ML20203D436
| ML20203D436 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 02/19/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20203D404 | List: |
| References | |
| 50-266-97-23, 50-301-97-23, NUDOCS 9802260059 | |
| Download: ML20203D436 (39) | |
See also: IR 05000266/1997023
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U.S. NUCLEAR REGULATORY COMMISSION
REGION 111
)
Docket Nos: 50-266,50-301
Licenses Nos: DPR-24, DPR-U
Report Nos: 50-266/97023(DRS), 50-301/97023(D RS)
Licensee: Wisconsin Electric Power Company, WEPCO
Facility: Point Beach Nuclear Plant, Units 1 & 2
Location: 6612 Nuclear Road
Two Rivers, WI 54241-9516
Dates: October 20 through November 7,1997
Inspectors: V. P. Lougheed, Acting Chief, Lead Engineers Branch
R. M. Bailey, Ope.ator Licensing Examiner
C. H. Brown, Reactor inspector
L. C. Collins, Resident inspector, Quad Cities
R. A. Winter, Reactor Inspector
Approved by: John A. Grobe, Director
Division of Reactor Safety
9802260059 980219
PDR ADOCK 05000266
G PDR
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-. EXECUTIVE SUMMARY
Point Beach Nuclear Plant, Units 1 & 2
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NR7 Inspection Report Nos. 50 266/97023(DRS),50 301/97023(ORS)
This inspection was to review the licensee's controls in the area of safety evaluations as well as
. the effectiveness of licensee controls in identifying, resolving and correcting problems.
Selected operational activities, maintenance procedures and safety evaluation training were
also reviewed. Finally, the inspection reviewed corrective actions to several of the issues
identified during the Operational Safety Team inspection conducted in late 1996.
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Doerations
. Shift tumovers were of good quality, panel walkdowns were of adequate frequency, and
control room manning exceeded administrative guidance. (Section 01.1)
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W . The October 23,1997, low-temperature overpressure protection (LTOP) actuation event
could have been prevented had inere been a larger initial margin between nominal
reactor coolant pressure and the LTOP actuation setpoint, had a pre-job briefing been
performed, and had procedural guidance specifying operator actions to control pressure
during the evolution been available. (Section 01.2)
i . The license made significant impru,.nents in operational procedural guidance and
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adherence. A repeat problem with danger tag sequencing not being completed in
- accordance with procedures was identified and was cited. (Section O3.1)
. The industry operating experience feedback program effectively handled the majority of
issues that the inspectors reviewed. However, review of two important issues was
significantly delayed, in another case, an applicable industry issue was closed without
a:tions during the industry operating experience review. (Section 07.1)
. Quality Assurance audit findings and self assessments appeared to provide a critical
review of the areas assessed. Licensee corrective actions in response to tne audit
findings were not always timely, and, in some cases, due dates and priorities for actions
were not assigned. The inspectors concluded that the corrective action process did not
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always capture specific issues raised in programmatic quality condition reports, resulting
in these issues not being formally addressed. A violation for the failure to perform an
operability determination, associated with a valve testing deficiency identified during a
quality assurance audit, was identified. -(Section 07.2)
. _ The corrective action system lacked prioritization and there was limited accountability for
ensuring that actions were completed.- These contributed to the large backlog of open
i items in the system. _(Section 07.3)'
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Maintenance
. The licensee failed to use calibrated test equipment, controlled by a measuring and test
equipment control program, to measure timed acceptance limits in a technical
specification monthly surveillance.~ (Section M1.1)
. Recent revisions to the maintenance procedures provided sufficient restoration steps for
reassembly and post maintenance testing. (Section M3.1)
Engineering
. The operability determinations reviewed were good and, in some cases, quite detailed.
However, this was not true in all cases and a wide quality spectrum was observsd.
(Section E1.1)
. The licensee's 10 0FR 50.59 procedure contained a comprehensive listing of licensing
basis documents which would allow preparation of adequate 50.59 safety evaluations.
