ML20202E981
| ML20202E981 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 02/10/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20202E939 | List: |
| References | |
| 50-266-97-26, 50-301-97-26, NUDOCS 9802190098 | |
| Download: ML20202E981 (23) | |
See also: IR 05000266/1997026
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U.S. NUCLEAR REGULATORY COMMISSION
REGIONlli
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Docket Nos: 50 266; $0-301
Report No: 50 266/97026(DRP); 50-301/97026(DRP) j
. Licensee: Wisconsin Electric Power Company, WEPCO
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Facility: Point Beach Nuclear Plant, Units 19nd 2
Location: 6612 Nuclear Road
Two Rivers, WI 542419516 ,
Dates: December 1,1997, through January 20,1998
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Inspectors: F. Brown, Senior Resident inspector .
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P. Louden, Resident inspector
L. Collins, Resident inspector, Quad Cities Station -
M. Kunowski, Project Engineer
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Approved by: J. . McCormick Barger, Chief
Reactor Projects, Branch 7
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9902190098 980210
PDR ADOCK 05000266
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EXECUTIVE HUM 1ARY
Point Beach Nuclear <lant, Units 1 and 2
NRC Inspection Repori No. 50-266/97026(DRP); 50 301/97026(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant
support, in addition to routine inspection procedure aspects, this inspection period included a
review of selected NRC and licensee identified problems and the corrective actions taken. The
report covers a seven week inspe: tion period by the resident inspectors.
9991RLLO.111
+ The Unit i high voltage station auxiliary transformer failed on January 8,1990. The
operators responded well, and safety-related equipment worked as expected. The failure
was caused by insulation degradetion which was attributable to inoperable bus duct strip
heaters. An automatic fast bus transfer did not occur as designed due to a design error.
The licensee performed a thorough and insightful review of this event and identified a
fundamental weakness in the use of some aspects of Technical Specifications (TSs) by
licensed operators. The NRC review identified inappropriate procedural adherence
standards regarding the use of emergency and abnormal operating procedures. Two
violations were identified. (Section 01.2)
. The licensee's use of the temporary information tag program was generally acceptable.
However, the inspectors identified severalinstances where tags were left hanging on
equipment longer than intended, and examples of the use of temporary information tags
on abandoned in place radioactive waste equipment instead of danger tags, which would
have been more appropriate. (Section O2.2)
. Corrective actions for problems with several procedures and for the premature securing
of cooling water to e reactor coolant pump were reviewed and found to be complete and
thorough. (Section 03)
Maintenance
. Two completed corrective actions were reviewed in the maintenance area. One, for a
foreign material exclusion issue, was determined to be narrowly focused, and the other
was appropriate, but the corrective action was not accurately documented in the
licensee's !ssue tracking database (NUTRK). The licensee indicated that a broad
evaluation was being performed in the area of foreign material exclusion under a
separate action from that reviewed by the inspectors. (Sections M4 and M8)
Enaineerina
. The inspectors concluded that the licensee had misapplied the TS requirements relating
to the performance of American Society of Mechanical Engineers (ASME)Section XI
inservice testing associated with pressure tests for Class 2 and 3 systems. However, the
licensee effectively identified and cor.ected the problem. (Section E1.1)
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The e^ gin 6ering department conducted a thorough root cause evaluation of problems
associated with the installation of the wrong tubing in a reactor vessellevel indication ,
system modification. (Section E2.1)
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Test control deficiencies associated with the containment accident fan coolers had been
identified in 1995, and new tests were to have been performed shortly after the
August 1997 restert of Unit 2. However, the new tests had not been performed as of the
end of November 1997. One violation was identified. (Section E8.1)
Plant Sucopa
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. The inspectors determined that the health physics department was effective in
addressing an adverse trend regarding workers failure to wear proper
dosimeters. (Section R4.1)
. Based on the results of a close-out inspection of the Unit 2 containment, the licensee
identified the need to perform additional cleaning and improve future close-out
cleanliness standards. (Section R4.2)
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Report Details
Summary of Plant Status
Unit 1 was placed on-line at the beginning of this inspection period, and remained at 98 percent
rated power until an end-of life power coastdown was started on January 17,1998. Power was
limited to 98 percent because of instability in the electro-hydraulic turbine controller at the higher
electrical output resulting from the newly installed low pressure turbines. A partialloss of offsite
power event occurred on January 8,1998. This event is discussed in Section 01.2.
Unit 2 remained in a mid-cycle outage throughout this period while modifications were made to
the auxiliary feedwater system. Dual unit operation was precluded pending completion of these
modifications.
I. Operations
01 Conduct of Operations
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01.1 General Comments (IP 71707)
The inspectors conducted frequent reviews of ongoing plant operations. The inspectors
observed Unit 1 and Unit 2 control room shift tumovers and observed cetrol room
] opemtions on a daily basis. Operator attentiveness to coraol boards and response to
alarms were good. The conduct of shift briefings, which was inconsistent between crews
in the past, improved.
01.2 Failure of Hiah Voltaae Station Auxiliary Transformer (HVSAT)
a. Inspection Scope (IP 75 07)
The inspectors reviewed the licensee's response to a loss of the Unit 1 HVSAT "1X03."
b. Observations and Findinas
Description of the Event
The Unit i HVSAT,"1XO3," isolated at 7:05 p.m. on January 8,1998, when protective
circuitry sensed a fault. At the time, Unit 1 was operating a; 98 percent power and Unit 2
was in cold shutdown. A severe winter storm (freezing temperatures,10 inches of snow,
and 42-mile-per-hour wind) was in progress. This isolation removed the normal source of
power from the H02 (Unit 1) and H01 (the Unit 1 and Unit 2 cross-tie and gas turbine
output) 13.8-kilovolt (kV) buses. Automatic relaying should have closed the H03 (Unit 2)
to H01 cross-connect breaker, "H52 31," which would have resulted in off-site power
being supplied in all three sections of the 13.8-kV bus through the Unit 2 HVSAT, "2X03."
