ML20137E873
| ML20137E873 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 03/24/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20137E844 | List: |
| References | |
| 50-382-97-02, 50-382-97-2, NUDOCS 9703280285 | |
| Download: ML20137E873 (24) | |
See also: IR 05000382/1997002
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I ENCLOSURE 2
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j U.S. NUCLEAR REGULATORY COMMISSION I
i REGION IV l
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Docket No.: 50-382 ;
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i License No.: NPF-38 !
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l Report No.: 50-382/97-02 l;
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- Licensee
- Entergy Operations, Inc. !
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Facility: Waterford Steam Electric Station, Unit 3 '
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! Location: Hwy.18 l
l Killona, Louisiana !
!; Dates: January 12 through February 22,1997
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inspectors: L. A. Keller, Senior Resident inspector ;
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T. W. Pruett,- Resident inspector ,
. G. A. Pick, Project Engineer ;
G. E. Werner, Project Engineer
i Approved By: P. H. Harrell, Chief, Project Branch D !
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Attachment: Supplemental Information !
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9703280285 970324 "'
PDR ADOCK 05000302
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EXECUTIVE SUMMARY 1
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Waterford Steam Electric Station, Unit 3 ,
f NRC Inspection Report 50-382/97-02
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This routine, announced inspection included evaluating aspects of licensee event response, !
- operations, maintenance, engineering, and plant support. The report covers a 6-week !
period of resident inspection. I
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Ooerations
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Observed operations activities were generally performed in a manner consistent
- with safe operation of the facility (Section 01.1).
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On January 22,1997, operations identified in Condition Report (CR) 97-0164 that l
certain emergency operating procedure (EOP) steps could not be implemented as
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written. The inspectors identified that this same issue was documented in a
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Problem Evaluation /Information Request (PElR) on January 12,1995. Operations '
l failed to aggressively pursue an issue involving potentially inadequate EOPs for over
j 2 years (Section 03.1).
i On February 11, relay failures in the vital 125-Vac system resulted in voltage
transients, which in turn resulted in the temporary loss of some important plant
j equipment. Operator performance following the voltage transients was good in that
j the lost loads were quickly identified and restored. The initial corrective actions
- appeared adequate. The adequacy of vital 125-Vac breaker coordination is
i unresolved pending further NRC review (Section O2.1).
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l Operator response to a nearby chemical spill and declaration of an Alert was
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conservative and consistent with the Emergency Plan (Section 04.1).
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l The discovery of a nitrogen pocket in Low-Pressure Safety injection (LPSI) Train A
} necessitated the modification of certain shutdown cooling flex-wedge gate valves !
, - because of pressure locking concerns. The potential impact on operability because
i of the existence of nitrogen pockets in both trains of LPSI remains unresolved
! pending further NRC review (Section M2.2).
l Maintenance
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! * Observed maintenance and surveillance activities were generally performed in
i accordance with procedures and achieved acceptable results (Section M1.1).
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expanded beyond previously established acceptance criteria. The licensee
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implemented a special test that resulted in smaller nitrogen pockets in both LPSI
j trains. The adequacy of the special test to meet the intent of Technical
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Specification (TS) Surveillance Requirement 4.4.2.j remains unresolved pending
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further NRC review (Section M2.2).
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- Mechanics utilized incorrect torque values during emergency diesel generator (EDG)
air start check valve maintenance activities that damaged a check valve. Separate
work crews derived different, incorrect torque values for the same application from
the same generic torque procedure. Additionallyi the peer quality control inspectors
involved in these activities concurred with the incorrect torque values. The failure
of mechanics and quality control personnel to correctly utilize the fastener torquing
procedure has potential generic implications. This issue is an unresolved item
pending further review to assess the adequacy of the scope and depth of the
licensee's corrective actions (Section M3.1).
Enaineerina
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- Management oversight and ownership of the PEIR process was poor. Breakdowns '
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in the tracking process resulted in the inability to identify the status of over 100 i
PElRs. Response due dates typically elapsed without any followup. Coupled with
the insights gained from the review of the engineering input process, the inspectors
concluded that the processes for managing engineering work were weak. Because ;
of the inability of the licensee to produce the open PEIRs for review, the inspectors !
were unable to determine if there were any safety concerns associated with open l
PElRs. This issue is an unresolved item pending further NRC review (Section E1.1).
Plant Suocon 1
- inadequate oversight during movement of radioactive material between storage '
locations resulted in two violations; one involving the failure to perform radiation I
surveys and another the failure to properly label containers of radiological material j
as " CAUTION, RADIOACTIVE MATERIAL" (Section R1.1). )
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Report Details
Summarv of Plant Status
The plant operated at essentially 100 percent power throughout this inspection period. An
Alert was declared on January 18,1997, following reports of a nearby chemical spill.
l. Operations
01 Conduct of Operations
01.1 General Comments (71707)
The inspectors performed frequent reviews of ongoing plant operations, control
room panel walkdowns, and plant tours. Observed activities were generally
performed in a manner consistent with safe operation of the facility. Operators l
responded well to a nearby chemical spill and vital 125-Vac electrical transients.
Housekeeping and material condition were generally good. Operators were familiar
with causes for lit control room annunciators. Shift turnover and plan-of-the-day ;
meetings were professional and information. However, some activities sppeared to I
be in violation of NRC requirements or indicate problem areas, as discussed below.
O2 Operational Status of Facilities and Equipment ,
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O2.1 Static Uninterruotible Power Sucolv (SUPS) SA Voltaae Transients l
a. Insoection Scope (71707,37551)
The inspectors reviewed the circumstances associated with SUPS SA voltage
transients, which occurred on February 11,1997. ,
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b. Observations and Findinas
On February 11 at 9:31 p.m. (CST), the control room received a SUPS SA trouble i
alarm, as well as numerous other annunciators and indications of equipment status l
change including: (1) letdown isolated, (2) instrument air supply to containment l
isolated, (3) Essential Chiller A tripped, and (4) Component Cooling Water (CCW)
Train A isolated from the rest of the system. The operation staff quickly restored
the affected equipment to normal status and no TS requirements were violated.
The initial investigation revealed that the voittge level on the output side of
SUPS SA dropped momentarily and that Breaker 34 in Power Distribution Panel
(PDP) 90A tripped. Breaker 34 supplies several engineered safeguard features
actuation system Train A isolation relays. Approximately 11 minutes after the first l
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alarm, another SUPS SA trouble alarm annunciated and the licensee found PDP 90A
Breaker 44 tripped. Breaker 44 supplied fuel handling building emergency filtration
components.
