ML20135E348
| ML20135E348 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 02/27/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20135E342 | List: |
| References | |
| 50-266-96-19, 50-301-96-19, NUDOCS 9703060443 | |
| Download: ML20135E348 (32) | |
See also: IR 05000266/1996019
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U.S. NUCLEAR REGULATORY COMMISSION '
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REGION ll! !
Docket Nos. 50-266, 50-301,72-005
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Report No. 50-266/96019, 50-301/96019, 72-005/96019
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Licensee: Wisconsin Electric Power Company, WEPCo
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Facility: Point Beach Nuclear Plant, Units 1 & 2 I
Location: 6612 Nuclear Road
Two Rivers, WI 54241-9516
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Dates: December 17,1996 Through January 27,1997 j
inspectors: A. McMurtray, Senior Resident inspector
C. Keller, Resident inspector
P. Louden, Resident inspector
M. Kunowski, Project Engineer !
Approved by: J. W. McCormick-Barger, Team Leader
Point Beach Oversight Team
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9703060443 970227
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PDR ADOCK 05000266
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EXECUTIVE SUMMARY
Point Beach Nuclear Plant, Units 1 & 2
NRC Inspection Report 50-266/96019, 50-301/96019, 72-005/96019
This inspection included aspects of licensee operations, engineering, maintenance, and
plant support. The report covers a six-week inspection period by the resident inspectors.
Onerations l
- On December 16,1996, the Unit 2 "A" (2A) residual heat removal (RHR) pump
was operated for 38 minutes with its discharge valve shut and no recirculation flow l
path available (Section 04.2). I
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- On December 17,1996, Unit 1 power was reduced from 100 percent to
90 percent. The reduction was well planned and executed (Section 04.1). I
Maintenance
- During the January 1997 performance of TS-83, a high fuel oil pressure alarm was
received after the emergency diesel generator (EDG) G-03 was accelerated to rated
speed. No condition report (CR) was written documenting the alarm
(Section M3.1).
- On January 16,1997, the licensee discovered that the Unit 1 RHR/ Low Head Core i
Deluge valve,1SI-852A, had not been stroked tested per American Society of
Mechanical Engineers (ASME)Section XI requirements since April 4,1994. This
valve was required to be stroke tested each cold shutdown (that is, every 12
months during refueling outages) in order to meet T/S 15.4.2.B.3 (Section M4.1).
- On December 27 and 28,1996, the Unit 1 containment inner personnel hatch failed
during Type B (10 CFR 50, Appendix J) leskage testing. Several test failures have
been noted for this door during the previous inspection periods (Section M4.2).
Enaineerina
- On November 26,1996, a helicoil repair was made to the Unit 2 "A" (2A) safety
injection (SI) pump, 2P-15A. The repair did not meet all the requirements of
Section XI Code Case N-496 (Section E2.1).
- On January 9,1997, the licensee determined that there was a potential thermal
overpressurization concern for the Unit 1 reactor coolant pump seal return piping
that penetrated containment during a postulated design bases accident. Insulation
was installed on the affectsd pipe section to mitigate this concern (Section E2.2).
l * On January 24,1997, the inspectors observed a pool of oil beneath the electric fire
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pump motor, P-35A. No CR was written nor was an operability evaluation
j performed for this condition (Section E3.1).
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e The licensee determined that there may have been a potential in the past for the
main steam safety valves (MSSVs) to not lift at the maximum assumed setpoint
during a loss of externalload. The licensee was aware in 1991 of the potential for
a variation in the MSSV setpoint due to ambient temperature changes in 1991
(Section E4.1).
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Plant Succort
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- The licensee discovered on December 29,1996, that a Unit 1 steam generator :
blowdown filter outlet sample was not obtained and analyzed for gamma scan and
tritium as required by Table 15.7.6-1 in TS 15.7.6 (Section R4.1).
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l * On January 23,1997, security reestablished the Unit 2 containment as a vital area
following steam generator replacement (Section S2.1).
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Report Details
Summarv of Plant Status
On December 17,1996, Unit 1 reduced power from 100 percent to 90 percent due to
station management's concerns with operations department performance after 2A RHR
pump, 2P-10A, was run with the discharge valve shut for 38 minutes (Sections O3.1 and
04.1). Unit 1 continued to operate at 90 percent throughout the inspection period.
Unit 2 remained shutdown and defueled during the inspection period for the steam
generator replacement refueling outage U2R22. Both replacement steam generators were
hydrostatically tested during this period.
l. Operations
01 Conduct of Operations
01.1 General Comments (71707) ;
The inspectors conducted frequent reviews of ongoing plant operations. During this
inspection period, the inspectors observed Unit 1 and 2 control room shift
turnovers, reviewed Operations' logs and daily observed control room operations.
The inspectors noted a better questioning attitude by auxiliary operators during
most control room turnovers. The inspectors also noted increased use of the
condition reporting system by operations personnel. During tours of the Primary l
Auxiliary Building, the inspectors noted improved material preservation of !
equipment and cleaning of boric acid leakage on equipment. l
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02 Operational Status of Facilities and Equipment l
02.1 System Recoverv and Restoration Proaram !
a. insoection Scone (71707)
A review of the new Nuclear Power Department Procedure (NP) 2.3.4, Revision 0,
" System Restoration," was conducted by the inspectors.
b. Observe 90ns and Findinas
On January 7,1997, the licensee implemented a new " System Restoratioa"
procedure. Tha purpose of this procedure was to establish a comprehensive
method for returning systems to operation following maintenance outages.
The inspectors reviewed this procedure and the " System Restoration" binders
created to track system restoration. The inspectors observed licensee personnel
using the "RHR System Restoration" binder prior to filling and venting the RHR
system on January 21 through 22,1997.
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c. Conclusions
The inspectors concluded that the new " System Restoration" procedure was more
detailed and comprehensive than documentation used during previous outages for
_ returning systems to service. The inspectors also concluded that the " System
Restoration" binders would aid operations in restoring systems and this effort was
l viewed as positive.
04 Operator Knowledge and Performance
04.1 Unit 1 Power Reduction
a. Insnection Scone (71707)
The inspectors observed the licensee's power reduction from 100 percent to 90
L percent. The following document was reviewed in support of this inspection:
Operations Procedure (OP)-3A, Revision 37, " Normal Power Operation to
Low Power Operation"
b. Observations and Findinas
On December 17,1996, the licensee reduced power on Unit 1 from 100 percent to
90 percent in accordance with OP-3A. This reduction in power was due to licensee
management's concerns about the 2A RHR pump event which occurred the
previous day (Section 04.2). Although this event did not affect the operation of
Unit 1, plant management decided to reduce Unit 1 power to focus attention on the
improper operation of the RHR pump.
The power reduction was performed by the Unit 1 control operator (CO) and a
second licensed operator with oversight by a designated senior reactor operator.
The inspectors observed the operators using the correct procedure during the power
reduction and observed proper communications between the shift personnel.
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c. Conclusions
The inspectors concluded that the evolution was well planned and executed.