This automatic function failed to operate, resulting in a loss of power to H01 and H02.
Dus H02 provides normal power to the Unit 1 Iow voltage station auxiliary transformer,
"1X04," which supplies power to the non-safety-related 4.16-kV switching buses "1 A03"
and "1 A04." The Unit 1 safety-related 4.16-kV buses, "1 A05" and "1 A06," are normally
fed from 1 A03 and 1 A04, respectively. The three operable emergency diesel generators
(EDGs) started on loss of voltage signals for 1 A05 and 1 A06, and the Unit 1 EDGs
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loaded to the assigned buses. The normal feed breakers between 1 A03 and 1 A05, and
between 1 A04 and 1 A06, opened to separate non safety-related buses from the EDGs.
The safety related 4.16-kV and 480-volt systems were de-energized only for the penod of *
time required for the EDGs to start, come up to speed, and load onto the 4.16 kV buses.
Station auxiliary loads, including feedwater, reactor coolant, and circulating water pumps,
were not affected by the loss of the HVSAT because they were being fed from the unit
generator supplied auxiliary transformer,"1X02." Output from the unit generator was not
affected because it connects to the switchyard distribution bus via the main transformer,
- 1X01." Charging and letdown iselated when 1 A05 and 1 A06 were de-energized.
Charging pumps were manually restarted after the EDGs re energized time two safety-
related buses. Two of the four station battery chargers were being fed through 1 A05 and
1 A06 when these buses lost power. Tha safety related batteries carried the loads on the
two affected direct current (DC) buses when the battery chargers lost power. The primary
and secondary portions of ; % plant remained stable throughout this event and the event
recovery. The isolation cruers for one of the four off site 345-kV feed liries opened
when 1X03 isolated. The other three off-site 345 kV lines were not affected.
Initial operator response focused on restoring power to the affected 13.8-kV and
4160-volt buses. The response was complicated by the absence of procedures for
recovering the 13.8-kV bus, Opraturs exercised proper restraint in waiting ur,til
procedural guidance was developed before taking action. The station gas turbine
generator,"GOS," w a started at 9:21 p.m.,2% hours after 1X03 was lost. This re-
energized buses HC' H02,1 A03, and 1 A04. Breaker H52 31 was closed manually at
10:50 p.m., paralleling G05 with off st i power from transformer 2X03. These actions
were delayed while plant staff reviewe the condition of buses H01 and H02, and
breaker H52-31 to ensure that re-ene.gzatior. would not result in initiation of. additional
faults or unintended isolations. Safety-reb > r us 1 A06 was reconnected to its normal
power source,1 A04, at 12:44 a.m. on Jant.n , 9,1998,5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 40 minutes after it
lost this source. Safety-related bus 1 A05 was reconnected to its normal power source,
bus 1 A03, at 4:18 a.m. on January 9,1998. The associated EDGs were secured after
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off-site power was supplied to each bus.
Initiatino Eauipment Failure and Eauipment Response
The licensee's event investigation team determined that this event was initiated when a
phase-to-phase short circuit occurred in the bus ductwork between transformer 1X03 low
voltage output connections and the low voltage isolation breaker, "H52-05," on bus H02.
This short developed due to water saturated and moisture damaged insulation. The root
cause ofit'is condition was determined to be the failure of strip heaters installed in the
bus ductwork and the H52 05 breaker cubicle. The function of these heaters was to
4 prevent condensation of moisture inside the ductwork and breaker cubical. The heaters
were found to be inoperable because of a failed ground fault indicating,20-ampere circuit
breaker. The breaker was located in a lighting panel and was coded as 120-volt
attemating current (AC) lighting. A corrective maintenance work order had been initiated
in August 1996 to repair the breaker. The work order was classified as " minor
maintenance," a classification which excluded it from system reviews performed during
1997. The work order was stillin the minor maintenance backlog on January 8,1998.
The inspectors and licensee subsequently reviewed the minor maintenance backlog
records No additional examples of inappropriately designated minor maintenance items
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were identified. The :icensee also performed thermography of the other bus ductwork
exposed to outdoor weather and determined that all strip heaters were functioning
propeny. A periodic review of all strip heater breakers was also implemented as an
immediate corrective action.
The non safety-releted bu cross-connect function of brWer H52 31 failed to work as
expected. The licensee's incident investigation team determined that this failure was
caused by a design error in the non safety related portion of modification package
MR9116*B, which had installed new control switches for the breakers. The new switches
were a different part number and had different contact logic than the original switches.
The engineers who performed and reviewed the modification work did not identify that the
contact logic of the new switches defeated the fast bus tra sfer function when the
breaker control switch was in its normal position (auto). The engineers also failed to
specify post modification testing for the fast bus transfer function. The lack of a periodic
test of the 13.8 kV fast bus transfer had been identified by the resident inspectors and
discussed in Inspection Report (IR) 50-266/96003(DRP); 50-301/96003(DRP), but the
licensee had not taken any action to verify the operability of the non-safety-related
function.
The inspectors reviewed the available plant parameter computer system alarm records,
the station and unit logs, the applicable sections of the Final Safety Analysis Report
(FSAR), the emergency operating procedures (EOPs) and abnormal operating
procedures (AOPs), and the desigr' basis documentation for the electrica,I distribution
systems and determined that all other plant equipment operated as expected, with the
minor exception of a failed synchronous check relay on one instrument bus. Power to the
instrument bus was not interrupted.
Operator Response
Following the loss of 1XO3, the operators entered AOP 18A Unit 1, " Train 'A' Equipment
Operation," Revision 4, and AOP 188 Unit 1, " Train 'B' Equipment Operation," Revision 2.