(Section E2.1)
. The safety evaluations and screenags being performed were of good quality and some
were considerably above average. However, one screening failed to identify that the
FSAR did not reflect the current plant procedures. (Section E2.2)
. Formal procedural raidance for updating the FSAR had been established, but was
imprecisely worded. The procedure assigned primary responsibility for preparing and
submitting the periodic update of the FSAR to an individual without any guidance on
timeliness. (Section E3.1)
. Recent changes to NP 10.3.1 have resulted in improved procedural guidance for
screening and writing 10 CFR 50.59 safety evaluations. The 10 CFR 50.59 procedure
effectively assigned responsibility for key areas to assure that 50.59 safety evaluations
were effectively prepared, reviewed and approved. Additionally, the necessary
pro:edural guidance existed for maintaining records and formally reporting to the NRC
the changes, tests, and experiments made in accordance with 10 CFR 50.59.
(Section E3.2)
. Training and qualification of licensee personnel to perform screenings and safety
evaluations appeared to meet the licensee's commitments to the NRC following the
1996 OSTI. There was consistency between the training and procedural requirements
for preparing safety evaluations and the training evaluation method appeared to be
satisfactory for the short term. (Sections E5.1, E5.2 and E5.3)
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Report Details
I. Operations
01 Conduct of Operations
01.1 Main Control Room Observations
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- a. Insoection Scoce (93802)
The inspectors observed main control room activities during shift tumovers, testing, and
special evolutions. The inspectors conducted interviews and reviewed station logs to
assess operations performance. The inspectors also reviewed a numtier of operating
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p procedures, as described in the list of documents at the end of this report.
b. Observations and Findinos
During this inspection period, the inspectors observed improved operating practices with
minimal differences between the two crews observed. The inspectors observed shift
turnovers in the control room. The inspectors observed that the oncoming crew
members would perform a routine watch relief in the control room. Then the on-coming
crew was gathered outside the control room and were briefed on plant status and work
priorities, with all members contributing in the discussion. Following the brief, each crew
member would assume his assigned position in the control room or plant. The
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inspectors noted that the improved shift turnover process was a recent change from a
previous practice of performing crew briefs in the control room.
The inspectors observed licensed reactor operators, called control operators (CO), ,
perform frequent walk downs of the control panels. Also, the COs were prompt to
respond to any control panel alarm and inform the Duty Operating Supervisor (DOS -
licensed senior reactor operator (SRO)). The inspectors observed consistent 3-way
communications among licensed operators inside the control room and plant operators
outside of the control room.
The inspectors observed that control room manning routinely exceeded administrative
guidance as well as regulatory requirements. The control room staffing included 3 COs,
a DOS and a Duty Shift Superintendent (DSS -licer ed SRO). Also, an additional '
operating supervisor (SRO) was assigned to the control room staff but was not required
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to stay in the control room. The inspectors were informed that increased manning had
been a recent change to enhance operations performance.
c. Conclusions
The inspectors concluded that shift turnovers were of good quality, panel walkdowns
were of adequate frequency, and control room manning exceeded administrative
guidance.
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01.2 Inadvertent Ooening of Low Temoerature Overoressure Protection (LTOP) Relief Valve
a. Instsection Scoce (93802)
The inspectors observed preparations for Unit 1 transition from cold shutdown condition
j to hot shutdown condition. During the inspection period, a Unit 1 reactor coolant pump
start resulted in an inadvertent opening of the LTOP relief valve at 415 pounds per
square inch (psig). The inspectors reviewed station logs and event recordings, and
interviewed (icensed operators to assess operations performance.
! b. Ohgrvations and Findings
The inspectors were informed that an inadvertent opening of the LTOP relief valve
occurred on October 23,1997, following the start of a reactor coolant pump on Unit 1.
The unit operator had been performing a fill and vent evolution in preparation for a plant
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heatup to hot shutdown condition. The reactor coolant system (RCS) had been placed
i in a solid condition with pressure being controlled in manual by the operator.
