ML20236V662
| ML20236V662 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 07/29/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20236V649 | List: |
| References | |
| 50-266-98-11, 50-301-98-11, NUDOCS 9808040118 | |
| Download: ML20236V662 (24) | |
See also: IR 05000266/1998011
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 111
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Docket Nos:
50-266; 50-301
Licenses Nos:
Report No:
50-266/98011(DRP); 50-301/98011(DRP)
Licensee:
Wisconsin Electric Power Company
Facility:
Point Beach Nuclear Plant, Units 1 & 2
Location:
6612 Nuclear Road
Two Rivers, WI 54241-9516
Dates:
May 26 through July 6,1998
Inspectors:
P. Louden, Resident inspector
P. Simpson, Resident inspector
M. Kunowski, Project Engineer
Approved by:
J. W. McCormick-Barger, Chief
Reactor Projects Branch 7
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EXECUTIVE SUMMARY
Point Beach Nuclear Plant, Units 1 & 2
NRC Inspection Report 50-266/98011(DRP); 50-301/98011(DRP)
This inspection included aspects of licensee n erations, engineering, maintenance, and plant
support. The report covers a 6-week inspect.on period by the resident inspectors.
Operations
Control room operators and supervisors demonstrated a safety-focused and conservative
approach to the Unit 1 reactor startup. Briefings for infrequently performed tests or
evolutions were good to outstanding, and reactor operator performance during the
approach to criticality was good with consistent three-way communications and constU
control board monitorir.g and attentiveness evident. Operators had to contend with
unnecessary challenges from secondary system components which distracted their
attention and complicated their efforts during the Unit 1 startup. (Section 01.1)
Unit 1 fuel movements were performed in a careful and deliberate manner and
distractions for fuel handling personnel from concurent activities in the containment were
kept to a minimum. (Section 01.2)
The licensee had not effectively implemented a recently developed defense-in-depth,
system maintenance planning matrix. This did not constitute a violation of NRC
requirements; however, it represented a deficiency within the production planning group.
(Section O3.1)
The inspectors discussed with station management deficiencies with scheduling an
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emergency diesel generator post-maintenance test involving the potential inappropriate
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entry into limiting conditions for opeinion for the Unit 1 Train "A" residual heat removal
system. Upon further review of this issue by station management, the testing was
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rescheduled to allow for correct plant conditions to be established for performing the test.
(Section O3.2)
A valve mispositioning event was the result of operator error in recalling the specific valve
required to be closed. The licensee identified the error and aggressively took actions to
evaluate and correct the problem. (Section 04.1)
Maintenance
Engineering personnel provided good support to the maintenance personnelinvolved in
the troubleshooting, repair, and testing of a Unit 1 "A" main steam line snubber.
Maintenance personnel adhered to applicable procedures during the repair work.
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Appropriate controls existed for foreign material exclusion and use of replacement parts.
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(Section M1.2)
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The installation of the Unit i reactor vessel head was conducted in a safe manner.
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However, a job supervisor's understanding of the requirements of Nuclear Business Unit
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Procedure 1.1.4," Procedure Use and Adherence," regarding procedural adherence was
inaccurate. (Section M1.3)
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The licensee identified and effectively corrected a problem regarding the failure to
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maintain the environmental qualification status of the containment hydrogen monitors for
both Units 1 and 2. A Non-Cited Violation was identified involving the failure to provide
an adequate procedure to maintain the EQ status of a safety-related component.
(Section M3.1)
Enaineerina
The licensee identified a calculational error in the service water system hydraulic flow
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model and subsequently implemented adequate interim administrative operational
restrictions as corrective actions. Licensee management committed to submit a
Technical Specification change request no later than July 31,1998, to address the error
in the long-term. (Section E2.1)
The licensee's procedures used during reactor startups and the approach to criticality
contained deficiencies which reflected a non-conservative approach to reactivity
management since the procedures did not incorporate well-established industry guidance
for criticality estimations when using boron dilution to achieve criticality. (Section E3.1)
A recently completed quality assurance audit of design engineering activities contained
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additional examples of previously identified concerns with the design engineering
organization. The inspectors concluded that, overall, the audit was probing and thorough
and appropriately identified design engineering deficiencies. (Section E7.1)
Plant Support
Radiological postings accurately depicted the radiological conditions in areas inspected.
Most areas were maintained free of contamination or kept to a very low contamination
level, allowing for access to areas by operators and providing good working environments
for the general outage workforce. (Section R1.1)
Health physics and emergency preparedness staff appropriately responded during a
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contaminated injured worker drill. The responding medical staff maintained a clear focus
on the health and safety of the " victim" that was not overridden by minor radiological
control concems. (Section P1.1)
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Repod Details
Summary of Plant Status
During this inspection period, Unit 2 operated at approximately 100 percent rated thermal power
and Unit 1 completed a scheduled refueling outage which began on February 14,1998. Unit 1
was made critical on June 27,1998, at 10:25 p.m. and was placed on line on June 30,1998,
at 12:26 p.m.
1. Operations
01
Conduct of Operations
01.1
Unit 1 Reactor Startup
a.
Inspection Scope (Inspection Procedures (IPs) 71707 and 71711)
The inspectors observed operations activities for the Unit 1 startup from the Cycle 24
refueling outage. The activities included the approach to criticality and subsequent power
ascension. During this inspection, the inspectors reviewed the following documents:
Operations Manual (OM) 1.1, Revision 2, " Conduct of Plant Operations"
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Reactor Engineering Surveillance Procedure (RESP) 4.1, Revision 13, " Initial
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Criticality and All Rods Out (ARO) Physics Tests"
Operations Procedure (OP) 18, Revision 32, " Reactor Startup"
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OP 1C, Revision 65, " Low Power Operation To Normal Power Operation"
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b.