Following initial troubleshooting activities, which included a megger test of
Breaker 44, the licensee attempted to shut Breaker 44, which resulted in another
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voltage transient on SUPS EA and the immediate trip of Breaker 44. This was '
unexpected since the megger test of Breaker 44 did not reveal a faulted condition
on the breaker or downstream loads. Plant systems responded to this voltage
transient in the same manner as the first event. Subsequently, the licensee
performed detailed troubleshooting on the electrical system and identified failed
isolation relays on both circuits associated with Breakers 34 and 44.
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The inspectors reviewed the SUPS voltage transient episodes to determine if the e
system responded as designed and if any operability concerns existed. In addition, l
the inspectors reviewed the Undated Final Seiety Analysis Report (UFSAR), circuit l
prints, and Vechnical Manual 457000005, " Isolation Panels (Relays and Switch
Kits)," Volume 1; and verified that the loads that were lost as a result of the voltage
transients were powered from the affected PDP. The inspectors determined that
there was not an immed' -te operability concern but noted that Breakers 34 and 44
failed to clear downstream faults prior to the PDP bus voltage dropping to
unacceptably low levels. i
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The licensee personnel established a team to review the SUPS SA event with plans f
to review system response, breaker coordination, and relay reliability. The team j
leader stated that both failed isolation relays would be sent to a testing facility for :
failure analysis. The team leader indicated that a root cause analysis would be j
completed for this event. i
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The licensee identified two theories for the SUPS SA trouble: (1) the isolation relay {
shorted causing excessive current load that caused SUPS SA to go into the !
current-limit mode, which reduced SUPS SA output voltage to levels that allowed
individual loads to drop off on low voltage; and (2) the fault caused currents in ,
excess of the inverter trip current and the entire inverter tripped. Subsequently, j
after losing the faulted load, the inverter immediately restored power to the )
remaining loads.
The inspectors did not identify any immediate operability concerns; however, the
inspectors ezpressed concern regarding SUPS breaker coordination. The adequacy
of vital 125J/ac breaker coordination is unresolved pending further NRC review
(50-382/9702-01).
c. Conclusions
Operator performance following the SUPS voltage transients was good in that loads i
that were lost were quickly identified and restored. Plant system responses were
consistent with faults on the affected PDP. The initial corrective actions appeared
adequate. A concern for additional followup was identified regarding SUPS breaker
coordination.
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03 Operations Procedures and Documentation
03.1 EOP issues Associated With Primarv and Secondary Samolina
a. insoection Scoce (71707,37551)
On Janutry 22, CR 97-0164 documented that the primary and secondary sample
coolers would not be available as required by the EOPs. The inspectors assessed
the adequacy of the EOPs relative to sampling and reviewed the history of this
issue.
b. Observations and Findinas
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in November 1996, the Combustion Engineering Owners Group approved Revision 4
to CEN-152, " Emergency Procedure Guidelines." Subsequently, the licensee
initiated a review of CEN-152, Revision 4, with the goal of eventually converting the
current EOPs to conform with Revision 4. During this review, operations personnel
identified that certain CEN-152 steps, which required steam generator and reactor
coolant system (RCS) sampling following a loss-of-coolant accident (LOCA) or
steam generator tube rupture (SGTR), could not be implemented as specified. The
steps could not be implemented because the CCW supply to the primary and
secondary sample coolers isolates on a safety injection actuation signal (SIAS) and
the CCW valves can not be opened because the SIAS can not be overridden. The
operators also noted that the current revision of the EOPs had similar steps requiring l
primary and secondary sampling following a LOCA or SGTR. CR 97-0164 was i
written to evaluate the potential inability to implement these steps, as written.
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During subsequent interviews with operators, the inspectors learned that the
potential inability to take sample: following a LOCA or SGTR was a known problem
that had been previously identified. Licensee management later identified that
PElR OM 84, initiated January 12,1995, stated: " Currently our EOPs require us to
draw a sample from the RCS or the steam generator during the procedure. In most
cases, the CCW to the sample coolers has been isolated due to SIAS/CIAS and the
valves cannot be opened until SIAS is reset. Since SlAS reset may not occur for
quite a while, it is unlikely we will be able to draw a sample for a long time. Since
we need to check RCS boron for Emergency Boratio.1 termination criteria and
Shutdown Margin checks and SG samples for activity to verify which steam
generator has a SGTR, we need some method of being ab!3 to draw a sample
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requests that Engineering devise some alternate method of supplying cooling water
to the sample coolers."
PEIR is a process used by the plant staff to request engineering assistance for
- resolving technical problems that do not meet the threshold for a CR. The
- inspectors concluded that it was inappropriate to use PElR in lieu of a CR for an
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issue involving the adequacy of EOPs. PEIR OM-84 was initially sent to engineering
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in January 1995, then forwarded to chemistry in February 1995, but remained open )
as of January 1997. The licensee could not determine why a CR was not issued for )
this issue in January 1995. The inspectors noted that the procedure for initiating l
CRs in January 1995, Procedure UNT-006-011, Revision 1, " Condition Reports," l
Section 4.1, required, in part, that individuals identifying an adverse condition
initiate a CR.
Following the January 1997 rediscovery of the EOP issue, the licensee contacted
Combustion Engineering to research the basis for the EOP steps requiring sampling. ,
The licensee stated that they were informed that the EOP steps in question were !
diagnostic in nature and that, if they were unable to take a sample, other sources of
information existed upon which to base decisions. As of the end of this inspection 1
period, the licensee was pursuing deletion of the EOP steps requiring primary and
secondary sampling. Until the procedure steps could be deleted, the licensee was j
adding a note to the steps requiring primary samples to use the postaccident j
sampling system as an alternate RCS sampling system if SlAS is not reset. The ;
inspectors verified that there were other sources of information, in lieu of sample i
results, available to the operators for the EOP steps involved. I
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c. Conclusions i
Operations personnel f ailed to initiate a CR in January 1995 when they first became
aware of the potential inability to implement EOP steps. Operations ownership of
this issue was lacking in that the issue remained unaddressed for over 2 years.