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The inspectors noted that RCS pressure had increased to approximately 355 psig during
the establishment of solid plant conditions, but was stabilized around 350 psig in
preparation to start the reactor coolant pump (RCP). Following RCP start, RCS
pressure had increased to LTOP actuation setpoint (s425 psig per Technical
Specification (TS) 15.3.15.A.1.a). The CO took manual action to stabilize pressure by
placing both the charging pump speed controller and the letdown pressure controller
(PCV-135)in manual. This was described in condition report (CR) 97 3488. The
licensee also noted that RCS pressure _was reduced and stabilized within accetable
limits following the LTOP actuation. The inspectors were informed that the LTOP
actuation had occurred at approximately 415 psig and that the pressure differential
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between the RCS pressure and the relief valve setpoint, just prior to the RCP start, was
only approximately 60 psig. During operator interviews, the inspectors determined that
a pressure spike of approximately 50 to 60 psig was normally expected following a RCP
start while in a solid plant condition. Additionally, the inspectors ascertained that the
preferred method to limit any pressure spike was to use only the letdown pressure
controller so that finer control of RCS pressure could be achieved. The inspectors
ascertained that manually adjusting both the charging pump speed controller and the -
letdown pressure controller simultaneously was considered unusual and unnecessary to
limit the pressure spike by most operators.
The inspectors noted that the following factors contributed to the LTOP actuation event:
. In September of 1996, the licensee requested a TS change to Section 15.3.15 in
order to raise both pressurizer power operated relief valves setpoint to 5440 psig
when the LTOP system was required to be operable. An NRC letter dated
January 13,1997, authorized the change as requested. However, the inspectors
identified that, at the time of this event, this approved TS change had not been
transmitted to the operating crews, nor had it been incorporated into the relief
valve setpoints.
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. The inspectors noted that the licensee normally started a RCP with the plant in a
solid condition and then heated up to hot shutdown before drawing a bubble in
the pressurizer. The inspectors noted that starting a RCP while solid resulted in
a large pressure spike, increasing the likelihood of an LTOP actuation. The
licensee acknowledged that their method differed from common industry practice
and required greater operator control. ,
. The inspectors noted that some licensed operators had a generic understanding
of the RCS pressure response following a RCP start while solid. However, there
was not any procedural guidance or written management expectations to ensure
adequate operator action to minimize the pressure excursions that might occur.
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. - The inspectors identified that the SRO had not performed a detailed pre-job brief
with the licensed reactor operator; therufore, there was no discussion of
- limit the consequences. This was especially significant as a training deficiency
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- regarding the licensed reactor operator's performance on charging and letdown ,
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system control and response had recently been identified by the licensee.
. c. Conclusions
The inspectors concluded that the October 23,1997, LTOP actuation event could have
been prevented had there been a larger initial margin between nominal RCS pressure
and the LTOP actuation setpoint, had a pre job briefing been performed, and had
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procedural guidance specifying operator actions to control pressure during the evolution
been available.
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03~ Operations Procedures and Documentation
03.1 Procedure Adequaev and imolementation
a. Insoection S. cop _e (93802)
The inspectors reviewed the danger tagging procedure, NP-1.9.15, and the
linplementation process. Included in the review was an evaluation of two safety related
systems (emergency diesel generator (EDG) and containment spray systems) and
related components which had been taken out of service with danger tags. Additionally,
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the inspectors reviewed six completed surveillance tests for EDGs G-01 & G-02.
b. Observations and Findinas
The inspectors walked down the EDG and accessible portions of the containment spray
system. The trspectors noted that all tags were properly placed on EDGs G 01 & G-02
and containment spray pumps P-14A & P-148, and the tags properly reflected the final
condition of the component. The inspectors were able to independently verify the
-isolation of vital equipment through a review of system prints.