Observations and Findinas
On June 27,1998, at 10:25 p.m., the Unit i reactor was made critical following the
Cycle 24 refueling outage. The inspectors observed operations activities from the
approach to criticality through power ascension to 20 percent rated thermal power.
The inspectors observed several briefings for licensee-categorized, infrequently
performed tests or evolutions. These briefings ranged in quality from generally good to
outstanding. The outstanding briefing, by a senior operations manager, contained a
review of procedural notes with an emphasis on precautions and limitations,
communication standards, roles and responsibilities of personnel, industry events and
contingency actions. In addition, during the approach to criticality briefing conducted by
reactor engineering personnel, the operations shift crew displayed an excellent
questioning attitude (see Section E3.1).
Reactor operator (RO) performance during the approach to criticality was good as
illustrated by consistent three-way communications and constant control board monitoring
and attentiveness. Command and control was generally good as reactivity changes and
startup activities were directed by a senior reactor operator (SRO) specifically dedicated
to Unit 1. Previous inspector-observed command and control weaknesses, documented
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in inspection Reports (irs) 50-266/97016(DRP); 50-301/97016(DRP) and
50-266/97020(DRP); 50-301/97020(DRP), such as a reactor engineer inappropriately
directing reactivity changes, were not evident during this reactor startup.
Several times during the Unit 1 startup, operators were challenged or startup activities
were delayed by problems with secondary system components. The "A" condensate
pump had to be removed from service when its lower motor bearing temperature
exceeded pump operating limits. The "A" feedwater pump was tagged-out because of
lube oil and casing leaks. The main generator disconnect indicator displayed an
intermediate position when the disconnect was actually closed. This later prot ed to be a
position limit switch problem. The "A" motor-driven auxiliary feedwater (AFW) pump
developed a leak in its minimum flow recirculation line. This resulted in the "A" motor-
driven AFW pump being declared inoperable. The main turbine had to be removed from
the tuming gear periodically to clean shaft lift pump oil filters because no replacement
filters were available. These equipment problems did not meet the operators
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expectations of what the plant material condition should be for a unit which had just
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completed a refueling outage.
c.
Conclusions
Control room operators and supervisors demonstrated a safety-focused and conservative
approach to the Unit 1 reactor startup. Briefings for infrequently performed tests or
evolutions were good to outstanding, and reactor operator performance during the
approach to criticality was good with consistent three-way communications and constant
control board monitoring and attentiveness evident. Operators had to contend with
unnecessary challenges from secondary system components which distracted their
attention and complicated their efforts during the Unit 1 startup.
01.2 Conduct of Unit 1 Fuel Reloadina Operations (IP 71707)
The inspectors observed Unit 1 fuel reloading activities. The inspectors noted that the
fuel movements were well-coordinated among personnelin the Unit 1 containment, at the
spent fuel pool, and in the control room. The SROs involved displayed good command
and control of the activities. Previously identified inspector concerns regarding
distractions during fuel handling operations (IR 50-266/98003(DRP);
50-301/98003(DRP), Section 01.4) did not recur. The fuel movements were performed in
a careful and deliberate manner, and distractions for fuel handling personnel from
concurrent activities in the containment were kept to a minimum.
O3
Operations Procedures and Documentation
O3.1
Defense-in-Depth Matrix Use Deficiencies
a.
Inspection Scope (IP 71707)
The inspectors reviewed the use and operator understanding of a recently developed
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equipment out-of-service matrix for safeguards, non-Technical Specification (T/S), and
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non-emergency safety features equipment.
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b.
Observations and Findinas
During a tour of the control room, the inspectors observed a " Defense-in-Depth" matrix
status board hanging on the control room wall. The inspectors noted that the matrix
contained cross-train maintenance references for safety-related, non-T/S plant
equipment. The notes section of the matrix also provided information regarding
out-of-service combinations which should be avoided. One of the notes stated that
" planned maintenance of the gas turbine shall not be undertaken if any of the emergency
diesel generators (EDGs) are out-of-service."
Plant conditions at the time consisted of the gas turbine generator (G05) being
out-of-service for maintenance and the Unit 1 Train "A" EDG being out-of-service for an
overhaul. The inspectors asked the control room supervisors about the current
configuration in reference to the statement on the matrix. Two of the supervisors were
not familiar with the matrix, and a third was aware that it had been developed but did not
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know its purpose. A condition report (CR) (98-2119) was subsequently generated
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regarding the EDG and gas turbine configuration. Based on a follow-up review of the
configuration, the licensee determined that no T/S had been violated and that the specific
note referenced was directed at dual-unit operations.
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The inspectors discussed this matter with the supervisor of the production planning group
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(PPG) whose organization was responsible for the implementation of the matrix. The
inspectors' concerns focused on the control room supervisors' lack of familiarity with the
matrix. If the matrix was not be,. $g used, it created a possible distraction in the control
room.
The PPG supervisor stated that the new Defense-in-Depth matrix had not been effectively
implemented and that operations department personnel had not received training on the
new matrix. Corrective actions to be taken in response to CR 98-2119 included training
operators and PPG work-week m nagers on the use of the Defense-in-Depth matrix.
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c.
Conclusions
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The inspectors concluded that the licensee had not effectively implemented a recently
developed defense-in-depth, system maintenance planning matrix. This did not
constitute a violation of NRC requirements; however, it represented a deficiersey within
the PPG.
03.2 Unit 2 Train "A" EDG Test Problems
a.
Inspection Scope (IP 71707)
The inspectors reviewed a planned EDG test and evaluated the appropriateness of the
licensee entering certain T/S limiting conditions for operation (LCOs) during the test.
Observations and Findinas
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On June 5,1998, while reviewing Point Beach Test Procedure (PBTP) 091, " Transient
Response of G02 Governor Following Maintenance Activity," Revision 0, a test to be
performed a few days later, the inspectors noted that the test required declaring the
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Unit 1 Train "A" residual heat removal (RHR) system out-of-sarvice. During a discussion
of the test with an RO, the inspectors questioned the planned Unit 1 decay heat removal
(DHR) configurations for the test. The RO indicated that he had raised the question
about the configuration at an earlier shift briefing but was informed that the condition was
allowable by T/S.
