ML021160683
| ML021160683 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 04/26/2002 |
| From: | Lanksbury R NRC/RGN-III/DRP/RPB5 |
| To: | Warner M Nuclear Management Co |
| References | |
| IR-02-005 | |
| Download: ML021160683 (33) | |
See also: IR 05000266/2002005
Text
April 26, 2002
Mr. M. Warner
Site Vice President
Kewaunee and Point Beach Nuclear Plants
Nuclear Management Company, LLC
6610 Nuclear Road
Two Rivers, WI 54241
SUBJECT:
POINT BEACH NUCLEAR PLANT
NRC INSPECTION REPORT 50-266/02-05; 50-301/02-05
Dear Mr. Warner:
On March 31, 2002, the NRC completed an inspection at your Point Beach Nuclear Plant. The
enclosed report documents the inspection findings which were discussed on April 5, 2002, with
you and members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel. Specifically, this inspection was a routine review of plant activities by resident and
regional inspectors.
Based on the results of this inspection, the inspectors identified one finding for which the safety
significance was still to be determined. This issue pertained to the self-revealing failure of the
Unit 2 'B' train safety injection pump, 2P-15B, due to gas binding on February 20, 2002. The
issue was determined to be of at least very low safety significance (Green) since one train of
the Unit 2 safety injection system was rendered inoperable.
M. Warner
-2-
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records System (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Roger D. Lanksbury, Chief
Branch 5
Division of Reactor Projects
Docket Nos. 50-266; 50-301
Enclosure:
Inspection Report 50-266/02-05; 50-301/02-05
cc w/encl:
R. Grigg, President and Chief
Operating Officer, WEPCo
R. Anderson, Executive Vice President
and Chief Nuclear Officer
T. Webb, Licensing Manager
D. Weaver, Nuclear Asset Manager
T. Taylor, Plant Manager
A. Cayia, Site Director
J. ONeill, Jr., Shaw, Pittman,
Potts & Trowbridge
K. Duveneck, Town Chairman
Town of Two Creeks
D. Graham, Director
Bureau of Field Operations
A. Bie, Chairperson, Wisconsin
Public Service Commission
S. Jenkins, Electric Division
Wisconsin Public Service Commission
State Liaison Officer
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE
RIII
RIII
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NAME
MKunowski/trn
RLanksbury
DATE
04/26/02
04/26/02
OFFICIAL RECORD COPY
M. Warner
-3-
ADAMS Distribution:
WDR
BAW
RidsNrrDipmIipb
GEG
PGK1
C. Ariano (hard copy)
DRPIII
DRSIII
PLB1
JRK1
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-266; 50-301
License Nos:
Report No:
50-266/02-05; 50-301/02-05
Licensee:
Nuclear Management Company, LLC
Facility:
Point Beach Nuclear Plant, Units 1 & 2
Location:
6610 Nuclear Road
Two Rivers, WI 54241
Dates:
February 20 through March 31, 2002
Inspectors:
P. Krohn, Senior Resident Inspector, Point Beach
J. Lara, Senior Resident Inspector, Kewaunee
Z. Dunham, Resident Inspector, Kewaunee
D. Chyu, Reactor Engineer
B. Winters, Reactor Inspector
Approved by:
Roger D. Lanksbury, Chief
Branch 5
Division of Reactor Projects
2
SUMMARY OF FINDINGS
IR 05000266-02-05; 05000301-02-05, on 02/20-03/31/2002, Nuclear Management
Company, LLC, Point Beach Nuclear Plant, Units 1 & 2. Operability Evaluations.
This report covers a 6-week routine resident inspection. The inspection was conducted by
resident and regional inspectors. The inspection identified one finding of at least very low
safety significance (Green) that, pending further regulatory review, was considered an
Unresolved Item. The significance of most findings is indicated by their color (Green, White,
Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process.
Findings for which the Significance Determination Process does not apply are indicated by
No Color or by the severity level of the applicable violation. The NRCs program for
overseeing the safe operation of commercial nuclear power reactors is described at its Reactor
Oversight Process website at http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html.
A.
Inspector-Identified Findings
Cornerstone: Mitigating Systems
To Be Determined (TBD). Unit 2. On February 20, 2002, the 2P-15B safety
injection pump failed, during monthly preventative maintenance bearing
lubrication activities, due to gas binding caused by back-leakage of nitrogen-
saturated water from a reactor coolant system safety injection accumulator.
Despite multiple opportunities to have identified the effects of the leaking
accumulator, the licensee's organization did not properly respond to adverse
accumulator leakage trends or effectively use industry operating experience to
prevent failure of the safety injection pump. This issue was considered an
Unresolved Item pending further regulatory review of the risk and problem
identification and resolution aspects of the safety injection pump failure.
This issue was determined to have a credible impact on safety and be of at least
very low safety significance (Green) since one train of the Unit 2 safety injection
system was rendered inoperable. (Sections 1R15.1 and 4OA2)
B.
Licensee-Identified Findings
A licensee-identified violation of very low significance was reviewed by the inspectors.
Corrective actions taken or planned by the licensee appeared reasonable. The violation
is listed in Section 4OA7 of this report.
3
Report Details
Summary of Plant Status
Unit 1 began the inspection period at full power and remained there until March 23, 2002, when
power was reduced to 30 percent to lower the worker radiation dose during restoration of a
reactor coolant system (RCS) wide-range pressure transmitter, turbine stop and governor valve
testing, condenser and crossover steam dump valve testing, atmospheric steam dump testing,
and repair of an oil leak on the 1P-28A main feed pump. Unit 1 was returned to full power
operation on the morning of March 24. Unit 1 remained at full power until March 30, when an
emergency operating facility computer networking problem caused the plant process computer
system to be declared unreliable. Reactor power was reduced to 97 percent during
troubleshooting efforts. Unit 1 was returned to full power operation on March 31 and remained
there through the end of the inspection period.
Unit 2 began the inspection period at full power and remained there until a Technical
Specification (TS) required forced-shutdown due to failure of the 2P-15B safety injection (SI)
pump on February 22, 2002. Following SI pump repairs and testing, Unit 2 was made critical
on February 25, and returned to full power operations on February 26. Unit 2 power was
reduced to 97 percent on March 19, due to a plant process computer failure that occurred while
loading software upgrades. Unit 2 was returned to full power operation later the same day
following correction of the software problems. Unit 2 remained at full power until March 30,
when an emergency operating facility computer networking problem caused the plant process
computer system to be declared unreliable. Reactor power was reduced to 97 percent during
troubleshooting efforts. Unit 2 was returned to full power operation on March 31 and remained
there through the end of the inspection period.
1.
REACTOR SAFETY
Cornerstones: Initiating Events and Mitigating Systems
1R04
Equipment Alignment (71111.04)
.1
125-Volt Direct Current (VDC) Partial System Walkdown
a.
Inspection Scope
The inspectors performed a partial system walkdown of the Units 1 and 2 125-VDC
distribution system to verify proper system configuration. The inspectors used licensee
checklists (CLs), weekly TS tests, and operating procedures during the walkdowns to
verify that the systems were properly configured for full power operations. The CLs and
TS tests were compared against design basis requirements to verify that the documents
aligned the 125-VDC system in accordance with design basis assumptions. The
inspectors also performed walkdowns in the control room to verify appropriate switch
positions and valve configurations.
The inspectors reviewed action request (AR) 2652, PC-43 Part 2, which was initiated
as a result of this inspection activity and discussed seven breakers, including the power
4
supply to a solenoid valve associated with the Unit 2 turbine-driven auxiliary feedwater
(TDAFW) pump recirculation valve, that were not included in the monthly, safety-related,
continuous-use CL. The inspectors also reviewed the document feedback form for
PC-43 Part 2, Revision 32, to verify that the missed breakers had been added to the
next revision of the CL. Finally, the inspectors evaluated other elements, such as
material condition, housekeeping, and component labeling.
b.