04.2 Unit 2 RHR Pumn Oneration with Discharae Valve Shut
a. Insnection Scone
A review of the licensee's incident investigation / root cause evaluation for the
operation of the 2A RHR pump with its discharge valve shut and no recirculation
flow path available was conducted. The following documents were reviewed:
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l * Root Cause Assessment of the Operation of the Unit 2 Residual Heat
l Removal Pump with the Discharge Valve Closed at Point Beach Nuclear
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Plant, dated January 16,1997
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l * Operations Written Work Order 9613927, " Filling and Venting of the RHR ;
System up to 2RH-716A & 2RH-7168 and Testing of RHR Pumps" l
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- Nuclear Power Department Procedure (NP) 1.2.2, Revision 1, " Technical I
Procedure Classification, Review and A,pproval"
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- Point Beach Test Plan (PBTP) 049, Revision 0, Unit 2 RHR System Fill and i
Vent
b. Observations and Findinas
On December 16,1996, the 2A RHR pump (2P-10A) was inadvertently operated
for 38 minutes with its discharge valve shut (2RH-709A) and no recirculation flow
path available. The system was being filled and vented after maintenance. The
licensee formed an Incident Investigation Team (llT) to investigate the
circumstances surrounding this event.
The llT concluded that the root cause was an error by the auxiliary operator (AO)
who performed the initial valve lineup. The AO failed to reposition the pump
discharge valve as required by the valve lineup list because of a place-keeping error.
The llT concluded that the AO should have been able to correctly align the system ]
based on his knowledge and skills.
The llT determined that the evolution was performed under an Operations Written
Work Order (WO) vice an approved test procedure. The WO contained several
valve lineups which listed valves in groups of up to 25 withuut delineators. The
RHR pump discharge valve,2RH-709A, was supposed to be repositioned open.
This valve was listed in the middle of the lineup, but should have been opened last.
The AO skipped this valve intending to come back to 4 at the end of the valve
lineup. When the last valve on the list was repositioned, the AO left the area
without having opened 2RH-709A.
The llT further determined that the AO used a field copy of the valve lineup to
prevent radioactive contamination of the master copy. After repositioning the last
valve on the valve lineup, the AO updated the master copy of the work order by
initiating the line next to the top valve in the lineup and drawing a verticalline down
tnrough all the initial lines next to each valve in that section. The AO did not
review the field copy; he had forgotten that 2RH-709A was still shut.
The inspectors questioned the operator as to why he skipped over valve 2RH-709A
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with the intent to reposition it at the end of the lineup. He stated that he was
l instructed through "on-the-job" training with another AO that valves required to be
l shut should be shut first and valves required to be opened should be opened last.
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The llT identified 17 concerns associated with this event. These concerns were
grouped into the following 6 catepries: l
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e Unclear management expectations for the conduct of valve lineups and the
use of work plans / procedures with signoffs >
e inadequate command, control, coordination, and communication by the
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The use of a non-safety related work plan and work order for post- !
maintenance testing and operability testing of a safety-related system
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e Configuration control
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l e Valve mispositioning and danger tag events
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e possible Duty Shift Superintendent (DSS) distraction due to illness and
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The llT provided recommendations in the Root Cause Assessment document that
covered the six categories identified above. The recommendation regarding the use ,
of an Operation Written Work Order to test safety-related components was to ,
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review the overall practice of using work plans as part of the formal post-
[ maintenance test (PMT) used for operability and return-to-service testing of safety-
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related components. The llT also noted that if work plans continued to be used for ;
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evolutions similar to the event in the investigation, that human factors concerns
were included in the writing of the work plan.
The licensee reperformed the fill and vent on the 2A RHR system on January 22,
1997. The procedure used, PBTP 049, was an approved test procedure.
c. Conclusions
The inspectors agreed with the llT root cause assessment and most of the
corrective actions. However, the inspectors were concerned that the llT
l recommendation did not conclusively state that approved procedures for testing
safety-related components would be used in all future testing.
The failure of the AO to open the RHR pump discharge valve,2RH-709A, as
j required by the valve lineup list is an example of a violation of 10 CFR 50,
! Appendix B, Criterion V, " Instructions, Procedures, and Drawings," which requires,
in part, that activities affecting quality be prescribed by documented instructions,
procedures, or drawings, of a type appropriate to the circumstances and be
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50-266(301)/96019-01a(DRP)). Although the valve mispositioning was identified
by the licensee and a thorough investigation was conducted, corrective actions
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taken for a previous valve mispositioning error involving the auxiliary feedwater !
system (h.;poction Repo'.t No. 50-266(301)/96006) should have prevented this i
event.
07 Quality Assurance in Operations
07.1 Plant On-Site Review Committee Meetina Observations (40500)
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The inspectors observed three Manager's Supervisory Staff meetings (MSSM) l
including MSSM 97-02. Issues discussed included procedures and safety i
evaluations (SEs) for testing of containment penetrations P12b and P30a and stroke
testing of RHR/ Low Head Core Deluge valve,1 SI-852A. Issues discussed during 1
MSSM 97-02 included turbine-driven auxiliary feedwater pump,2P-29, PMT issues, i
and the missed Unit 1 chemistry T/S surveillance test documented in Licensee !
Event Report (LER) 266/96-014. '
Several examples of committee members displaying good questioning attitude and
challenging of staff information were observed by the inspectors. The inspectors
have continued to note improvements in committee members' questioning attitude
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during recent MSS meetings.
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08 Miscellaneous Operations issues
08.1 (Closed) Insoector Follow-uo item (IFI) 301/94013-05(DRP): Reactor Coolant
System (RCS) Leakage Increase and Piping Pressure Wave l
On July 17,1994, after the 2A SI pump was used to fill the 2B Si accumulator,
licensee personnel noted that the level in the pressurizer relief tank (PRT) was
increasing. An RCS leak rate calculation determined that 0.3 gallons per minute
(gpm) was leaking through the Si line check valve, SI-8678, and test line valve, SI-
839D, and out the test line header relief valve, SI-8878, into the PRT. This leakage
path was confirmed on July 19,1994, by measuring elevated temperatures on the
suspected flow path.
The licensee determined that the leak rate was limited by leakage past air-operated
valve (AOV), SI-839D, which used spring pressure to seat the disc. The licensee
believed that the valve disc came off its seat when the 2A SI pump was started
because of a slight pressure wave from the pump. This allowed RCS pressure to
lift the SI-887B relief valve.
The licensee analyzed the worst case scenario and calculated that a 4,800 pounds
per square inch - gauge (psig) pressure wave was possible during the ovolution.
The licensee initially determined that no water hammer or hydraulic transient
occurred based on the piping having been properly filled and vented, piping
walkdowns, and the absence of any sounds being heard by operators during the
event.
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On July 20,1994, after performing an engineering analysis and discussions with
the AOV vendor, licensee personnel entered containment, installed a pressure gage
l at a test connection near relief valve SI-887B and increased the spring pressure on
SI-839D. Subsequently, the gage pressure started falling and the PRT level stopped
increasing. Within about 15 minutes of increasing the AOV spring pressure, the
leak was stopped. I
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As part of the licensee's investigation into the cause of the increased RCS leakage, i
accumulator fill evolutions were monitored on Unit 1 and Unit 2 to determine if
l pressure surges in the Si test line during the fill could have affected the position of
SI-839D. The results of the monitoring showed that pressure surges on the order
of 1850 psig to 2073 psig occurred during accumulator fill evolutions. These
pressure surges were above the test line relief valve SI-887B setpoint. After these 1
pressure surges were determined, the licensee performed cal::ulations which l
showed that the Si test line and supports were not overstressed.
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The licensee decided to reduce the pressure surge by slowing down the
accumulator fill rate by throttling the globe valves downstream of the accumulator
fill AOVs. The licensee stated that the pressure surge caused by valve slam was
directly proportional to the flow rate in the pipe just before the valve closes. The
flow rate was reduced from 150 gpm to 20 gpm which reduced the calculated
pressure surge to less than the test line relief valve setpoint. The globe valves
were locked in the throttled position and Operating instruction (01)-100, Revision 6,
" Adjusting St Accumulator Level and Pressure" was changed to state the new fill I
rate.