Based on the inspectors' understanding regarding the nature of the EDG test, it did not
appear that the testing fell under the surveillance aspects of T/S 15.3.1.A.3.b.4, which
states that when reactor coolant temperature is less than 140 Fahrenheit (F), one of the
two RHR loops may be temporarily out-of-service to meet surveillance requirements. The
inspectors discussed this matter with a senior stction manager who indicated that he
would look into the matter further.
On June 6,1998, the operations manager and the plant manager informed the inspectors
that their reviews of the matter resulted in the determination that the intent of the T/S was
to allow for required surveillance as discussed in T/S Section 15.4. The T/S was not
appropriate for use when performing post-maintenance testing. As a result, PBTP 091
was re-scheduled and performed at a later time in the outage when the steam generators
were available for DHR. This alleviated the concern with the out-of-service configuration
of the Unit 1 Train "A" RHR system.
c.
Conclusions
The inspectors identified deficiencies with scheduling an EDG post-mainteriance test
involving the potential inappropriate entry into LCOs for the Unit 1 Train "A" RHR system.
Upon further review of this issue by station management, the testing was rescheduled to
a point in the outage when plant conditions would be appropriate.
04
Operator Knowledge and Performance
04.1 Valve Mispositionino Event Durino Safety iniection (SI) Check Valve Testino
a.
Inspection Scope (IP 71707)
The inspectors reviewed the circumstances and operator responses surrounding a valve
mispositioning event which occurred during SI system check valve testing.
b.
Observations and Findinos
On June 16,1998, the operations department conducted a routine surveillance test to
determine the Unit 1 SI system check valve leak rates as required by T/S 15.4.16. Unit 1
status at the time of the test was: reactor coolant system (RCS) temperature at
approximately 160"F, RCS pressure at approximately 340 pounds per square inch gauge
(psig), the "A" reactor coolant pump in operation, and the Train "A" RHR system in
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operation in the normal DHR mode.
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The operators in the control room and in the primary auxiliary building were in the process
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of aligning the Train "B" RHR system for the check valve testing. During the performance
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of Step 4.8.2 of Technical Specification Test Procedure (TS) 30, "High and Low Head
Safety injection Check Valve Leakage Test," Revision 17, an in-plant operator, after
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reviewing the required valve position and verifications for the step, entered a
contaminated area to perform the tasks. The first valve manipulation required was to
shut the 1RH704B RHR *B" pump suction valve; however, the operator began to close
the 1RH704A RHR *A" pump suction valve. The operator heard unexpected flow
turbulence with the valve about three-quatters of the way shut and reverified with an
assisting operator, who was standing outside the contaminated area, which valve was to
be closed. The assisting operator stated that 1RH704B was the valse to be shut, and the
first operator immediately re-opened the 1RH704A valve.
During this time, the Unit 1 RO received a Train "A" RHR low flow alarm in the control
room, noted the decreasing flow, and took action to restore RHR flow and control RCS
pressure which had started to increase. Approximately 30 seconds later, RHR flow had
been restored and the RO subsequently stabilized the primary system. Operators noted
that the Train "A" flow had decreased from 1500 gallons per minute to approximately
220 gallons per minute during the valve closing. The highest RCS pressure observed
was approximately 370 psig which was below the low temperature over-pressure
protection system set point of 415 psig.
Control room supervision suspended the test while the event was investigated. The
momentary reduction in RHR Train "A" system fie v brought into question the operability of
the "A" RHR pump. An operability determination (OD) was requested to evaluate any
possible pump degradation as a result of the event. The OD concluded that the
"A" RHR pump remained operable because the lowest flow rate encountered was above
the vendor specification for minimum flow for the pump.
Based on interviews and other data evaluated by operations department corrective
actions personnel, the root cause of the event was determined to be operator error. The
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operator had read the step which called for the appropriate valve to be manipulated;
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however, the operator closed the opposite train valve. The two valves were physically
located next to each other. The licensee determined that contributing factors for the
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event involved the failure to maintain good repeat-back communications when executing
procedure steps and the failure to maintain a " continuous use" procedure "in hand" within
a contaminated area,
Corrective actions included re-emphasizing self-checking, clear repeat-back
communications, and the need for individuals working with a " continuous use" procedure
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to maintain an "in hand" copy regardless of the location of the work activity.
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The inspectors noted that the manipulation of the wrong RHR system valve involved a
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failure to follow prescribed procedures and was considered a violation of 10 CFR Part 50,
Appendix B, Criterion V, " Instructions, Procedures, and Drawings." However, this
non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited
Violation (NCV), consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV-50-266/98011-01(DRP)).
c.
Conclusion
The inspectors concluded that the valve mispositioning was the result of operator error in
recalling the specific valve required to be closed. The inspectors determined that the
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licensee had identified the error and aggressively took actions to evaluate and correct the
problem. The resultant violation was considered an NCV.
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06
Operations Organization and Administration
06.1 Operations Department Organizational Chanoes
On June 25,1998, the licensee announced that one of the current assistant operations
superintendents would assume a new position in the engineering department. The new
assistant operations superintendent was selected from the existing duty shift
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superintendent (DSS) pool, that is, the pool of second-line supervisory SROs. The
vacancy in the DSS pool would be filled by a current duty operations supervisor, a
first-line supervisory SRO. These changes were scheduled to be effective in
mid-July 1998. The inspectors did not identify any obvious negative impact on the
operations department as a result of the changes.