Findings
No findings of significance were identified.
.2
Unit 2 TDAFW System Partial Walkdown Following Mini-Recirculation Valve
Accumulator Modification
a.
Inspection Scope
The inspectors performed a partial system walkdown of the Unit 2 TDAFW pump
system to verify proper system configuration following modifications to provide a
nitrogen backup accumulator to the mini-recirculation valve, 2AF-4002. The inspectors
used licensee CL 13E, Part 1, Auxiliary Feedwater Valve Lineup Turbine Driven, during
the walkdowns to verify that the system was properly configured for full power
operations. The CL and safety evaluation used to install the nitrogen backup
accumulator were compared against design requirements to verify that the accumulator
had been installed in accordance with design basis assumptions. The inspectors
performed walkdowns in the control room, primary auxiliary building, Unit 2 facade,
cable spreading room, turbine building, and the auxiliary feedwater pump room to verify
appropriate switch and valve positions. The inspectors also reviewed the completed
copy of CL 13E, Part 1, to verify that auxiliary operators had used independent
verification and self-checking human performance techniques to identify typographical
errors and incomplete position designations for some of the newly installed backup
nitrogen accumulator valves associated with the Unit 2 TDAFW pump system. Finally,
the inspectors evaluated other elements, such as material condition, housekeeping, and
component labeling.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05)
a.
Inspection Scope
The inspectors walked down the following areas to assess the overall readiness of fire
protection equipment and barriers:
Fire Zone 310, Air Compressor Room
Fire Zone 246, Electrical Equipment Room - Unit 2
Fire Area A26, Fire Zone 307, Battery Room D-05
5
Emphasis was placed on the control of transient combustibles and ignition sources, the
material condition of fire protection equipment, and the material condition and
operational status of fire barriers used to prevent fire damage or propagation. Area
conditions/configurations were evaluated based on information provided in the
licensees Fire Hazards Analysis Report, August 2001.
The inspectors toured the three fire zones to verify that fire hoses, sprinklers, and
portable fire extinguishers were installed at their designated locations, were in
satisfactory physical condition, and were unobstructed and to verify the physical location
and condition of fire detection devices. Additionally, passive features such as fire doors,
fire dampers, and mechanical and electrical penetration seals were inspected to verify
that they were located per Fire Hazards Analysis Report requirements and were in good
physical condition.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification (71111.11)
.1
Resident Inspector Quarterly Review: Shutdown Loss-of-Coolant Accident (LOCA)
a.
Inspection Scope
On March 19, 2002, the resident inspectors observed licensed operator training
involving a LOCA while shutdown. The scenario was applied to both Units. The
inspectors evaluated crew performance for clarity and formality of communication; the
ability to take timely action in the safe direction; the prioritizing, interpreting, and
verifying of alarms; the correct use and implementation of procedures, including alarm
response procedures; timely control board operation and manipulation, including
high-risk operator actions; and group dynamics.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Rule Implementation (71111.12)
a.
Inspection Scope
The inspectors reviewed the implementation of the maintenance rule to verify that
component and equipment failures were identified, entered, and scoped within the
maintenance rule and that select structures, systems and components were properly
categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The
inspectors reviewed station logs, maintenance work orders (WOs), condition reports
(CRs), ARs, (a)(1) corrective action plans, selected surveillance test procedures, and a
sample of CRs to verify that the licensee was identifying issues related to the
maintenance rule at an appropriate threshold and that corrective actions were
appropriate. Additionally, the inspectors reviewed the licensees performance criteria to
6
verify that the criteria adequately monitored equipment performance and to verify that
licensee changes to performance criteria were reflected in the licensees probabilistic
risk assessment. Specific components and systems reviewed were:
480-Volt Alternating Current Electrical System
Instrument Air
b.
Findings
No findings of significance were identified.
1R14
Personnel Performance During Non-Routine Plant Evolutions (71111.14)
.1
Unit 2 Forced Shutdown Due to 'B' SI Pump Failure
a.
Inspection Scope
The inspectors observed control room activities associated with a Unit 2 forced
shutdown on February 22, 2002, following failure of the 2P-15B SI pump due to gas
binding on February 20, 2002. Since repair of the pump was expected to exceed the
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed in TS Action Condition Requirement 3.5.2, the licensee commenced a
normal shutdown and progression to cold shutdown, as reported in Event
Notification 38718. The inspectors assessed the adequacy of operations activities
during the reduction of electrical load, reactor shutdown, plant cooldown, and
stabilization of RCS temperature and pressure above the residual heat removal (RHR)
system initiation point. Additionally, the inspectors reviewed maintenance operations for
implementation of risk management, conformance to approved site procedures, and
compliance with TS requirements. The inspectors reviewed 5 ARs written as a result of
the forced shutdown, including AR 2284, Unit 2 Shutdown to Mode 4 Almost Causes a
UE [Unusual Event] Entry; AR 2289, AOP [Abnormal Operating Procedure] 8A, High
Coolant Activity, Is Unclear On When To Restore Normal PAB [Primary Auxiliary
Building] Access; and AR 2323, U2 N32 Source Range Detector Failure With Less
Than One Cycle of Operation.
b.
Findings
No findings of significance were identified.
.2
Personnel Performance During Propane Leak
a.
Inspection Scope
On March 4, 2002, the inspectors observed control room crew actions during a propane
leak from a 500-gallon storage tank adjacent to a well water pumphouse. The propane
tank was located outside of the protected area. The propane leak was considered a
Toxic/Flammable Gas Intrusion and classified as an Unusual Event by the licensee.
Offsite fire department assistance was requested and obtained from the Town of Two
Creeks volunteer fire department. The propane leak was reported to the NRC under
7
The inspectors monitored licensee communications and actions to ascertain whether
appropriate personnel evacuations were considered; to determine the possible ignition
impact of the propane leak on adjacent fuel oil storage tanks and switchyard electrical
distribution lines; to monitor propane sampling results to determine if explosive
atmospheres existed in any portions of the nearby turbine building or vital equipment
areas; to monitor licensee actions in determining whether personnel evacuations from
selected site locations were required; and to monitor contractor and offsite fire
department efforts to stop the propane leak. The inspectors considered wind velocities,
ambient temperatures, projected wind shifts, and the rate of the propane tank inventory
loss to determine the potential impact of the leak on site equipment and operations.
The inspectors also monitored initial manning of the technical support center to
determine licensee preparation for potentially worsening conditions. Finally, the
inspectors reviewed AR 2448, Unusual Event Declared on March 4, 2002: Lack of
Plant Guidance, which discussed the lack of orders to terminate smoking or other spark
producing activities during the initial stages of the propane leak.
b
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
.1
2P-15B SI Pump Failure Due to Gas Binding During Monthly Lubrication Run
a.
Inspection Scope
The inspectors reviewed a self-revealing failure of the 2P-15B Unit 2 SI pump on
February 20, 2002. During the subsequent repair and replacement activities, the
inspectors conducted reviews to verify compliance with TS action condition statements;
observed pump disassembly and reassembly; inspected failed parts; reviewed post-
maintenance testing activities; and reviewed Final Safety Analysis Report (FSAR)
design requirements. The inspectors also reviewed Operability Determination
(OBD) 000011, Gas Binding of SI Pumps, to verify that the licensee had considered
the potential effects of gas binding on:
Unacceptable water hammers due to the rapid refilling of voided SI injection lines
upon pump start
Gas migration to other piping that may have rendered adjacent emergency core
cooling system (ECCS) equipment sharing common suction piping inoperable
Accident analyses due to a delay in injecting water into the reactor core as a
result of having voided volumes in the SI pump discharge lines
Various leaking (or failed open) valves in the system
Flow and pressure instrument sensing lines
Pressure-locking SI system valves during pressure transients
Load amplification due to the constructive combination of reflected shock waves
in partially voided SI injection lines.