04 Operator Knowledge and Performance
04.1 Nearbv Chemical Soill and Declaration of Alert (93702. 71707)
On January 18, a tanker carrying pyrolysis gasoline ran aground 10 miles north of
Waterford 3 at 1:45 a.m. (CST) and spilled a portion of its cargo into the Mississippi i
River. The licensee was notified of the spill at 3:17 a.m. by the St. Charles Parish
Emergency Operations Center and later at 3:48 a.m. by the U.S. Coast Guard. At
4:05 a.m. the control room staff isolated the control room air intake and entered
off-normal Procedure OP 901-520, " Toxic Chemical Release." After evaluating the
event, the licensee declared an Alert at 4:20 a.m. and, as a precautionary measure,
onsite personnel were sheltered. No detectable airborne chemical concentrations
were identified on site. The licensee subsequently determined that the spill did not
impact site equipment or personnel.
The Coast Guard initially estimated that 250,000 gallons of gasoline was released;
however, followup communications indicated that only 4,400 gations was released.
At 6:05 a.m., following a Coast Guard report that the spill was no danger to
Waterford 3, operations personnel downgraded the Alert to an Unusual Event at
6:21 a.m. and terminated the shelter order. The event was terminated at 7:20 a.m.
The inspectors responded to the site and reviewed the actions taken by the licensee
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to respond to the event. The inspectors concluded that the declaration of Alert was
conservative and that the spill did not adversely affect the plant.
08 Miscellaneous Operations issues (92901)
08.1 (Closed) Violation 50-382/9510-01: Failure to ensure that TS requirements
properly translated into a standing instruction. On November 30,1995, the 1
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inspectors determined that the guidance identified in Standing Instruction 95-13
was less conservative than the requirements specified in TS 3.7.4, Table 3.7-3,
" Ultimate Heat Sink Minimum Fan Requirements." Specifically, the guidance would
have allowed removing three dry cooling tower fans from service below 92.8 F,
instead of the TS-specified 90 F (dry bulb) and 81 F (wet bulb). The licensee ,
attributed the root cause to poor engineering review of regulatory requirements and I
a failure of the operators to compare the guidance provided by the Engineering
organization to TS requirements.
The inspectors confirmed that the licensee implemented the following corrective
actions: (1) incorporated the corrected standing instruction guidance into
Procedure OP-100-014, " Technical Specification Compliance," Revision 4;
(2) presented the lessons learned from this event to design engineering and j
operations personnel; and (3) revised Procedure 01-016-000, " Daily Instructions and l
Standing Instructions," Revision 5, to enhance the guidance to operations personnel l
for issuing standing instructions.
fl. Maintenance
M1 Conduct of Maintenance
M 1.1 General Comments
a. Inspection Scoce (62707. 61726)
The inspectors observed all or portions of the following maintenance and
surveillance activities:
Penetration
- WA 01152830 Bench Test Charging Pump AB Discharge Rel:ef Valve
- WA 01155969 Replace Failed Electroswitch Control / Latching Relay
b. Observations and Findinas
in general, the inspectors found the conduct of maintenance and surveillance to be
good. All activities observed were performed with the work authorization (WA)
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package and/or test procedures present and in active use. Technicians were
experienced and knowledgeable of their assigned tasks. When applicable,
I appropriate radiation control measures were implemented. The inspectors observed
supervisors monitoring job progress and quality control personnel were present
whenever required by procedure.
M2 Maintenance and Material Condition of Facilities and Equipment
M 2.1 SUPS SA PDP-90A Circuit Breaker 44 Testina and Circuit 44 Isolation Relav
Reolacement (62707)
On February 12, the inspectors observed portions of the testing of Circuit
Breaker 44 and troubleshooting and replacement of the Circuit 44 isolation relay.
During the performance of the activities, an electrical maintenance supervisor was
present to observe the maintenance, in addition, the system engineer observed
portions of the activities.
Initially, troubleshooting of PDP-90A Circuit 44 was conducted under Work
Authorization (WA) 01117733. The technicians identified that Isolation
Relay ARM-EREL-2685A (fuel handling building radiation monitor) failed, which
caused a short circuit. The other components / loads downstream of Breaker 44
were tested and found to be acceptable.
Subsequently, WA 01155969 was initiated to replace the failed isolation relay and
to test Breaker 44. The work was performed in accordance with
Procedure ME-OO7-005, " Testing Procedure Electroswitch Control / Latching Relay,"
Revision 4, and Procedure ME-007-002, " Testing Procedure Molded-Case Circuit ,
Breaker," Revision 11. !
The inspectors observeri the technicians shop test the replacement isolation relay,
remove the failed relay, and test Breaker 44. The technicians followed the
procedures and used good maintenance practices during the performance of the
activities.
M2.2 Nitroaen Pockets in LPSI Pipino
a. Insoection Scope (71707. 61726)
The inspectors reviewed the circumstances regarding the expansion of the nitrogen
pocket at Penetration 39 and observed the special test on February 22 that
performed a vacuum fill of LPSI Penetration 39.
l b. Observations and Findinas
NRC Inspection Report 50-382/96-14 discussed LPSI system water hammer events
and the existence of nitrogen pockets in LPSI Train B in the sectiori of piping that
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penetrates containment. The nitrogen pockets could not be vented because no vent
valves existed in the affected piping and the inability to flush the affected piping at j
power. The licensee evaluated the existing nitrogen pockets and concluded that a
water hammer, with a pressure wave slightly in excess of system design pressure,
would occur following a SlAS. The licensee concluded that such a water hammer
would not prevent LPSI from injecting into the RCS since past LPSI water hammer i
events did not result in any component / piping / system damage. The licensee did,
however, modify certain LPSI Train B shutdown cooling flex-wedge gate valves
because of concerns regarding pressure locking following a water hammer. The
review of the LPSI water hammer events and concerns related to the existence of ,
nitrogen pockets was previously identified as an unresolved item pending further I
NRC review (50-382/9614-01). I
Following the discovery of nitrogen pockets in December 1996, the licensee
performed periodic ultrasonic testing (UT) to monitor the size of the LPSI Train B
pockets and determine if pockets were forming in the Train A piping. On
January 27, UT revealed a new nitrogen pocket in the LPSI Train A pipe at
Penetration 38. This pocket measured 4 inches of arc (0.8 cubic feb.) and could
not be vented or flushed at power. Upon discovery of the Train A gas bubble, the
licensee modified the Train A flex-wedge gate valves. Additionally, the licensee
completed an operability analysis (CR 97-0200) that established a void size of i
8 inches of arc as acceptable, using the same rationale as the analysis for the !
Train B nitrogen pockets.