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Miscellaneous Operations issues
08.1 (Closed) Violation (VIO) 50-266/96007-01(DRP): 50-301/96007-01(DRP): This violation
involved three examples of operators fainng to follow station procedures. Subsequently,
the licensee revised the subject procedures and re-emphasized standards for operator
conduct with the operations staff. Over the past year, NRC inspectors have reviewed the
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implementation of these standards, described in Operations Manual (OM) 1.1, " Conduct
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of Operations." Based on the results of this review, the inspectors concluded that
operator performance, including procedure adherence, has significantly improved (for
example, see irs 50-266/97006(DRP); 50-301/97006(DRP),50-266/97010(DRS);
50-301/97010(DRS), 50-266/97020(DRP); 50-301/97020(DRP), 50-266/97023(DRS);
50-301/97023(DRS), and 50-266/97026(DRP); 50-301/97026(DRP)).
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08.2 (Closed) VIO 50-266/96007-02(DRP): 50-301/96007-02(DRP): This violation comprised
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three examples where procedures used by operators resulted in inadequate equipment
configuration control. The individual procedures were revised to correct the configuration
control errors and, as part of a larger effort to improve the quality of procedures, the
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licensee reviewed numerous station procedures and equipment lineup checklists to
ensure that proper equipment configuration control was maintained. Tnis broader-scope
corrective action, which was discussed in Section M8.1 of IR 50-266/98009(DRP);
50-301/98009(DRP), has been effective, overall, in reducing the number of configuration
control problems.
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08.3 (Closed) VIO 50-266/96008-01(DRP): 50-301/96008-01(DRP): This violation comprised
two examples of inadequate procedures orinstructions. In one example, reactor
engineering procedures allowed reactor power to reach 3.5 percent with only one reactor
coolant pump operating. This conflicted with T/S 15.3.5-2 and 15.3.5-4 for maintaining a
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minimum number of reactor coolant temperature channels operable during power
operations. The procedures were subsequently revised and T/S 15.3.1.A.1.a was also
revised to correct a similar conflict.
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The second example involved the failure to provide licensee personnel with adequate
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instructions for performing a weekly qualitative assessment of leakage from a temporary
patch on a section of service water (SW) system pipe. After the inspectors notified the
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licensee of the failure, adequate instructions were provided to personnel. The pipe was
subsequently repaired.
II. Maintenance
M1
Conduct of Maintenance
M1.1 Observed Tests and Surveillance UP 61726)
During this inspection period, the inspectors observed all or portions of the tests and
surveillance listed below. The inspectors observed that workers involved with the
activities were following the requirements in the appropriate procedures. Operators were
attentive to their responsibilities during the activities and system / test engineers were
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actively involved in the evolutions.
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PBTP 090," Transient Response Test of G01 Governor 1-ollowing Maintenance
Adjustment," Revision 0
PBTP 091, " Adjustment and Transient Load Response Test of G02 Governor."
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Revision 0
Operations Refueling Test (ORT) 38, " Safety injection Actuation with Loss of
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Engineered Safeguards AC [ alternating current)(Train B) Unit 1," Revision 29
ORT 4, * Main Turbine Mechanical Overspeed Trip Device Unit 1," Revision 11
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The inspectors also noted that the performance of the control room operators involved
with the PBTP 091 test was excellent. The control room operators displayed consistent
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questioning attitudes, discussed upcoming steps and plant responses among each other,
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and raised questions to the SRO in charge of the test.
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M1.2 Repair of "A" Steam Generator Main Steam Line Snubber 1HS-2
a.
Inspection Scope UP 62707)
The inspectors observed maintenance activities associated with the repair of Unit 1
steam generator "A" main steam header east snubber,1HS-2.
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b.
Observations and Findinas
During snubber inspections on June 23,1998, at 11:00 a.m. with the Unit 1 RCS greater
than 400 F, the licensee identified that the hydraulic fluid reservoir for the "A" side steam
generator snubbers was overflowing. The licensee initiated CR 98-2501 to document the
condition. The overflowing reservoir supplied hydraulic fluid to a total of five snubbers,
three on the "A" steam generator and two on the "A" main steam line. Engineering
personnei evaluated the condition and recommended that all five snubbers be declared
inoperable. Operations personnel declared all five snubbers inoperable on June 23,
1998, at 6:00 p.m. Technical Specification 15.3.13.2 requires the snubbers to be
restored to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or an orderly shutdown be initiated. The
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licensee initiated an around-the-clock effort to determine and correct the cause of the
problem.
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The licensee discovered during troubleshooting that snubber 1HS-2 was low on hydraulic
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fluid. Maintenance personnel removed 1HS-2 for as-found testing under the control of
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Work Order 9811536. Performance testing indicated that a problem existed with the
intemal control unit portion of the snubber. From inspection of the internal control unit by
maintenance and engineering personnel, the licensee identified that a check valve had
stuck shut. The stuck check valve caused fluid to be ported back to the hydraulic fluid
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reservoir rather than to the opposite side of the snubber cylinder whenever the snubber
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piston moved, thus resulting in the overflowing of the reservoir. The licensee did not
determine a definitive root cause for the stuck closed check valve because of insufficient
conclusive evidence. The snubber was eventually repaired and re-installed and post-
maintenance testing results were satisfactory. The snubbers were then declared
operCie on June 26,1998, at 4:43 a.m.
The inspectors concluded that engineering personnel's continuous involvement in the
evaluation and repair process was an illustration of good support to the maintenance
organization. During the troubleshooting and repair phases of the activity, the inspectors
noted that maintenance personnel appropriately followed procedures. Additionally, the
inspectors noted good foreign material exclusion and material control practices were
exercised during the initial disassembly as well as during reassembly of the snubber. The
inspectors also observed appropriate implementation of quality control hold points.
c.
Conclusions
The inspectors concluded that the testing and the repair work were performed in
accordance with approved procedures. Engineering personnel provided good support to
the maintenance personnelinvolved in the troubleshooting, repair, and testing of snubber
1HS-2. Appropriate controls existed for foreign material exclusion and use of
replacement parts.
M1.3 Reactor Vessel Head Installation Activities
a.