The inspectors compared the unit " Narrative Log" entries to the sequence of steps in
AOPs 18A and 188 and found that the logs did not indicate that equipment was retumed
to service in the procedurally specified sequence. The inspectors discussed this finding
with the incident investigation team. The licensee reviewed the use of AOPs 18A and
188, and concluded that the operators had performed as trained, in that procedure steps
were followed in the order specified. The licensee also informed the inspectors that
Procedere OM [ Operations Manual) 3.7, " Emergency Operating Procedure Use and
Adherence," Revision 4, authorized the performance of EOP and AOP steps
out-of-sequence and the addition of non-specified steps, as long as the procedure intent
was not changed. Procedure 'M 3.7 specified that these actions were not considered
procedure deviations. The inspectors reviewed the information provided by the licensee
and concluded that the operators had performed AOPs 18A and 18B in accordance with
their procedures and training. The insmtors noted that the blanket authorization to
perform steps out-cf-sequence and i r Mm non-specified steps was inconsistent with
, the upper tier licensee Procedure NP [Nuuear Business Unit Procedure) 1.1.4,
" Procedure Use and Adherence," Revision 1 and wnh TS 15.6.8.3 which required
approval by the cognizant group head (duty shift superintendent in operations) and one of
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the duty and call superintendents for changes to procedures. This blanket authorization
was, therefore, inappropriate to the circumstances, and a violation
(VIO 50-266/97026-01(DRP); 50 301/97026-01(DRP)) of 10 CFR Part Sr, m,.. andix B,
Criterion V.
Use of TSs
On January 9,1998, the inspectors requested that the licensee clarify an apparent
inconsistency in the application of TS 15.3.7.A.1 and TS 15.3.0. Specifically, the licensee
had entered TS 15.3.0 (initiation of sctions to shut down a reactor when conditions not
allowed by TS existed) on January 9,1998, when GOS was shutdown for a short period to
remove ice from the compressor intake and 1XO3 was still out of-service. Logged entry
into TS 15.3.0 had been made for the loss of power to the two affected battery chargers
on Janue.ry 8,1998, but TS 15.3.0 had been exited when the battery chargers were re-
energized at 7:15 p.m., which was prior to G05 being placed in-service at 9:21 p.m. The
licensee informed the inspectors that the on-shift crew had erred in not remaining in
TS 15.3.0 until GOS was placed in-service, and that the licensee's incident investigation
team, which had been formed to review the loss of off site power event, would perform a
complete review of TS use during the event.
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On January 13,1998, the licensee amended the 10 CFR 50.72 notification A r this event
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to include information on the failure to enter TS 15.3.0 for three conditions: loss of 1XO4
(required for electrical distribution operability by TS 15.3.7.A.1.c), loss of 1Xh .vithout
- G05 being in-service (required for electrical distnbution operability by TS it !.A.1.b),
and loss of normal power supply to 1 A05 and 1 A06 concurrently (required for electrical
distribution operability by TS 15.3.7.A.1.i). Technical Specification 15.3.0.8 requires that
action be initiated within one hour to place the affected unit in hot shutdown within seven
hours of entering this specification. Fortuitously, all conditions requiring entry into
TS 15.3.0.B were corrected prior to the expiration of the seven hours, but the failure to
recognize the applicability of TS 15.3.0.B and initiate action to shut down within one hour
was a violation (VIO 50-266/9702602(DRP); 50-301/97026-02(DRP)) of TS 15.3.0.
The incident investigation team interviewed many licensed senior reactor operators
(SROs) who did not understand the requirement to enter TS 15.3.0 in cases where the
TS contained ambiguous wording for establishing LCO operability requirements and
specific permissible conditions dd not apply. In the case of electrical distribution,
TS 15.3.7.A.1 specified conditions required prior to taking a unit critical. Technical
Specification 15.3.7.B.1 provided permissible conditions which modified the requirements
of TS 15.3.7.A.1 when a unit was at power. Many SROs did not recognize that
TS 15.3.7.A.1 established basic LCO operability requirements for a unit anytime it was
critical, and that if TS 15.3.7.A.1 was not satisfied, and no permissible condition in
TS 15.3.7.B.1 applied, then entry into TS 15.3.0 was required. The licensee initiated
immediate action, including briefing each operating crew and placing a required-reading"
entry in the control room Operations Notebook to address tisis fundamental shortcoming
in use of the TSs. Long term corrective actions, including changes to the initial and
requalification programs, were beHg considered at the end of the inspection period.
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c. Conclusions
The Unit 1 HVSAT failed on January 8,1998. The operators responded well, and safety-
related equipment worked as expected. The failure was caused by insulation degradation
which was attributable to inoperable bus duct strip heaters. An automatic fast bus
transfer did not occur as designed due to a design error. The licensee performed a
thorough and insightful review of this event and identified a fundamental weakness in the
use of some aspects of TSs by licensed operators. The NRC review identified
inappropriate procedural adherence standards regarding the use of EOPs and AOPs.
Two violations of NRC requirements were identified.
O2 Operational Status of Facilities and Equipment
02.1 ygrification of Safety System Vpive Positions flP 71707)
The inspectors independently verified valve positions for the U.tt i safety injection and
containment spray systems. The inspectors noted that all valwis v'ere positioned
according to controlled drawings and were in the proper position tu perform the intended
engineered safety fettures function. The inspectors noted that significant amounts of
t'oric acid had crystallized around the inner bearing seal area of the safety injection
pumps. The inspectors called this to the attention of an SRO who had the seal area
rinsed with deionized water. The SRO further stated that a review of the expectations for
auxiliary operators to clean seal leaks would be performed.