On February 21, after perforrr.ing maintenance on Flow Control Valve Sl-138A, UT I
revealed that the 21-foot horizontal run of pipe at Penetration 39 was completely
voided and that the void extended down the upstream vertical section of pipe for
about 84 inches. The 72-hour action for TS 3.5.2 had been entered on
February 20, at 9:57 a.m., for LPSI Train A being inoperable for the maintenance on
Valve Sl-138A. The licensee concluded that the significant increase in void size .
resulted from leaving Valve SI-138A open for several hours, which decreased the l
pressure in the affected piping, and in turn, allowed nitrogen to leave solution. As
of the end of this inspection period, the licensee did not have an evaluation
documenting the rate of nitrogen leaving solution following the opening of a flow
control valve. The rate of nitrogen pocket expansion after opening a LPSI flow
control valve will be reviewed during followup of Unresolved item 50-382/9614-01.
TS Surveillance Requirement 4.4.2.j requires venting of the emergency core cooling
system pump casings and discharge piping high points following maintenance that
drains part of the system. On February 21, the licensee concluded that TS
Surveillance Requirement 4.4.2.j was not properly completed following past
maintenance activities since nitrogen pockets existed in the LPSI penetration high
points and no attempt had been made to vent (no vents exist at these locations) the
piping. At 8 p.m. on February 21, TS 3.0.3 and 4.0.3 were entered because
operators could not perform TS Surveillance Requirement 4.4.2.j on LPSI Train B,
which made Train B inoperable under TS 3.5.2 until the surveillance was completed,
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coincident with Train A remaining inoperable because of the nitrogen pocket at
Penetration 39. TS 3.0.3 requires that within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action be initiated to place the
unit in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. However, TS 4.0.3 allows the action
requirements to be delayed up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to complete the surveillance.
Special Test Procedure (STP) 01156545, " Vacuum Fill of LPSI Penetration," was
developed to vent the affected LPSI piping using the installed drain valve.
STP 01156545 and its attached 10 CFR 50.59 screening evaluation were reviewed
and approved by the Plant Operations Review Committee on February 22. The STP
required the connection of a vacuum pump to Drain Valve SI-1401 A at
Penetration 39, evacuation of the nitrogen gas to 28 inches vacuum, and slowly
opening Valve SI-138A, which would admit water under pressure from the static
head of the refueling water storage pool. The test procedure established an
acceptance criteria of no greater than a 8-inch etc in the LPSI piping at Containment
Penetration 39.
The inspectors observed the performance of STP 01156545 on February 22. The
inspectors noted that the prejob brief for this test was good and that the test was )
performed in accordance with the procedure. At the completion of the 'est, there
remained a 7-inch arc, which met the acceptance criteria; however, the licensee
reperformed the test in an attempt to further reduce the arc. The second test i
iteration resulted in a 4-inch arc. The licensee performed several followup UT and
verified the arc did not subsequently expand. Although a void still remained at
Penetration 39, the licensee concluded that the vacuum fill met the intent of TS
Surveillance Requirement 4.4.2.j for LPSI Train A and exited TS 3.0.3 and 4.0.3.
The licensee subsequently completed the vacuum fill for the two LPSI Train 8
penetrations, which reduced the size of the nitrogen pockets as follows:
(1) Penetration 36 arc went from 11 to 6 inches and (2) Penetration 37 arc went
from 10 to 7 inches.
The inspectors noted that the Waterford 3 Safety Evaluation Review stated, "During
normal operation, the emergency core cooling system lines will be maintained in a
filled condition. Suitable vents are provided and administrative procedures will
require that emergency core cooling system lines be returned to a filled condition
following events such as maintenance that require draining of any of the lines.
Maintaining the lines in a filled condition will minimize the likelihood of water
hammer occurring during system startup." Review of the adequacy of
STP 01156545 to meet the intent of TS Surveillance Requirement 4.4.2.j remains
unresolved pending further NRC review (50-382/9702-02).
c. Conclusions
The concerns regarding the impact of failure to maintain the lines in a filled
condition on operability of the LPSI system remain unresolved pending further NRC
review. The adequacy of the vacuum fill procedure to meet the intent of TS
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Surveillance Requirement 4.4.2.j is a new unresolved item pending further NRC
review.
M3 Maintenance Procedures and Documentation
M3.1 EDG Fastener Torauina Errors (62707)
On February 3, mechanics replaced the EDG B air start check valves. During
installation of the replacement check valves, the outlet flange for Valve EGA161B ,
cracked because mechanics over-torqued the 3/4-inch bolts. The licensee '
subsequently determined that the correct torque value was95-110 ft-lbs, whereas
the craft used 250 ft-Ibs. The licensee determined that mechanics over-torqued the
other EDG B air start check valve (160 ft-Ibs) and both EDG A air start check valves I
(160 ft-lbs) on January 28. J
The work packages for the EDG air start check valve replacement activities
referenced Procedure MM-001-068, Revision 0, " General Torquing and
Detensioning Practices," which established generic torque values based on the i
fastener material. Section 5.2.1.1 of MM-001-068 stated, in part, if no torque l
values are given in approved procedures, work instructions or vendor information, '
then determine torque values by using Attachments to this procedure as follows:
(A) for flange connections with spiral wound gaskets use Attachment 6.6; for other
gasket materials, use Attachment 6.7 or (B) for metal-to-metal connections, use
Attachment 6.5.
On January 28, the craft personnel performing the check valve replacements on
EDG A looked but did not find the torque value in the EDG technical manual for the
check valve fasteners. The craft then inappropriately utilized Attachment 6.7 of
Procedure MM-001-068 resulting in the use of 160 ft-lbs of torque.
Attachment 6.7 lists torque requirements for bolt material A-307.B, A-193.B-7,
A-564.630, and A-193.B-8. Since the botting material was ASTM A-449 SAE
Grade 5, Attachment 6.7 was not applicable. On February 3, two different work
crews were replacing the EDG B check valves. One crew was working on Valve
EGA16? B, while the other crew was simultaneously working on Valve EGA 1628.
The crew working on Valve EGA 162B also inappropriately used Attachment 6.7
resulting in a torque of 160 ft-lbs. The crew working on Valve EGA 1618, decided
inappropriately that Attachment 6.5 was the appropriate reference. Attachment 6.5
listed 250 ft-Ibs as the appropriate torque value for 3/4-inch Grade 5 bolts, but was
intended for metal-to-metal connections only.
For both the January 28 and February 3 activities, " peer" quality control inspectors
concurred with the incorrect torque values. The NRC inspectors verified that the
peer quality control inspectors involved were certified as quality control inspectors.