Inspection Scope (IP 61707)
The inspectors observed the installation of the Unit i reactor vessel head en
May 30,1998.
b.
Observations and Findinas
The inspectors attended the pre-job briefing conducted for the installation of the Unit 1
reactor vessel head. Mechanical maintenance personnel performed the work which was
directed by Routine Maintenance Procedure (RMP) 9096, " Reactor Vessel Head Removal
and Installation," Revision 16. The job supervisor thoroughly discussed the various
aspects of the evolution. The job foreman presented the position assignments to each
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worker ensuring that all personnelinvolved understood their responsibilities. A health
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physics (HP) supervisor reviewed radiological controls requirements and answered
questions from the workers.
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The inspectors determined that the pre-job briefing was conducted well, overall.
However, one topic of discussion did reveal some confusion regarding procedural
adherence requirements. During the course of the procedure review, the job supervisor
stated that if steps had to be performed out-of-sequence, Nuclear Business Unit
Procedure (NP) 1.1.4, " Procedure Use and Adherence," allowed a supervisor to alter
steps with no further action. Work crew personnel questioned this position given that the
procedure was a " continuous use" procedure. The job supervisor maintained that the NP
allowed for this discretionary supervisory action. The inspectors discussed this matter
with the job supervisor following the briefing.
The inspectors subsequently discussed the procedural adherence interpretation given by
the maintenance supervisor with the maintenance managei. The maintenance manager
indicated that the supervisor was mistaken and that he would immediately ensure that all
maintenance supervisors understood the intent of NP 1.1.4 regarding this matter.
Condition Report 98-2244 was written documenting the issue.
The inspectors have previously discussed procedural adherence issues and plant staff
misunderstanding of the intent of NP 1.1.4 in IR 50-266/98006(DRP);
50-301/98006(DRP), Section M1.2. A Notice of Violation (NOV) was issued regarding
this matter. The inspectors did not identify any procedural adherence violations during
vessel head installation; however, the job supervisor's understanding of NP 1.1.4
requirements was inaccurate.
The inspectors had no concerns regarding the actual conduct of the reac'or vessel head
movement. The evolution was conducted in a careful and safety-focused manner. All
individuals involved with the evolution were observed to be following good radiological
controls practices, and the crew leader provided clear direction to the work crew.
c.
Conclusions
The inspectors concluded that the installation of the Unit i reactor vessel head was
conducted in a safe manner. However, the job supervisor's understanding of the
requirements of NP 1.1.4 regarding procedural adherence was inaccurate.
M3
Maintenance Procedures and Documentation
M3.1 Containment Hydroaen Monitor Environmental Qualification Problems
a.
Inspection Scope OP 37751)
The inspectors reviewed the circumstances surrounding the licensee's identification that
the environmental qualification (ecd requirements for the Unit 1 and Unit 2 containment
hydrogen monitors had not been followed.
b.
Observations and findinos
During a review of the need to replace the existing containment hydrogen monitors,
engineering personnelidentified that the EQ standards for the hydrogen monitors had not
been maintained. The vendor manual for the monitors specified that whenever the
connections for the hydrogen sensors were disconnected and reconnected, the terminals
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were to be coated with an epoxy-type material to provide protection from the
environment. Other than records for initial installation, the licensee could not locate any
j
documents or records that indicated the coating had been applied following
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repair /cahbration activities,
j
Subsequently, all the hydrogen monitors for both Unit 1 and Unit 2 containments were
declared out-of-service at 1:16 p.m. on June 15,1998. A notification was made to the
NRC in accordance with 10 CFR Part 50.72(b)(2)(iii)(D) for the inoperable condition of a
safety system which prevented it from fulfilling its safety function of mitigating the
consequences of an accident. Technical Specification Table 15.3.5-5, item 10, requires
that a minimum of one hydrogen monitor be operable during power operations. Declaring
the monitors out-of-service placed Unit 2 in a 72-hour l_CO.
The licensee subsequently obtained an equivalent silicone coating material and applied
the silicone two days later. The procedure was also revised to include the vendor's
requirements for use of the coating. The licensee performed an OD to account for the
curing time of the silicone coating because the recommended curing time exceeding the
,
allowed outage time per T/S. The inspectors and technical specialists from the
I
NRC Office of Nuclear Reactor Regulation reviewed the OD and had no concerns.
The root cause of the failure to maintain the EQ of the hydrogen monitors was the
absence of a step from the routine maintenance procedure (RMP) 10.34, " Containment
Hydrogen Monitors," Revision 11, to apply the terminal coating tollowing repairs. The lack
of the terminal epoxy coating invalidated the EQ of the monitors. This non-repetitive,
licensee-identified and corrected violation of Criterion V, " Instructions, Procedures, and
Drawings," Appendix B,10 CFR Part 50, is considered an NCV (50-266/9801102(DRP);
50-301/98011-02(DRP)) consistent with Section Vll.B.1 of the NRC Enforcement Policy.
c.
Conclusions
The inspectors concluded that the licensee identified and effectively corrected a problem
regarding the failure to maintain EQ status of the containment hydrogen monitors for both
Units 1 and 2. A Non-Cited Violation was identified involving the failure to provide an
adequate procedure to maintain the EQ status of a safety-related component.
