ML20217D353
| ML20217D353 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 03/21/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20217D341 | List: |
| References | |
| 50-266-98-03, 50-266-98-3, 50-301-98-03, 50-301-98-3, NUDOCS 9803270399 | |
| Download: ML20217D353 (30) | |
See also: IR 05000266/1998003
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U.S. NUCLEAR REGULATORY COMMISSION -
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REGION ll1
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Docket Nos:
50-266, 50-301
License Nos:
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Report No:
50-266/98003(DR P), 50-301/98003(DR P)
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Licensee:
Wisconsin Electric Power Company
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Facility:
Point Beach Nuclear Plant, Units 1 & 2
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Location:
6612 Nuclear Road
Two Rivers, WI. 54241-9516
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Dates:
January 20 through March 2,1998
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Inspectors:
F. Brown, Senior Resident inspector
P. Louden, Resident inspector
P. Simpson, Resident inspector
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Approved by:
J. W. McCormick Barger, Chief
Reactor Projects Branch 7
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9003270399 900321
ADOCK 0500C266
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EXECUTIVE SUMMARY
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Point Beach Nuclear Plant, Units 1 & 2
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NRC Inspection Report No. 50-266/98003(DRP); 50-301/98003(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant
support. The report covers a six-week inspection period by the resident inspectors.
Operations
The Unit 2 startup on February 7,1998, was conducted well; however, operators
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continued with unit startup without completely understanding the cause, or identifying all
of the effects, of a waterhammer which occurred in the main steam piping during startup
preparations. This was indicative of a lack of sensitivity to the potential consequences of
waterhammer events. Licensee management initiated a high-level root cause evaluation
of the event and the operator response. (Section O1.1)
Operators were observed circumventing the licensee's work control process by verbally
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directing adjustments to nonsafety-related control valves during a unit startup. Operators
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performing informal troubleshooting caused an unplanned closure of the moisture
separator reheater steam flow control valves during a unit shutdown, resulting in a four
percent reactor power transient. The operator response to this minor transient was
adequate, but the control room command and control roles were not consistent with the
expectations in the procedure for conduct of operations. (Section O1.2)
Personnel who inspected new fuel assemblies demonstrated appropriate attention-to-
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detail. (Section O1.3)
Operations personnel safely conducted and controlled fuel movements. However,
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containment work activities lacked coordination, and there was minimal management
oversight of containment activities early in the refueling outage. (Section 01.4)
The reactor coolant pump lube oil collaction systems were found not to be in accordance
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with the requirements of 10 CFR Part 50, Appendix R, Section 111.0. This condition was
identified during the licensee's Appendix R rebaselining project. Effective compensatory
actions were implemented and corrective actions were planned. (Section O2.1)
The licensee procedures for operation of the two units were inappropriate in that they
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created the potential for sustained operation at a reactor thermal power in excess of the
facility license limits. Two examples of a violation were identified. The licensee
responded promptly to this inspector finding, and the procedures were revised prior to the
exit meeting. (Section O3.1)
One violation was identified for an engineer who failed to follow the danger tag procedure
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for operating permits. No training had been provided to engineers on the operating
permit controls. Corrective actions were taken by the licensee prior to the end of the
inspection period. (Section O3.2)
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Operators were observed using reactor engineering instructions (REls), such as REl 11,
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"End of Life Coastdown," to change reactor power. The REls provided specific
operational guidance and steps which were more appropriate for operating
procedures. (Section O3.3)
A deficiency existed in auxiliary operator knowledge and understanding of the operation of
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oil reservoirs on safety-related pumps. Licensee management indicated that training
enhancements would be made to address this deficiency. (Section 04.1)
Maintenance
Operators performed well during a special test of an emergency diesel generator.
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Additional staff was provided for performance of the test and the test was effectively
coordinated. Operators promptly identified and corrected an inadvertent service water
isolation caused by an inadequate test procedure. (Section M1.1)
Maintenance staff performed lifts of the reactor vessel head and upper intemals without
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incident. Procedures were followed; however a lack of strong oversight, coordination,
and control in containment was noted when foreign material entered the refueling cavity
pool during the upper internals lift. (Section M1.2)
The licensee implemented improved work planning processes for on-line maintenance
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and refueling outages. Safety significant modifications were either completed or were
scheduled for completion during upcoming outage periods. Notwithstanding these
positive accomplishments, there was a large backlog of safety-related repairs and
planned modifications, and some work activities were being deferred from their originally
scheduled outage windows. The inspectors did not identify any examples of unsafe
conditions created by the deferral of work items, but were concerned that the delays in
implementing modifications would effect plant operations, such as the power transient
described in Section O1.2 of this report.
The licensee provided the following backlog information: Open Corrective Maintenance
items - 2069 (212 identified as high priority); Open Condition Reports - 2424; Operations
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Workarounds - 36; Open Engineering Work Requests - 309; Open Modifications - 465.
(Section M2.1)
One violation was identified for a safety-related service water pump that was replaced
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with a work package which was inappropriate to the circumstances. An effective licensee
follow-up assessment of material control concerns identified the need for some broad
improvements in the control of nuclear grade parts and material. Programmatic
corrective actions were planned at the end of the period; however, short term corrective
actions did not receive the appropriate level of documentation and follow-
up. (Section M2.2)
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Enaineerina
Plant staff, including design engineering personnel, continued to identify design basis
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issues. These issues were entered into the corrective action program in a prompt
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manner, and plant management evaluated and responded to each in an appropriste
fashion. (Section E1.1)
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Reactor engineering department actions to resolve a repetitive reactor coolant pump seal
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leak-off alarm were not prompt or coordinated well, resulting in a long standing distraction
to operators in the control room. No formal mechanism existed to disable control room
annunciators or to return them to service. (Section E2.1)
Engineering evaluations were used to disposition failures of inservice test acceptance
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criteria. Engineering management responded promptly by issuing informal clarification of
the expectation to use the condition report and operability determination system for such
failures. After additional inspector involvement, the appropriate procedures were also
modified to more clearly discuss this expectation. (Section E3.1)
Plant Support
There were no significant plant support findings during this inspection period.
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Report Details
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Summary of Plant Status
Unit 1 was in an end-of-life coastdown and Unit 2 was in a mid-cycle outage (U2MC23) at the
start of the inspection period. Two-unit operation was achieved when Unit 2 was restarted on
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February 7,1998. Unit 1 was shutdown on February 14,1998, for a refueling outage (U1R24).
Inspection Focus
During this inspection period, the inspectors focused on the effectiveness of licensee corrective
actions and completed routine inspection activities, and gathered information for a future vertical
slice review of the 125-Volt direct current system.
1. Operations
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Conduct of Operations
01.1
General Comments. Unit 2 Startup. and Main Steam System Waterhammer
a.
Inspection Scope (IP 71707)
The inspectors conducted frequent reviews of ongoing plant operations, including daily
observations of control room activities and control room shift tumovers. The inspectors
observed the startup of the Unit 2 reactor on February 7,1998.
b.
Observations and Findinas
The inspectors noted that the Unit 2 startup was conducted and controlled well, as
evidenced by the use of formal communications, thorough reactor status change
pre-briefings, and self checking by allindividuals involved. The operating supervisor (OS)
in charge of the reactor startup displayed good command and control of the activities.
Notwithstanding the positive operator performance associated with startup activities, the
inspectors were concemed by the response of operators and engineers to a
waterhammer event which occurred while pre-startup evolutions were being performed.