02.2 Control of Posted Plant information
a. Inspection Scope flP 71707)
The inspectors reviewed the licensee's program for identifying, posting information
pertaining to, and repairing equipment deficiencies. The specific proceduralized program
reviewed included the use of temporary information tags and pasted plant drawings as
described in OM 5.4.4 " Control of Posted Plant Information," Revision 2.
b. Observations and Findinas
Procedure OM 5.4.4 described the method which ensured that the dissemination of plant
information was appropriately authorized, documented, and reviewed. The use of
temporary information tags was discussed in Section 7 of OM 5.4.4. The temporary
information tag program was required to be reviewed quarterly by operations department
staff for applicability and accuracy.
The inspectors independently walked down the temporary information tag locations in the
plant and reviewed the two most recently completed audits of the tag logs. The
inspectors had three observations regarding ths temporary information tag program:
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The current ter 'oorary information log contained 11 items which were greater than
2 years old. Thu inspectors asked licensee management whether 2-year-old
items met the conditions to be part of the amporary information program. Station
management stated that the intent of the temporary information program was to
identify circumstances which would last for only a short duration and that it was
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not appropriate to include 2-year old items in the program. Licensee management
stated that the uso of the temporary information tag program would be reviewed.
During a temporary tag walkdown, the inspectors noted that a tag dated
March 1995 had been placed on the Unit 1 flux mapping control panel. Directly
below the tag was a permanent label on the panel which contained the same
wording as the temporary information tag. Further review revealed that the
permanent label had been installed in July 1997, and that the temporary
information tag should have been removed. Notewc< thy was that during the last
two quarterly reviews (both dated after the permanent label was installed), the
temporary tag was documented as still applicable and verified to be in-place. The
inspectors determined that the operators' attention-to-detail during the
performance of the quartsrly reviews was lacking.
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The third inspector observation involved temporary information tags which were
placed on the waste evaporator system. The wording on the tags informed the
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reader that the equipment was abandoned in-place and that the valves were
serving as isolation boundaries. The inspectors questioned licensee management
, regarding the appropriateness of using the temporaiy information program for this
application. This particular case would have been more appropriately handled
through the danger tag program.
c. Conclusio_n_3
The inspectors concluded that generally the temporary information tag program was
implemented effectively. However, the inspectors identified uses of temporary tags which
were not within the intended scope of the program.
O3 Operations Procedures and Documentation
As part of the inspection into the licenseo's corrective action program, the inspectors
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reviewed the responses to three self-identified problems documented through the
problem identification process. The inspectors' focus was on the adequacy of the root
cause evaluations and the effectiveness of corrective actions.
O3.1 Corrective Actions to Address Discrecancy Between Procedures (IP 71707)
The licensee identified a diccrepancy between Operations Procedure (OP) 3C, " Hot
Shutdown to Cold Shutdown," Revision 66, and OP 7A " Placing Residual Heat Removal
System in Operation," Revision 33, and dor"Jmented the problem in Condition Report
(CR) 97-0852. Procedure OP 3C, Step 4.12.2, required the operators to align the
residual heat removal (RHR) system for operation, wsh the reactor coolant temperature
between 370 degrees Fahre lheit (*F) and 380 *F. The initial condition requirements for
OP 7A, however, stated that the reactor coolant temperature was to be less than 350 F.
A control operator noted this problem and the OP 3C Procedure was revised. The Final
Safety Analysis Report (FSAR) further stated that the RHR system is aligned for decay
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heat removal after the reactor coolant temperature had been reduced below 350 F.
3 The inspectors reviewed the revised OP 3C and noted that steps in the procedure were
changed to ensure that the reactor coolant temperature was below 350 "F prior to
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removing the RHR system from its low head safety injection alignment. The inspectors
determined that the actions taken addressed the problem and that a good questioning
attitude was displayed by the operator who originated the concern.
03.2 Root Cause Evaluation Addressino Premature Securina of Component Coolina Water tg
Unit 2 "B" Reactor Coolant Pump
a. Inspection Scope (IP 71/0,i
The inspectors reviewed the root cause evaluation and correctisa actions implemented to
address problems identified with the premature securing of the component cooling water
(CCW) supply to the Unit 2 "B" reactor coolant pump (RCP).
b. Observations and Findinas
Operations personnel initiated a condition report (CR) on July 24,1997, after the CCW
supply to the Unit 2 RCP was secured and danger tagged while the RCS temperature
was above 370 *F. This was done in preparation to secure the "B" RCP for pump scal
work; however, securing cooling water with the RCS above 370 "F was undesirable in
that pump seal damage would be accelerated had seal water cupply been lost. The duty
shift supervisor erroneously made the decision to secure the CCW supply, even though
the Unit 2 control operator questioned the decision given current plant conditions.
Based on the results of the event investigation, the licensee determined that the root
cause was non conservative decision making on the part of the duty shift supervisor.
Contributing factors included programmatic concems regarding the lack of an oversight
issue manager, inadequacies with the use of notes and precautions in the danger tag
procedure, and a failure to develop an overall work plan with scheduled event sequences.
To address these concerns, the operations manager conducted a training session to
review this event and emphasize conservative decision making, conflict resolution,
modifications to the work control process, and a complete revision of the danger tagging
, procedure (NP 1.9.15).
The licensee also initiated a restructuring of the entire work control process which was
ongoing at the conclusion of the inspection. The licensee stated that one of the work
control process changes will be to establish work-week managers who will be responsible
,. for maintaining oversight of ongoing work activities,
c. Conclusiens
The inspectors determined that the root cause evaluation performed to address the
concerns described above was thorough and identified the appropriate root causes and
contributing factors. The corrective actions taken by the operations department were also
deemed to be effective.