The licensee investigated the July 17,1994,2B accumulator fill evolution to
determine if there were any deviations from the normal filling method which may
have contributed to this event. The licensee concluded that no evidence could be
found that plant conditions or the method of filling the accumulator contributed to
the opening of SI-839D.
The inspectors had no concerns with the licensee's stress calculations, root cause,
or corrective actions. This issue is considered closed.
(Closed) Confirmatorv Action Letter (CAL) No. Rlli-96-012: The CAL concerned the
adequacy of the volume of control room annunciator alarms, the adequacy of
licensed reactor operator hearing, and the ability of the Duty Technical Advisor to
respond within 10 minutes to the control room. in a letter dated September 9,
1996, the licensee adequately responded to the CAL. In addition, the CAL issues
were discussed at a pre-decisional enforcement conference on September 12,
l 1996, as part of an escalated enforcement action. In a letter dated January 31,
1997, the licensee again addressed the CAL issues as part of the response to the
Notice of Violation and Proposed imposition of Civil Penalties that resulted from the
escalated enforcement action. The CAL is closed and the CAL issues will be
reviewed as part of the overall NRC review of the licensee's January 31,1997,
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response. An IFl will
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l track NRC review of a licensee commitment in the September 9,1996, response to
establish and implement by March 31,1997, a formalized self-assessment program
to periodically assess all aspects of control room conduct (IFl 50-266(301)/96019-
02(DRP). ,
IJL Maintenance
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M1 Conduct of Maintenance
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M1.1 General Comments
NRC Inspection Procedures 62707 and 61726 were used in the inspection of plant
maintenance and surve!!!ance activities. The inspectors observed and reviewed .
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selected portions of the following maintenance and test activities:
- WO 99370, "P-012A&B Spent Fuel Pool Pumps Design Basis Flow Test"
- Inservice Test (IT)-11 A, Revision 1, " Performance Test for Spent Fuel Pool
l Heat Exchanger HX-13A/B"
- IT-05, Revision 32, " Containment Spray Pumps and Valves (Quarterly)
Unit 1"
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- IT-07, Revision 24, " Service Water Pumps and Valves (Quarterly)"
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- Routine Maintenance Procedure (RMP) 9008-1, Revision 14, " Residual Heat :
Removal Pump Removal and Installation"
- IT-14, Revision 11 " Quarterly inservice Test of Fuel Oil Transfer System
Pumps and Valves"
- RMP-1108, Revision 5, "G-01 Redundant Systems Six Month Post-Diesel
Annual Check"
- * RMP-1108, Revision 5, "G-02 Redundant Systems Six Month Post-Diesel
Annual Check"
- Installation Work Plan (lWP) 95-042A, " Modification of Valves 2SI-857A&B
Unit 2"
- Technical Specification Test (TS)-83, Revision 4, " Emergency Diesel
Generator G-03 Monthly"
- TS-71, Revision 14, " Monthly Electric Motor Driven Fire Pump Functional
Test"
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[ * PBTP 049, Revision 0, " Unit 2 RHR System Fill and Vent"
- WO 9700220, "P-32E Service Water Pump High Vibrations"
- The work performed under thest., activities was prcfessional and thorough.
l Technicians were experienced and knowledgeable of their assigned tasks. The
I work package was present at the jobsite and actively used by the technicians for all
work observed. System engineers were frequently observed monitoring job
progress.
i M2 Maintenance and Material Condition of Facilities and Equipment
. M2.1 Unit 2 Secondarv Hvdrostatic Testino of New Steam Generators
a. Insoection Scooe (61726)
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, The inspectors reviewed PBTP-041, Revision 2, " Hydrostatic Test of Unit 2 HX-1 A
l Steam Generator" and PBTP-042, Revision 2, " Hydrostatic Test of Unit 2 HX-1B !
Steam Generator" during observations of these surveillance activities.
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b. Observations and Findinos !
l The inspecte abserved hydrostatic testing of both steam generators,2HX-1 A and
2HX-18. The inspectors verified that required hydrostatic test pressures were
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reached and stabilization times were met prior to the start of testing. The
l inspectors looked for leakage inside the steam generator bowls and or, the piping, )
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instrument lines, manways, and handholes. Slight leakage was noted at hydrostatic l
- pressure at the manways and handholes. No other leakage was noted and inside l
the bowls remained dry. Licensee testing staff examined all required areas of the '
steam generators and found no deficiencies.
c. Conclusions
The testing was well performed and the inspectors had no concerns. I
M3 Maintenance Procedures and Documentation
M3.1 jfah Fuel Oil System Pressure Alarm on EDG G-03
a. Insoection Scone (61726)
The monthly test of EDG G-03 was observed in December 1996 and January 1997
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and the following documents were reviewed:
- TS-83, Revisions 3 and 4, " Emergency Diesel Generator G-03 Monthly"
- Final Safety Analysis Report (FSAR) Section 8.2.3, " Emergency Power"
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- NP 5.3.1, Revision 4, " Condition Reporting System" !
- - CR 96-1856, "High Fup! Oil System Pressure Alarm on G-03 EDG"
b. Observations and Findinas l
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On January 21,1997, TS-83 was performed to satisfy the normally scheduled '
l- monthly cellup (routine surveillance). During performance of step 4.15, the EDG ,
l - was accelerated to rated speed. Once the diesel engine reached 900 rpm, the i
inspectors observed the EDG engine fuel oil pump discharge pressure indicator l
reading approximately 61 psig. The normal range for this reading on the EDG logs
was 20 to 50 psig. The operator did not notice this reading until he received the .
Low /High Fuel Oil Pressure a! arm. At this point, the reading was approximately 56 l
psig. The EDG operator reported the reading to the control room. The DSS said 1
that the discharge pressure would decrease as the diesel was loaded.
Once the EDG was loaded to 2500 kilowatt (kW), the inspectors noted that the ,
reading was approximately 48 psig and was within the normal range listed on the l
logs. I
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During the last performance of TS-83 on December 26,1996, CR 96-1856 was !
written stating that the fuel oil system pressure high/ low alarm was received after
the generator field was flashed in step 4.13. Upon investigation, the fuel oil
system pressure was high by approximately 10 psig. The G-03 fuel oil filters were
changed out and TS-83 was reperformed. The Low /High Fuel Oil Pressure alarm,
was not received during the subsequent test. Although CR 96-1856 was not
closed out at the end of the inspection period, no corrective action or evaluation
was contained on this CR other than changing out the fuel oil filters.
The inspectors noted that no CR was written for the high fuel oil pressure alarm
received during the performance of TS-83 on January 21,1997.
c. Conclusions
The inspectors were concerned that since no CR was written for the alarm received
t during the January 21 test that no reevaluation of the condition took place and no
! examination of any operability concerns occurred.