M8
Miscellaneous Maintenance issues
M8.1 (Closed) VIO 02073 from Enforcement Action (EA) 96-273: irs 50-266/96006(DRP):
50-301/96006(DRP) and 50-266/96007(DRP): 50-301/96007(DRP): This issue,
pertaining to frequently out of-calibration pressure gauges on the discharge line of the Si
pumps, was discussed in IR 50-266/96006(DRP); 50-301/96006(DRP) and considered
with other problems for escalated enforcement. On December 3,1996, an NOV was
issued for those problems (EA 96-273) and included, for the pressure gauges, a violation
(VIO 02073) of Criterion Xil, " Control of Measuring and Test Equipment," of Appendix B,
10 CFR Part 50. A civil penalty of $325,000 was imposed with the NOV. The licensee
committed to extensive corret,'ve actions in its response to the NOV in a letter dated
January 31,1997. For the pressure gauge issue, these actions included the replacement
of the local-readout analog gauges with more accurate and reliable remote
instrumentation. The licensee eventually installed Foxboro flow transmitters near the
pumps and digital flow indicators in the main control room. In addition, the licensee
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reestablished the tracking and trending of instrumentation and calibration equipment,
reemphasized with instrumentation and calibration personnel the use of the condition
reparting system for adverse calibration trends and out-of-calibration equipment, and
conducted a special review of allinstalled inservice testing program support
instrumentation. Results of reviews by the resident inspectors and by a regional
specialist (IR 50-301/98010(DRS)) indicated that the programmatic corrective actions
have been effective. During the corrent inspection, based on a discussion of the new
instrumentation with the responsible engineer and the results of a review of calibration
records, the inspectors concluded that previous problems with maintaining the SI pump
discharge pressure gauges in calibration had been corrected.
M8.2 (Closed) VIO 50-266/96008-02(DRP): 50-301/96008-02(DRP): This violation comprised
three examples of failure to folicw procedures. In one example, the licensee had
recurrent problems with maintenance work request stickers or tags not being removed
after maintenance was completed. The licensee revised NP 8.1.1, "Werk Order
Processing," to clarify requirements and expectations for the use of work request stickers
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and tags, including the provision of a step in each work order directing workers to remove
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stickers or tags when maintenance is completed. in addition, training was provided to
plant personnel on the proper use and disposition of work request stickers and tags.
1
The second example involved the failure of plant personnel to write a CR for a washer
that had been installed without proper documentation on a casing cover of one of the
turbine-driven AFW pumps. Since identification of this problem, the licensee had
undertaken a major effort to increase worker participation in the condition reporting
process. As discussed in irs 50-266/97010(DRS); 50-301/97010(DRS) and
50-266/97023(DRS); 50-301/97023(DRS), the inspectors concluded, based on the results
of a followup review of the CR system, that this effort has been successful, overall.
During the current inspection, the inspectors noted that NP 8.1.1, " Work Order
Processing," included a requirement that the originator of a work request initiate the
appropriate CR in accordance with NP 5.3.1, " Condition Reporting System," and a
requirement that an SRO review the work order to ensure that a CR was initiated, if
I
necessary.
The third example involved several ..: stances of the failure of personnel to follow
NP 8.4.10," Exclusion of Foreign Material from Plant Components and Systems," and
maintain proper foreign material exclusion (FME) controls around the spent fuel pool.
Since these events, the licensee has revised the procedure to clarify recommendations
and requirements and has counseled personnel on the need for proper FME controls. In
addition, resident inspector observations of work activities and the results of reviews of
condition reports indicated that current FME controls were adequate,
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Ill. Enaineerina
E2
Engineering Support of Facilities and Equipment
E2.1
SW System Hydraulic Analysis Problem
a.
Inspection Scope (IP 37751)
The inspectors reviewed a licensee-identified error with the correct assumptions for the
isolation of some non-essential SW loads during an accident. This issue was identified
as part of an ongoing licensee review of the SW system hydraulic flow analysis model.
b.
Observations and Findinas
An error was identified in the SW hydraulic flow analysis which had taken credit for
isolating the non-essential SW loads during the injection phase of an accident. The
licensee identified that five non-essential SW loads would not be isolated. The five loads
involved service building, spent fuel pool heat exchanger, Unit 1 turbine building, Unit 2
turbine building, and water treatment sample room. The licensee determined, based on
further analysis, that some of the associated valves would close (or would be closed)
during the accident sequence; however, none of these valves would isolate all of the non-
essential SW loads. During periods when two or more SW pumps were out-of-service,
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the failure to isolate these non-essentialloads would prevent the SW system from
maintaining adequate flow and pressure to support safe shutdown. However, if operators
were able to isolate the loads for the service building at a minimum, adequate flow and
pressure could be maintained for safe shutdown.
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In response to the identJication of this problem, the licensee performed a 10 CFR 50.59
!
safety analysis and developed administrative operating limitation instructions for the
j
SW system, which were approved by the Manager's Supervisory Staff (the onsite review
committee) on May 29,1998. These instructions were intended to ensure that the
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SW system configuration under normal plant conditions satisfied the associated
)
T/S LCOs. In addition, operator actions to iso l ate the loads were incorporated in
)
applicable emergency operating procedures.
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The licensee committed at the exit meeting held on July'9,1998, to submit a T/S change
request to the Office of Nuclear Reactor Regulation, no later than July 31,1998, to
specifically address isolation of non-essential SW loads. The submission of the
T/S change will be tracked as inspection Follow-up item 50-266/98011-03(DRP);
50-301/98011-03(DRP).
c.
Conclusions
The licensee identified a calculational error in the service water system hydraulic flow
model and subsequently implemented adequate interim administrative operational
restrictions as corrective actions. Licensee management committed to submit a T/S
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change request no later than July 31,1998, to address the error in the long-term.
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E3
Engineering Procedures and Documentation
E3.1
Reactor Enaineerina Surveillance Procedure Deficiency Durina Unit 1 Reactor Startuo
a.
Inspection Scope (IP 71711)
The inspectors noted a deficiency with the adequacy of RESP 4.1, Revision 13, " Initial
Criticality and All Rods Out (ARO] Physics Tosts," and OP 1B, Revision 32, " Reactor
Startup," during Unit 1 approach to critical.
b.