When the mechanics applied 250 ft-lbs to the Valve EGA161B outlet flange, they
noted that the flange cracked. The mechanics contacted maintenance management
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and generated CR 97-0267. The licensee subsequently determined that the correct
torque value, as listed in the vendor technical manual, was95-110 ft-lbs. l
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- The licensee replaced the cracked check valve on February 3. The licensee
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concluded that the remaining over-torqued check valves did not represent an 1
operability concern. The check valves were appropriately retorqued during
subsequent EDG train outages. The inspectors agreed that the over-torqued check
valves did not represent an operability issue but were concerned with the generic
implications associated with the craft's apparent inability to appropriately utilize
Procedure MM-001-068. As of the end of the inspection period, the licensee was
still researching other maintenance tasks which utilized Procedure MM-001-068 in
an attempt to determine if other components were inappropriately torqued.
Additional reviews of the licensee's corrective actions will be performed to l
determine if all aspects of this issue have been addressed. This issue remains
unresolved pending the NRC's review of the licensee's actions (50-382/9702-03).
M8 Miscellaneous Maintenance issues (92902)
M8.1 (Closed) Inspection Followuo item 50-382/9504-05: Review chilled water stroke
time test methodology and stroke time test results. This item was initiated to
ensure review of changes to the stroke test methods (or chill water valves. The
inspectors verified that the licensee changed Procedure OP-903-118, " Primary
Auxiliaries Quarterly IST Valve Test," Sections 7.2 and 7.3, to eliminate
preconditioning prior to stroking the valves in their safety actuation position (e.g.,
normally open/ throttled valves were closed then timed open if the safety function
was to open). Also, the licensee altered the test locations for valves that are
" conditioned" by the plant computer to eliminate any bias the control circuit had on
the stroke time.
As long-te.rm corrective actions, the inspectors determined that engineering
developed Design Change 3468, " Essential Chilled Water Chemistry
improvement /NNS Train Relocation to the Supplemental Chilled Water System,"
Revision O. This design change should eliminate stagnant water that resulted in
corrosion product buildup and reduced cooling flow through safety-related air
handling units. Design Change 3468 realigns the nonsafety-related portion of the
chilled water system to the supplementary chiller system (also nonsafety). This
reduces the loads supplied by the essential chiller units and allows increased flow
through the safety-related air handling units. The licensee intended to fail-open the
air handling unit throttle valves to achieve the increased flows. After completing
the postmodification flow balance test, the design change alters the throttle valves
to " passive" failed-open, which eliminates the need to perform inservice stroke time
tests on the valves.
M8.2 (Closed) Violation 50-382/9607-01: Failure to follow procedures involving
mechanical retests, surveillance testing, and acceptance criteria. This violation
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involved failure to (1) perform mechanical retests following maintenance, (2) adhere '
to limitations during surveillance testing, and (3) meet acceptance criteria.
In response to the failure to perform mechanical retests for maintenance affecting
control room envelope door seals, the licensee (1) revised Procedure MM-006106, i
l " Plant Door Maintenance," to perform a pressurization test on the envelope _
l following door maintenance, (2) reviewed maintenance activities involving airlock
doors for the controlled ventilation area system and the fuel handling building, and
l (3) replaced pressure boundary testing engineering procedures with operations TS
pressure boundary procedures. !
In response to the failure to ensure surveillance test parameters were established
during control room pressurization, the licensee counseled personnel responsible for
performing the test and revised the pressurization test procedure to ensure the test '
pressure was maintained during the test or the intake flow results normalized to the ;
- pressure band described in the procedure. In response to the failure to verify
acceptance criteria are met, the licensee reviewed the maintenance procedure and i
determined that the requirement to perform a chalkline test on control room I
envelope doors was incorrect and revised the procedure to remove the acceptance
criteria. ],
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M8.3 (Closed) Violation 50-382/9611-03: Inadequate test procedure results in a water '
hammer during system restoration. This violation resulted from work instructions
that failed to provide explicit information for system restoration, which resulted in a
water hammer of the auxiliary CCW system. Although the oncoming control room
operators were notified that the system could be restored, weak communication
resulted in the failure to return the loop setpoint to " normal." The licensee
attributed personnel error by planning personnel during package development as a
contributing root cause.
The inspectors reviewed the corrective actions described in their violation response,
which included: (1) providing additional guidance in the maintenance planner's
guide to specify that precautions, limitations, and acceptance criteria, in procedures
must be transferred to work instructions if other portions of the procedure are
referenced; (2) reviewing the method of performing operator shift turnovers, which
identified no required changes; however, the review did identify some
enhancements that were undergoing management review; (3) reiterating
management expectations for what will be discussed during prejob briefs,
particularly work step sequence and reliability risks or impact statements; and
(4) reviewing other control loop calibration procedures for similar setpoint
restoration weaknesses.
M8.4 (Closed) Unresolved item 50-382/96202-15: Adequacy of American Society of
Mechanical EngineersSection XI test for CCW fail-safe valves. Inspectors identified
this same item as Violation 50-382/9624-02 in NRC Inspection
Report 50-382/94-24, Section M1.1. NRC issued the violation on January 9,1997.
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M8.5 (Closed) LER 50 382/95-004: Noncompliance with TS surveillance requirements
because of an inadequate procedure. On September 7,1995, quality assurance
, personnel assigned responsibility to operations to resolve the apparent discrepancies
among Procedures OP-903-013, " Monthly Channel Checks," UNT-OOS-026,
" Technical Specification Component Tables," and Regulatory Guide 1.97,
" Instrumentation for Light-Water-Cooled Nuclear Plants to Assess Plant Conditions
During and Following an Accident," Revision 3. This issue was originally identified
in December 1993 and documented in CR 93-0294. The licensee immediately
initiated a review to confirm that the containment isolation valve position indications
functioned by performing the surveillance test. The licensee initiated a root cause
assessment to determine the cause for the delay in resolving the issue and to
i determine the cause for the discrepancy. The licensee documented the root cause
evaluation in CR 95-0758. !
The licensee determined that personnel had failed to perform the required l
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containment isolation valve position indication verifications as required by
TS 4.3.3.6, " Post Accident Monitoring instrumentation." The licensee assigned the
most probable root cause as inadequate technical verification during original
development of the postaccident monitoring instrumentation test procedure.
Corrective actions for the failure to include all the postaccident monitoring
instrumentation in Procedure OP-903-013 included performing a detailed technical
review of all postaccident monitoring instrumentation requirements. This
licensee-identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the
violation was identified by the licensee, was not willful, actions taken as a result of
a previous violation should not have corrected this problem, and appropriate
corrective actions were completed by the licensee (50-382/9702-04).