The inspectors evaluated the OBD to verify that the venting locations, frequency, and
instructions given to auxiliary operators for the conduct of venting were conservative and
8
maintained SI pump operability. The inspectors reviewed SI and residual heat removal
(RHR) pump suction and discharge piping isometric drawings to determine available
venting points, the creation and effect of loop-seals for unventable portions of the
injection line, and the extent to which voided gas volumes could have migrated back
towards other ECCS pumps. The inspectors interviewed selected engineering
personnel and reviewed pump internal drawings to determine the effects of varying
pump casing gas volumes on SI pump operability. The inspectors reviewed the impact
of 2SI-845E, Unit 2 2P-15B SI Pump To Reactor Coolant Loop 'A' Cold Leg SI Check
Valve, back-leakage on TS 3.4.14 RCS pressure insolation valve leak rate
requirements. The inspectors also reviewed the licensee's troubleshooting plan to
identify the leakage path from the Unit 2 'A' SI accumulator, 2T-34A, back to the 2P-15B
SI pump casing and future check valve repair plans.
The inspectors reviewed Operating Instruction (OI) 163, SI, RHR, and CS [Containment
Spray] Pump Runs, Revision 1, to determine whether monthly SI pump runs for
preventative maintenance bearing lubrication activities constituted preconditioning for
TS required quarterly surveillance tests. The inspectors applied the results of
OBD 000011 to both Units 1 and 2 to verify that the licensee had considered the full
effects of accumulator back leakage on all ECCS equipment.
The inspectors interviewed selected engineering personnel and correlated Unit 2 A SI
accumulator level and pressure history, 2P-15B SI pump injection line volumes, and
nitrogen solubility data to determine when the 2P-15B SI pump had become inoperable.
Finally, the inspectors considered previous licensee operating experience (OE) and
corrective action program opportunities to have prevented failure of the 2P-15B SI
pump.
b.
Findings
Self-Revealing Condition
On February 20, 2002, at 1:00 a.m., the 2P-15B SI pump was started in accordance
with OI-163 as part of a monthly preventative maintenance bearing lubrication activity.
The control room operators noted that when the pump was started, motor current
increased normally, but then decayed to less than 10 amps. The normal SI pump
running current was 30 amps. Additionally, the pump developed no discharge pressure.
The auxiliary operator stationed locally in the vicinity of the SI pump noted a loud noise
near the end of the pump coastdown, observed excessive seal leakage, and reported
the presence of an acrid smell to the control room. The Duty Shift Superintendent
arrived in the pump area shortly thereafter, observed the excessive seal leakage, and
perceived the acrid smell. Through follow-up discussion and observation it was
concluded that the acrid smell was emanating from the inboard pump seal area. The
Duty Shift Superintendent (the lead Senior Reactor Operator on-shift) directed the
isolation of the pump to secure the excessive seal leakage. The 2P-15B SI pump was
declared inoperable and TS Action Condition 3.5.2.A.1 entered at 1:00 a.m. on
February 20, 2002. Technical Specification Action Condition 3.5.2.A.1 required an
inoperable ECCS train be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the affected
Unit be placed in Mode 3 (Hot Standby) within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 4 (Hot
Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
9
Subsequent licensee inspection of the pump revealed damage to the rotating element,
the coupling and shaft keys between the pump and the motor, the pump internal
wearing rings, and other components. The licensee concluded that the cause of the
equipment damage was pump gas binding as the result of back-leakage of nitrogen-
saturated water from the SI A accumulator through at least two check valves,
2SI-845E, Unit 2 2P-15B SI Pump To Reactor Coolant Loop 'A' Cold Leg SI Check
Valve, and 2SI-889B, Unit 2 2P-15B SI Pump Discharge Check Valve, to the
discharge side of the 2P-15B pump. When the pressure of the nitrogen-saturated water
was reduced from the accumulator pressure (750 pounds per square inch gauge) to the
SI pump suction pressure (~30 pounds per square inch gauge), the nitrogen came out
of solution, causing the 2P-15B gas binding.
The licensee proceeded with the repair of 2P-15B with the expectation that the pump
would be repaired, tested, and returned to service prior to the expiration of 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS
Action Statement 3.5.2.A.1. At approximately 2:00 p.m. on February 22, 2002, the
licensee determined that pump repairs and testing could not be completed before the
expiration of the TS action statement. Accordingly, shutdown of Unit 2 began at
2:48 p.m. Mode 3 was reached at 7:26 p.m., and Mode 4 at 1:38 a.m. on
February 23, 2002. Operator performance during the shutdown was reviewed in
Section 1R14.1 of this report. During the time that the Unit 2 'B' ECCS train was
inoperable, the A' ECCS train remained in standby service and was capable of
performing the intended safety function.
Operability of 2P-15B SI and Other ECCS Pumps
The inspectors reviewed and found acceptable, the licensee's OBD conclusion that
venting the SI lines at least every 5 days was sufficient to ensure continued operability
of the Units 1 and 2 SI pumps. The frequency was based on observed accumulator
leakage history and would increase proportionately if accumulator leakage rates
increased. The inspectors also concluded that the Units 1 and 2 'A' train SI pumps had
remained operable since these pumps had been run frequently to refill SI accumulators
and had effectively swept any nitrogen-saturated water or gas voids back into the
accumulators each time the pumps were run. The Unit 1 'B' train SI pump was
considered to have been operable based on the time of the last successful run and the
observed accumulator level trends which indicated insufficient leakage to fill the Unit 1
'B' SI pump with nitrogen-saturated water leading to gas binding failure as had occurred
with 2P-15B.
Concerns for voiding of common ECCS piping were eliminated due to elevation
differences between the SI pump casings and other ECCS pump common suction lines
(the SI pump casings were 3.5 feet above the common ECCS suction line), the fact that
the adjacent pump (2P-15A) exhibited no symptoms of gas binding, and the likelihood
that at least a portion of the evolved gas had been venting through the 2P-15B pump
shaft seals. The inspectors also reviewed the effect of the SI flow delay to the reactor
core during design transients caused by partially voided injection lines and determined
that the limiting parameter of concern, nuclear fuel peak centerline temperature,
remained bounded by existing accident analyses. A review of the gas voiding on water
hammer, shock amplification loadings, valve pressure locking, and instrumentation
effects raised no other operability concerns.
10
Analysis
The inspectors assessed this issue using the Significance Determination Process. The
inspectors concluded that the failure of the 2P-15B SI pump had a credible impact on
safety since the 2P-15B SI pump was credited for mitigating the consequences of
design basis and risk significant transients including: reactor trips, transients without the
secondary power conversion system, loss of a single 125-VDC safeguards bus, small
break LOCAs, stuck open pressurizer power-operated relief valves, medium break
LOCAs, loss of offsite power, loss of offsite power plus loss of the gas turbine with one
emergency alternating current power source unavailable, steam generator tube rupture,
and main steam line break accidents. Consequently, the failure of the 2P-15B SI pump
had a credible impact on safety and was associated with the mitigating systems
cornerstone.