Step 1 of Attachment A to NP 5.3.1 states that a CR should be initiated for
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nonconformances that may appear to be adverse to the safe and orderly conduct of
the operation of PBNP, and Example 7 in Attachment A notes that discrepancies
associated with alarms that were conditions that may affect equipment operability
warrant initiation of a CR The inspectors concluded that the high fuel oil pressure
alarm received during the performance of TS-83 on January 21,1997, was a i
condition that could affect EDG operability, j
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l The failure to write a CR was contrary to NP 5.3.1 and an example of a violation of 1
! 10 CFR 50, Appendix B, Criterion V (VIO 266(301)/96019-01b(DRP)). l
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M4 Maintenance Staff Kno'wledge and Performance
M4.1 Missed Surveillance Test for the Unit 1 RHR/ Low Head Core Deluae Valve
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a. Insoection Scoce (37551 & 61726)
The at-power stroke test of the RHR/ Low Head Core Deluge Valve,1SI-852A, was !
observed. The following documents were reviewed:
- PBTP 048, Revision 0, " Full Stroke Open Test of 1SI-852A" i
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- SE 97-007, Revision 1, PBTP 048, " Full Stroke Open Test of 1SI 852A"
- CR 97-136, " Missed Technical Specification Surveillance Test"
- Point Beach Memorandum (PBM)96-542, "Self Assessment of Safety
Related Equipment Testin0"
- FSAR Section 9.3, " Auxiliary Coolant System" l
b. Observations and Findinas
On January 16,1997, the licensee discovered that the Unit 1 RHR/ low head core
deluge valve,1SI-852A, had not been stroke tested per ASME Section XI since i
April 4,1994. This valve was required to be stroked tested each cold shutdown
(typically each annual refueling outage) per ASME Section XI and T/S 15.4.2.B.3. ]
The discovery was made during the final reviews of valve inservice testing (IST) l
being performed to verify that stroke tirning IST acceptance criteria bounded design
basis requirements. These reviews were part of the licensee's corrective actions ;
for surveillance testing violations discussed in Inspection Report 50-
266(301)/96006 and at the pre-decisional enforcement conference on
September 12,1996.
Previous stroke testing of 1SI-852A was performed during cold shutdowns to limit
radiation exposure for the local position verification. Similar valves 1SI-852B,2SI-
852A, and 2SI-852B were all stroke tested within the required periodicity during
PMTs.
The plant simulator was used to test various scenarios which could be encountered
during performance of this test. Feedback from the simulator runs was
incorporated into the test procedure.
On January 17,1997, the inspectors observed the performance of PBTP 048. This
procedure stroked 1SI-852A as required by ASME Section XI while Unit 1 was at
90 percent powr The inspectors compared the valve stroke times with
acceptance criteria and noted that the times were acceptable.
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On October 2,1996, the licensee issued PBM 96-542. In this self-assessment, the . !
i- licensee noted that several relief and check valves were not controlled by the ,
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existing licensee callup systems. This assessment noted that this condition could l
result in these valves not being tested on their required frequency. 'Section XI '
valves and their IST requirements were looked at during this assessment. ;
The inspectors reviewed CR 97-136 and discussed the corrective actions for the
missed T/S surveillance testing of 1SI 852A with the cognizant engineer and site :
engineering management._- Licensee management stated in the exit meeting on l
l January 29,1997, that the existi.ig system for calling up T/S-required surveillance !
!- testing may not inciude all equipment required to be tested. The inspectors wero (
! concerned that other T/S equipment may not be tested at the frequency required. 1
Also, the inspectors were concerned that the licensee's corrective action for this !
issue was not comprehensive enough to ensure that all equipment was tested at i
the frequency required,
c. Conclusions
The inspectors concluded that the performance of PBTP 048 was well-planned and
professionally executed.
However, the inspectors also concluded that inadequacies existed in the licensee's
systems for ensuring that equipment was tested at its required frequency. Also,
. the inspectors were concerned that corrective actions, committed to by the licensee
! at the end of the inspection period, were not comprehensive enough to prevent
recurrence of this condition for other required T/S equipment.
T/S 15.4.2.B.3 required that IST of ASME Code Class 1,2, and 3 valves be
performed in accordance with Section XI of the ASME Boiler and Pressure Vessel !
Code (1986) and applicable Addenda as required by 10 CFR 50.55a. Section IWV- l
! 3412(a) of Section XI requires that valves that cannot be exercised during plant
operations be full-stroke exercised during cold shutdowns. Contrary to this,1SI-
852A, an ASME Code Class 2 valve that could not be exercised during plant
operations, was not stroke tested during the two refueling outages (in the spring of
1995 and 1996) between April 4,1994 and January 17,1997, a violation of T/S l
15.4.2.B.3 (VIO 50-266/96019-03(DRP)).
M4.2 Unit 1 Containment inner Hatch Surveillance Test Failure and Corrective i
Maintenance l
a. Insoection Scone (61726 & 62707)
On December 27 and 28,1996, the Unit 1 containment inner personnel hatch failed
l its leakage test during the two performances of TS-10A, Appendix B. The
following documents were reviewed by the inspectors during their evaluation of
these failures:
'
i
! i
l 14
L
, = -
_. _ _ _
, .. .
I
- CR 96-1860, " Unit 1 Containment Hatch Exhibited Higher Than Normal
Leakage"
- CR 96-1870, " Potential Failure of Containment Upper Hatch" l
- WO 9614145, " Personnel Access Air Lock Excessive Leakage"
- T/S 15.4.4, " Containment Tests" and T/S 15.3.6, " Containment System"
l
l * Containment Leakage Rate Testing (CLRT) Program, Revision 0
i
- TS-10A, Appendix B, Revision 13, " Hatch Door Seals Unit 1"
l * FSAR Section 5, " Containment System"
I
b. Observations and Findinas
The Unit 1 inner and outer hatch door seals were vacuum tested on December 27,
1996, as allowed by T/S 15.4.4.1 and the CLRT program. Operations personnel
secured the Unit 1 forced vent and equalized pressure across the inner door prior to
performing TS-10A, Appendix B. The licensee had previously told the inspectors
l that they believed that the forced ventilation was the cause of previous inner door
!
test failures.
The inner door leakage exceeded acceptance criteria given in TS-10A, Appendix B
but was not above criteria which required a full pressure test of the airlock. The
,
inner door o-rings were replaced and the door alignment was adjusted per WO
l
9614145. Subsequent initial testing met TS-10A, Appendix B acceptance criteria.
On December 28,1996, during final testing of the inner door, significant air leakage
was noted by testing personnel around the shaft seal on the remote operator for the '
inner door. The leakage noted exceeded T/S 15.4.4.1 and the CLRT program
l requirements. The inner door was appropriately declared inoperable and the T/S
15.3.6.A.1.d.(3) limiting condition for operation (LCO) was entered.
Maintenance personnel replaced the quad-ring shaft seal that failed, the inner door
passed a full pressure airlock test per CLRT requirements, and the LCO was exited.
Several failures of the lanu personnel hatch door during TS-10A, Appendix B
testing have been docunsnted in Inspection Reports 50-266(301)/96012(DRP) and
50-266(301)/96015fDRP). The inspectors noted a concern in Inspection Report
j 50-266(301)/96012(DRP) that the licensee had not fully analyzed nor determined
the root causes of the inner door test failures.
c. Conclusions
The inspectors were concerned with the continued failures of the inner personnel
hatch door during TS-10A, Appendix B testing. The inspectors were also
15
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l , .. .
,
! concerned that the root causes of the leakage problem have not yet been identified.
This is considered an IFl pending further review by the inspectors of inner personnel
hatch door testing, the licensee root cause investigation, and corrective actions for
this issue (IFl 266/96019-04(DRP)).
Ill. Enoineerina
E1 Conduct of Engineering
E1.1 Enaineerina Reviews Durina the insoection Period
Based on the large number of 10 CFR 50.72 reports issued during this inspection
period, the inspectors have noted that engineering personnel have been re-analyzing
old assumptions, displaying a more questioning attitude, and reporting concerns
raised. The inspectors viewed all these developments as positive.