M8.6 (Closed) LER 50-382/96-008: Loss of chemical volume control charging flow. On
June 6,1996, with Charging Pump AB operating, operators started Charging
Pump B and noted that charging flow indication decreased to O gpm. The operators
immediately secured Charging Pump B but charging flow remained at O gpm.
Subsequently, when operators started Charging Pump B and secured Charging
Pump AB, charging flow returned to 44 gpm. The licensee determined that a
pressure spike lifted Relief Valve CVC-192AB and suspected that the pump
discharge check valve failed to close. Operators subsequently started Charging
Pump A and tagged Charging Pump AB out-of-service so that they could investigate )
this loss of charging flow. Mechanics found the setpoint of Relief
Valve CVC-192AB approximately 300 psi below the required setpoint of 2735 psi. l
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The licensee established a root cause investigation team to identify the root cause,
event sequence, and required corrective actions for this event.
On June 16 with Charging Pump B operating, Relief Valve CVC-1928 lifted when
operators started Charging Pump A. The system flow increased from 44 gpm to
46 gpm instead of the expected 88 gpm. Operators secured Charging Pump A and !
flow decreased to 2-4 gpm. Subsequently, when operators started Charging
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Pump A and secured Charging Pump B, charging flow returned to 44 gpm. The I
licensee incorporated this second incident into the previously established root cause ;
investigation. Relief Valve CVC-1928 lifted when the pump start caused entrapped
air under the valve seat to flow through the valve. The air became entrapped )
following maintenance. Relief Valve CVC-192AB lifted because of setpoint drift I
(~ 2400 versus 2700 psig - cause unknown) and a degraded pulsation dampener.
The pulsation dampener failed to decrease the amplitude of the pressure spikes
because of the loss of elasticity.
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The corrective actions to prevent recurrence included: (1) installing a vent valve
upstream of the relief valve; (2) replacing the relief valves with a different model
without bellows; (3) initiating quarterly relief valve set pressure tests to trend for l
evidence of setpoint drift problems; (4) establishing increased preventive I
maintenance on the pulsation dampener bladder; and (5) modifying the nitrogen
Schrader valve to allow on-line filling and measurement of bladder pressure.
The inspectors confirmed that the licensee had replaced the relief valves, )
established 60-month preventive maintenance tasks to replace the pulsation '
dampener bladder, installed vent valves, and scheduled the installation of the i
nitrogen fill schrader valves. The inspectors confirmed that the licensee established
a work authorization to replace the nitrogen fill schrader valves but delayed
installation instructions until parts were received. The inspectors reviewed the work
packages for the Train A relief valve replacement and vent valve installation and
identified no problems.
The licensee concluded that since each relief valve relieves a maximum of 65 gpm,
both Relief Valves CVC-192AB and CVC-192B must have lifted during these events
for the charging flow to decrease during the first event. Since both relief valves
lifted, the inspectors confirmed that a total loss of charging flow occurred and
would not have been available during a small break LOCA. The Waterford 3 small
break LOCA analysis credits flow from one charging pump. During the initial part of
the small break LOCA, the RCS pressure is above the high pressure safety injection
pump shutoff pressure, and only charging pumps can provide flow. The inspectors I
reviewed the consequences of lack of charging flow during the time when RCS I
pressure is above the shutoff head of a high pressure safety injection pump. The
inspectors determined that no accident analysis acceptance criteria would have
been exceeded because of a lack of charging flow. ;
The loss of charging flow violated TS 3.1.2.4 because operators lost tt" "' 'y to
inject borated water for approximately 2 minutes, independent review N 3
inspectors confirmed that this event had low safety significance. This
licensee-identified and corrected violation is being treated as a noncited violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the
violation was identified by the licensee, was not willful, actions taken as a result of
a previous violation should not have corrected this problem, and appropriate
corrective actions were completed by the licensee (50-382/9702-05).
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Ill. Enaineerina
l E1 Conduct of Engineering
j E1.1 Review of PEIR Process
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a. insoection Scoce (37551)
! Because of concerns related to PElR OM-84, discussed in Section 03.1 of this I
report, the inspectors attempted to review the other open PElRs.
2 b. Observations and Findinas
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Site Directive W5.602, " Problem Evaluation /Information Request," describes the
process for personnel to request engineering assistance to resolve technical
matters. The PElR process was not intended to be utilized for resolution of
operability issues, conditions adverse to quality, or other matters requiring a CR.
On January 12,1995, PEIR OM-84 was written by operations to document a
concern regarding the apparent inability to take EOP required samples postaccident.
PElR OM-84 was forwarded to engineering for disposition with a requested due date
of February 28,1995.
As of January 1997, a response had not been provided for PElR OM-84 when the
issue was rediscovered during an EOP review. The inspectors subsequently
requested c3 pies of all the other open PElRs on January 23, in order to determine if
there were other issues that were not adequately addressed. During the inspection
period, the licensee provided 70 PEIRs for review, which included 46 that exceeded
their " response required by" date in some cases the open PEIRs were over 5 years
old. The licensee also indicated that there were over 100 additional PElRs that they
could not determine the status of, which might also be open. In some cases no
copy of the PElR existed; for some the records indicated engineering had responded
but the requesting organization did not have a record of receipt, and for others there j
was a record of receipt but no indication of whether the answer had been accepted.
As of the end of the inspection period, the licensee was still attempting to
determine how many PEIRs were open and their status. The inspectors noted that
the PElR process was deficient in that: (1) there was no requirement for followup
when a PElR response due date elapsed, (2) the licensee could not determine the
status of numerous PElRs, (3) personnel routinely bypassed the appropriate " Log
Coordinator" thereby defeating the established tracking r 'echanism, and (4) licensee
management was unaware of the status of the program. )n January 30,1997, the
licensee initiated CR 97-0317 to document the apparent breakdown in the PElR
process.
The inspectors performed a cursory review of the PElRs provided and were
concerned that several of the open PElRs involved issues that potentially required
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prompt resolution and therefore may not be adequately addressed. The inspectors
were unable to resolve these concerns within this inspection period. The review of
open PElRs and the issue related to not writing a CR for a nonconforming item ,
identified by a PElR, as discussed in Section 03.1, are an unresolved item pending !
further NRC review (50-382/9702-06).