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The inspectors identified a discrepancy from procedure NP-1.9.15 during a review of
selected danger tag location sheets. The inspectors noted on two different danger tag
location sheets (97 753 & 97 800) that the " Tag Sequence" had not been filled in even
though the danger tags had been issued recently (October 7 & 18, respectively) and
were hanging in place. Contrary to this, procedure NP-1.9.15, Section 6.2.1.i states, in
part, that the danger tag location sheet preparer shal; fill out the sheet with a danger tag
sequence. Additionally, Section 6.3.3.b of NP-1.9.15 requires that the qualified tagger
position the equipment or components as specified in the " sequence" column and
' required position" column on the danger tag location sheet. A similar deficiency was
NRC-identified in Inspection Report 50-266/96018(DRP); 50 301/96018(DRP). The
failure to follow the procedure is a violation of 10 CFF. Ped 50 Appendix B, Criterion V
- Instructions, Procedures, and Drawings," that requires the p' ant to be operated and
maintained in accordance with approved procedures (VIO 50-266/97023-01a(DRS);
50 301/97023-01a(DRS)).
The inspectors noted that a recent revision to the EDG surveillance test procedures
TS-81 & TS-82 made enhancements to the clarity and performance criteria. No
observed testing activities were noted during this inspection period. However, the
inspectors noted that test results were appropriately documented and reviewed in a
timely manner.
c. C&Oclusions
The inspectors concluded that the licensee had made significant improvements in
procedural guidance and adherence. A repeat problem with danger tag sequencing not
being completed in acccrdance with procedures resulted in a violation of plant
procedures.
07 Quality Assurance in Operations
07.1 Industrv Ooerating Exoerience Feedback Program
a. Insoection Scoce (40500)
The inspectors reviewed the licensee's program and procedure for operational
experience feedback by selecting several industry events, NRC generic letters and
information notices, and the Institute of Nuclear Power Operations (INPO) significant
operating event reports (SOERs), and assessing the licensee's effectiveness in
disseminating information to plant staff and initiating corrective actions as appropriate.
The inspectors reviewed the latest revision of the procedure for review of industry
operating experience, NP 5.3.2," Industry Operating Experience Review Program,"
b. Observations and Findings
The corrective action program (CAP) under the Quality Assurance (QA) department was
a matrix organization with four permanent operating experience coordinator (OEC)
positions as well as staff from other departments assigned CAP functions but reporting
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to their respective departments'line management. The external OEC was one of the
cuordinators reporting to the CAP manager. This organization was new, having been ,
formed over the last year, and was not yet fully staffed, which appeared to contribute to
a high workload for the existing coordinators.
The inspectors determined that, with two minor exceptions, procodure NP 5.3.2 was
generally followed. The two exceptions were as follows: NP 5.3.2 stated ' at an
- effectiveness review of the industry operating experience program would ' a performed
every 18 months. This review had not been completed, within the last 18 months.
Licensee personnel stated that they were taking credit for a OA audit of the program to
satisfy the effectiveness review requirement. The inspectors reviewed the QA audit and
noted that the audit focused on program compliance and did not assess the overall
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effectiveness of the program. Secondly, NP 5.3.2 stated that a semiannual report on
the industry operatirig experience program performance would be sent to managers.
Only one report had been generated in the last year. The licensee stated that neither
the effectiveness review or the semiannual report were planned to be completed in the
near future due to resource issues.
The inspectors reviewed a number of external industry operating experience issues and
the licensee's assessment and corrective actions associated with the issues. The
majority of issues were handled in accordance with the procedure and appeared to be
appropriately dispositioned. However, the inspectors found two important industry
issues in which review and actions were significantly delayed, and a third case was
missed by the operating experience review program, as discussed below.
The licensee review of INPO SOER 96-01, " Control Room Supervision, Operational
Decision Making, and Teamwork," dated September 27,1996, was initially delayed due
to " higher priority issues in the operating experience review group" as stated in the
licensees' corrective action tracking system databast (NUTRK). Based upon further
entries in the NUTRK system, the inspectors ascertained that the station's response
and actions associated with the SOER were delayed due to a lack of operations'
personnelinvolvement. However, in April 1997, CR 97-1043 was generated to
document the delays and prompt action was then initiated, including a training session
during operator requalification training. However, some actions associated with the
issue remained open at the end of the inspection with no priority assigned.