The waterhammer was evidenced by a noise audible in the work control center, and by
main steam system pipe movement and insulation damage in the turbine hall. After the
waterhammer subsided, an engineering supervisor inspected the main steam lines for
obvious damage. No damage was noted and the operators proceeded with startup. The
inspectors were informed of this event only after withdrawal of control mds had
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commenced. Through discussions with the involved individuals, the inspectors
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concluded that the operations staff and weekend duty engineers had not developed a
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clear understanding of the type of waterhammer that had occurred (for example, slug
formation versus steam void collapse), its exact location in the main steam piping, or its
potential consequence other than that no visible damage had occurred and no steam
leaks currently existed. The inspectors were further concerr.ed that the operations
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manager and plant manager were not informed of the waterhammer prior to the unit
startup.
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The licensee initially categorized condition report (CR) 98-0477, for the waterhammer, as
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a level *B" concem, requiring a root cause evaluation. The CR was subsequently
upgraded to a level"A"(highest) concem by the plant manager. Walkdowns performed
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during the root cause evaluation of this event identified damage to energy absorbers on
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the steam pipe to the condenser dump valves. This damage was missed during the pre-
startup walkdowns. A CR and operability determination were prepared for the damaged
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energy absorbers after the inspectors questioned the effect of this condition on the ability
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of the steam system to perform its specified functions. The energy absorbers were
determined to be operable but degraded.
In reviewing the response of operators to this event, and to other, less significant,
waterhammer events during this inspection period, the inspectors concluded that plant
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staff were not sensitive to the potential effects of waterhammer events. This concern
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was discussed with the licensee staff, who stated that the inspectors' conclusion was
consistent with the preliminary results of the root cause evaluation,
c.
Conclusions
The Unit 2 startup was conducted well; however, operators continued with unit startup
without completely understanding the cause, or identifying all of the effects, of a
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waterhammer which occurred in the main steam piping during startup preparations. This
was indicative of a lack of sensitivity to the potential consequences of waterhammer
events. Licensee management initiated a high level root cause evaluation of the event
and the operator response.
01.2 Control of Setpoint Adiustments and Troubleshootina
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a.
Inspection Scope (IP 71707)
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The inspectors observed the conduct of operations in the control room and in the plant.
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Operators were observed making or directing adjustments to the moisture separator
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reheater (MSR) steam flow controller and flow control valves during unit startup and
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shutdown. The inspectors assessed the adequacy of administrative controls for these
manipulations,
b.
Observations and Findinas
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On February 9,1998, during the Unit 2 power ascension, the inspectors observed the
operating crew place the nonsafety-related MSR steam flow controller into service.
Operating Procedure (OP) 1C, " Low Power Operation to Normal Power Operation,"
Revision 62, directed this activity. While performing the procedural steps, the operator in
the field noted that one of the four flow control valves was not tracking with the other
valves. All four valve positioners receive a common pneumatic signal from a single
controller. The operators contacted instrument and controls (l&C) technicians, and the
OS provided verbal direction to the I&C technicians to make the required adjustment to
the valve positioner. The flow control valve performed satisfactorily after the adjustment
was made. After the work was completed, the OS initiated a work order (WO) tag which
documented the adjustment of the positioner. The OS told the inspectors that the use of
verbal direction to authorize adjustments to balance-of-plant equipment, such as the MSR
steam supply and feedwater flow control valves, was not uncommon, but that this
practice was not used on safety-related systems or components,
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The inspectors subsequently asked plant management what controls existed to ensure
that adjustments to safety-related equipment were adequately controlled, and what
guidance existed to ensure that adjustments to balance-of plant equipment, such as the
feedwater flow control valves, were evaluated for their potential impact on the primary
plant prior to execution. The production planning manager and operations manager
subsequently stated that a new revision to the Nuclear Power Department Procedure
(NP) 8.1.1, " Work Order Processing," required that all adjustments of primary and
secondary system plant equipment be controlled by the WO process prior to performance
of work.
The inspectors observed control room activities associated with shutting down Unit 1 on
February 14,1998. The shutdown commenced from 75 percent reactor power.
Step 4.2.4 of OP 3A, " Normal Power Operation To Low Power Operation," Revision 40,
directed the operators to throttle steam flow to the MSRs by manually adjusting the MSR
steam flow controller. This controller is located in the back panels of the control room. A
reactor operator (RO) attempted to perform this step, but the controller responded in an
unexpected manner. The RO requested that the OS look at the controller. The duty shift
superintendent (DSS) and the duty operating supervisor (DOS) remained in front of the
panels while the OS looked at the MSR controller. The RO and OS manually manipulated
the controller in an unsuccessful effort to determine why it was not responding as
expected. When the OS manipulated the MSR controller a second time, all four MSR
flow control valves closed rapidly and unexpectedly. This created an approximately four
percent primary plant power transient. The DOS left the control room and locally opened
the MSR steam flow control valves, restoring the steam crossover temperature. The
crew initiated CR 98-0537 to document this event, and initiated a WO for l&C to
troubleshoot and repair the MSR controller. The controller was repaired and the load
reduction resumed, approximately two hours later. The I&C technician determined that
the OS had initiated the MSR steam flow control valve closure by de-latching two meshed
gears in the controller.
The inspectors considered the operator response to this transient to be adequate, but
noted that the DSS assumed an active command and control role when the DOS left the
control room. This action was not consistent with the expectations for DSSs specified in
Operations Manual Procedure (OM) 1.1, but it did not have any direct effect on safety
during this event. The inspectors noted that the power transient was initiated by
operators performing informal troubleshooting on the nonsafety-related MSR steam flow
controller without adequate training on the operation of the controller, and without
procedural guidance or authorization. Both of these observations were discussed with
the operations manager. The inspectors will continue to review the adequacy of
procedures and procedure implementation under inspection follow-up item
(IFI) 50-206/97020-02(DRP); 50-301/97020-02(DRP). Finally, the inspectors noted that
the MSR steam flow controller was not designed for manual manipulation, but that it was
manually manipulated for both startups and shutdowns. An open modification existed to
replace these controllers, but the Unit 1 modification had recently been deferred (see
Section M2.1 for additional discussion of maintenance and modification backlog and
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deferrals).
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c.
Conclusions:
Operators were observed circumventing the licensee's work control process by verbally
directing adjustments to nonsafety-related MSR steam flow control valves during a unit
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startup. Operators performing informal troubleshooting caused an unplanned closure of
the MSR steam flow control valves during a unit shutdown, resulting in a four percent
reactor power transient. The operator response to this minor transient was adequate, but
the control room command and control roles were not consistent with the expectations in
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the procedure for conduct of operations.
O1.3 New Fuel Receipt inspections (IP 71707)
The inspectors observed the unloading, inspection, and storage of new fuel assemblies.
Three different operations crews were observed handling the new fuel. Handling
operations were carefully conducted to ensure no damage occurred to the new fuel.
Reactor engineering personnel conducted detailed and thorough inspections of each
assembly to verify no damage had occurred to the fuel in transit from the manufacturer.
The inspectors noted that Refueling Procedure 2A, " Receipt of New Fuel Assemblies,"
Revision 33, was used at the job site. Good coordination was observed between
operations department and reactor engineering personnel.
01.4 Conduct of Refuelino Operations
a.
Inspection Scope (IP 71707)
The inspectors observed Unit 1 refueling outage work activities including the disassembly
and removal of the reactor vessel head, reactor vessel upper internals removal, and fuel
off-loading. See Section M1.2 for further discussion of refueling maintenance activities.
b.
Observations and Findinos
On February 26,1998, the licensee started removing fuel from the Unit 1 reactor. The
inspectors attended the pre-job briefing for fuel movement and observed the removal of
the fuel from the reactor vessel and the transfer of fuel to the spent fuel pool. The
inspectors had the following observations:
The pre-job briefing for the fuel movement was thorough and a free exchange of
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information existed. Individual responsib;lities (operations and health physics)
were established and supervisory command and control was clearly defined.