E2 Engineering Support of Facilities and Equipment
E2.1 Heliccil Renair to 2A S1 Pumo 1
a. Insoection Scooe (37551) )
l
An inspection of a helicoil repair to the 2A SI pump,2P-15A, was performed. The l
following documents were reviewed
- FSAR Section 6.2, " Safety injection System" )
i
- NP 7.2.5, Revision 3, " Repair / Replacement Program" l
- ASME Boiler and Pressure Vessel Code,1986 edition, no addenda, Section
XI, " Rules for Inservice Inspection of Nuclear Power Plant Components"
- Regulatory Guide 1.147, Revision 11, " Inservice inspection Code Case
Acceptability ASME Section XI Division 1"
b. Observations and Findinas
On November 26,1996, the inspectors reviewed a helicoil threaded insert repair of
a bolt hole on the 2P-15A casing. The inspectors questioned the licensee
concerning whether or not the repair was performed in accordance with the ASME
Boiler and Pressure Vessel (B&PV) Code. On December 17,1996, the licensee
informed the inspectors that helicoil repairs had inappropriately been exempted in
NP 7.2.5 (paragraph 1.5.10), the licensee's governing procedure for Section XI of <
,
l
l Footnote 6 to 10 CFR 50.55a(g) stated that Regulatory Guide 1.147, " Inservice
Inspection Code Case Acceptability - ASME Section XI, Division I," listed Code
Cases that were considered acceptable for use with Section XI components, such
16
i
. -
, .. .
as the 2P-15A SI pump. Code Case N-496, listed in Regulatory Guide 1.147 as
acceptable, specified six requirements that applied to the use of helical-coil (helicoil)
threaded inserts. After the licensee determined that Code Case N-496 applied to
the helicoil repair, the licensee evaluated the repair and determined that the six
requirements of the Code Case N-496 had been met; however, extensive evaluation
was required to show that the repair met the requirement that the insert satisfy
original construction loading limits for the threaded connection.
The failure to include instructions for meeting Code Case N-496 in the NP 7.2.5 or
in the WO used for the repair on the Si pump is an example of a violation of 10 CFR
60, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," which
requires, in part, that activities affecting quality be prescribed by documented ,
instructions, procedures, or drawings, of a type appropriate to the circumstances I
and be accomplished in accordance with these instructions, procedures, or I
drawings (VIO 301/96019-01c(DRP)). l
l
When the inspectors questioned the licensee after the repair was completed, none j
of the code case requirements were documented as being met. NP 7.2.5 was !
subsequently revised to ensure that Code Case N-496 requirements were applied to
helicoil repairs.
c. Conclusions
The inspectors determined that appropriate instructions had not been provided in a
procedure or WO for a helicoil repair on the 2P-15A SI pump. After an extensive
evaluation the licensee determined that the repair met established ASME Section XI
criteria. The licensee subsaquently revised its ASME " Repair and Replacement"
program governing procedure to ensure that appropriate instructions would be
provided for future helicoil repairs.
E2.2 Potential Overoressurization of Isolated Pioina in Containment Durina a Lame Break
Loss of Coolant Accident (LBLOCA)
a. Insoection Scone (37551)
An inspection into the licensee's evaluation of thermally induced overpressurization
of isolated water-filled piping sections in containment was conducted. The
evaluation was in response to Generic Letter (GL) 96-06, " Assurance of Equipment
Operability and Containment Integrity During Design-Basis Accident Conditions."
The following documentation was reviewed by the inspectors:
- GL 96-06, dated September 30,1996
+ Wisconsin Electric Calculation 97-06,1/9/97, " Operability Determination for
Containment Penetration P-11 Trapped Fluid Pressurization"
17
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,
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'
3
l * Wisconsin Electric Letter, VPNPD-96-090, " Dockets 50-266 and 50-301 GL
! 96-06 Assurance of Equipment Operability and Containment integrity During
Design Basis Accident Conditions Point Beach Nuclear Plants, Units 1 and 2"
- Design Change Package WO 9700318,1/9/97, " Seal Water Retum Line
, insulation (Unit 1)"
!
!
l *
FSAR Section 9.2, " Chemical and Volume Control System" !
.
!
I
b. Observations and Findinas
{
There were three issues of concem in GL 96-06. The inspection dealt with the
third issue, the thermally induced overpressurization of isolated water filled piping
) sections in containment which could jeopardize the ability of accident-mitigation
systems to perform their safety functions. The overpressurization could also lead
- to a breach of containment integrity via bypass leakage.
On October 30,1996, the licensee issued letter VPNPD-96-090 which responded j
to the GL. In this letter, the licensee stated that there were six water-filled piping
'
l
i sections in each containment which were potentially susceptible to thermally- j
induced overpressurization. These sections would be evaluated and the results of j
the evaluations and subsequent corrective actions would be provided in the 120-
]
day response to the GL.
l On January 9,1997, the licensee determined that five of the six potentially
l susceptible water-filled piping sections discussed in the October 30 letter did not
have overpressurization concerns. The initial analysis for the sixth piping section,
which assumed that the piping inside containment was insulated, concluded that
there was no overpressurization concern. However, after previous system )
walkdown information was reviewed, the licensee discovered that the piping-Unit 1
reactor coolant pump (RCP), chemical and volume control system (CVCS), seal :
'
i
'
retum piping--was not insulated. The licensee revised the analysis and concluded
that thermal overpressurization for this isolated water-filled piping section was a
l
concern.
On January 9,1997, the licensee issued a four-hour report in accordance with 10
CFR 50.72(b)(2)(iii)(C) for this issue. This condition would occur during a large i
break LOCA (LBLOCA) when both the inboard and outboard containment isolatien i
valves in this seal retum piping shut. The heat input from the LBLOCA to the
isolated section of pipe would heat the trapped liquid overpressurizing the pipe.
The licensee declared the containment inoperable and entered a one-hour T/S LCO.
The LCO was exited after the breaker for one of the isolation valves,1CV-313, was '
tagged open so that the valve would not close on a containment isolation signal.
l The opening of the breaker effectively removed the overpressurization potential. A
four-hour T/S LCO was then entered for the inoperable containment isolation valve.
!
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_ . . - _ _
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The licenses then installed thermal insulation on the seal retum pipe which
eliminated the overpressurization concern. The licensee subsequently removed the
danger tag from the containment isolation valve, restored the breaker to its normal i
position, and exited the LCO.
c. Conclusions
The inspectors had no concerns with the licensee's actions to correct the potential
thermal overpressurization condition and concluded that the licensee properly 1
entered and exited all T/S-required LCOs during resolution of the issue. ;
!
E3 Engineering Procedures and Documentation
E3.1 Dil Leakaae From Electric Fire Pumo P-35A Motor
I
a. Insoection Scoce (61726 & 37551) i
On January 24,1997, the inspectors observed a pool of oil beneath the electric fire i
pump motor, P-35A. Portions of the following documents were reviewed during
inspection of this issue:
- WO Request 9611753,"Large Amount of Oil on Base of Electric Fire Pump
Motor, P-35A" l
l
- TS-71, Revision 14, " Monthly Electric Motor-Driven Fire Pump Functional j
'
Test"
- NP 5.3.1, Revision 4, " Condition Reporting System"
- NP 8.1.1, Revision 2, " Work Order Processing"
- T/S 15.3.14, " Fire Protection System"
- FSAR Section 9.6.1, " Fire Protection System"
b. Observations and Findino
On January 24,1997, the inspectors notified operations of the oil beneath the P-
35A motor and an AO was dispatched to the pump. The inspectors also noted a
WO tag for request 9611753 hanging on the motor. The work order tag had been
written on October 23,1996. Further review by the inspectors determined that no
CR had been written for the oil leak, and that the system engineer indicated that he
thought the WO had been written to cleanup oil that spilled during filling of the
,
motor oil reservoir. Because this condition was only documented with a WO tag,
l no operability determination was made for the P-35A pump. NP 8.1.1, the WO
l procedure, noted that conditions requiring a CR should be documented per NP
5.3.1, which also requires an operability determinations be performed for certain
condition.
