2 PORVs
i 50-295/364-96020-09 Ual Review of design change package and past operability
'
l assessment for recirculation sump
l 50-295/304-96020-10 URI Review of final calculations and modification
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documentation for the pressurizer relief piping
50-295/304-96020-11 URI Review GL 96-06 response
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- Closed
2
50-295/96017-09 URI Water intrusion into the 1 A AFW pump turbine inboard
- bearing reservoir
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50 295/304-96020-06 NCV Failure to test valves as required by the IST program
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List of Acronyms
AOP Abnormal Operating Procedure
ASME American Society of Mechanical Engineers
DFP Digital Filter Processor '
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ECCS i Emergency Core Cooling Systems
EDG Emergency Diesel Generator
EM Electrical Maintenance '
i FRV Feedwater Regulating Valve
- GL~ . Generic Letter i
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IP Inspection Procedure
ISA independent Safety Assessment
IST Inservice Test
. .. LOCA Loss of Coolant Accident
MM Mechanical Maintenance
MSLB Main Steam Line Break
- NCV Non Cited Violation
NRC Nuclear Regulatory Commission l
OOS Out-of-Service
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PDR Public Document Room
PIF Problem identification Form
PM Preventive Maintenance
- PORC. Plant Operations Review Committee
PORV Power Operated Relief Valve !
! PZR Pressurizer
RCP Reactor Coolant Pump
RHR l
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RWST Refueling Water Storage Tank
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SMAD Systems Material Analysis Department
TS Technical Specifications
UFSAR Updated Final Safety Analysis Report
, URI Unresolved item
US Unit Supervisor
VIO Violation
, ZAP Zion Administrative Procedure
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