Just prior to starting fuel movement, a check was conducted to verify the
requirements of refueling Technical Specification (TS) 15.3.8 had been satisfied.
The check concluded that the lower containment hatch could not be adequately
closed. Repairs were pursued, and the TS requirements were satisfied after
about a one-hour delay. A check had not been performed earlier in the outage to
ensure that the requirements of the refueling TS had been completed.
In preparation for fuel movement, operations personnel installed suspended
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lighting in the reactor vessel?The inspectors noted that the operator suspending
the lighting occasionally had to move to the refueling bridge guide railing and
reach into the cavity to secure the lighting. The operator braced himself along the
cavity railing; however, the use of a safety harness would have been more
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appropriate for the circumstances. The inspectors brought this to the refueling
operations supervisor's attention. The supervisor stated that a safety hamess
would be used in the future.
The inspectors noted that foreign material exclusion controls were not
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implemented for concurrent work activities on the "B" steam generator upper
elevations. The location of the activities were such that anything dropped from
the work areas could have fallen into the cavity and onto the core. The refueling
operations supervisor noted this and notified the responsible work group
supervisor. Subsequent work on exposed portions of the steam generators was
conducted under foreign material exclusion controls.
When the transfer cart was sent to containment to receive the first fuel assembly,
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it was noted that the dummy fuel assembly, used for fuel handling system
surveillance checks, was stillin the upender on the cart. The transfer cart was
then returned to the spent fuel pool side and the dummy fuel assembly was
removed. This indicated a lack of thoroughness on the part of the previous
operations crew, who conducted the fuel handling system checks, to verify that
equipment was ready for fuel movement.
The first fuel assembly was placed on the transfer cart and was moved into the
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transfer tube and stopped. This was done to conduct containment wall
radiological su veys to determine radiation dose rates. Previous experience had
identified radiation streaming from the transfer tube area that affected dose rates
along the containment wall. Health physics technicians identified localized areas
which met the requirements for a high radiation area. Health physics supervision
then determined that additionallead shielding should be placed along the affected
portions of the containment wall. Due to a lack of planning, the lead shielding was
not pre-staged. This led to a delay of almost three hours, while the shielding was
gathered and installed.
The inspectors observed that a radiological control posting on the refueling bridge
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manipulator was in contact with the manipulator cabling. When the manipulator
was lowered, the moving cable in contact with the posting caused the posting to
move about. The inspectors alerted health physics technicians of the condition
and it was immediately corrected. The inspectors discussed the occurrence with
health physics management, highlighting earlier inspector observations of
postings inappropriately placed on or near moving equipment.
The inspectors noted a high level of work activities ongoing in the area around the
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refueling cavity during the fuel movement operations. The operation of multiple
cranes, workers speaking loudly, and scaffolding movement all contributed to a
noisy environment within the containment. The operators involved with the fuel
movement stated to the inspectors that a more controlled, quieter environment
would be more conducive to focused fuel movement operations.
The fuel moves were well coordinated amongst the operations staff involved, and
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repeat back communications were used. The refueling OS maintained good
command and control over the activities, considering the working environment.
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The inspectors held a meeting with plant management on February 27,1998, to convey
the observations discussed above, and those discussed in Section M1.2 of this report. In
addition, the inspectors related that there had been minimal management oversight noted
in the plant for the activities observed. Plant management stated that these issues would
be reviewed and appropriate actions would be taken. Improvement of conditions and
controls for fuel movement were noted on the final day of the inspection period.
c.
Conclusions
The inspectors concluded that operations personnel safely conducted and controlled fuel
movements. However, severalinspector observations indicated that containment work
activities lacked coordination. Minimal management oversight of containment activities
was also noted.
02
Operational Status of Facilities and Equipment
O2.1
Reactor Coolant Pump (RCP) Lube Oil Collection System (LOCS) not in Compliance with
10 CFR Part 50. Appendix R. Reauiiements
a.
Inspection Scope (IP 71707 and IP 37551)
The inspectors reviewed the circumstances surrounding the licensee identified problems
with the LOCS for both Unit 2 RCPs.
b.
Observations and Findinas
On December 23,1997, licensee engineering personnel conducted a walkdown of the
Unit 2 RCP LOCS as part of the ongoing 10 CFR Part 50, Appendix R, rebaselinbg
project. The engineers determined that the installed LOCS did not fully meet the
requirements of 10 CFR Part 50, Appendix R, Section Ill.O. This issue was subsequently
documented in Licensee Event Report (LER)98-004, dated February 13,1998.
The nature of the nonconformances included potentialleakage sites outside the LOCS
boundary and potentially inadequate drain paths between the oil deflector and the leak off
tray. Similar deficiencies were ascribed to the Unit 1 RCP LOCS due to its similar design.
Immediate licensee compensatory measures included:
briefing all oncoming shift personnel regarding the nonconforming condition and
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its potential consequences;
modifying monthly containment surveillance checks to focus on identifying RCP oil
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leaks and reporting them to system engineering; and
modifying Abnormal Operating Procedure 18 to add a note regarding the
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nonconforming condition.
The licensee further committed to design and install the appropriate modifications in both
Unit 1 and Unit 2 by the end of the next refueling outages (Spring 1999 and Fall 1998,
respectively). The failure to install a RCP LOCS to collect oil from all potential
pressurized and unpressurized leakage sites is a violation of 10 CFR 50, Appendix R,
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Section 111.0. However, this non-repetitive, licensee-identified and corrected violation was
considered a non-cited violation (NCV 50-266/98003-01(DRP); 50-301/98003-01(DRP))
consistent with Section Vll.B.1 of the NRC Enforcement Policy.
c.
Conclusions
The RCP LOCSs were found to be in non-compliance with the requirements of
10 CFR Part 50, Appendix R, Section Ill.O. This condition was identified during the
licensee's Appendix R rebaselining project. Effective compensatory actions were
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implemented, and corrective actions were planned.
03
Operations Procedures and Documentation
O3.1
Inadeauste Operatina Procedure for Control of Reactor Power
a.
Inspection Scope (IPs 71707 and IP 92901)
While performing follow-up of an unresolved item (URI), the inspectors reviewed the
licensee's procedures for controlling reactor power. The URI had been opened, when
inspectors observed unit operation at 100.2 percent rated thermal power.
b.
Observations and Findinas
Point Beach Nuclear Plant Unit 1 and Unit 2 Facility Operating Licenses, Section 3.A,
state that "The licensee is authorized to operate the facility at reactor core power levels
not in excess of 1518.5 megawatts thermal [MWt)." During an inspection performed in
January 1996, inspectors observed operation of Unit 2 at 100.2 percent of the licensed
thermal power, without operator action to reduce power, and opened
URI 50-206/96018-03; 50-301/96018-03 to assess whether the observed condition was a
violation of NRC requirements.
Licensed operators informed the inspectors that unit power was controlled such that the
average thermal output for an eight hour period did not exceed 1518 MWt in accordance
with Operation Procedure (OP) 2A, " Normal Power OperatHn," Revision 28.
Procedure OP 2A directed that operators maintain an eight hour average output of
1518 MWt in accordance with Reactor Engineering Instruction (REI) 1.0, but did not state
that sustained output of more than 1518.5 MWt was unacceptable. The problem with use
of an eight hour average for determining maximum allowed thermal power was that a
lower than licensed power, early in the eight-hour period, would potentially allow operation
at a higher than licensed power later in the eight-hour period. The inspectors considered
OP 2A to be inappropriate to the circumstances and an example of a violation
(VIO 50-206/98003-02a(DRP); 50-301/98003-02a(DRP)) of 10 CFR Part 50, Appendix B,
Criterion V, because it created the potential of operation of the unit in a manner outside
the limits of the facility license.