19
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On January 27,1997, the inspectors observed performance of TS-71. All required
acceptance criteria in the 10-minute test were met; however, the inspectors- j
observed oil leaking from the motor during the test. No CR was written to "
' document the oil leakage; however, the AO performing the test did note the leakage
l in the test procedure. . The inspectors reviewed the results of two' additional TS-71
l tests conducted after the October 23rd date when the WO tag was hung. Neither
of these tests documented any oilleakage from the P-35A motor.
j The inspectors were informed during discussions with the system engineer that the
- motor was scheduled to be repaired during the first week of February 1997.
c. Conclusions
!
The inspectors were concerned that no CR was written nor was an operability
l -- evaluation conducted for the oil leak condition and no reanalysis of the cause of the
oil leakage was performed.
'
Step 1 of Attachment A to NP 5.3.1 stated that a condition report should be
- initiated for nonconformances that may appear to be adverse to the safe and
L orderly conduct of the operation of PBNP. Attachment A also stated that
conditions that may affect equipment operability warrant initiation of a CR. The
inspectors concluded that the oil leakage from the P-35A electric fire pump motor 1
was a condition that may affect equipment operability and thus warranted a CR.
10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings," I
required that activities affecting quality be prescribed by documented procedures of 1
a type appropriate to the circumstances and be accomplished in accordance with ]
these procedures. The failure to write a CR for the oil leak on October 23,1996, or '
during any subsequent TS-71 monthly tests was contrary to procedure NP 5.3.1 l
and is considered an example of a violation Criterion V (VIO 266(301)/96019- l
01c(DRP)). -
)
E4 Engineering Staff Knowledge and Performance
E4.1 Main Steam Safetv Valve (MSSV) Setooint Drift
a. Insnection Scooe (37551)
An inspection was conducted of the licensee's response to Information Notice (lN)
96-03, "MSSV Setpoint Variation as a Result of Thermal Effects." IN 96-03 was
issued on January 5,1996, to alert licensees to a possible source of variation in the
setpoint of safety valves as a result of changes in temperature in and around the
valves. The following documents were reviewed by the inspectors:
- IN 89 90, Supplement 1,4/3/91, " Pressurizer Safety Valve Lift Setpoint
Shift"
l
i
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-. , , . . - . - ,-. . - , , . . , . _, , - -
- - . -
.
<* .
- Wisconsin Electric Memo, NPM 91-0718, 5/30/91, " Evaluation of !
Information Notice #89 90 and Supplement #1" j
- Wisconsin Electric Memo, NPM 93-0215,4/6/93, NRC Information Notice
95-02 " Malfunction of a Pressurizer Code Safety Valve" l
,
- Operability Determination dated 11/21/96, " Unit 1 and Unit 2 MSSVs"
- Operability Determination dated 12/31/96, "1 MS-02007,1 MS-02012,1 MS- l
02013, 2MS-02007, 2MS-02011 MSSVs"
- Operability Determination dated 1/03/97, "1 MS-02007,1 MS-02012,1 MS- !
02013, 2MS-02007, 2MS-02011 MSSVs"
- FSAR Section 14.1.9, " Loss of External Electrical Load" i
b. Observations and Findinas
On April 23,1996,in response to information Notice 96-03, the licensee
determined that the MSSVs were tested at ambient temperatures of 70oF to 80 F.
These valves typically saw in-service, ambient temperatures between 0 F and
100 F, depending on outside air temperature.
On November 21,1996, the licensee issued an operability determination for the
MSSVs based on the results of setpoint testing at Wyle Laboratories. The Wyle
test results showed that the MSSV setpoints were different at full pressure lift
conditions than the setpoints of MSSVs tested with a lift assist device. Also,
additional testing at Wyle showed that setpoints varied wah ambient temperature
during testing. i
The operability determination adjusted the setpoint of the MSSVs based on the
Wyle setpoint drift test data and concluded that all Unit 1 MSSVs would relieve at l
full capacity below the maximum setpoint assumed in the current Unit 1 accident ;
analysis.
l
l
The licensee issued a second operability determination on December 31,1996, l
which concluded that worst case scenarios were not used in the first operability
determination. The second operability determination used worst case adjusted
setpoints and concluded that the MSSVs may exceed their design basis pressure l
setpoint for the loss of external load analysis. On December 31,1996, the licensee
made a four-hour report in accordance with 10 CFR 50.72(b)(2)(iii)(D) stating that
there may have been a potentialin the past that the MSSVs would not have lifted
at the maximum assumed setpoint.
The second operability determination also stated that maintaining the MSSVs above
i 40.3 F would provide necessary margin to be within the accident analysis. The
l licensee erected a tent over the Unit 1 MSSVs and verified valve temperatures
l remained greater than 40.3 F.
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'
a; 4 ' ' 3
i
.
A third operability determination was issued on January 3,1997, which concluded -
'
- that the MSSVs for Unit 1 were operable based on a parametric comparison of key
inputs and a quantification (with a sensitivity analysis) of the effect of these key
inputs on the results of a revised loss of external load analysis. The revised loss of
' load analysis modeled the MSSVs as lifting at the design setpoint and accounted for
head losses between the steam generators and the MSSVs.
On April 3,1991, Supplement 1 to IN 89 90, " Pressurizer Safety Valve Lift
Setpoint Shift," was issued. The purpose of this supplement was to alert licensees -
L to environmental factors that may affect the lift setpoint of all safety (relief) valves,
l including MSSVs.
The licensee issued memo, NPM 91-0718, dated May 30,1991, titled " Evaluation ,
j ' of Information Notice #89-90 and Supplement #1." In this memo the licensee
l recommended that the MSSV setpoint test process be reviewed to confirm that the.
!. setpoint test was conducted at the same conditions as actual valvs service.
I
However, no actions were taken by the licensee until 1996.
c. Conclusions
.The inspectors determined that the licensee was aware in 1991 of the potential for
the MSSV setpoint to drift due to ambient temperature changes--a condition
adverse to quality, but did not take prompt action to correct this condition. The
problem was addressed on January 3,1997.
10 CFR 50, Appendix B, Criterion XVI, required measures be established to assure
that conditions adverse to quality be promptly identified and corrected. The failure
to promptly resolve the MSSV setpoint issue is considered a violation of Criterion
XVI (VIO 266/301-96019-05(DRP)).
E4.2 LBLOCA Delav Time Assumotions Not Correct
a. insoection Scone (37551)
'
The licensee identified that the SI system full flow delay times may be greater than
what was assumed in the LBLOCA analysis. The following documentation was
reviewed during this inspection:
,
- FSAR Section 14.3.2, " Major Reactor Coolant System Pipe Ruptures
! (LOCA)"
L
l * FSAR Section 8.2.3, " Emergency Power"
l
l
- Westinghouse Letter WES 74-47, dated 5/31/74, " Westinghouse Motors in :
! Safety-Related Systems"
)
,
- Wisconsin Electric Calculation N-90-085, dated 10/17/90, " Safety injection
Pump Starting Curves"
i
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. . -. --. . . .