Additionally, during review of a OA audit on Operations, the inspectors noted that an
abnormal operating procedure (AOP) 6-A," Dropped Rod," was not consistent with
industry practices. In particular, the AOP did not direct operators to place rod control in
manual but rather instructed operators to verify " rods in AUTO and stepping." The
procedure had been under review for different deficiencies as a result of the QA audit
since May 1997. The Operations Manager was aware of the procedure issue and
intended to change the procedure to either place limits on automatic rod motion or to
direct operators to place rod controlin " manual." However, no procedure revision had
been completed six months after the issue initially surfaced. The procedure revision
due date had been extended three times and had no priority assigned. The inspectors
were concerned in this case with the lack of prompt procedure revision of important
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operational procedures, i.e., abnormal operating procedures, upon discovery of
potentially nonconservative actions
Approximately one year ago, the external OEC began more formal tracking and review I
of lower level industry operating experience, such as NRC daily events and items posted I
on INPO's Nuclear Network and also recently implemented bulletin board pos :'gs (
throughout the plant highlighting events and issues from other facilities. The inspectors ]
viewed these actions as positive initiatives in the station's efforts to improve operating
experience feedback. However, in one case the inspectors reviewed, an event reported
to the NRC by another pressurized water reactor facility was reviewed and closed by the
OEC as not applicable. This event involved a potential training deficiency regarding an
FSAR assumed time for operator actions during a steam generator tube rupture event.
The NRC later identified that the issue was applicable to Point Beach and, following
i NRC identification, the licensee started to evaluate the issue. However, the licensee
missed an opportunity to self-identify that the event was applicable during the industry
operating experience review.
c. Conclusions
The industry operating experience feedback prcgram effectively handled the majority of
issues that the inspectors reviewed. However, review of two important issues was
significantly delayed. In another case, an applicable industry issue was c!osed without
actions during the industry operating experience review.
07.2 Self Assenments and Quality Assurance (OA) Audits
a. Insoection Scope (40500)
The inspectors reviewed a number of self assessments and QA audits performed in
1997. The inspectors also reviewed the licensee's corrective actions in response to the
audit findings and interviewed both the OA auditors and members of the audited
organization.
b. Observations and Findings
Overall, the QA audits and particularly the self assessments appeared to identify
significant issues and reflected a critical review of the area assessed. However,
licensee corrective actions in response to audit findings appeared to lack appropriate
priority and, in one case, were found to be inadequate. The inspectors also identified
that a prompt operabilKy determination was not performed for QA identified relief valve
testing issues.
in-Service Testing (IST) Program Audit
The IST program audit identified a number of deficiencies including one QA significant
issue with respect to the relief valve program. The overall conclusion was that the IST
and relief valve programs were not up to industry standards. A 1996 audit had
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previously Mentified the IST program as a OA significant issue. A total of eight quality
condition repris (OCRs) and ten observations were documented,
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The licensee's program required that, for QA significant issues, a root cause evaluation
be performed. The inspectors observed that although QCR 97-0148 was written on
, July 17,1997, the root cause evaluation was not started until mid-October. The 1
licensee was unable to provide any explanation for the delay. The root cause evaluation
was not complete at the end of the inspection, and the inspectors noted that no due date i
was assigned in the licensee's corrective action tracking system. The root cause !
evaluator told the inspectors that the evaluation was near completion but that it would
not address the specific issues identified in the QCR. The inspectors ascertained that
the licensee's corrective actions to QA-identified significant issues, such as the IST
program deficiencies, was not aggressive. Because of the three month delay in the
licensee starting the root cause evaluation, the inspectors were unable to assess the
licensee's thoroughness in dispositioning QA findings. However, the repetitiveness of
the QA finding, the delayed start of the root cause evaluation, the lack of an assigned
cor1pletion date, and the failure of the evaluation to address specific issues did not
portend a thorough job.