Procedure REl 1.0, " Power Level Determination and Guidelines," Revision 20, provided
guidelines for operating the units, and was invoked by OP 2A. This procedure directed
that an eight hour average thermal output of 1518 MWt be maintained by matching actual
power to a calculated target reactor thermal output (RTOT). The RTOT was calculated
by the plant computer based upon power output to each point in time during an eight hour
period. Procedure REI 1.0 specifically stated that the RTOT could potentially be as high
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as 1521 MWt. In add; tion, REl 1.0, paragraph 4.5, stated that sustained power operation
above 100.6 percent (1527.6 MWt) was not allowed. This implied an allowable sustained
power rate of up to 100.6 percent, a value in excess of the licensed limit. The inspectors
considered REI 1.0 to be inappropriate to the circumstances and an example of a
violation (VIO 50-206/98003-02b(DRP); 50-301/98003-02b(DRP)) of 10 CFR Part 50,
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Appendix B, Criterion V, because it created the potential of operation of the unit in a
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manner outside the limits of the facility license.
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After identifying the inappropriate content of OP 2A and REI 1.0, the inspectors
immediately brought the issue to the attention of senior plant management. The plant
staff took prompt action to ensure that the units would not be operated at sustained
power levels in excess of the license limits. The inspectors did not observe any
instances where operators intentionally took action to raise thermal power to a value in
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excess of the licensed limit. Changes to OP 2A and REI 1.0, to eliminate the potential for
exceeding licensed thermal output, were issued prior to the exit meeting for this
inspection period.
c.
Conclusions:
The licensee procedures for operation of the two units were inappropriate in that they
created the potential for sustained operation at a reactor thermal power in excess of the
facility license limits. Two examples of a violation were identified. The licensee
responded promptly to this inspector finding, and the procedures were revised prior to the
exit meeting.
03.2 Deficiencies in the Operatina Permit Proaram
a.
Inspection Scope (IP 71707)
The inspectors reviewed the licensee's recently implemented operating permit process.
This process authorizes groups other than the operations department to operate the
equipment cover by the permit. One issue reviewed involved the failure of a operating
permit log designee to follow the danger tag procedure.
b.
Observations and Findinas
On February 13,1998, an operating permit was placed on the Unit 2 containment fan
cooler system to allow for installation of test equipment. The test being performed was
Operating instruction (01) 131, " Performance Test of 2HX-15D1 Containment Fan Cooler
Unit 2." About an hour after a new operating crew started work, an auxiliary operator
(AO) informed the control room that he was about to close the "D" containment fan motor
breaker in preparation for the 01131 test. The DSS questioned this action. The AO
indicated that he was being authorized to perform the action by the cognizant engineer
who was signed on to the operating permit. After some discussion, the DSS allowed the
AO to complete the manipulation. The inspectors, who were in the control room at the
time, asked the shift supervisors if they had been informed of the 01131 activities
planned for their shift. The supervisors indicated that the engineer had not directly
notified them of any planned equipment operations, and had not obtained authorization to
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operate any equipment associated with Of 131.
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Procedure NP 1.9.15, " Danger Tag Procedure," Revision 5, stated, in part, that the
individual signed on the operating permit log shall:
obtain shift supervision authorization before operating equipment controlled by an
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operating permit.; and
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as directed by shift supervision, notify or obtain authorization to operate
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equipment controlled by operating permit tags, while performing the work.
At the request of the inspectors, the shift supervisors asked the engineer whether he was
aware of the procedural requirements described above. The engineer indicated that he
was not familiar with these requirements. Condition Report 98-0539 was written to
document the occurrence. Management screened and categorized the occurrence as a
level"D" problem (lowest priority).
The inspectors reviewed the training given on a recent danger tag proceduro revision and
the operating permit program. Maintenance staff had received recent training, and
interviews indicated that the maintenance groups were aware of the expected actions and
responsibilities. Likewise, operations personnel were also sufficiently trained on the
procedure. However, the engineering staff had not received formal training on the
revised danger tag procedure. The inspectors were informed by operators that this was
not the first time that engineers had signed onto operating permits. All site engineering
personnel were subsequently trained on the requirements and responsibilities associated
with the operating permit program.
The inspectors determined that the failure of the engineer to follow the operating permit
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requirements of NP 1.9.15 constituted a violation (VIO 50-301/98003-03(DRP)) of
10 CFR Part 50, Appendix B, Criterion V.
c.
Conclusions
An engineer failed to follow the danger tag procedure for operating permits. The
inspectors determined that no training had been provided to engineers on the operating
permit controls, but that more than one engineer had signed on to operating permits.
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Corrective actions were taken by the licensee prior to the end of the inspection period.
O3.3 Use of Reactor Enaineerina instructions for Operatina the Units
The inspectors noted that operators were using guidance contained in REl 11. "End of
Life Coastdown," to operate Unit 1. The inspectors were concerned that REI 11 provided
specific operational guidance which was more appropriately contained in an operating
procedure. This concern was discussed with licensee management, who acknowledged
the observation.
04
Operator Knowledge and Performance
04.1 Auxiliary Operator Knowledae Deficiencies Reaardina Safety System Pump Oilers
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a.
Inspection Scope (IP 71707)
The inspectors reviewed the licensee's program for routine monitoring of safety system
pump oil levels.
b.
Observations and Findinas
The inspectors identified that the outer bearing oil reservoir for the Unit 1 "A" safety
injection pump was positioned much lower than the corresponding oil level mark on the
bearing housing. In this position, tt.e reservoir would not add make-up oil until the
bearing oil level was lower than desired. The inspectors notified maintenance
supervision of the condition, and it was corrected within a few hours. Although the
mispositioned reservoir did not present an operability concern for the pump, the
inspectors were concerned that the reservoir sppeared to have been mispositioned when
refilled by an auxiliary operator (AO). Additionally, the condition had not been identified
by AOs during their routine rounds.
The inspectors discussed this issue with several AOs. These discussions indicated that
confusion existed among the AOs regarding the operation of the oiler reservoirs.
Additionally, routine log sheets only required the AOs to note oillevelin the reserwir
bulbs, not to evaluate the level setting relative to the pump bearing. The inspectors were
also informed that recent training for the AOs on pump oil reservcdre hed not been as
detailed as previous oil reservoir training. Operations management indicated that the
continuing training program for AOs would be modified to include a module on the oil
systems and potential problems to be aware of during rounds,
c.
Conclusions
The inspectors identified a mispositioned oiler, and after follow-up, concluded that a
deficiency existed in AO knowledge and understanding of the operation of oil reservoirs
on safety-related pumps. Licensee management indicated that training enhancements
would be made to address this deficiency.
08
Miscellaneous Operations issues
08.1
(Closed) LER 50-266/98-005: Missed TS Test for Control Rod Exercises. On
January 21,1998, the licensee determined that the TS required bi-weekly rod exercises
had not been performed on Unit 1 for over thirty days. Upon identification of the missed
,
surveillance, the licensee performed the test and achieved satisfactory results. The root
cause of the failure to perform the test was attributed to a clerical error when data was
inputted into the surveillance tracking database for the previous rod exercising
surveillance. The wrong status code was inputted and, as a result, the database did not
flag the need for the required surveillance. Corrective actions included a change to the
computer software to reduce the risk of this type of error being repeated. A programmatic
,
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change in the work scheduling process will provide 12-week rolling schedules which will
contain all required surveillances. The nonrepetitive, licensee identified and corrected,
failure to perform the required surveillance is being treated as a non-cited violation
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(NCV 50-266/98003-04 (DRP)) of TS Table 15.4.1-2, item 10, consistent with
Section Vll.B.1 of the NRC Enforcement Policy.