.
,. .
Wisconsin Electric Letter dated 2/4/81. " Dockets Nos. 50-266 and 50-301
Technical Specification Change Request No. 65 Point Beach Nuclear Plant
Units 1 and 2"
- Wisconsin Electric Letter NPL 96-0391, dated 12/11/96, " Dockets 50-266
and 50-30130 Day Report of ECCS Evaluation Model Changes,10 CFR
50.46 Point Beach Nuclear Plant, Units 1 and 2"
b. Observations and Findinas
While reviewing design basis valve closure times for the IST program, a licensee
engineer discovered that the safety injection (SI) flow delay times may be greater
than what was assumed in the LBLOCA analysis. This resulted in a one-hour report
in accordance with 10 CFR 50.72(b)(1) for Unit 1 and a four-hour report in
accordance with 10 CFR 50.72(b)(2)(i) for Unit 2 on January 8,1997.
The LBLOCA analysis assumed that the high and low head Si systems were capable
of delivering flow within 5 seconds and 17.7 seconds respectively. The licensee
conservatively determined that the delay times (assuming offsite power available)
for high head and low head Sl flow could be 8 seconds for high head and 23.7
seconds for low head Si from the time an SI signal was generated.
The 8-second high head Si flow delay time consisted of a 2-second SI signal
processing time,1-second delay for sequencer plus uncertainty, and 5 seconds for
the SI pump to start and get up to full speed. The 23.7-second low head Si flow
delay time consisted of a 2-second Si signal processing time,7-second delay for j
sequencer plus uncertainty, and 14.7 seconds for the low heed pump to start and i
get up to speed.
]
The inspectors questioned the licensee regarding the basis for these delay times. l
The licensee stated that the 2-second Si signal processing delay time was based on
response time test data from Westinghouse. The 1-second delay time for the high
head pump and the 7-second delay time for the low head pump for sequencer delay i
plus uncertainty were based on information contained in section 8.2.3 of the FSAR.
The 5-second delay far the high head pump to start and get up to speed was based
on a Wisconsin Electr,c calculation, and the 14.7 second delay for the low head
pump to start and get up to speed was based on information from Westinghouse.
The licensee performed a preliminary evaluation assuming the longer delay times of
8 seconds for high head and 23.7 seconds for low head Si flow from the time at
which an SI signal was generated. This change resulted in a peak cladding
temperature penalty of less than 50 F. The licensee stated that an additional 50 F
penalty would result in a peak cladding temperature of 2187oF. The licensee
concluded that the Si system v'as capable of performing its function to maintain
the calculated LBLOCA peak centerline temperature below the acceptance criterion
of 2200 F required by 10 CFR 50.46.
23
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!
!
.i
c. Conclusions
The inspectors had no concems with the licensee's basis for the safety injection
delay times or the licensee's analysis of the change to the peak cladding
temperature.
i
E4.3 Potential Cloaoina of Refuelina Cavity Drain Line Durina a LOCA
a. Insoection Scone (37551)-
On January 20,1997, the NRC was notified by the licensee in accordance with
10 CFR 50.72(b)(1) that sufficient water may not be available during a LOCA for ,
the recirculation portion of the accident due to potential clogging of the refueling. '
cavity drain. The inspectors reviewed the 10 CFR 50.72 notification; CR 97-169,
" Safety Analysis Uncertainty Due to Water Being Held in the Lower Refueling
Cavity"; CR 96-1848, " Material Certifications for Modification Package Are
incomplete"; and temporary changes to Emergency Operating Procedure (EOP) 1.3,
" Transfer to Containment Sump Recirculation," during this inspection.
b. Observations and Findinas
h
The current safety analyus for both Units at Point Beach assumed 184,185 gallons
of water were delivered from the Refueling Water Storage Tank (RWST) to the RCS i
and containment sump following a LOCA. Sufficient RWST water delivery ensured '
enough water for recirculation and suberiticality. The analysis assumed that any
!
water from the RCS or containment spray which entered the refueling cavity would
l drain into the containment sump.
While evaluating CR 96-1848, which questioned whether a flapper valve in the
refueling cavity drain line could fail, the licensee determined that the lower refueling
cavity may retain up to 46,000 gallons of water due to drain line clogging. If the
46,000 gallons of water was held in the refueling cavity, the amount of water
l removed from the RWST per the existing EOPs would not provide the 184,145
'
gallons required by the existing analysis.
The licensee changed EOP 1.3 to remove more water from the RWST to provide the
, required amount of water needed by the analysis. The inspectors reviewed the CRs
l associated with this issue and the changes to EOP 1.3.
j c. Conclusions
! !
The inspectors had no concerns with the licensee's immediate corrective action, i
changes to EOP 1.3, or the 10 CFR 50.72 notification. The inspectors will !
followup on any additional long term corrective actions during the review of the LER l
for this issue. I
! !
!
,
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E8 Miscellaneous Engineering issues
E8.1 (Closed) Unterolved item (URI) 266/94011-03(DRP): Diesel Generator Cable Trays
Contrary to Fire Protectio.. Requirements
On June 6,1994, the licensee discovered that three cable trays containing cables
for the new diesel generator project were improperly routed. The new cable trays
introduced intervening combustibles between the safe shutdown service water
cable trays in the AFW pump room.
This conJition was outside the 10 CFR 50, Appendix R exemption granted for the
AFW pump room on July 3,1985. The licensee performed a fire protection
technical evaluation and an SE for this condition. Licensee interim ections taken
upon discovery included attaching a single layer of Kaowool or equivalent fire
barrier on the tops and cottoms of these open cable trays and conducting twice per
shift fire watches in the AFW pump room.
After reviewing the technical adequacy of the licensee's actions, the inspectors
considered this item closed based on the following
i
1) An exemption was granted by the NRC on July 18,1995, from the
requirements of Section Ill.G.2.b of Appendix R to allow the intervening
combustibles in the form of cable fillin three cable trays to remain installed
in the AFW pump fire area. The NRC concluded that the plant configuration,
administrative controls, and the fire protection provided for in the AFW l
pump fire area provided reasonable assurance that at least one train of
equipment and cabling required to achieve and maintain safe shutdown
would remain operable following a fire.
2) The licensee conducted fire protection training from August 1995 to May
1996 with their design engineers.
3) The licensee added references to their Design Control Checklists concerning
fire protection requirements and compliance with the Fire Protection
Evaluation Report, the licensee's documented fire protection progiam.
The three new cable trays which introduced intervening combustibles between the
service water cable trays in the AFW pump room were contrary to the requirements
of 10 CFR 50, Appendix R, Section Ill G.2.b prior to the July 18,1995, exemption.
However, this violation is considered non-cited because the criteria specified in
NUREG 1600, Criterion Vil, Paragraph B.1 were met (NCV 266/301-96019-
06(DRP)).
l
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i IV. Plant Suonort
R1 Radiological Protection and Chemistry (RP&C) Controls
1
l
R1.1 General Comments !
l
NRC Inspection Procedure 71750 was used in the performance of an inspection of
l the plant support area.
l From a radiological standpoint, the pnmary auxiliary building was in good condition,
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allowing access to most sections of the facility. Radiological housekeeping was
i generally good. During tours of the facility, the inspectors noted that barriers and
signs were in good condition.