NRC Inspection Report 50-382/9605 documented concerns with the Engineering
input process. The report documented that: (1) no method existed to track the
number of current Engineering inputs, (2) the licensee could not specify which
safety-related structures, systems, and components may have been affected by
Engineering Inputs, and (3) a peer or supervisory review of the guidance provided in
the Engineering input was not required. Because of the initial inability to provide
information regarding the scope and usage of Engineering inputs, engineering
initiated a significant CR to perform a formal root cause analysis to determine if
Engineering inputs had been inappropriately utilized. The inspectors concluded that
many of the problems associated with the Engineering Input process were l
applicable to the PEIR process. J
c. Conclusions
Management oversight and ownership of the PEIR process was inadequate.
Because of breakdowns in the tracking process, the licensee could not identify the
status of over 100 PElRs. Response due dates typically elapsed without any
followup. In some cases, the response due dates had elapsed 5 years earlier. I
Coupled with the insights gained from the review of the Engineering input process
in NRC Inspection Report 50-382/9605, the inspectors concluded that the
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processes for managing engineering work were inadequate. Because of the inability
of the licensee to produce the open PElRs for review, the inspectors were unable to I
determine if there were any safety concerns associated with all of the open PElRs.
This issue is an unresolved item pending further NRC review.
E2 Engineering Support of Facilities and Equipment
E.2.1 Review of Facility and Eauipment Conformance to UFSAR Description
A recent discovery of a licensee operating a 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. While
performing the inspections discussed in this report, the inspectors reviewed the
applicable portions ci the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording in the areas reviewed was consistent
with the observed plant practices, procedures and/or parameters. No anomalies
between the UFSAR and operation of the facility were identified.
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E8 Miscellaneous Engineering issues (92903) I
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E8.1 (Closed) Violation 50-382/9522-01: Inadequate and ineffective corrective actions !
implemented in response to degraded conditions. The inspectors identified this 1
violation because engineers had credited operation of the ultimate heat sink
cross-connect valves during a design-basis accident without verifying the material
condition and/or without testing the valves. The engineers had changed the
categorization of the valves from " passive" closed to " active" open. Also, the
inspectors determined that engineers failed to initiate a CR for a known system
deficiency.
As corrective action to prevent recurrence, the licensee completed the following:
(1) initiated emergency response resource guide that identified necessary actions to
ensure that one basin had sufficient volume during accident conditions (Note: a
separate unresolved item requires review of calculations related to the ultimate heat
sink volume); (2) established a task to test the cross-connect valves during l
Refueling Outage 8; (3) reiterated management expectations for initiation of
corrective action documents; (4) established program requirements for trending of ,
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important equipment performance; and (5) established an integrated plan to address
generic performance issues. For the second example, the licensee initiated a task to i
reverse the flow orifice during Refueling Outage 8.
The inspectors verified that emergency preparedness had incorporated emergency
resource guide information into emergency response implementing procedures.
Also, the inspectors confirmed that personnel had completed the required reading.
The inspectors confirmed that the licensee initiated tasks to test the cross-connect
flow path between the ultimate heat sink basins and to reverse the flow orifice
orientation. The inspectors determined that the licensee established program
requirements and promulgated guidelines for trending performance variables.
Management issued a memorandum that described the deficiencies and reiterated
their expectations for initiating corrective action documents and having a
questioning attitude. The licensee has been implementing a self-improvement
program to improve identification and correction of deficient conditions and to alter
the site culture such that personnel do the correct thing the first time.
E8.2 (Closed) Unresolved item 50-382/9522-02: Operability evaluation and corrective
actions for ultimate heat sink. This item involved the adequacy of the wet cooling
tower basin inventory to mitigate design-basis accidents, without taking credit for
the wet cooling tower cross-connect valves. The adequacy of the wet cooling
tower basin inventory was reviewed during engineering and technical support
inspection (NRC inspection Report 50-382/96-202). The basin inventory was found
to be acceptable with the exception of when the wet cooling tower basin would be
used as the source for emergency feedwater in lieu of the condensate storage pool.
The inability of the wet cooling tower basins to support emergency feedwater
operation, in lieu of the condensate storage pool, was the subject of
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Violation 50-382/9612-05 in NRC Inspection Report 50-382/96-12, Section E8.4.
NRC issued the violation on November 4,1996.
E8.3 (Closed) Unresolved item 50-382/96202-03: Adequacy of emergency feedwater
operation from the auxiliary CCW basin. Inspectors identified this same item as
Violation 50-382/9612-05 in NRC Inspection Report 50-382/96-12, Section E8.4.
NRC issued the violation on November 4,1996.
E8.4 (Closed) Insoection Followuo item 50-382/9510-02: This item is related to the
licensee experiencing speed drift in the steam-driven emergency feedwater pump.
This issue was reviewed as documented in NRC Inspection Report 50-382/96-12,
and as a result of the review, it was determined that the licensee had taken the
appropriate actions to address the concern of speed drift of the emergency
feedwater pump governor.
E8.5 (Closed) inspection Followuo item 50-382/9516-01: This item involves the need for
the licensee to update the UFSAR to reflect the current status of the essential
cooling water system. Since the issuance of this item, NRC inspections have
identified additional examples of where the UFSAR has not been updated, and as a
result of the identification of these examples, issued Unresolved item
50-382/96202-14 in NRC Inspection Report 50-382/96-202. This item will be
reviewed when the unresolved item is closed. j
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IV. Plant Support
R1 Radiological Protection and Chemistry Controls
R 1.1 Radioloaical Postina and Labelina ;
a. Insoection Scope (71750)
On February 18 and 19, the inspectors performed independent radiation surveys in
selected areas of the reactor auxiliary building and protected area using a licensee
BICRON Surveyor 200 survey meter. In addition, the inspectors evaluated the
posting of radiological areas and labeling of radioactive material storage containers.
b. Qbservations and Findinas
The inspectors performed surveys near Sealand Container 21248-5 noted the
folfowing: (1) the on-contact dose rate was 5.5 mR/hr, the radiologically controlled
area was posted at 1.4 mR/hr, the radioactive material tag dated February 7,1997,
specified that the on-contact dose rate was less than 2 Mr/hr, and the access point
to the sealand container was not posted as a " RADIATION AREA."
Radiation protection independently verified the on-contact dose rate and the
radiologically controlled area boundary dose rate using an Eberline RO2 survey
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meter. Based on the results of the survey, the licensee extended the radiologically
controlled area boundary to a dose rate of less than 0.6 Mr/hr and posted the
sealand container as a " RADIATION AREA." Radiation protection entered the
sealand container and determined that the source of the abnormal dose rates was a
radioactive material vacuum cleaner reading 120 mR/hr on contact and 15 mR/hr at
30 centimeters.