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08.2 (Closed) URI 50-206/96018-03: 50-301/96018-03: Routine Operation at 100.2 Percent
Power. This item is dispositioned in Section O3.1 of this report.
11. Maintenance
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M1
Conduct of Maintenance
M1.1 Tests and Surveillances
a.
Inspection Scope (IP 61726)
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The inspectors observed and reviewed pedormance of Point Beach Test
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Procedure (PBTP)-077, " Transient Response of G-02 Replacement Govemor,"
Revision 0,
b.
Observations and Findinas
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Test PBTP-007 was performed on January 22,1998, to verify that the new govemor on
emergency diesel generator G-02 would pedorm properly under accident loading
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conditions. Additional control room staffing was provided for the performance of this test,
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and individual assignments were made to all involved operators. The senior licensed
operator controlling the test provided good coordination of control room activities. The
= first portion of the test was started by simultaneously removing the normal source of
power from safety-related 4160-volt electrical distribution Bus 2A-05, and inserting a
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manual safety injection (SI) signal for the Unit 2 "A" train All systems and components
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worked as expected, and the inspectors observed that operators performed the
necessary test verifications in the control room and the G-02 loom.
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The second part of the test was performed by opening and then re-closing the G-02-
output breaker to 2A-05, and then verifying that G-02 and the bus loads responded
properly. The results of this part of the test were also considered to be as expected, until
an annunciator indicated a problem with the radioactive waste system. The control
(reactor) operator responding to this annunciator identified that the service water (SW)
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supply isolation valve for the radioactive waste system had closed.' The operators then
noted that the SW supply valve to the auxiliary building air conditioning system had also
closed. The operating crew concluded that the automatic isolation of the two nonsafety-
,
related SW loads had been caused by a SW isolation engineered safety feature (ESF)
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actuation. This ESF function ensures that SW is not diverted from safety-related loads
under postulated accident conditions. The operators reset the Unit 2 "A" train Si signalin
accordance with PBTP-77, and restored the SW system valves to their normal position
using the SW operating instruction. A four-hour report for the inadvertent ESF actuation
was made in accordance with 10 CFR 50.72(b)(2)(ii). - The licensee subsequently
' determined that PBTP-007 was inadequate because the inadvertent ESF actuation could
have been avoided by resetting the Si signal between the first and second parts of the
test. The inadvertent SW isolation was of minimal safety significance, so the use of an
inappropriate procedure was considered to be a non-cited violation
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(NCV 50-266/98003-05(DRP); 50-301/98003-05(DRP)) of 10 CFR Part 50, Appendix B,
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Criterion V, " Instructions, Procedures, and Drawings," consistent with Section IV of the
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c.
Conclusions
Operators performed well during a special test of G-02. Additional staff was provided for
performance of the test, and the test was effectively coordinated. Operators promptly
identified and corrected an inadvertent SW isolation caused by an inadequate test
procedure.
M1.2 Maintenance Refuelina Activities
a.
Inspection Scope (IP 62707 and 71707)
The inspectors observed large portions of the refueling evolutions performed by
maintenance department staff.
b.
Observations and Findinas
The maintenance department staff was responsible for lifting the Unit i reactor vessel
head and upper internals following Routine Maintenance Procedure (P.MP) 9096,
" Reactor Vessel Head Removal and Installation," Revision 16. The reactor vessel head
lift was preceded by an appropriate pre-job brief during which questions were asked by all
participating groups and intergroup communications were good. The evolution was
performed in a coordinated and controlled manner. The procedure was followed. The
inspectors did not identify any significant concerns; however, the use of at least three
different procedures by the maintenance, operations, and reactor engineering
departments complicated the coordination of activities associated with the head lift
evolution. Licensee management acknowledged this observation.
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During the pre-job brief for the upper internals lift, the responsibility for oversight and
command within containment was not defined. Additional planning for potential problems
could have been performed. The lift of the upper internals was performed in a deliberate
and professional manner by the crane operator and lead mechanic, who followed the
procedure as written. The absence of a clear chain of coordination and command was
evidenced by the indecision and confusion exhibited when a thermoluminescent
dosimeter (TLD) from a health physics technician fell into the refueling cavity pool during
the movement of the upper internals. The TLD parts were eventually removed from the
pool without incident. The cavity rail was a foreign materials exclusion area, and the TLD
was taped to the technician's clothing; however, the taping method was inadequate. See
Section 01.4 for discussion of inspector and licensee response to these observations.
c.
Conclusions
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Maintenance staff performed lifts of the reactor vessel head and upper internals without
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incident and in accordance with the procedure; a lack of strong oversight, coordination,
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and control in containment was noted when foreign material entered the refueling cavity
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pool during the upper internals lift.
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.M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Maintenance and Modification Backloo -
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inspection Scope (IP 62707)
The inspectors monitored ongoing outage planning activities to ensure that TS limiting
conditions for operation were satisfied, to ensure that risk assessment considerations
were included in the scheduling of maintenance activities, and to ensure that safety
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significant repairs and modifications were implemented in a timely manner.
b.
Observations and Findinas
The licensee implemented a new outage planning process for U1R24. This process
resulted in improvements in activity planning and scheduling prior to commencing the
outage. A 12-week rolling work schedule was also initiated during this assessment
period. Both of these initiatives provided mechanisms for increased use of risk
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assessment in the scheduling and performance of maintenance activities. The new
planning processes required the completion of modification and repair work packages
much earlier than in previous outages. Early development of work packages allowed for
better resource loading determinations and better estimates of work duration, both of
which facilitated the proper use of risk assessment in establishing plant conditions and
controlling equipment availability.
' The inspectors reviewed outage review committee meeting minutes to determine which
safety-related corrective maintenance and modification work items were being performed
during U2MC23 and U1R24. Severalimportant work items were performed or scheduled
for performance, including auxiliary feedwater pump low suction pressure protection
system modifications, main control board wire separation modifications, and SW pipe
replacement and modifications. The completion rate for items in the U2MC23 schedule
was good. The inspectors did not identify any examples where time-sensitive,
safety-critical repairs or modifications with regulatory commitment dates were removed
from U1R24; however, several work items for safety-related repairs and modifications had
been removed from U1R24. Examples of deferred items included replacement of
auxiliary feedwater check valves (potential waterhammer issue), replacement of SI -
accumulator level transmitters (inaccurate control room indication issue), and portions of
the main control board wire separation modification (licensing basis conformance issue).
The nonsafety-related modification to the MSR steam flow controllers was also deferred
from U1R24 (see Section O1.2). These work items were delayed or deferred because
the engineering, planning, and maintenance capabilities of the facility prevented their
completion during the planned outage period. Deferred items which could not be
performed with the unit on-line were scheduled for future outages. Deferred items which
could be performed with the unit on-line were not given scheduled completion dates. The
production planning manager informed the inspectors that there was currently no method
for determining the impact of deferred work on future outages, or for determining when
work delayed for performance on line would actusily be performed.
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s.
The licensee provided the inspectors the following information on backlogs, effective
February 20,1998:
Open Corrective Maintenance items:
2069 (212 identified as high priority)
Open Condition Reports:
2424
Operations Workarounds:
36
Open Engineering Work Requests:
309
Open Modifications:
465
c.