- R4 Staff Knowledge and Performance in RP&C
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R4.1 Missed Unit 1 Steam Generator Blowdown Samole
a. Insoection Scope (71750)
- The inspectors investigated a missed Unit 1 steam generator blowdown filter outlet
j sample. The following documents were reviewed:
- T/S 15.7.6, " Radioactive Effluent Sampling and Analysis Requirements" )
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- LER 266/96-014, "SG Blowdown Sample Not Performed in Accordance With '
T/Ss"
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- CR 96-1882, " Missed S/G Blowdown Filter Outlet Sample" I
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b. Observation and Findinas ;
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f On December 29,1996, the licensee discovered that the sample was not obtained
l and analyzed for gamma scan and tritium as required by Table 15.7.6-1 in T/S
- 15.7.6. The T/S required that the blowdown be sampled and analyzed for gamma
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emitters twice weekly.
The licensee's immediate actions included obtaining and analyzing a blowdown
j sample, reviewing primary to secondary leakrate data, reviewing the blowdown
i monitor data, and reviewing the service water discharge monitor data. These
reviews showed that there was no increase in blowdown activity over this period. 1
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The inspectors discussed this issue with Chemistry personnel. The inspectors
leamed that chemistry sample frequencies and schedules were identified in
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Chemistry procedure, CAMP-101, Revision 47, " Daily Routine Sampling Schedule
for Operating, Refueling, or Shutdown Units." This procedure relied on the
knowledge and experience of personnel performing the chemistry samples to know
where all the sample requirements were located. The technician that missed the
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blowdown sample was required to analyze several other primary plant samples
during his shift. The blowdown sample was listed in a different part of the
procedure from the rest of the primary samples. The licensee made a temporary
change to CAMP-101 to relocate the blowdown sample into the section which j
contained the rest of the primary samples requirements. , j
Additionally, the inspectors leamed that there was no formal callup (routine activity
schedule) system to notify the technician of required T/S samples to ensure that the !
sample testing frequency was met. '
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c. Conclusions l
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The inspectors had no concerns with the licensee's immediate corrective actions; ;
however, the inspectors were concerned the lack of a formal callup system to j
notify the technician of required T/S samples to ensure that the sample testing . t
frequency was met. Similar concerns with the licensee's adequacy in ensuring that ;
.T/S required equipment was tested within its frequency was discussed in j
l. Section M4.1. t
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This condition was contrary to the requirements of T/S 15.7.6.A, which required ,
j steam generator blowdown to be sampled and analyzed for gamma emitters twice !
! weekly. However, this victation is considered non-cited because the criteria )
l specified in NUREG 1600, Criterion Vil, Paragraph B.1 were met !
S2 Status of Security Facilities and Equipment
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l- S 2.1 Security Revitalization of Unit 2 Containment (71750)
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On Janua' ry 23, security reestablished the Unit 2 containment as a vital area
l following steam generator replacement work. The inspectors walked down the
l outside of the Unit 2 facade and inside the fE. :ade, outside of containment. The
inspectors also reviewed Point Beach Security Guidelines (PBSG) 7.2, Revision 0,
" Vitalization of Unit 2," and discussed the revitalization with security personnel.
The vital access doors into the facade were reactivated and the outside of the
facade was enclosed prior to walkdown searches of the revitalized areas. The
inspectors had no concerns with the revitalization of the Unit 2 containment.
V. Manaoement Meetinas
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X1 Exit Meeting Summary
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l The inspectors presented the inspection results to licensee management at the conclusion
j of the inspection on January 29,1997. The licensee acknowledged the findings
j presented.
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- 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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X2 Unit 2 Restart Commitments Management Meeting ['
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On January 24,1997, Point Beach management met with NRC regional staff at the NRC I
Region til office. This meeting was held to discuss the status of Unit 2 startup !
commitments that the licensee made in a letter dated December 12,1996 and the NRC
confirmed in a CAL dated January 3,1997. .
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
Wisconsin Electric Power Comoany (WEPCol
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i A. J. Cayia, Plant Manager '
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l T. G. Staskal, Acting Operations Manager
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G. R. Sherwood, Maintenance Field Services Manager Maintenance ;
l J. G. Schweitzer, Manager Site Engineering !
- P. B. Tindall, Health Physics and Chernistry Manager !
, D. F. Johnson, Manager-Regulatory Services and Licensing
l T. C. Guay, Regulatory Services Manager
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INSPECTION PROCEDURES USED
l IP 37551: Onsite Engineering
IP 40L00: Effectiveness of Licensee Controls in identifying, Resolving, and Preventing
Problems
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IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
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IP 71750: Plant Support Activities
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-301/96019-01 A VIO Criterion V violation for not following RHR valve lineup, .
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list
50-266(301)/96019-01 B VIO Criterion V violation for failure to initiate CRs (2 1
examples)
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50-301/96019-01C VIO Criterion V violation for failure to provided instructions
on properly repairing a bolt hole on the 2A Si pump
50-266(301)/96019-02 IFI Review commitment for formal control room self
assessments
50-266/96019-03 ViO Missed T/S surveillance test for Unit 1 RHR/ low head
core deluge valve
50-266/96019-04 IFl Unit 1 containment inner personnel hatch test failures
50-266(301)96019-05 VIO Criterion XVI violation for inadequate corrective actions
for MSSV setpoint drift
50-266/96019-06 NCV Diesel generator cable trays contrary to fire protection
requirements
50-266/96019-07 NCV S/G blowdown sample not performed in accordance
with T/Ss
Closed
50-301/94013-05 IFl RCS leakage increase and piping pressure wave
l Rlli-96-012 CAL Control room activities
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50-266/94011-03 URI Diesel generator cable trays contrary to fire protection
requirements
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LIST OF ACRONYMS USED
AO Auxiliary Operator
AOV Air-Operated Valve
ASME American Society of Mechanical Engineers
B&PV Boiler and Pressure Vessel
CAL Confirmatory Action Letter
. CAMP Chemistry Procedure .
CFR Code of Federal Regulations
CLRT Containment Leakage Rate Testing
CO Control Operator
CR Condition Report
- F Degrees F6hrenheit
DRP Division of Reactor Projects
DSS Duty Shift Superintendent
ECCS Emergency Core Coo!ing System
EDG Emergency Diesel Generator
EOP Emergency Operating Procedure
ESF Engineered Safety Feature
FSAR Final Safety Analysis Report
GL Generic Letter
gpm Gallons per Minute
IFl inspection Followup Item
llT Incident Investigation Team
IN information Notice
IP inspection Procedure
ISI Inservice inspection
IST inservice Testing
IT Inservice Test
IWP Installation Work Plan
kW Kilowatt
LCO Limiting Condition for Operation
LER Licensee Event Report
LBLOCA Large Break Loss of Coolant Accident
LOCA Loss of Coolant Accident
MSSM Manager's Supervisory Staff Meeting
NCV Non-Cited Violation
l NDE Non-Destructive Examination
l NP Nuclear Power Department Procedures
i NRC Nuclear Regulatory Commission
!_ _01 Operating Instruction
- OP Operations Procedure
OOS Out-of-Service
PBM Point Beach Mernorandum
PBTP Point Beach Test Plan
PMT Post-Maintenance Testing
PRT Pressurizer Relief Tank
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' psig pounds per square inch - gauge !
QA Quality Assurance '
RCP Reactor Coolant Pump !
RMP - Routine Maintenance Procedure !
RP&C Radiological Protection and Chemistry Protection !
-SE Safety Evaluation
SFP Spent Fuel Pool
S/G Steam Generator {
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SI Safety injection ,
T/S Technical Specification :
URI Unresolved item i
V!O Violation i
WEPCo Wisconsin Electric Power Company I
WO Work Order - )
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