Using the Significance Determination Process Phase 1 Screening Worksheet for the
Mitigating Systems Cornerstone, the inspectors concluded that failure of the 2P-15B SI
pump was considered to be at least of very low safety significance (Green). Pending
further inspector and Region III review of the regulatory and risk aspects of the pump
failure, the safety significance of the finding is To Be Determined and this issue will be
considered an Unresolved Item (URI). Problem identification and resolution aspects of
the failure are discussed in Section 4OA2 of this report.
.2
2P-15B SI Pump Failed to Meet Differential Pressure Acceptance Criteria
a.
Inspection Scope
The inspectors reviewed OBD 000005, 2P-15B SI Pump Failed to Meet Differential
Pressure Acceptance Criteria, to determine operability following a rebuild of the 2P-15B
SI pump due to a failure caused by gas binding on February 20, 2002. Specifically, the
inspectors reviewed Inservice Test IT-02 High Head Safety Injection Pumps and Valves
(Quarterly) Unit 2, Revision 48, performed on February 24, 2002, to determine the
impact of the 800 gallons per minute flow test point which was found to be below the
acceptance criteria of the FSAR pump curve. The inspectors reviewed the licensee's
position that failure of 2P-15B to meet the SI pump curve defined in FSAR
Figure 14.3.2-13, PBNP High Head Safety Injection Flow, at 800 gallons per minute
constituted an operable-but-degraded condition applicable to the SI pump curve rather
than the SI pump itself. The inspectors reviewed the effects of the reduced SI pump
flow on nuclear fuel peak clad temperatures to verify that existing analyses remained
bounding for all design basis accidents. Finally, the inspectors reviewed licensee plans
to modify the SI pump rotating assembly or revise the FSAR SI pump flow curve to
verify that as-built equipment capabilities were accurately reflected in the design bases.
b.
Findings
No findings of significance were identified.
.3
Non-Quality Assurance (QA) Ammeter and Voltmeter Installed In Safety-Related Battery
Chargers
a.
Inspection Scope
11
The inspectors reviewed the OBD associated with AR 2432, Non-QA Parts Used in SR
[Safety-Related] Equipment, D-107 Delayed, to understand the impact of a Non-QA
ammeter installed in safety-related battery charger D-109 in August 2000 and a Non-QA
voltmeter installed in safety-related battery charger D-108 in April 2000. The inspectors
interviewed the 125-VDC system engineer and reviewed battery charger FSAR design
basis requirements to determine if failure of the meters could prevent the fulfillment of
any safety-related functions. The inspectors also considered whether design basis
requirements to restore battery chargers to 125-VDC safety-related buses within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
following a design basis accident, concurrent with loss of offsite power, had been
validated against current emergency and abnormal operating procedures.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (OWAs) (71111.16)
.1
Cumulative Effect of OWAs
a.
Inspection Scope
Using the OWA list effective on March 25, 2002, the inspectors reviewed the cumulative
effect of OWAs to determine the total impact of these workarounds on plant operations.
Specifically, the inspectors considered the interactions between OWAs associated with
emergency diesel generator (EDG) starting air systems, manual operator action
required to reseat crossover steam dump valves, safety-related battery room ventilation
fan high air flow velocities resulting in water on electrical equipment, air ejector radiation
monitor sensitivity to increasing turbine hall temperatures, direct current bus
over/undervoltage alarms during routine starts of Units 1 and 2 safeguards pumps,
frequent condenser water box level alarms while on ice melt operation, and the frequent
venting of SI pumps and piping due to back-leakage past check valves between the SI
accumulators and the refueling water storage tank on the operator's ability to implement
abnormal and emergency operating procedures. The inspectors also reviewed OWA
meeting minutes from October 2001 to March 2002 to verify that the licensee had been
conducting periodic reviews of OWAs and considering the total impact of workarounds
on plant operations. The inspectors reviewed probabilistic risk assessment personnel
involvement in the periodic workaround reviews to verify that the licensee was
attempting to gain risk insights concerning the cumulative effect of OWAs.
b.
Findings
No findings of significance were identified.
.2
Condenser Air Ejector Radiation Monitors Trend Upward With Increasing Turbine Hall
Temperatures
a.
Inspection Scope
12
The inspectors reviewed OWA 0-00C-002 RMS [Radiation Monitoring System] to
identify potential effects on the ability of operators to respond to steam generator tube
rupture events and implement abnormal and emergency operating procedures. The
workaround concerned the Units 1 and 2 condenser air ejector radiation detectors
which, during normal operations, were operating at less than 0.005 percent of full scale.
Due to the low alarm setpoint and the low number of detector ionizing events associated
with the detectors, normal seasonal temperature changes in the turbine building
frequently caused detector alarms. The inspectors interviewed radiation protection
personnel to review plans to change procedures to adjust the background constant for
the detectors. The inspectors reviewed design basis transient analysis to verify that the
proposed changes were bounded by existing steam generator tube rupture analyses
and to verify that the operators ability to rapidly detect steam generator tube ruptures
would not be comprised by the proposed changes. In addition, the inspectors verified
that the proposed changes would allow operators to detect steam generator tube leaks
that were well below TS RCS leakage limits. Finally, the inspectors performed limited
walkdowns of the air ejector discharge piping to verify that turbine hall ambient
temperature changes were the only external factor influencing detector count rates.
b.
Findings
No findings of significance were identified.
1R19
Post-Maintenance Testing (71111.19)
.1
EDG G-02 Post-Maintenance Testing Following Electrical Generator Rotor Rewinding
a.
Inspection Scope
The inspectors observed portions of maintenance activities for the G-02 generator
replacement. Subsequently, the inspectors reviewed design basis requirements and
observed portions of the G-02 load capacity tests performed in accordance with Point
Beach Test Procedure 110, Emergency Diesel Generator G-02 Test, Revision 0, to
verify that the G-02 EDG was capable of performing its design and licensing basis
functions. The inspectors reviewed the completed test documentation to verify that all
acceptance criteria had been met. The inspectors also reviewed design basis
requirements and completed documentation for TS Procedure TS-82, Emergency
Diesel Generator G-02 Monthly, Revision 62, to verify operability and configuration of
the EDG G-02. Finally the inspectors reviewed AR 2403, G-02 Intra-Pole Connecting
Strap Installed Improperly, which discussed the improper installation of one of seven
straps that connected the eight rotor poles in series, to evaluate the rigor of the quality
assurance organization oversight that had been applied to the 10 CFR Part 50,
Appendix B, certified vendor that had rewound the EDG rotor.
b.
Findings
No findings of significance were identified.
.2
Replacement of 'C' Service Water (SW) Pump Parts Following Vibration Level Increase
13
a.
Inspection Scope
The inspectors observed post-maintenance testing activities conducted in accordance
with WOs 0203115 and 0202837 and Inservice Test IT 07C, P-32C Service Water
Pump (Quarterly), Revision 10, following replacement of the 'C' SW pump wearing
rings, column bolting, spider bearings, shafts, and packing glands to verify that the tests
were adequate for the scope of the maintenance work which had been performed and
that the testing acceptance criteria were clear and demonstrated operational readiness
consistent with design and licensing basis documents. The inspectors observed
portions of the pump replacement activities and reviewed completed maintenance and
test records to verify that foreign material exclusion controls were properly applied;
inservice leak tests were properly performed; pump and motor vibrations following
reassembly were at acceptable levels; motor power supply lugs and cables were
properly reattached and assembled; the motor had acceptable electrical performance
characteristics; and shaft runout and bearing clearances following reassembly were
within acceptable limits. The inspectors also reviewed the safety evaluation screening
used to re-baseline the SW pump performance characteristics to verify that all design
basis and American Society of Mechanical Engineers Code requirements were satisfied
for the new pump assembly. Finally, the inspectors reviewed AR 2327, Motor Purchase
Without Recommended Accessory, which discussed a stabilizer bushing sold by the
motor vendor that was not installed during 'C' SW pump modifications activities.
b.