Conclusions
The licensee implemented improved work planning processes for on-line maintenance
and refueling outages. Safety significant modifications were completed or were
scheduled for completion during upcoming outage periods. Notwithstanding these
positive accomplishments, there was a large backlog of safety-related repairs and
planned modifications, and some work activities were being deferred from their originally
scheduled outage windows. The inspectors did not identify any examples of unsafe
conditions created by the deferral of work items, but were concerned that the delays in
implementing modifications could affect plant operations, such as the power transient
described in Section 01.2 of this report.
M2.2 Service Water Pump Modification
a.
Inspection Scope (IPs 62707. 61726. and 37551)
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The "A" SW pump (P-32A) was rebuilt during the inspection period. The inspectors
reviewed the circumstances leading up to the pump replacement, observed the
replacement of the pump and surveillance testing of the pump, and assessed the
technical evaluations associated with out-of-tolerance test and inspection results.
b.
Observations and Findinas
Point Beach has six two-stage " wet-pit" type SW pumps. These pumps are subject to
high vibration because of their design and service environment. Three pumps are
required to meet accident analysis loads, assuming loss of emergency power to the other
three pumps. The TSs allow one pump to be out-of-service for up to seven days, an
allowed outage time which is longer than that provided for (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) in NUREG 1431,
" Standardized TSs for Westinghouse Plants." The extended outage time is based upon
the physicallimitations (pump design and rigging considerations) which impact pump
replacement.
Risk Assessment in Schedulina Pump Repair
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The P-32A pump was found to be in the alert range for vibration on September 30,1997.
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The licensee subsequently placed P-32A on an increased frequency of vibration analysis,
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implemented special operating restrictions for the pump, and ordered replacement parts
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to support a pump replacement. The pump replacement included installation of modified
parts and troubleshooting of the cause of the vibration. The P-32A vibration was reduced
to below the alert range when the operating Unit 2 circulating water pump was secured
during the Unit 2 shutdown in November 1997. The licensee subsequently noted that
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forebay water level, and hence net positive suction head for the SW pumps, increased
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when circulating water pumps were stopped.
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When pump vibration went below the alert range, the pump replacement was postponed
from December 1997, when only one unit was operating, to the first week of
February 1998, when two units were scheduled to be operating. While either condition
would have been allowed under T/Ss, performance of the pump replacement with a
single unit operating would have been preferable from a risk perspective.
Vibration data for P-32A obtained on January 26,1998, exceeded the allowed operability
value by approximately 25 percent after a Unit 2 circulating water pump was started. The
service water pump was promptly declared inoperable. Plant engineering and operating
staff recognized that scheduling a unit startup prior to repairing a known problem with a
SW pump war potentially inappropriate, and initiated CR 98-0296 on January 26,1998, to
document this conclusion. Plant management recognized the significance of this issue,
and required a root cause evaluation and establishment of effective corrective actions
and lessons-learned.
The inspectors considered the decision, in November 1997, to postpone repair of P-32A
until two units were operating to have been non-conservstive, but considered the
licensee's January 1998 documentation and follow-up to this issue to have been
appropriate.
Performance of Work and Procedure Adeauacy
Work Order (WO) 9711936001 provided authorization for performance of the P-32A
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replacement. This work order was supported by three " Work Plans," one each for
mechanical work, electrical work, and pump balancing. Work started on January 28,
1998. The P-32A discharge check valve, SW 32A, was opened and inspected using a
routine maintenance procedure while the pump was out-of-service. The inspectors
considered the overall knowledge and performance of the mechanics involved in the
P-32A and SW-32A work to have been good. The level of detail in the procedural steps
of the SW 32A procedure and P-32A work plans was adequate. The inspectors identified
severalissues associated with use of the P-32A work plans. These issues were
discussed with plant management and are described below.
Desian Control and Condition Reportina: The replacement pump was fitted with an inlet
basket strainer with two-inch by two-inch openings, but the openings on the removed
pump's inlet basket strainer were only one-inch by one-inch. The mechanics and
component engineer involved with pump replacement had not documented this
discrepancy on a CR or within the WO work plan. The work plan did not contain any
descriptive information for the strainer, so it was not readily apparent which strainer size
was correct. The inspectors obtained and reviewed the controlled vendor drawing for the
SW pumps, and determined that it did not contain sufficient detail to determine which, if
either, strainer was correct. After the inspectors identified this issue, the licensee
initiated CR 98-0357 to document the difference in strainers. The licensee determined
that Spare Parts Equivalency Evaluation Document 96-050 supported use of the
replacement strainer. The licensee canceled Technical Evaluation 92-64, Revision 1,
under which the strainer with one-inch by one-inch openings had been purchased. The
inspectors also noted during the reassembly of the pump that two shims were installed to
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eliminate axial misalignment between the pump and pump motor. However, the location
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and size of these shims were not recorded in the work package. The absence of this
information from the design record could affect future out-of service durations for the
Pump.
Control of Procedures: The inspectors noted that the WO work plans for the P-32A
replacement were not marked as controlled documents and were not provided with
revision numbers. The inspectors also identified that the date on each WO work plan
page indicated when it was printed, not when the document was developed or revised.
,
Control and Trackina of Material: The inspectors noted that the WO package did not
include any drawings depicting what the replacement pump assembly should look like,
what all the parts of the pump were, and where all replacement parts should be used.
There was a comprehensive bill of material at the job site, but it was not controlled as
part of the WO or as part of any other controlled system. The WO work plans did contain
complete lists of replacement parts, but these lists referenced material control numbers
which, in some cases, could not be readily traced to the parts being used. The
inspectors also noted that mechanics were not specifically documenting that items
obtained for the job were actually being used in the replacement of the pump. The
inspectors noted that the use of multiple, and not completely cross-referenced, material
identification records created a human factors problem for an independent party or
supervisor trying to certify the completion of work. The inspectors observed that the lack
of detail in the work package documentation was being compensated for by the direct
involvement of the component engineer in the maintenance activity. This engineer was
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providing information to the mechanics regarding the fit-up and assembly of the pump.
While the inspectors considered the engineer's knowledge level and level of involvement
to be positive, the lack of formality in controlling the pump design basis (materials and
configuration) was a concem. The licensee responded to the inspectors' concerns by
performing maintenance department and quality assurance reviews of the P-32A
replacement and a sampling of other WO work plan safety-related maintenance activities.
No operability issues were identified during these reviews, but CRs 98-0344,-0348,
-0359, -0361, -0391, -0396, -0453, -0456, -0467, -0506, and -0524 were written to
identify examples of concerns with the adequacy of WO work plan instructions and
material control issues. All identified items were being addressed through the licensee's
corrective action program. The inspectors determined that no significant regulatory
concerns were contained in these CRs.
The inspectors discussed the above concerns with licensee management. Management
acknowledged that the replacement of the safety-related service water pump should have
been performed using a procedure, based upon the procedural requirements of NP 1.2.2,
" Technical, Procedure Classification, Review, and Approval," Revision 3. The licensee
believed that use of a procedure would have addressed many of the inspectors concerns.
The use of a work instruction which did not provide current drawings to support use of a
revised pump configuration, did not include a comprehensive list of materials for
assembling the replacement and reused pump components, and did not provide for
positive identification of the nuclear quality grade components actually used in the final
pump assembly was a violation (VIO 50-206/98003-06(DRP); 50-301/98003-06(DRP)) of
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10 CFR Part 50, Appendix B, Criterion V," Instructions, Procedures, and Drawings."