Observations and Findinas
Prior to the Unit 1 approach to caticality on June 27,1998, reactor engineering personnel
conducted a pre-evolution brief for control room personnel. At the conclusion of the
briefing, the DSS asked the reactor engineer monitoring the startup evolution what the
upper and lower limits for the estimated critical boron concentration were and what
contingency actions should be taken if those limits were approached; the reactor was to
be made critical through dilution of the RCS with all control rods out. The reactor
engineer had not predetermined any estimated critical boron concentration limits nor any
contingency actions. This resulted in a delay while the reactor engineer and operators
determined what limits to use and then calculated the corresponding boron dilution
parameters. The limits established were the T/S limits for shutdown margin and
maintaining less than a +5"F moderator temperature coefficient. The DSS, in
consultation with the reactor engineer, then developed contingency actions to take if the
tolerances on estimated critical boron concentration were approached. Unit 1 went
critical at 1642 parts per million, very close to the estimated critical boron concentration of
1641 parts per million.
The inspectors determined that neither procedure OP 1B nor RESP 4.1 contained any
requirements to determine in advance the tolerances for estimated critical boron
concentrations or associated contingency actions should those limits be exceeded. The
licensee's procedures for estimated critical control rod position does include control rod
position limits. Also, no procedural controls existed for maintaining the RCS boron
concentration within T/S limits during the approach to criticality. The reason for diluting to
criticality following a core refueling was to approach criticality in a slow, deliberate, and
controlled manner while verifying that the new reactor core responds as predicted. Based
on a review of industry operating experience, the inspectors noted that establishing limits
for both estimated critical rod position and critical boron concentration and the bases for
.
those limits is a common industry practice. In addition, proceduralized contingencies for
premature criticality or not achieving criticality within a pre-established band are
,
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fundamental industry expectations for reactivity management. Noteworthy, was that the
licensee had recently performed a self-assessment (S-A-98-09) of the reactor engineering
organization, specifically examining reactivity management, and failed to identify this
fundamental deficiency. The inspectors discussed these concerns with plant
management.
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Upon further review of the procedure deficiencies, the licensee identified that the industry
operating experience guidance had been included in previous revisions of RESP 4.1.
However, sometime in 1992, during the procedure change process, the guidance was
deleted. The inspectors discussed with station management the observation that similar
problems of this type had occurred in the past.
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c.
Conclusions
The inspectors concluded that the licensee's procedures used during reactor startups and
the approach to criticality contained deficiencies which reflected a non-conservative
approach to reactivity management since well-established industry guidance for criticality
estimations were not incorporated into the procedure.
E7
Quality Assurance (QA)in Engineering Activities
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E7.1
QA Audit of Desian Enaineerino Processes
The licensee's QA organization conducted a biennial audit of design engineering
processes as summarized in Audit Report A-P-98-01, dated June 16,1998. All major
design control activities / products including modifications, temporary modifications, design
,
calculations, engineering specifications, control and review of vendor documents,
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engineering change requests, and engineering work requests were reviewed to verify
compliance with 10 CFR Par 150, Appendix B, Criterion 111.
The licensee's audit team concluded that the overall design engineering processes were
marginally effective in ensuring the accurate documentation and implementation of design
controls. The audit team initiated a total of 22 CRs. In addition, the team could not close
two 1997 QA Program Significant issues related to calculations and translation of design
information due to a lack of improvement in those areas.
The inspectors reviewed Audit Report A-P-98-01 in light of recent design engineering
performance trends and determined that the audit findings typified previously identified
concerns with the design engineering organization. The inspectors concluded that
overall, the audit was probing and thorough and appropriately identified design
engineering deficiencies.
E8
Miscellaneous Engineering issues
E8.1
(Closed) VIO 03013 from EA 96-273: irs 50-266/96006(DRP): 50-301/96006(DRP) and
50-266/96007(DRP): 50-301/96007(DRP): This issue, pertaining to the number of
SW pumps needed for accident mitigation, was discussed in IR 50-266/96006(DRP);
50-301/96006(DRP) and in Licensee Event Report 50-266/96004-01; 50-301/96004-01,
and considered with other problems fur escalated enforcement. On December 3,1996,
an NOV was issued for those problems (EA 96-273) and included, for the SW pump
issue, a violation (VIO 03013) of T/S 15.3.3.D and Criterion XVI, " Corrective Action," of
Appendix B,10 CFR Part 50. A civil penalty of $325,000 was imposed with the NOV.
,
The licensee committed to extensive corrective actions in its response to the NOV in a
{
letter dated January 31,1997. For the SW pump issue, these actions included the
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prompt preparation and submittal of a license amendment request to correct
T/S 15.3.3.D, which did not specify the minimum number of pumps needed for accident
mitigation.
On July 9,1997, Amendments No.174 (Unit 1) and No.178 (Unit 2) were issued
specifying the minimum number of SW pump.s required for design basis accident
mitigation. Subsequently, during continuing refinement of its SW model, the licensee
identified additional problems with the SW LCO in that the lowest functional capability or
performance levels of equipment required for safe operation of the facility was not
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specified. This issue is discussed further in Section E2.1.
E8.2
(Closed) Inspection Follow-Up Item (IFI) 50-266/96008-05(DRP): 50-301/96008-05(DRP):
The inspectors reviewed the issues associated with reverse direction leak testing of gate
valves. The licensee identified (in September 1996) that six containment isolation valves
(three for each Unit) associated with the containment heating steam system were
inappropriately being tested in the reverse direction (the direction opposite to normal
flow). The valves were subsequently removed via a modification in which the heating
steam supply line containment penetration and the condensate return line penetration
were cut and capped. The licensee had not used the containment heating steam system
for many years. No other instances of inappropriate leak testing of gate valves were
identified. This non-repetitive, licensee-identified and corrected violation of Section Ill.C.1
of Appendix J, " Primary Reactor Containment Leakage Testing for Water-Cooled Power
Reactors," of 10 CFR Part 50, which required that the valves be tested in the direction of
normal flow, is considered a NCV (NCV 50-266/98011-04(DRP); 50-301/98011-04(DRP))
consistent with Section Vll.B.1 of the NRC Enforcement Policy.