O3.3 Evaluation of the Adeauacy of Reactor Coolant Pumo Breaker Rackina Reauirements
The inspectors reviewed the licensee's evaluation of a level"D" (lowest priority) CR which
descrii>ed concerns regarding the accuracy of breaker positioning instructions for RCP
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breakers; Specifically, the concems involved operations procedures which were overly
restrictive for maintaining breaker positions within the seismic qualifications.
Operations department staff determined that r:o problems existed with the procedure and
that the documented concern would be placed in the procedure " tickler" file for
consideration during the next procedure revision. The inspectors considered these
actions acceptable, but noted that the use of the station's more formal, procedure
feedback program process might have provided greater assurance that the issue would
be resolved in a timely manner.
05 Operator Training and Qualifications
05.1 License.1 Operator Examination Security -
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a. Inspection Scoce UP 71707)
, The inspectors reviewed the circumstances surrounding a licensee-identified concem
regarding licensed operator examination security during 1997 requalification testing.
D. Observations and Findinas
Operations depadment training staff discovered five remedial requalification study guides
on a former employee's personal local area network (LAN) directory on December 19,
1997c The existence, of the study guides on an unsecured computer created the concem
that the annual requalification examination had been compromised. The issue was
documented in OR 97-4125 and a root cause investigation was initiated by the licensee.
The 1997 requalification examination was administered on March 3 to March 21 and
August 4 to September 26l1997. The former employee worked for the operations -
training department and was part of the 1997 licensed operator requalification
examination team. One of his assigned duties was to develop the remedial study guides.
Members of the licensee's root cause team, which reviewed the matter, provided the
inspectors with the following information: '
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. The examination question bank was a closed databasef The questions contained -
within the database were not accessible for self study use by operators.
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The LAN directory, which contained the remediation study material, could only be
accessed by three individuals at the site (LAN managers and computer staff.)
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The material contained in the study guides was not of sufficient detail to allow an
individual to directly ascedain the content of a specific question.
. ' Test scores did not improve following the time frame that the remediation material
was placed on the unsecured computer.
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Employees involved with the requalification examination were briefed and bound
by a security agreement for the duration of the testing.
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The former employee, whose directory contained the remediation guides, was
interviewed by the beense. The individualindicated that he tightly controlled the
study guides and he did not leave his computer unattended while the information
was in the directory.
Based on the above hformation, the licensee concluded that an examination compromise
had not occurred and that the potential for a compromise was not very probable. The
inspectors a0 reed with this conclusion.
c. Conclusions
The inspectors determined that e compromise of the 1997 annuallicense requalification
examination had not occurred.
08 Miscellaneous Operations issues n
08.1 (Closed) Licensee Event Report (LER) 50-266/96011: 50-301/96011: " Delta T* Trip
Setpoints Not Reduced in Accordance With TS. On November 21,1996, the licensee
discovered that " delta T" trip setpoints were not reduced in accordance with TSs during
the Unit 1, cycle 24 startup. Technical Specification 15.3.10.B.1.c required that the
overpower and overtemperature " delta T" setpoints be reduced if a measured hot channel
factor exceeded the full power limit and it could not be subsequently demonstrated within
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that the limits were met. This LER addressed deficiencies in the clarity of the
TS in effect in November 1996. The licensee submitted a TS amendment request which
the NRC Office of Nuclear Reactor Regulation approved on January 16,1997. The failure
to perform the " delta T" trip setpoint adjustments when it was datermined that full powcr
hot channel facters would have been exceeded based on the measured values at
28 percent power was considered a violation of TS 15.3.10.B.1.c. However, this non-
repetitive, licensee identified and corrected violation was considered a non-cited violation
(NCV 50-266/97026-03(DRP); 50-301/97026-03(DRP)) consistent with Section Vll.B.1 of
08.2 (Closed) LER 50-266/96006: 50-301/96006: Emergency Power Out of Service Coincident
With Opposite Train Service Water Pump Out of Service. This LER involved cross train
removal of a service water pump coincident with the out-of-service of the opposite
standby emergency power train. Specifically, while one of the Train B EDGs was
undergoing a monthly surveillance test, a Train A service water pump (P-328) start switch
was placed in the pull-to-lock position. This condition, which was not allowed by TSs,
lasted for approximately 30 seconds. The control operator realized that an operability
question existed with the Train B EDG being tested. The operator then retumed the
service water pump switch to the AUTO position.
The licensee's investigation identified deficiencies in the procedure for voluntary entry into
limiting conditions for operations (Nuclear Procedure 10.1) and the duty and call
superintendent guidance (DCS 3.1.7) regarding interpretation of the TS. Both procedures
were enhanced to call attention to the service water pump cross-train issue.
The inspectors reviewed the licensee's actions including an evaluation of the adequacy of
the current voluntary entry into limiting conditions for operations procedure (Nuclear
Procedure 10.1.1, Revision 7) and the DCS 3.1.7 guidance. The inspectors noted that
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clear guidance was contained within each of these documents which should preclude
recurrence of this type of event. This item is closed.
08.3 (Closed) LER 50-266/96003: 50-301/96003: Plant Operation outside of Design Basis of
the Low Temperature Overpressure Protection System (LTOP). On June 21,1996, the
licensee identified that a procedure allowed operation with two high pressure safety
injection (SI) pumps available while the reactor coolant system (RCS) was in the water-
solid condition and RCS temperature was below the LTOP enable temperature of 360 'F.
This was in conflict with the design basis for LTOP which assumed a worst caso mass
input transient of one St pump discharging to the RCS while N system was solid and
'ressure relief provided by one power-operated relief valve. The licensee stated that
there were no instances where both Si pumps discharged to the RCS svith LTOP
enabe The licensee subsequently revised the procedure to reflect the design basis
and requested a license amendment to also align TS 15.3.15, on LTOP, with the design
basis, in addition, based on a reevaluation, the licensee requested that the LTOP-enable
temperature be lowered to 355 'F. The license amendment with the revised temperature
limit was subsequently issued February 20,1997.