The inspectors followed up on the specific issues raised in the OCR and determined that
the system engineer was reviewing the issues, although there was no action item or due
date for such a review. The system engineer stated that only a few of the issues were
valid; however, the engineer could not provide any documentation to support this
conclusion. The engineer stated that he had reviewed the main steam and pressurizer
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relief valve testing to ensure operability of currently installed valves but he had not
reviewed testing results for the other safety related valves mentioned in th QCR.
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QCR 97-0148 stated,"Raquirements for testing safety-related relief valves per ASME
Section XI,1986 -OM 1(1981) criteria were not met in all instances." The OCR
identified sixteen different specific testing deficiencies. NP 5.3.7," Operability
Determinations," Attachment A, * Management Expectations for Performing a Written
Prompt Operability Determination," described types of conditions that should receive a
written operability evaluation if the system, structure, or component was to remain in
service, item 2.6, " Errors in test;ng, testing methodology, instrumentation or data that
could invalidate surveillance testing that is used to demonstrate continued operability of
SSCs (systems, structures, and components)," appeared to apply to the relief valve
testing discrepan-ies documented in the OCR. Although the QCR stated that test
requirements were not met, no operability determination for the affected valves was
performed, nor was any other assessment made to ensure that the testing deficiencies
- did no' irnpact the valves' ability to function. The failure to perform an operability
determination in accordance with NP 5.3.7 is considered an example of a violation of 10
50-301/97023-01b(DRS)). An evaluation of the OCR performed on October 26,1997,
following inspector questioning, did not directly address operability but did provide
reasonable justification to consider the affected valves operable. However, the
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inspectors were concerned that the licensee's corrective action program failed to ersure
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that QA identified issues that could affect equipment operability, such as these testing
deficiercies, were formally captured and assessed.
Another QCR from the QA audit identified 16 sets of valves that were inappropriately
excluded from the IST program. A prompt operability determination was completed for
only one set of valves. The IST engineer told the inspectors that the other valve sets did
meet all IST requirements and, therefore, no prompt operability determination was
required. The engineer stated that this was discussed with the SRO on shift; however,
there was no documentation to support either the conclusion reached or the
. conver.tation. The lack of a written justification for the other sets of valves was another
example of informal resolution of operability questions. Bec6use of the significant
deficiencies in the IST program identified by both the licensee and the NRC, the
inspectors were concerned about this informal disposition of a QA finding. The
inspectors noted that, again, the OCR was being reviewed as a programmatic issue,
and the follow up on specific Msues was informally nddressed.
Ooerations Audit
A QA operations audit concluded that thts Operations department was effectively
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operating Poini Beach but was not effective in inducing other departments to address
corrective maintenance on equipment and components that affect plant operations. The
QA organization documented a number of issues on OCRs, including a problem witn
use of calibrated measuring and test equipment and equipment aclation and control of
danger tags. The inspectors noted that these findings were consistent with NRC
inspection findings, such as those in Sections M1.1 and O3.1.
The inspectors reviewed several of the QCRs initiated by the audit documenting
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longstanding corrective maintenance items on the EDGs, including operator
work arounds. Although specific corrective maintenance in response to the audit
findings had not yet been performed, an operator work-around list was generated and
maintained by the Ope:ations department to better prioritize equipment issues. The
inspectors were satisfied that none of the deficiencies affected the operability of the
EDGs.
c. Conclusions
- Audit findings and self assessments appeated to proWde a critical review of the area
assessed. Licensee corrective actions in response to the audit findings were not always
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timely, and, in some cases, due dates and priorities for actions were not assigned. The
. Inspectors concluded that the corrective action process did not always capture specific
issues raised in programmatic QCRs, resulting in these issues not being formally
addressed. A violation for the failure to perform an operability determination, associated
with a valve testing deficiency identified during a quality assurance audit, was identified.