E8.3
(Closed) VIO 50-266/95014-01(DRP): 50-301/95014-01(DRP): This violation involved
four examples where safety evaluations for spent fuel dry cask activities were not
- conducted in accordance with Station Procedure NP 10.3.1," Authorization of Changes,
Tests, and Experiments (10 CFR 50.59 and 72.48 Reviews)." As stated in the cover
letter of IR 50-266/95014(DRP); 50-301/95014(DRP), the NRC concluded that the
licensee had taken appropriate corrective actions for this violation. These actions
included a revision of the procedure to clarify expectations and requirements and better
training on the procedure and regulations for personnel who conduct safety evaluations.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1
General Comments (IP 71750)
j
During this inspection period, the inspectors conducted frequent tours of the primary
auxiliary building and Unit 1 containment. The inspectors noted that postings accurately
depicted the radiological conditions in the areas. Most areas were maintained free of
contamination or kept to a very low contamination level, allowing for access to areas by
operators and creating good working environments for the general outage workforce.
Personnel dose recorded for the Unit 1 outage was 169.7 person-rem (estimated from
plant staff records of self-reading dosimeter readings) versus a pre-outage goal of 130.0
person-rem. The main contributors to the higher than anticipated total exposure were 27
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person-rem of exposure accrued because of emergent maintenance activities and a total
extension of the outage by 61 days.
P1
Conduct of Emergency Planning Activities
P1.1
Contaminated Injured Worker Emeraency Response Drill (IP 71750)
The inspectors observed an emergency response drill conducted on June 4,1998. The
drill targeted first responder, control room personnel, site medical, and offsite medical
response activities. The inspectors noted that health physics (HP) personnel provided
effective radiological controls at the " scene" and the " victim" was assayed for
contamination. Centrol room personnel used the appropriate emergency plan procedure
to request an ambulance from an area hospital. Medical workers responding to the
" scene" were not impeded unnecessarily by HP personnel. First responder assessment
of the " victim's" status was limited. The inspectors could not clearly ascertain if
radiological contamination concerns contributed to the first responder's actions.
However, upon the medical staffs' arrival at the " scene," a clear focus was maintained on
the health and safety of the " victim" and was not overridden by minor radiological control
concems.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on July 9,
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
S. A. Patuiski, Site Vice President
M. E. Reddeman, Plant Manager
R. G. Mende, Operations Manager
W. B. Fromm, Maintenance Manager
C. R. Peterson, Director of Engineering
J. G. Schweitzer, Site Engineering Manager
R. P. Farrell, Health Physics Manager
V. M. Kaminskas, 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
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
I
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 71711:
Startup Following Refueling Outages
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ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-266/98011-01(DRP)
Failure to follow procedures, Appendix B,
Criterion V
,
50-266/98011-02(DRP)
inadequate maintenance procedure, Appendix B,
50-301/98011-02(DRP)
Criterion V
50-266/98011-03(DRP)
IFl
Licensee to submit T/S change request to address
!
50-301/98011-03(DRP)
service water model error
50-266/98011-04(DRP)
Improper leak testing of gate valves, Appendix J
50-301/98011-04(DRP)
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Closed
50-266/98011-01(DRP)
Failure to follow procedures, Appendix B,
Criterion V
50-266/98011-02(DRP)
Inadequate maintenance procedure, Appendix B,
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50-301/98011-02(DRP)
Criterion V
50-266/96007-01(DRP)
Operator performance of shift duties
50-301/96007-01(DRP)
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50-266/96007-02(DRP)
Configuration control
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50-301/96007-02(DRP)
50-266/96008-01(DRP)
Leakage /SW leak patch / conditions outside TS
50-301/96008-01(DRP)
50-266/VIO 02073(DRP)
EA 96-273
Criterion Xfl, control of measuring and test
50-301/VIO 02073(DRP)
equipment
50-266/96008-02(DRP)
Failure to follow procedures
50-301/96008-02(DRP)
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50-266/VIO 03013(DRP)
EA 96-273
Criterion XVI, corrective action
50-301/VIO 03013(DRP)
50-266/98011-04(DRP)
Leak testing of gate valves, Appendix J
50-301/98011-04(DRP)
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50 266/96008-05(DRP)
IFl
Containment isolation valve testing discrepancies
50-301/96008-05(DRP)
50-266/95014-01(DRP)
Inadequate safety evaluation /10 CFR 72.48
50-301/95014-01(DRP)
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LIST OF ACRONYMS USED IN POINT BEACH REPORTS
Alternating Current
American Society of Mechanical Engineers
CFR
Code of Federal Regulations
Current Licensing Basis
CR
Condition Report
Division of Reactor Projects
Division of Reactor Safety
i-
Duty Shift Superintendent
Enforcement Action
Emergency Planning
Environmental Qualification
F
Fahrenheit
Final Safety Analysis Report
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Health Physics
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IFl
Inspection Follow-Up Item
!
IP
inspection Procedure
individual Plant Evaluation
IR
Inspection Report
In-Service Test Procedure
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Non-Cited Violation
,
NP
Nuclear Power Business Unit Procedure
NRC
Nuclear Regulatory Commission
Ol
Operating Instruction
Operations Manual
Out-of-Service
OP
Operations Procedure
ORT
Operations Refueling Test
Post-Accident Sampling System
PPG
Production Planning Group
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psig
Pounds Per Square Inch Gauge
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Prompt Operability Determination
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PBTP
Point Beach Test Procedure
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Quality Assurance
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RESP
Reactor Engineering Surveillance Procedure
Routine Maintenance Procedure
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Reactor Operator
Radiation Protection
Refueling Water Storage Tank
Safety Evaluation Report
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Spent Fuel Pool
)
Safety injection -
Senior Reactor Operator
Turbine Driven Auxiliary Feedwater
T/S
. Technical Specification
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TS
Technical Specification Test Procedure
Unresolved item
Violation
VNCR
Control Room Ventilation
1
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