II. Maintenance
M4 Maintenance Staff Knowledge and Performance
M4.1 Forelan Material Exclusion Contro! Carino Polar Crane Wirino Chanceout
e, inspection Scope flP 62707)
The inspectors reviewed the effectiveness of licensee corrective actions taken to address
an incident involving failure to adequately implement foreige. .aaterial exclusion (FME)
techniques,
b. Observations and Findinos
Licensee root cause report number 97-028 addressed an occdrrence documented in
CR 971768 which involved the loss of FME controls on June 2,1997. A team of
maintenance workers were replacing lights on the Unit 2 polar c*ane. During the work, a
metal ferrule nut from a wire for one of the lights fell from the crane intr' the lower transfer
canal.
Based on the results of the event investigation, the licensee determined that the root
cause was poor worker practices and ineffective self checking. The workers erected
FME barriers; however, the barriers did not provide sufficient controls for an item as small
as a wire ferrule.
The inspectors determined that better self-checking could have possibly prevented the
t. vent from occurring. In addition, the adequacy of the FME barriers erected and the
quality of the FME governing procedure were considered contributing factors. These
latter fac+ ors were not included in the licensee's investigation. The licensee informed the
inspectors that a separate root cause evaluation was being performed for programmatic
aspects of FME control.
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c. Conclusions
The licensee's corrective actions for the loss of FME control event were narrowly focused
on human performance deficiencies and did not address any associated programmatic
problems.
M8 Miscellaneous Maintenance issues
M8.1 (Closed) LER 50-266/96001: Inadvertent Engineered Safety Feature (ESF) Actuation in
Train B Due To DC System Ground. On April 5,1996, maintenance activities were
underway to locate a ground associated with the Train 9 JC electrical system. A test rig
used to locate the ground inadvertently actuated the Train B ESF circuitry resulting in the
starting of all Train B safety injection equipment. The cause of the actuatio i was an
inadequate ground detection technique. The use of a light bulb t.e rig abng with the
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ground in the system completed a circuit which provided enough current to actuate the SI
circuitry.
The licensee stated in the LER that an evaluation would be performed to identify better
industry ground detection techniques. This e' fort was completed in 1996 and the review
team recommended that a test configuration used at one of the baseline plants be
implemented. The licensee's issue tracking database (NUTRK) described the
recommendation and indicated that the issue would be closed following the acceptance
of the proposed new ground detection technique.
The inspectors discussed the corrective actions with the cognizant maintenance
department supervisor. The inspectors were told that the corrective actions described in
the tracking database were not the actual actions taken. Electrical maintenance had
purchased a state-of-the art ground testing meter different than what was described in
the NUTRK database. The inspectors had no technical concems regarding the use of the
purchased ground detection equioment. However, the information contained within the
NUTRK database system for documented closure of the item was inaccurate. This item is
closed.
111. Enaineerina
E1 Conduct of Engineering
E1.1 Failure to Conduct American Society of Mechanical Enaineers (ASME)Section XI
Pressure Tests
a. Inspection Scope (IP 37551)
The inspectors reviewed the circumstances surrounding the licensee identified problem
involving the failure to perform ASME Section XI 40-month pressure tests on Class 2 and
Class 3 systems.
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b. Observations and Findinal
During a review of the pressure test program, engineenng personnelidentified that the
requAt 40-month inservice inspection pressure test for the following systems had not
been accomplished: the Unit i boric acid storage tanks and associateri piping, the air
start system for the G01 and G02 EDGs, waste gas system tanks and piping, and the
( Unit 2 refueling water storage tank.
The deficiency in the pressure test program was first identified in September 1996 and
documented in CR 96-840. Engineering management decided that the test could be
delayed until an ongoing pressure test program upgrade was completed. On
November 4,1997, the pressure test issue was re visited. The pressure test engineer
determined that CR 96-840 did not address operability of the affected systems. This
deficiency was documented in CR 97-3730 and an operability determinaticn was
performed. The systems were determined to be operable, and the licenses de;ided that
for those systems that were currently out of service, tests would be completed prior to
returning them to service.
C. lanuary 2,1998, the licensee determined that TS 15.4.2.B.1 had historically been
misinterpreted. Technical Specification 15.4.2.B.1 t,tates, in part, that inservice
inspection of ASME Code Class 1, Class 2, and Class 3 components shall be performed
in accordance with Section XI of the ASME Boiler and Pressure Vess91 Code and
applicable Addendc. Historically, the failure to meet the Section XI required tests was
viewed as a nonconformance and was not regarded as a missed TS surveillance test.
The licensee concluded that failure to meet the Section XI Code requirements should
have been treated as a missed TS surveillance test.
The licensee identified the deficient pressure tests based on a review of potentially
affected systems. The systems were declared inoperable and TS 15.4.3 was entered for
a missed surveillance test. All tests (except for G02 related systems) were subsequently
conducted within the 24-hour allowance provided in TS. The licensee planned to perform
the G02 air start system test as part of the retum-to-service for the EDG which was
out of service for an upgrade mod:fication.
The failure to perform the inservice tests required by ASME Section XI is considered a
violation of TS 15.4.2.B.1. However, this non-repetitive, licensee-identified and corrected
violation was considered a non-cited violation (NCV 50-266/97026-04(DRP);
50-301/97026-04(DRP)) consistcnt with Section Vll.B.1 of the NRC Enforcement Policy,
c. Conclusions
The inspectors concluded that the licensee had misapplied the requirements of the TS
relating to the performance of ASME Section XIinservice testing. However, the licensee
effectively identified and corrected the problem. One non-cited violation was identified.