The licensee initiated a formal root cause evaluation of the material controlissues
identified by the inspectors and by the subsequent quality assurance assessments. A
month after the issues of work package content and material controls were identified, the
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inspectors reviewed the status of corrective actions for the CRs listed above and
identified that no immediate corrective actions were documented. This was of concem
because a refueling outage and other safety-related activities, such as a major
maintenance outage for the G-01 emergency diesel generator, were underway. This
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concem was discussed with maintenance department management, who indicated that
initial communications to maintenance staff had been made, but that follow-up actions to
ensure these communications had been effective were also appropriate.
)
Surveillance Testina and Technical Evaluations
The inspectors observed testing associated with Inservice Test Procedure (IT) 07A,
IT 078, and IT 07C. These tests were specified as post-maintenance testing for the
replacement of Service Water Pump P-32A and the repair of discharge Check
Valve SW-32A. The inspectors reviewed the three ITs and did not identify any significant
issues. The test results for IT 07A were satisfactory, but the flows for P-32B and P-32C,
,
!
when measured by IT 07B and IT 07C, respectively, were out-of-tolerance on the high
side. The licensee completed operability determinations (ODs) for these failed test
,
results and attributed the indicated high flows to improvements in the performance of
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SW-32A (less back leakage with P-32A secured). The inspectors reviewed CRs 98-0349,
98-0350,98-0362, and 98-0457, which documented the failed tests and the SW-32A
improvements. The inspectors considered the licensee ODs to be technically accurate,
but lacking in support information. The inspectors had to obtain additional information on
the service water hydraulic model and the inservice test requirements for the valves in
order to independently confirm the conclusions reached by the licensee staff,
c.
Conclusions
A safety-related SW pump was replaced without adequate documentation in the work
package. The inspectors were also concerned by aspects of the material control
practices used. An effective licensee follow-up assessment of the inspectors' concems
identified the need for some broad improvements in the control of nuclear grade parts
and material. Programmatic corrective actions were planned at the end of the period;
however, short-term corrective actions did not receive the appropriate level of attention
and follow-up. A violation was identified for an inadequate work instruction that failed to
provide appropriate material controls.
M8
Miscellaneous Maintenance issues
M8.1 (Closed) LER 50-266/98-006-00: Unanticipated Partial SW System isolation During A
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Special Test. This item is discussed in Section M1.1 of this inspection report.
Ill. Enaineen'n2
E1
Conduct of Engineering
E1.1 ' identification of Desion Basis issues and Nonconformances
The inspectors observed that plant staff, ir4cluding the design engineering group,
continued to identify design basis issues. These issues were entered into the
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corrective action program in a prompt manner, and plant management evaluated and
responded to each in an appropriate fashion.
E2
Engineering Support of Facilities and Equipment
E2.1
Unit 2 RCP Seal Return Flow Indication Spikina
a.
Inspection Scope (IPs 71707 and IP 37551)
The inspectors reviewed the circumstances surrounding the cause of a frequent main
control room annunciator alarm for Unit 2 "A" RCP seal water flow.
b.
Observations and Findinas
During main control room observations, the inspectors noted that the " Unit 2 'A' RCP seal
l
water flow low /high" alarm frequently activated and then cleared immediately. The
relevant chart recorder indicated a spike (low) of about one second in duration followed
by flow retuming to normal. On one occasion, the inspectors observed this alarm
activate as many as 10 times in a 25-minute period. Based upon the observed operator
response, the inspectors concluded that this alarm had become a distraction to the
operators in the control room.
The inspectors held a meeting with engineering supervision and staff to learn what efforts
had been taken to identify and correct the cause of the frequent alarm. Reactor and
systems engineering staff provided the inspectors with several potential scenarios that
could cause the detected flow spike and initiate an alarm. The staff also told the
inspectors that the manufacturer of the RCP seals believed the problem was in the
instrumentation (not a physical problem with the seals). Based upon this assessment,
attempts had been made to adjust instrumentation dampening circuits to eliminate the
alarm, but this had not been effective.
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During the course of the meeting, it became clear to the inspectors that the resolution
'
management of the problem was not well controlled and no one had been assigned
single-point responsibility for the matter. It was also evident that the involved engineers
were not sensitive to the distraction created in the control room by the frequent alarm.
Engineering supervision indicated that an " owner" for the issue would be assigned and a
responsible supervisor would monitor the resolution of the issue. The inspectors were
,
told that operations department managers had discussed the repetitive alarm with
engineering department managers on several occasions, but had not been demanding
enough to ensure an adequate engineering response.
During continued follow-up of this issue, the inspectors noted that a midnight control room
shift had disabled the annunciator in question. When questioned about the disabling of
the alarm, control room supervisors and control operators indicated that the decision was
j
made because the alarm had became a nuisance and was a distraction from on-going
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Unit 1 activities. The inspectors noticed that subsequent control room crews placed the
annunciator back in-service. A review by the inspectors revealed that no formal program
existed for disabling control room annunciators or tracking their status. Compensatory
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measures were informally discussed by operations supervisors and control operators
prior to disabling the annunciator. The alarms were logged in the unit specific logbook as
being out-of-service. Operations management acknowledged that they were aware that
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no formal program existed. Following a discussion between the inspectors and the
operations manager, interim guidance was provided to the operating crews to define
expectations for disabling annunciators.
Toward the end of the inspection period, the gas stripper system was retumed to service
l
and the alarm spiking no longer occurred. The technical explanation of the effect the gas
stripper had on the RCP seal flow had not been determined.
c.
Conclusions
The inspectors concluded that reactor engineering department actions to resolve a
repetitive RCP sealleak-off alarm were not prompt or coordinated well. The lack of a
prompt, coordinated response resulted in a long-standing distraction to operators in the
control room. The inspectors also noted that no formal mechanism existed to disable
control room annunciators or return them to service.
E3
Engineering Procedures and Documentation
E3.1
Use of Enaineerina Evaluations Versus Operability Determinations Followina 1SI-850
Valve Testina
a.
Inspection Scope (IP 37551)
The inspectors reviewed the licensap's use of engineering evaluations to determine
operability following inservice testing (IS
f safety system pumps and valves.
b.
Observations and Findinos
On January 16,1998, the licensee conducted routine quarterly IST of the Unit 1 safety
injection recirculation sump valves. Following the performance of the Train A valve
(1SI-850A) test, it was noted that the times to open the valves were slower than the
specified acceptance criteria. The operations supervisor declared the valve out-of-
service, and requested an engineering evaluation be performed to address the issue.
The evaluation was subsequently performed, and the valve was declared back-in-service.
The inspectors observed the valve being retumed to service. The inspectors questioned
why an engineering evaluation had been performed when the basis statement of
TS 15.4.2.8 stated that operability determinations were used for failures to meet IST
acceptance criteria. The control room supervisors indicated that the use of an
engineering evaluation had been the acceptable past practice for such situations. The
inspectors discussed this issue with engineering departmental management, who agreed
that an operability determination should have been used. An operability determination
!
was then performed, and the valve was placed back-in-service prior to exceeding the TS
allowed outage time.
I
The inspectors noted that the use of an engineering evaluation for the return-to-service of
components following inservice tests had been a routine practice in the past. Following
this occurrence, the engineering manager issued an electronic memorandum to all
engineering department staff to alert them to the proper method of dispositioning
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acceptance criteria discrepancies. The memorandum stated that a condition report would
be written and an operability determination would be developed when equipment failed to
meet IST acceptance critena.
The inspectors also noted that recent revisions to operability determination procedure
(NP 5.3.7) did not succinctly state this current management expectation. This was
discussed with the IST coordinating engineer, who subsequently revised the procedure to
more clearly discuss the proper use of engineering evaluations and operability
determinations following IST surveillances.
c.