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07.3 Corrective Action System
a. jmoection Scone (40500)
The inspectors revicwed the NUTRK action items for a sampling of residual heat
removal system condition reports ar.d condition reports open for over five years,
b,~ Observations and Findinos
The inspectors observed that the licensee had a large number of items in the corrective
action system. Discussions with the system manager irMicated that the system had
over 4000 opened items. Due to the concerns noted in Section 07.2, the inspectors
questioned how prionties wera assigned, The licensee explained that the system had a
formula to calculate what priority should be assigned. However, the inspectors
observed that priorities were not assigned on over 60 percent of the action items
reviewed.
Additionally, the inspectors noted tbV the system was set up to " assign" an action item
to an individual. That individual then had a month to " receive" the item, before a due
date was given. If the Individua! decided not to receive the item, then someone else
would be " assigned," and that Individual would have a month to decide whether to
receive the item, or reassign it. The inspectors noted one example where a ite'n was
entered into the system in September 1996; however, no actions were assigned until
July 1997,10 months lat3r. The inspectors found two 1997 exarnples where action
items went for six months between being generated and being received. The licensee
stated that they had recently changed the system such that agreement was reached
during a cally meeting as to who would rece!ve the condition report action item before
the item was assigned. However, the licensee acknowledged that the computer system
still required someone to formally " receive" the item, and that the procedure allowed up
to a month beftto that " receipt" needed to be made.
The inspectors also saw that the corrective action system due dates were determined by
the " receiving" party, and some items were closed without ever being assigned due
dates. This made it difficult to assess overall timeliness However, for those actions
where due dates were assigned, approximately 31 percent received due date
extensions, and approximately 27 percent were overdue, whether or not extensions
were requested. In the case of the item discussed above which took 10 months before
the action item war assigned, a due date of August 31,1997, was assigned. At the time
of the inspection (October - November 1997), the tracking system showed the item as
overdue, but with no actions taken although it had been overdue for two months. The
inspectors also identified one case where sh: oxtensions were granted, but the item was
overdue at the time it was closed. In a third case, an open item was overdue after four
extensions.
Inspection Report 50-261/97010(DRS); 50-301/97010(DRS) noted that the corrective
action system had approximately 2400 items in it as of September 1997. Tharefore, it
appeared that the licensee had recently input a large number of issues into the
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corrective action program. While this increase was extremely commendable, the
inspectors were concerned that the problems identified above could counteract the
benefits raised by increased identification of issues,
c. Conclusions
The inspectors concluded that the corrective action system lacked prioritization and that
there was limited accountability for ensuring that actions were completed. These
contributed to the large backlog of open items in the system.
08 Miscellaneous Operations issues
08.1 (Closed) Violation 50-266/96003-01: 50-301/96003-01: Procedures for Surveillance and
Testing of Safety Related Equipment. The issue involved inspectors observing boric
acid crystal buildup on drains that operators were supposed to observe for leakage
during surveillances. To resolve this issue, the licensee revised the procedures to
require cleaning away of any accumulated boric acid prior to the surveillance. The
licensee also established acceptance criteria for assessing any observed leakage. The
inspectors reviewed the revised procedures and concluded that the actions taken should
be sufficient to prevent iocurrence. This item is closed.
08.2 (Closed) Violation 50-266/96006-02: 50-301/96006-02: Failure to Log a Condition
Where Technical Specifications Had Not Been Met. The inoperability of t% containment
hatch outer door had not baen logged in the operator's log causing confusion for
subsequent shifts on the door's correct status. The licensee has described this
occurrence ir, a "Lesmns Learned" document and made it required reading for
Operations. The licensee has briefed Operations staff during Plant Status Update 97-1.
Additionally, the licensee has performed a complete rewrite of some procedures and
included log maintenance under Attachment 5," Standards and Expectations for Logs,"
of OM 1.1," Conduct of Plant Operations." The inspectors concluded that the licensee
had taken appropriate actions. This item is closed.