Findings
No findings of significance were identified.
.3
EDG G-01 Post-Maintenance Testing Following Limited Maintenance Window
a.
Inspection Scope
The inspectors reviewed design basis requirements and observed post-maintenance
testing performed in accordance with Technical Specification Test (TS) 81, Emergency
Diesel Generator G-01 Monthly, Revision 62, to verify operability of the Unit 1 'A' train
EDG following a limited maintenance window which had deferred selected vendor
recommended inspections while replacing engine oil filters. Completed surveillance test
documentation was reviewed to verify that the EDG satisfied all required acceptance
criteria and remained capable of performing the intended safety functions. The
inspectors also reviewed selected safety evaluations to verify that the delayed
maintenance did not increase the probability of occurrence of a malfunction of
equipment important to safety that was described in the current licencing basis. Finally,
the inspectors verified that the deferred maintenance inspections had been entered into
the licensee's work planning program and scheduled for completion within 90 days of
the original inspection date.
b.
Findings
No findings of significance were identified.
1R23
Temporary Plant Modifications (71111.23)
14
.1
Installing a Stabilizer Bushing for SW Pump P-32C-M
a.
Inspection Scope
The inspectors reviewed Temporary Modification TM 02-006, Steady Bushing for
P-32C-M, to verify that the modification was properly installed, had no effect on the
operability of the safety-related equipment, and adequately reduced vibration levels.
The inspectors observed SW pump testing and associated vibration measurements
after the installation of the temporary modification to ensure that the pump was capable
of performing its intended safety function.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator (PI) Verification (71151)
Cornerstones: Initiating Events, Mitigating Systems
.1
a.
Inspection Scope
The inspectors reviewed portions of the Units 1 and 2 1999, 2000, and 2001 data for the
RHR System Unavailability PIs using the definitions and guidance contained in Nuclear
Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 2.
The inspectors reviewed station log entries, Licensee Event Reports, selected inservice
text procedures, and system engineer data sheets to verify that planned and unplanned
unavailability hours were characterized correctly in determining PI results. The
inspectors also performed independent calculations to verify PI data.
b.
Findings
No findings of significance were identified.
15
.2
Unplanned Power Changes Per 7,000 Critical Hours PI
a.
Inspection Scope
The inspectors reviewed Units 1 and 2 2001 data for the Unplanned Power Changes per
7,000 Critical Hours PI using the definitions and guidance contained in Nuclear Energy
Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 2.
The inspectors reviewed station log entries, Licensee Event Reports, and licensee
quarterly data tracking sheets for unplanned power changes greater than 20 percent of
full power to verify that all power changes were properly characterized as planned or
unplanned in determining the PI results. The inspectors also performed independent
calculations to verify PI data.
b.
Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1
2P-15B SI Pump Failure Due to Gas Binding During Monthly Lubrication Run
a.
Inspection Scope
The inspectors reviewed the corrective action and operating experience program history
surrounding the self-revealing failure of the 2P-15B Unit 2 SI pump due to gas binding
on February 20, 2002. Specifically, the inspectors reviewed the corrective action and
operating experience history provided by the licensee in Root Cause Evaluation 000044,
Unit 2 Safety Injection Pump Damaged During Routine Preventative Maintenance, to
determine the causes of the 2P-15B failure. A description of the circumstances and
operability considerations associated with the safety injection pump failure are provided
in Section 1R15.1 of this report.
b.
Findings
The licensee initiated a root cause evaluation team on February 23, 2002, to identify
why the safety injection pump failure had occurred and to determine corrective actions
to prevent reoccurrence. The licensee's evaluation identified that plant staff had not
properly responded to adverse SI accumulator trends that increased the potential for
gas binding of the SI pumps. The licensee also concluded that the operating experience
program had not been effective in ensuring timely implementation of corrective actions
from previous lessons learned.
The inspectors reviewed the corrective action and operating experience history collected
by the root cause evaluation team and noted at least two specific opportunities for the
licensee to have identified the Unit 2, 'A' accumulator, 2T-34, adverse leakage trend
prior to the 2P-15B SI pump failure.
16
Action Request 1862, Excessive Leakage of 2T-34A SI Accumulator, was
initiated on January 15, 2002, by a licensed reactor operator who identified an
adverse trend in the rate of decrease of the Unit 2 'A' accumulator level. The
operator recommended further evaluation to pinpoint a leakage path since his
analysis efforts had been inconclusive. He attached a graph of the accumulator
level history to the AR which showed a marked increase in the accumulator
leakage rate following performance of the last quarterly 2P-15B TS surveillance
test on December 29, 2001. Prior to December 29, accumulator level had been
decreasing at a rate of approximately 1 percent per day. However, following the
quarterly surveillance test and fill of the accumulator on December 29, the
average rate was 4 to 5 percent per day.
Action Request 1862 was reviewed by plant management on January 16, 2002,
and closed, with no further action, to an open WO to investigate leakage through
the accumulator fill valve.
Condition Report 01-0454, Unit 2 'A' Safety Injection SI Accumulator Level, was
initiated on February 12, 2001, by a different licensed reactor operator who
identified that the Unit 2 'A' accumulator level was lowering slowly, requiring
refilling numerous times per OI-100, Adjusting SI Accumulator Level and
Pressure. Work Order 9935625 was initiated to determine whether the
accumulator drain valve, 2SI-844A, or the accumulator fill valve, 2SI-835A, was
leaking. Results of WO 9935625 were inconclusive and CR 01-0454 was closed
to WOs 9939167 and 9939168 to correct the drain and fill valve seat leakage
during the next refueling outage. In closing CR 01-054, the system engineer
noted that either both the drain and fill valves were leaking or another drain path
existed. At the time of the 2P-15B SI pump failure, the WOs to repair the
accumulator fill and drain valves had not yet been completed and remained
open.
Several other Unit 1 and 2 corrective program opportunities had existed to cause the
licensee to question accumulator leakage paths and the consequences of continued
leakage on SI pump operability. Condition Reports 97-1044, Unit 1 SI Accumulator
Stop Valves Leak By; CR 96-0908, Unit 1 SI Accumulator Level Loss; CR 98-0171,
2SI-843B SI Accumulator First Off Isolation Valve Leaking; and CR 99-2717 identified
various combinations of leaking accumulator drain, local sample isolation, and fill valves.
Each CR was closed to a WO which repaired the leaking valves. Other corrective action
program opportunities that had existed and should have caused the licensee to more
thoroughly question potential accumulator leakage paths and the Unit 1 and 2 leakage
consequences included;
Condition Report 96-1789, SI Accumulator (1T-34A) Level Decreasing, was
initiated on December 17, 1996, and identified that the Unit 1 SI accumulator had
been decreasing about 1 percent per day. The CR was closed to WO 94893
which, at the end of this inspection period, had not been traced to closure in the
licensees work planning system.
Condition Report 97-3942, Unit 1 'A' SI Accumulator Lost 86.6 Gallons of
Borated Water, was initiated on December 1, 1997, and identified that the
17
leakage, following evaluation, was believed to be going through fill valve,
1SI-835A. The CR was closed to WO 9714938 which identified that the
accumulator continued to leak even when the drain valve, 1SI-844A, was
isolated. The CR indicated that because of the leakage investigation done, and
other actions in place under CR 97-3932, the only additional action needed was
the creation of a new item for engineering personnel to evaluate if the noted rate
of level increase in the reactor coolant drain tank was acceptable. This action
item had not been created when the CR was closed.