Conclusions
The inspectors identified a potentially inappropriate practice of using engineering
evaluations to disposition failures to satisfy IST acceptance criteria. Engineering
management responded promptly to this observation by issuing an informal clarification of
the expectation for using the CR and operability determination systems. After additional
inspector involvement, the appropriate procedures were also modified to more clearly
discuss this expectation.
E8
Miscellaneous Engineering issues
E8.1
(Closed) Unresolved item (URI) 50-266/97006-06(DRP): 50-301/97006-06(DRP):
Adequacy of Twice Per Shift Fire Rounds for Degraded 10 CFR Part 50, Appendix R,
Areas. The inspectors reviewed the licensee's current licensing basis for
10 CFR Part 50, Appendix R, programs. The licensee's Fire Protection Evaluation Report
detailed the compensatory actions to be taken for various fire condition action levels and
referenced safe shutdown areas. The compensatory measures to be taken when areas
are degraded was defined in OM 3.27," Control of Fire Protection and Appendix R Safe
Shutdown Equipment," Revision 6. The twice por shift fire rounds were outlined in this
procedure. The inspectors determined that the licensee was implementing the fire
rounds in accordance with the current licensing basis. The inspectors also noted that the
licensee had revisited this issue in response to NRC Information Notice 97-048,
" inadequate or inappropriate Interim Fire Protection Compensatory Measures." The
inspectors had no further concerns regarding this matter.
E8.2
(Closed) URI 50-266/96012-08(DRP): 50-301/96012-08(DRP): Pressurizer Safety Valve
Setpoint Too High. This item was updated in Inspection Report 50-266/97020(DRP);
50-301/97020(DRP), Section E8.1. That update stated that the corrective actions, tests
reports, and installation of Unit 2 safety valves were adequate. However, the inspectors
had remaining questions regarding Unit 1 valves. The two questions involved the
completeness of the original operability determination in addressing temperature changes
and their effect on Unit 1 valves, and setpoint drift and its impact. The update also
identified that the event which was reported under 10 CFR 50.72 requirements but was
not followed up with a written LER. The LER (50-266/96-014) was subsequently
submitted on October 24,1997.
Following a discussion with the inspectors at the time of the aforementioned inspection
report, the licensee conducted further evaluations of the Unit 1 safety valves and
amended the original operability determination. The results of the analysis indicated that
at lower ambient temperatures the valve lift point would increase by 2.01 percent
.
(2542.1 pounds per square inch gauge). This was within the ASME Section XI limit of
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103 percent of the nameplate (2559.6 pounds per square inch). Analysis of the setpoint
drift effects resulted in a minimal increase in the lift setpoint over a 36-month period
(frequency of valve testing).
The initiating condition associated with this issue was an inappropriate test temperature
used in testing safety-related components. This nonrepetitive, licensee-identified and
corrected violation is being treated as a non-cited violation (NCV 50-266/98003-07(DRP);
50-301/98003-07(DRP)) of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control,"
consistent with Section Vll.B.1 of the NRC Enforcement Policy.
E8.3
(Closed) LER 50-266/96-014: Pressurizer Safety Valve Lift Setpoint Out of Tolerance
Due to Temperature Effects. This item is discussed in Section E8.2 above.
E8.4
(Closed) URI 50-266/95004-05(DRP): 50-301/95004-05(DRP): Adequacy of Design
Modification. This item dealt with the quality of engineering work associated with a
design modification implemented in 1994. The modification was subsequently removed
when the licensee determined that it was ineffective. The inspectors determined that the
design work associated with this modification was not of a high quality, but concluded that
further review of this issue served no purpose since the quality of engineering work has
been the subject of significant er.forcement actions subsequent to the 1995 identification
of this issue.
IV. Plant Support
R1
Radiological Protection and Chemistry (RP&C) Controls
R1.1
General Comments
NRC Inspection Procedure 71750 was used in the performance of an inspection of the
plant support area. In general, the inspectors found the auxiliary building to be
appropriately posted and controlled for radiological hazards. Workers within the auxiliary
building were observed wearing required dosimeters and following good radiation worker
practices. However, the inspectors had concerns regarding the performance of the
health physics organization during refueling operations. These observations are
contained in Sections 01.4 and M1.2 of this report.
V. Management Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on March 5,1998. The licensee acknowledged the findings
presented. The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
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Wisconsin Electric Power Company
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S. A. Patuiski, Site Vice President
- A. J. Cayia, Plant Manager
M. E. Reddemann, Quality Assurance Manager
R. G. Mende, Operations Manager
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W. B. Fromm, Maintenance Manager
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J, G. Schwaitzer, Site Engineering Manager
R. P. Farrell, 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, and Preventing
Problems
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IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observations
!
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 92901:
Follow-up of Operations issues
IP 92903:
Follow-up of Engineering issues
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-266/98003-01(DRP)
Inadequate Oil Collection System
50-301/98003-01(DRP)
50-266/98003-02a(DRP)
Inadequate Thermal Power Procedure
50-301/98003-02a(DRP)
50-266/98003-02b(DRP)
Inadequate Thermal Power Procedure
50-301/98003-02b(DRP)
j
50-301/98003-03(DRP)
Operating Permit Procedure Violation
50-266/98003-04(DRP)
50-266/98003-05(DRP)
Inadequate Test Procedure
50-301/98003-05(DRP)
50-266/98003-06(DRP)
Inadequate Maintenance Procedure for P-32A
50-301/98003-06(DRP)
50-266/98003-07(DRP)
inadequate Test Controls
50-301/98003-07(DRP)
Closed
50-266/99005
LER
Missed Control Rod Surveillance
50-266/96018-03(DRP)
Routine Operation at 100.2 Percent Power
50-301/96018-03(DRP)
50-266/98006
LER
Service Water isolation During Special Test
50-266/97006-06(DRP)
Adequacy of Fire Rounds
50-301/97006-06(DRP)
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ITEMS OPENED, CLOSED, AND DISCUSSED (Continued)
Closed (Continued)
50-266/96012-08(DRP)
Pressurizer Safety Valve Setpoints
50-301/96012-08(DRP)
50-266/96014
LER
Pressurizer Safety Valve Setpoints
50-266/95004-05(DRP)
Adequacy of Design Modi'ication
50-301/95004-05(DRP)
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LIST OF ACRONYMS USED IN POINT BEACH REPORTS
i
Alternating Current
Auxiliary Operator
American Society of Mechanical Engineers
CFR
Code of Federal Regulations
Current Licensing Basis
CR
Condition Report
Division of Reactor Projects
Duty Shift Superintendent
Engineered Safety Feature
Emergency Planning
Final Safety Analysis Report
l&C
instrument and Control
IFl
inspection Follow-up item
IP
inspection Procedure
Individual Plant Evaluation
IR
Inspection Report
Inservice Testing
In-service Test Procedure
LCO
Limiting Condition for Operation
LER
Licensee Event Report
LOCS
Lube Oil Collection System
MWt
Megawatt Thermal
Non-Cited Violation
NP
Nuclear Power Department Procedure
NRC
Nuclear Regulatory Commission
01
Operating Instruction
Operations Manual
Out-of-Service
OP
Operating Procedure
ORT
Operations Refueling Test
OS
Operating Supervisor
Post-accident Sampling System
PBTP
Point Beach Test Procedure
Public Document Room
OA
Quality Assurance
Reactor Coolant Pump
REI
Reactor Engineering Instruction
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Routine Maintenance Procedure
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Radiation Protection
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Refueling Water Storage Tank
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1
Safety Evaluation Report
Spent Fuel Pool
SW.
Turbine Driven Auxiliary Feedwater
Thermoluminescent Dosimeter
TS
Technical Specification
TS
Technical Specification Test
Unresolved item
- VIO
Violation .
VNCR
Control Room Ventilation
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