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E2 Engineering Support of Facilities and Equipment
E2.1 Review of Corrective Actions For a Chance to a Reactor Vessel Level Indication System
(RVLIS) Modification Made Without Usino the Chance Reauest Process
a. Inspection Scope (IP 37551)
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Tha inspectors reviewed the licensee's corrective actions taken to address problems
associated with changes made to the RVLIS modification without rising the modificatio.,
change request process,
o. Observations andJndinos
The subject event involved the improper authorization for construction personnel to install
different size tubitig than specified in the modification design package. Construction
personnel requested to install %-inch tubing rather than the design drawing specified
Winch tubing. A construction supervisor authorized the use of the smaller tubing, but did
not recognize the seismic requirements inherent in the Winch design specification. The
responsible design engineer noted the discrepancy during a post-installation walkdown.
The problem was documented in CR 97-3457 and root cause analysis97-103.
The inspectors determined that the root cause evaluation was thorough, with probing
evaluations into the causes of the problem. Some of the corrective tv i were not
complete at the end of the inspection period and will be reviewed during a future
inspection. These corrective actions will be tracked under
Violation 50-266/97021-02(DRP); 50-301/97021-02(DRP), which was issued to
describe a violation regarding the inoperability of the containment hatch interlock. The
licensee's proposed corrective actions for this violation include addressing weaknesses in
the work control procedures related to implementation of proper design control.
c. Conclusion;
The inspectors concluded that the licensee performed a thorough root cause evaluation
into problems associated with the RVLIS modification.
E8 Miscellaneous Engineering issues
E8.1 (Closed) Unresolved item (URI) 50-266/95011-02(DRP): 50-301/95011-02(DRP):
Inadequate Testing of Containment Accident Fan Coolers. In inspection Report
(IR) 50-266/95011(DRP); 50-301/95011(DRP), the inspectors documented a potential
operability concem regarding the Unit 11HX-15D containment accidant fan cooler. Data
from performance test PC-56," Containment Accident Recirc Heat Exchanger
Perforrmance Monitoring Unit 2 " Part 2, Revision 5, was used to calculate a fouling factor
for the heat exchanger. When the fouling factor of 0.0014 was used to calculate the heat
removal rate for the cooler, the licensee determined that the heat removal rate was less
than the 50 million British thermal units per hour specified in the FSAR. The engineering
staff chose to disregard the data due to uraertainties associated with the test, including
inappropriate test conditions ar d instrument inaccurecies.
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The inspectors further identified in IR 50-266/95011(DRP); 50-301/95011(DRP) that other
nonconservative values for service water temperature and flow rate, in addition to the
nonconservative fouting factor of 0.0014, were used in the containment accident fan
cooler heat removal calculation and other calculations used to justify cooler opeirability.
The inspectors classified these issues as an unresolved item and requested that the
licensee submit a formal written evaluation to the NRC. A response, dated January 19,
1996, was submitted in which the licensee concluded that the test results were
inconclusive due to test inaccuracy. The licensee stated that in addition to setvice water
flow instrumentation inaccurarles, test results could vary based on the number of service
water pumps in operation and service water temperatures. Tne licensee's evaluation
concluded that the fan cooler had remained operable. This operability evaluation was
based on a specialimproved accuracy test and a computer analysis of the summer of
1995 flow and water temperature conditions, in addition, routine and preventive
maintenance was performed on the containment fan coolers to ensure system reliability.
The inspectors concluded that the operability evaluations were adequate. However, the *
licensee planned a number of corrective actions to pursue more accurate performance
tests.
A revised test Procedure, PBTP-040, * Performance Test of 1HX-15D Containment Fan
Cooler," using more accurate service water flow instruments and controlled test
conditions, was performed for Unit 1 in March 1996 and a similar test was planned for
Unit 2. During this inspection, the inspectors identified that the revised test had not been
conducted for Unit 2 and concluded that the results of the Unit 1 test, performed on '
December 20,1995, were unreliable. g
The inspectors considered this failure to conduct an adequate performance test using a
satisfactory test procedure and adequate test instrumentation to be a Violation
(VIO 50-266/97026-05(DRP); 50-301/97026-05(DRP)) of 10 CFR Part 50, Appendix B,
Criterion XI," Test Control," as described in the attached Notice of Violation.
c. Conclusions
Test control deficiencies associated with the containment accident fan coolers had been
identified in 1995, and new tests were to have been performed shortly after the
August 1997 restart of Unit 2. However, the new tests had not been performed as of the
end of November 1997. One violation was identified.
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IV. Plant Succod
R4 Staff Knowledge end Perfonnance in Radiological Protection and Chemistry
R4.1 Corrective Actions Taken to Address Radiation Workers without Self Readino Dosimeter
- (E.RJ)
a. - Inspection Scope (IP 7175_0)
-The inspectors reviewed the effectiveness of health physics (HP) department corrective
actions taken to address radiation workers entering the radiologically controlled area
(RCA) without the required secondary dosimeter (SRD).
b. Observations and Findingt
<
As part of the licensee's problem identification process, CRs were written during 1997
that identified instances where workers entered (or attempted to enter) the RCA without
wearing the required SP.D. The third quarter trending anahsis noted that 32 CRs had
been written for the year to date signify' e adverse trend. This prompted licensee
- management to request a root cause ir s e v.!vn of the problem.
Personnelin HP could not determine a single root cause. Worker accountability for
maintaining proper radiation worker practices had lapsed and the number of new radiation
workers had increased.
The HP department implemented several corrective actions to address the problem.
Dosimeter requirements were re-emphasized at a general plant meeting on October 3,
1997, and in a general plant publication. Stronger accountability for proper radiation
worker practices was implemented which required that a worker's RCA access be
suspended following three noncompliances. An RCA " greeter" was staged at the
entrance to the RCA. This individual (usually an HP technician) woulo verify that the i
workers were wearing proper dosimeters, question te workers as to the location of and .
expected time in the work areas, and provide the workers with spscial information
regarding ongoing activities within the RCA.