Condition Report 98-1004, SI Accumulator Level Decrease, was initiated on
March 11, 1998, and identified that the Unit 2 'A' accumulator was decreasing by
approximately 3 percent per day. The initial recommendation was to close this
CR to an open WO written to repair seat leakage on the 2T-34A accumulator
outlet valve, 2SI-841A. At the request of the system engineer, however, the CR
was re-opened to evaluate and track the issue of dissolved nitrogen coming out
of solution once it had leaked by the accumulator isolation valve. Condition
Report 98-1004 contained a September 1999 cross-reference to OE at another
commercial pressurized water reactor which discussed gas binding of high-head
SI pumps via back-leakage through check valves that isolate the RCS from the
In addition, several industry OE opportunities had existed to alert the licensee to
examine SI accumulator leakage paths and the potential SI pump operability
consequences. Operating experience opportunities included:
Information Notice (IN) 97-040, Potential Nitrogen Accumulation Resulting From
Back-Leakage From Safety Injection Tanks, was evaluated by the license in
September 1997. As a result of the review, Operating Procedure OP-1A, Cold
Shutdown to Hot Shutdown, was revised to require venting of the high point of
the accumulator discharge lines prior to startups.
Information Notice 88-023, Potential for Gas Binding of High-Pressure Safety
Injection Pumps During a Loss-of-Coolant-Accident, Supplements 1 through 4,
were evaluated between January 1989 and May 1993. These supplements
focused on gas binding of the high head SI pump suction due to back-leakage
Information Notice 88-023, Potential for Gas Binding of High-Pressure Safety
Injection Pumps During a Loss-of-Coolant-Accident, Supplement 5, and
licensee OE document 9876, 4B HHSI [High-Head Safety Injection] Pump Gas
Binding, were evaluated by the licensee in June 1999. During the evaluation,
the licensee concluded that previous OE responses on the gas binding subject
were incomplete, not thorough, and too narrowly focused, and that the potential
for nitrogen accumulation in the SI piping from check valve or multiple valve
leakage paths had not been addressed. This conclusion resulted in the
generation of a single action item under IN 88-023 for the performance of an
in-depth re-evaluation of the gas binding phenomena, including re-evaluation of
all prior documents on the gas binding issue. The inspectors noted that a CR
18
concerning the lack of rigor of the previous OE responses was not initiated
during the processing of IN 88-023, Supplement 5.
The IN 88-023 action was created in September 1999, and assigned to an
engineer for further evaluation and completion by January 2000. One due date
extension was granted and the evaluation was competed during April 2000. In
the evaluation, the engineer concluded that the SI system was susceptible to gas
binding in the event of leakage from the SI accumulators through multiple check
valves and/or motor-operated valves. In addition, the engineer concluded that,
Frequent filling of an accumulator can be evidence of check valve leakage, and
Small leakage over time can result in gas coming out of solution and voiding
significant amounts of ECCS piping. The engineer recommended that another
action item be created to address these concerns and listed specific areas to be
addressed including:
Addition of guidance to OI-100, Adjusting SI Accumulator Level and
Pressure, to check for ECCS piping voids when frequent accumulator
filling was required
Consideration of adding frequent venting of the ECCS piping upstream of
the first- and second-off RCS check valves
Discussions between engineering and operations personnel concerning
OI-100 procedure changes occurred between June 2000 and December 2001.
At the beginning of December 2001, an action item was initiated to complete
OI-100 revisions by March 8, 2002. The OI-100 revision had not been issued
prior to the gas binding failure of 2P-15B on February 20, 2002.
In reviewing the corrective action program history of the in-depth re-evaluation of
the gas binding phenomena for the single action item associated with IN 88-023,
Supplement 5, the inspectors noted eight due date extensions encompassing
18 months (June 2000 to December 2001) before operations personnel agreed
to the recommended OI-100 revisions and the revision date of March 8, 2002,
was agreed upon. During the intervening 18 months, the inspectors noted
deferral of OI-100 revisions for changes in system engineers, conflicts with a
Unit 2 refueling outage, assignment of a new system engineer, further research
on the feasibility of corrective actions, evaluation of the impact of improved TSs
on the planned revision, and operations review of the recommended changes.
Pending further regulatory review, this issue will be carried under the URI opened in the
2002 Problem Identification and Resolution Inspection Report 50-266/02-03(DRP);
50-301/02-03(DRP) as URI 50-301/02-03-01.
19
4OA6 Meetings
Exit Meeting
The resident inspectors presented the routine inspection results to Mr. M. Warner and
other members of licensee management at the conclusion of the inspection on
April 5, 2002. The licensee acknowledged the findings presented. No proprietary
information was identified.
Interim Exit Meeting
Senior Official at Exit:
N/A. Phone call with Ms. F. Flentje
Date:
January 23, 2002, via telephone
Proprietary (explain yes)
No
Subject:
Results of an licensee investigation on failure to
follow a work order.
Change to Inspection Findings:
No
4OA7 Licensee-Identified Violations
The following finding of very low significance was identified by the licensee and is a
violation of NRC requirements which meets the criteria of Section VI of the NRC
Enforcement Policy, NUREG-1600 for being dispositioned as a Non-Cited Violation
(NCV).
If you deny the NCV, you should provide a response with the basis for your denial,
within 30 days of the date of this inspection report, to the Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies
to the Regional Administrator, Region III; the Director, Office of Enforcement, United
Stated Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC
Resident Inspector at the Point Beach facility.
NCV Tracking Number
Requirement Licensee Failed to Meet
NCV 50-266/02-05-01
10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, required, in part, that activities
affecting quality be prescribed by documented instructions,
procedures, or drawings of a type appropriate to the
circumstances and shall be accomplished in accordance
with these instructions, procedures, or drawings. Contrary
to the above, on March 27, 2001, electricians commenced
work on the 125-VDC system without authorization from
the Duty Shift Superintendent as required by Work Order 9928468. In addition, the workers went beyond the
scope of the work order and performed work in an
energized 125-VDC panel. These two issues, combined,
constituted a violation of more than minor significance
because the issues could be viewed as a precursor to a
significant event. Since this finding did not result in a loss
20
of safety function, the inspector determined that, through
the use of Significance Determination Process Phase 1
Screening Worksheet, the issues were of very low safety
significance (Green). These two issues were described in
the licensees corrective actions program as Condition
Reports 01-1073 and 01-1029. This is being treated as a
Non-Cited Violation.