The radiological protection superintendent stated that the vacuum cleaner had been
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moved into the sealand container on February 17 and that the technician did not
perform a survey following the movement to update the radiological warnings.
Following the inspectors' identification, the licensee posted the sealand containes as
a " RADIATION AREA," updated the radioactive material tag information, and
initiated CR 97-0378.
10 CFR 20.1501 requires that each licensee make or cause to be made, surveys
that may be necessary for the licenset to comply with the regulations in
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10 CFR Part 20. The inspectors detern.:ned that the failure to perform a dose rate !
survey following the movement of radioactive material to Sealand
Container 21248-5 resulted in the failure to post the access to the sealand
container as a " RADIATION AREA" in accordance with 10 CFR 20.1902 and is a
violation of 10 CFR 20.1501 (50-382/9702-07).
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On February 18,1997, the inspectors noted an unlabeled yellow shipping container i
located behind the tool room. Based on a review of the material shipment record, l
the inspectors noted that the container stored radioactive materialin excess of the
quantities listed in Appendix C to 10 CFR Part 20. Radiation protection stated that
the container had recently been moved to the protected area from the reactor
auxiliary building, that the container should have been labeled " CAUTION,
RADIOACTIVE MATERIAL," and that the appropriate label should have been placed
on the container, j
10 CFR 20.1904(a) requires that each container of licensed material bear a durable,
clearly visible sabel bearing the words " CAUTION, RADIOACTIVE MATERIAL." The i
inspectors determined that the failure to properly label the container of radioactive
material a violation of 10 CFR 20.1904(a) (50-382/9702-08).
c. Conclusions
inadequate oversight during movement of radioactive material between storage
locations resulted in two violations involving the failure to perform radiation surveys
and the failure to label containers as " CAUTION, RADIOACTIVE MATERIAL."
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V. Manaaement Meetinas
X1 Exit M:ating Sumrnary
The inspectors presented the inspection results to members of licensee management
at the conclusion of the inspection on February 25,1997. 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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[ ATTACHMENT i
SUPPLEMENTAL INFORMATION i
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PARTIAL LIST OF PERSONS CONTACTED !
Licensee
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! R. G. Azzarello, Manager, Maintenance
i C. M. Dugger, Vice-President, Operations 6
l T. J. Gaudet, Manager, Licensing
l D. A. Landeche, Radiation Protection Superintendent
! T. R. Leonard, General Manager, Plant Operations
D. C. Matheny, Manager, Operations l
D. W. Vinci, Superintendent, System Engineering l
A. J. Wrape, Director, Design Engineering '
NRC
C. P. Patel, Waterford 3 NRR Project Manager
INSPECTION PROCEDURES USED
37551 Onsite Engineering
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61726 Surveillance Observations
62707 Maintenance Observations -
71707 Plant Operations
71750 Plant Support Activities
92901 Followup - Plant Operations
92902 Followup - Maintenance
92903 Followup - Engineering
93702 Event Response
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ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-382/9702-01 URI Review adequacy of vital 125 Vac breaker coordination
(Section O2.1)
50-382/9702 02 URI Adequacy of vacuum fill procedure to meet TS Surveillance
Requirement 4.4.2.] (Section M2.2)
50-382/9702-03 URI Appropriate torquing requirements not specified during EDG
maintenance activities (Section M3.1)
50-382/9702-04 NCV Failure to perform channel checks of the containment
isolation valve position indicators (Section M8.5)
50-382/9702-05 NCV Loss of charging flow for 2 minutes (Section M8.6)
50-382/9702-06 URI Review open PElRs to determine if issues have been
adequately addressed (Sections 03.1 and E1.1)
50-382/9702-07 VIO Failure to perform a dose rate survey resulted in failure to
post the access to the container as a " RADIATION AREA"
(Section R1.1)
50-382/9702-08 VIO Failure to properly label the container of radioactive
material a. violation of 10 CFR 20.1904(a) (Section R1.1)
Closed
50-382/9504-05 IFl Review chilled water stroke time test methodology and
stroke time test results (Section M8.3)
50-382/9522-01 VIO Inadequate and ineffective corrective actions implemented
in response to degraded conditions (Section E8.1)-
50-382/9522-02 URI Operability evaluation and corrective actions for ultimate
heat sink (Section E8.2)
50-382/9510-01 VIO Failure to ensure that TS requrt.ments properly translated
into a standing instruction (Section 08.1)
50-382/9516-01 IFl UFSAR not updated to reflect changes made to the
essential coding water system (Section E8.5).
50-382/9510-02 IFl Speed drift of the emergency feedwater pump governor
(Section E8.4).
50-382/9607-01 VIO Failure to follow procedures involving mechanical retests,
surveillance testing, and acceptance criteria (Section M8.2)
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50-382/9611-03 VIO Inadequate test procedure results in a water hammei during
system restoration (Section M8.3) {
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50-382/96202-03 URI Adequacy of emergency feedwater operation from the !
auxiliary CCW basin (Section E8.3) ;
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50-382/96202-15 URI Adequacy of ASME Section XI test for CCW fail-safe i
valves (Section M8.4) l
50-382/9702-04 NCV Loss of charging flow for two minutes (Section M8.1)
50-382/9702-05 NCV Failure to perform the monthly channel checks of the !
containment isolation valve position indicators j
(Section M8.6) i
50/382/95-004 LER Noncompliance with TS surveillance requirements because I
of an inadequate procedure (Section M8.5)
50-382/96-008 LER Loss of chemical volume control charging flow
(Section M8.6)
Discussed
50-382/9614-01 URI Review of the response to the water hammer events that i
occurred in the LPSI system (Section M2.2) ,
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LIST OF ACRONYMS USED
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CCW Component Cooling Water
CFR Code of Federal Regulations l
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CR Condition Report j
CST Central Standard Time
EDG Emergency Diesel Generator
EOP Emergency Operating Procedure
gpm Gallons Per Minute
LOCA Loss-of-Coolant Accident i
LPSI Low-Pressure Safety injection
NRC Nuclear Regulatory Commission l
PDP Power Distribution Panel
PElR Problem Evaluation /Information Request
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psi Pounds per Square Inch
SIAS Safety injection Actuation Signal
STP Special Test Procedure
SUPS Static Uninterruptible Power Supply i
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TS Technical Specification l
UFSAR Updated Final Safety Analysis Report
UT Ultrasonic Testing
Vac Volts-Alternating Current
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