The inspectors reviewed worker performance following the implementation of these
actions. Immediate improvements were noted in worker performance, as reflected in a
reduction in CRs referencing this problem. The inspectors observed the performance of
the " greeters" at the RCA entrance and concluded that this initiative was effective.
c. Conclusio_n
The !nspectors determined that the HP department was effective in addressing an
2- adverse trend regarding workers failure to wear proper dosimeters.
R4.2 Unit 2 Containment Close-out
The health physics manager and the outage planning manager performed a post-outage
walkdown of the Unit 2 containment and identified excessive amounts of dirt and debris.
This material was removed from containment prior to containment close-out, and the
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health physics manager stated t. A permanent corrective actions were going to be
implemented to ensure that the containment was thoroughly cleaned following future .
outages and prior to close-out walkdowns. The inspectors considered the effort to
improve containment post-outage cleanliness to be a positive initiative.
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V. Manaaement Meetinas
Xi Exit Meet.ng Summary
- The inspectors presented the inspection results to members of licensee management at
the conclusion of the inspection on January 20,1998. The licensee acknowledged the
findings presented. The inspectors asked the licensee whether any materials examined
duing the inspection should be considered proprietary. No proprietary information was
identified.
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PARTIAL LIST OF PERSONS CONTACTED
License,
Wisconsin Electric Power Company (WEPCo)
- S. A. Patuiski, Site Vice President
A. J. Cayla, Plant Manager--
R. G. Mende, operations Manager -
W. B. Fromm, Maintenance Manager
J. G. Schweitzer, Site Engineering Manager
P. B. Tindall, Health Physics Manager-
D. F. Johnson, Regulatory Services and Licensing Manager ;
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, ar Preventing
Problems ,
IP 61726: Surveillance Observations
IP G2707: Maintenance Observations
IP 71707: Plant Operations
IP 71750: Plant Support Activities
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-266/97026-01 (DRP) VIO Inappropriate Procedure Adherence Guidance
50-301/97026-01 (DRP)
50-266/97026-02 (DRP) VIO Failure to Enter TS 15.3.0
50-301/97026-02 (DRP)
50-266/97026-03 (DRP) NCV * Delta T" Trip Setpoints Not Reduced in
50-301/97026-03 (DRP) Accordance with Technical Specifications
50-266/97026-04 (DRP) NCV Failure to Perform Inservice Tests Required by
50-301/97026-C 4 (DRP) ASME Section XI
50-266/97026-05 (DRP) VIO Failure to Conduct an Ar' equate Performance Test
50-301/97026-05 (DRP) Using Test Procedure and Test Instrumentation
Closed
50-266/96011 LER " Delta T" Trip Setpoints Not Reduced in
50-301/96011 Accordance With Technical Specifications
50-266/96006 LER Emergency Power Out-of-Service Coincident With
50-301/96006 Opposite Train Service Water Pump Out-of-Ser/ ice
50-266/96003 LER Plant Operation Outside of Design Basis of the Low
50-301/96003 Temperature Overpressure Protection System
50-266/96001 LER inadvertent Engineered Safety Features Actuation
in Train 8 Due to DC Gystem Ground
50-266/95011-02(DRP) URI Inadequate Testing of Containment
50-301/95011-02(DRP) Accident Fan Coolers
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LIST OF ACRONYMS '.EED IN POINT BEACH REPORTS
l AC Alternating Current
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ANSI Amsrican National Standards institute
AOP Abnormal Operating Procedure '
ASME American Society of Mechanical Engineers
CCW Component Cooling Water System
CFR Code of Federal Regulations
CLB Current Licensing Basis
CR Condition Report
CVCS Chemical and Volume Control System
DC Direct Current
DCS Duty and Call Superintendent
DRP Division of Reactor Projects
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
EOP Emerger cy Operating Procedure
ESF Engineered Safety Feature
EP Emergency Planning
'F Degrees Fahrenheit
FME Foreign Material Exclusion
FSAR Final Safety Analysis Report
HP Health Physics
HVAT High Voltage Station Auxiliary Transformer
IFl Inspection Follow-up Itom
IP inspection Procedure
IPE Individual Plant Evaluation
IR inspection Report
ILRT Integrated Leak Rate Test
IT In-service Test
kV kilovolt
LAN Local Area Network
LCO Limiting Condition for Operation
LER Licensee Event Report
LTOP Low Temperature Overpressure Protection
MSIV Main Steam Isolation Valve
MSS Manager's Supervisory Staff
NCV Non-Cited Violation
NDE Non-Destructive Examination
NRC Nuclear Regulatory Commission
NUTRK Licensee's issue Tracking Database
01 Operating Instruction
OM Operations Manual
OOS Out-of-Service
OP Operating Procedure
ORT Operations Refueling Test
PAB Primary Auxiliary Building
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PASS Post accident Sampling System _
PBTP Point Beach Test Procedure
PDR Public Document Poom
POD Prompt Operability Determination
QA-- Quality Assurance -
RCA Radiologically Controlled Area
RCP Reactor Coolant Pump
RCS _ Reactor Coolent System
RMP- Routine Maintenance Procedure
RP Radiation Protection
RVLIS Reactor Vessel Level Indication System
RWST Refueling Water Storage Tank
SALP Systematic Assessment of Ucensee Performance
SER- Safety Evaluation _ Report
_SFP Spent Fuel Pool
SI Safety Injection
SSC Structures Systems or Components
TDAFW - Turbine Driven Auxiliary Feedwater
TS Technk;al Specification
URI Unresolved item
USQ Unreviewed Safety Question 1
VIO = Violation
VNCR Control Room Ventilation
' WMTP_ Wisconsin Michigan Test Procedure
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