21
KEY POINTS OF CONTACT
Licensee
J. Anderson, Production Planning Group Manager
L. Armstrong, Design Engineering Manager
C. Arnone, Outage Manager
A. Cayia, Site Director
F. Flentje, Senior Regulatory Compliance Specialist
D. Gehrke, Nuclear Oversight Supervisor
N. Hoefert, Engineering Programs Manager
R. Hopkins, Nuclear Oversight Supervisor
V. Kaminskas, Maintenance Manager
C. Krause, Regulatory Compliance
R. Mende, Director of Engineering
D. Schoon, Operations Manager
R. Pulec, Site Assessment Manager
D. Shannon, Radiation Protection Supervisor
C. Sizemore, Training Supervisor
P. Smith, Operations Training Supervisor
J. Strharsky, Assistant Operations Manager
T. Taylor, Plant Manager
S. Thomas, Radiation Protection Manager
R. Turner, Inservice Inspection Coordinator
P. Walker, Training Manager
M. Warner, Site Vice-President
T. Webb, Licensing Manager
NRC
D. Spaulding, Point Beach Project Manager, NRR
ITEMS OPENED, CLOSED, AND DISCUSSED
Open
50-266/02-05-01
Failure to follow work order instructions for initiating work and
performing work beyond the scope of authorization. (Section
4OA7)
Closed
50-266/02-05-01
Failure to follow work order instructions for initiating work and
performing work beyond the scope of authorization. (Section
4OA7)
Discussed
50-301/02-03-01
2P-15B Safety Injection Pump Failure During Monthly
Preventative Maintenance Lubrication Activity (Section 1R15.1)
22
LIST OF ACRONYMS USED
Action Request
CFR
Code of Federal Regulations
CL
Checklist
CR
Condition Report
Division of Reactor Projects
Final Safety Analysis Report
IN
Information Notice
Inservice Test
Loss-of-Coolant-Accident
NRC
Nuclear Regulatory Commission
OBD
Operating Experience
Operating Instruction
OP
Operating Procedure
Operator Workaround
Performance Indicator
Quality Assurance
Safety Injection
Turbine-Driven Auxiliary Feedwater
TS
Technical Specification
Unresolved Item
VDC
Volts Direct Current
LIST OF DOCUMENTS REVIEWED
1R04 Equipment Alignment
Periodic Checks
43 Part 2
Switch and Breaker Alignment Checks
Revision 32
0-TS-EP-001
Weekly Power Availability Verification
Revision 2
Safety Evaluation
SCR 2002-0090
Revision of TS-EP-001 and PBF-2035 To
Incorporate Revised Bus Voltage Limits
March 8, 2002
FSAR 8.6.3
120 VAC [Volts Alternating Current]
Instrument Power (Y)
June 2001
AR 2652
PC-43 Part 2
March 22, 2002
Master Data Book
(MDB) 3.2.12
D-31, DC [Direct Current] Distribution
Revision 10
MDB 3.2.12
D-41, DC Distribution
Revision 9
Point Beach Drawing
E-94 Sheet 140
Connection Diagram Instrument Rack C207
Revision D
Point Beach Drawing
PBE-174
Internal Wiring Diagram Local Instrument
Rack C207
Revision E
Nuclear Work Order
(WO) 924198
P-29 AFP [Auxiliary Feedwater Pump] Recirc
Control Solenoid
September 11, 1992
Task Sheet 0009750
Unit 2 Aux Feedwater System Check
Valves/Flow Indicator
October 1, 1993
Tag Series 2AF-4002
IC Rev1-2
2P-29 AFP [Auxiliary Feedwater Pump] Mini
Recirc Control
March 25, 2002
2P-29 AFP Mini Recirc Control, Add Backup
Air to AF-4002
February 28, 2002
Plant
Modification/Minor
Change 02-001
TDAFP [Turbine-Driven Auxiliary Feedwater
Pump] Mini Recirc Valve (1/2AF-4002)
Instrument Air Accumulator Addition
January 2, 2002
Procedure Feedback
Request
PC-43 Part 2, Switch and Breaker Alignment
Checks
March 22, 2002
Operating Procedure
(OP) 11A G-01
Emergency Diesel Generator G-01
Revision 3
OP 11A G-02
Emergency Diesel Generator G-02
Revision 4
Checklist (CL) 13E
Part 1
Auxiliary Feedwater Valve Lineup
Turbine-Driven Unit 2
Revision 14
24
Temporary Change
2002-0127
Auxiliary Feedwater Valve Lineup
Turbine-Driven Unit 2
March 11, 2002
Safety Evaluation
SCR 2002-0010
Backup Air Systems for Auxiliary Feedwater
Pump Minimum Flow Recirculation Valves
January 25, 2002
Point Beach Drawing
Bech 6118 M-217
P&ID Auxiliary Feedwater System - Sheet 1
Revision E
Point Beach Drawing
Bech 6118 M-217
P&ID Auxiliary Feedwater System - Sheet 2
Revision E
1R05 Fire Protection
Fire Hazards Analysis
Report
Fire Area A29, Fire Zone 310, Air
Compressor Room
August 17, 2001
Fire Hazards Analysis
Report
Fire Area A01-E, Fire Zone 246, Electrical
Equipment Room - Unit 2
August 17, 2001
Fire Hazards Analysis
Report
Fire Area A26, Fire Zone 307. Battery Room
D-05
August 17, 2001
1R11 Licensed Operator Qualifications
Simulator Guide 0065
Shutdown Malfunctions #1
Revision 1
Shutdown Emergency
Procedure (SEP) 2
Shutdown LOCA Analysis - Unit 2
Revision 2
SEP 2.2
Shutdown LOCA [Loss of Coolant Accident]
With RHR [Residual Heat Removal] Aligned
For Decay Heat Removal - Unit 2
Revision 7
1R12 Maintenance Rule Implementation
MTN Rule Coord File
T7.2.6
2000 480 VAC Electrical - Maintenance Rule
Performance Criteria/Goals
March 26, 2001
480 VAC Performance Criteria Assessments
Since January, 2001
January, 2002
Maintenance Rule Function List for 480 VAC
Electrical
March, 2001
Design Basis
Document DBD-21
480 VAC System Design Basis Document
Revision 1
Health Physics
Implementing
Procedure 4.56
Testing Supplied Air For Air-Line
Respiratory Equipment
Revision 15
25
Air Compressor Out-of-Service Times -
August 1999 to February 2002
Document Maintenance Rule System
Performance Compared to Performance
Criteria in MRLIN
January 28, 2002
Instrument Air Performance Criteria
Assessments since January, 2001
Work Orders for Instrument Air Initiated or
Completed Between 1/1/200 and 3/7/2002
NPM 2001-0251
2000 Annual Report for the Maintenance
Rule
March 26, 2001
1R14 Personnel Performance During Non-Routine Plant Evolutions
Power Operation to Hot Standby
Revision 58
Reactor Shutdown
Revision 33
Hot Standby to Cold Shutdown
Revision 86
AR 2284
Unit 2 Shutdown To Mode 4 Almost Causes
a UE [Unusual Event] Entry
February 23, 2002
AR 2285
2RE-109 Went Into Hi Alarm Tonight
February 23, 2002
AR 2287
2Re-109 High Alarm Due To Crud Burst
During Unit 2 Shutdown for 2P-15B SI
Pump Repairs
February 23, 2002
AR 2289
AOP 8A, High Coolant Activity, Is Unclear
On When To Restore Normal PAB [Primary
Auxiliary Building] Access
February 23, 2002
AR 2290
Unexpected Alarm On Radiation Monitor
RE-109
February 23, 2002
A2323
U2 N32 Source Range Detector Failure
With Less Than One Cycle of Operations
February 26, 2002
AR 2448
Unusual Event Declared on 3-4-02: Lack of
Plant Guidance
March 7, 2002
NPM 2002-0116
Point Beach Nuclear Plant Emergency
Preparedness Response to March 4, 2002 -
Unusual Event, Toxic/Flammable Gas
Intrusion
March 7, 2002
1R15 Operability Evaluations
26
OBD 000011
Gas Binding of SI [Safety Injection] Pumps
February 24, 2002
OBD 00005
2P-15B SI Pump Failed to Meet Differential
Pressure Acceptance Criteria
February 24, 2002
Design Basis
Document DBD 11
SI and CS [Containment Spray] System
Revision 0
Phase 2 Significance
Determination
Process Worksheets
Risk-Informed Inspection Notebook for Point
Beach Nuclear Plant, Units 1 and 2,
Prepared by Brookhaven National
Laboratory
November 29, 2000
OI-100
Adjusting SI Accumulator Level and
Pressure
Revision 16
OI-163
SI, RHR [Residual Heat Removal], and CS
Pump Runs
Revision 1
Inservice Test (IT)
IT 02
High Head SI Pumps and Valves (Quarterly)
Unit 2
Revision 48
Drawing PB 02 MSIL
000 001 45
P&ID Safety Injection System Unit 2
Revision E
Drawing PB 02 MSIL
133 002 10
SI Pump Discharge to Injection Unit 2
SI-150IR-1 and SI-1501R-3
Revision E
PB Drawing 02 MSIL
133 003 10
SI Pump Discharge to Injection Line Unit 2
SI-150IR-1 and SI-1501R-2
Revision E
Drawing PB 02 MRDL
183 001 14
Suction From RWST to SI, CS, RHR Pumps
Unit 2
Revision E
Drawing PB 02 MRHL
183 001 06
SI RHR System to Reactor Vessel Unit 2
Revision E
Drawing PB 02 MSIL
183 054 00
2" SI Piping in Containment Unit 2 - Sheet 1
Revision E
Drawing PB 02 MSIL
183 055 01
2" SI Piping in Containment Unit 2 - Sheet 2
Revision E
Drawing PB 02 MSIL
183 056 00
2" SI Piping in Containment Unit 2 - Sheet 3
Revision E
Drawing PB 02 MSIK
000 001 48
P&ID Safety Injection System Unit 2
Revision E
Drawing PB 02 MSIK
000 001 49
P&ID Safety Injection System, Unit 2
Revision E
27
Drawing PB 02 MSIK
000 002 43
P&ID Safety Injection System, Unit 2
Revision E
Drawing PB 01 MESK
000 002 49
P&ID Safety Injection System, Unit 1
Revision E
Drawing PB 01 MSIK
000 001 55
P&ID Safety Injection System, Unit 1
Revision E
Drawing PB 01 MSIK
00012 45
P&ID Safety Injection System, Unit 1
Revision E
OPR 000007
QA Classification of Replacement Ammeter
and Voltmeter for Safety-Related Battery
Charger
March 7, 2002
FSAR Section 8.7
125 VDC Electrical Distribution System
(125V)
June 2001
1R16 Operator Workarounds
Monthly Operator
Work Around Meeting
Minutes
October 2001 to March 2002
Operator Work
Around Summary
Summary List
March 25, 2002
FSAR 14.2.4
Steam Generator Tube Rupture
June 2001
OWA 0-00C-002
1 and 2 RE-215 Trends Up With Increasing
Turbine Hall Temperatures
March 25, 2002
1R19
Post-Maintenance Testing
Point Beach Test
Procedure 110
EDG G-02 Test
Revision 0
Technical
Specification Test
(TS)-82
Emergency Diesel Generator G-02 Monthly
Revision 62
CAP002391
G01 EDG Amber Light Lit When G02 EDG
Stopped Running
March 5, 2002
Design Basis
Document DBD-16
Emergency Diesel Generator System
Revision 0
AR 2403
G-02 Intra-Pole Connecting Strap Installed
Improperly
March 5, 2002
IT 07C
P-32C Service Water Pump (Quarterly)
Revision 10
28
Safety Screening
SCR 2002-0089
0P-32C Rebaselining
March 7, 2002
Procedure Change
Request Form
Modification of IT-7C Attachment A Flow
Rate Acceptance Criteria Upper Limit From
4790 to 5098 Gallons Per Minute
March 8, 2002
Dissassemble/Inspect/Rebuild Pump
Assembly Being Removed and Reinstalled
Under Work Order 0202837
WO 0202837
Dissassemble Pump and Inspect and
Replace Parts as Per RMP [Routine
Maintenance Procedure] 9216-1, 2, 3
RMP 9216-1
Service Water Pump Motor Removal and
Installation
Revision 3
RMP 9612-2
Service Water Pump Motor Removal,
Installation and Maintenance
Revision 3
RMP 9612-3
Service Water Pump Vibration Testing and
Balancing for Post Maintenance Testing
Revision 5
ASME Code
Repair/Replacement/
Modification Form
2002-0018
Replace Bolting at Column-to-Column
Flanges for P-32C Service Water Pump
March 6, 2002
AR 2326
P32C OOS Due to High Vibrations
February 27, 2002
AR 2327
Motor Purchase Without Recommended
Accessary
February 27, 2002
AR 2291
EM [Electrical Maintenance] Workplan Had
Incorrect Data For G-02 Rotor Resistance
Equation
February 24, 2002
TS 81
Emergency Diesel Generator G-01 Monthly
Revision 62
Safety Evaluation
2001-0056
TRM [Technical Requirements Manual]
Section 3.8.3, Standby Emergency Power
Source Inspection
October 8, 2001
Safety Evaluation
Screening
Deferral of G-01 Maintenance Inspection Up
To Three Months Beyond EMD [Electro-
Motive Diesel] Owners Group
Recommended Maintenance Period
February 27, 2002
29
Preventative
Maintenance Work
Order Deferral
Request
G-01 Emergency Diesel Generator - Two
Year Maintenance
March 12, 2002
Surveillance Work
Order Interval
Extension Request
G-01 Emergency Diesel Generator - Two
Year Maintenance
March 12, 2002
1R23
Temporary Plant Modifications
TM 02-006
Steady Bushing for P-32C-M
February 27, 2002
CAP002326
P32C OOS due to High Vibrations
February 27, 2002
CAP002327
Motor Purchase Without Recommended Accessory
February 27, 2002
NP 7.3.1
Revision 12
4AO1 Performance Indicator Verification
Regulatory Assessment Performance Indicator
Guideline
Revision 2
Point Beach
Form 1650
Mitigating System Cornerstone Monthly
Unavailability and Verification, LHSI [Low Head
Safety Injection], January to December 2001
Revision 0
IT-03
Low Head Safety Injection Pumps and Valves
(Quarterly) Unit 1
Revision 43
IT-40
Safety Injection Valves (Quarterly) Unit 1
Revision43
IT-45
Safety Injection Valves (Quarterly) Unit 2
Revision 43
Spreadsheet
Point Beach Units 1 and 2, Initiating Events
Cornerstone Quarterly Tracking Sheet, 1Q99 to
4Q01
4OA2 Problem Identification and Resolution
Root Cause
Evaluation 000044
U2 [Unit 2] Safety Injection Pump
Damaged During Routine Preventative
Maintenance
April 2002
Operating Instruction
(OI) OI-100
Adjusting SI Accumulator Level and
Pressure
Revision 16
Potential for Gas Binding of High Pressure
SI Pumps During a Loss-Of-Coolant
Accident
Supplement 5
April 23, 1999
30
Potential Nitrogen Accumulation Resulting
from Backleakage from SI Tanks
June 26, 1997
CR 01-0454
Unit 2 A SI Accumulator Level
February 12, 2001
AR 2245
2P-15B SI Pump Fails During OI-163
Performance
February 20, 2002
AR 2262
Concerns About Gas Binding of SI Pumps
and System Leakage
February 21, 2002
AR 2264
Untimely Implementation of
Recommendations from Information Notice 88-23, Supplement 5
February 21, 2002
AR 2292
February 24, 2002
AR 2294
Unit 1 and 2 SI Accumulators Require
Frequent Filling Due to Check Valve L
February 24, 2002
AR 2295
SI Pumps and Piping Require Frequent
Venting
February 24, 2002
AR 2296
Valves Found Mis-Positioned in Unit 2
Containment
February 25, 2002
AR 2299
Missed Opportunity to Use OE on Safety
Inject Pump
February 25, 2002
AR 2325
Venting of CS Pump Suction
February 26, 2002
AR 2432
Non-QA Parts Used in SR [Safety-Related]
Equipment, D-107 Delayed
March 6, 2002