08.3 LGosed) Insnection Follow uo item 50 266/96018-02: 50-301/96018 02: Fire Brigade
and Control Room Staffing. At the time this item was opened, the DO3 was expected to
leave the main control room in response to a plant fire. The DSS was expected to
remain in the main control room and act as the fire brigade chief. The DSS and DOS
were the only licensed SROs for coverage of a dual unit control room during back shift
hours. The inspectors verified that a recent revision to operations manual procedure
OM 1.1, " Conduct of Operations," had incorporated management expectations to
increase main control room staffing to three SROs and deleted the DSS's responsibility
as fire brigade chief, appropriately delegating the responsibility to an individual without
control room duties. These changes allowed one of three SROs to respond during a
plant fire without jeopardizing plant operations oversight in the main control room. The
inspectors concluded that the licensee's corrective actions had been appropriate. This
item is closed.
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08.4 fClosed Violation 50-266/96018-01: 50-301/96018-01: Failure to follow prescribed i
procedures as outlined in TS 15.6.8.1 (2 examples), in regard to the first example:
during observation of control room activities, a unit control operator only once walked
down the entire panel over a four hour period. This was contrary to the expectations
stated in operations manual procedure OM 3.1. The inspectors verified that a revision
to operetions manual procedure OM 1.1, " Conduct of Operations," had incorporated
management expectations to monitor control panels on a frequent basis which included
a comprehensive review of the control panel Indications at regular intervals
(approximately every 15 minutes). Regarding the second example: during routine
testing of emergency diesel generator G 02, an operator failed to perform visual checks
of the test ports during a barring evolution (i.e. hand jacking of the engine for one
revolution). The inspectors verified that a recent revision of TS test TS 82," Emergency
Diesel Generator G-02 Monthly," had incorporated a management expectation to have
the operatur check the test ports for discharge following the barring evolution. The
inspectors concluded that the licensee's corrective actions had been appropriate. This
item is closed,
11. Maintenanga
M1 Conduct of Maintenance
M1.1 1).sgsf an Uncalibrated Stoowatch during Degraded and Loss of Voltage Surveillance
a. Insoection Scoce
The inspectors observed portions of the monthly technical specification surveillance for
4160/480 Volt relays for degraded ano loss of voltage, performed by electrical
maintenar,ce technicians and coordinated with the control room. The inspectors
reviewed the applicable procedures and interviewed operations, maintenance, and
supervisory personnel about current practices for taking timed measurements,
b. Observations and Findings
While observing 4160/480 Volt degraded and loss of voltage relay monthly sunteillances
on Unit 2, the inspectors noted that personnel used an uncalibrated stopwatch to
measure 4.16 kV bus undervoltage relays 2-274/A05,2-275/A05,2-276/A05,
2-27-4/A06(27-4),2-27-5/A06(27-5) and 2-27-6/A06(27-6) pickup time delay setpoint
values.
The licensee considered this instrument surveillance to be a channel functional test,
basically Intended to observe alarm lights and relay tripped indication. However, the
inspectors determined that the procedures,2RMP 9071-1 and 2RMP 9071-2, specified
a setpoint and low and high limits, creating acceptance criteria which had to be satisfied
to pass the test. The licensee stated that, for instrurnentation surveillances which were
chanael calibrations, timed measurements, as required by the TS on a refueling outage
frequency, used calibrated bench style equipment such as electronic timers or strip
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chart recorders. Although not required by TS, the licensee had extended the channel
functional check to include a calibration type timing test by specifying the lower and
upper timed limits in the monthly surveillance procedure. The failure to meet a l
survell!ance requirement acceptance criteria would require that the system or
component be declared inoperable and the appropriate limiting condition for operation
be en% red. By using an uncalibrated stopwatch the licensee did not have a verifiable
means to ensure that the acceptance criteria were met and that the measured
equipment was oporable. At the time of the inspection, the licensee had few
stopwatches in the calibration program and these were generally used for operational
tests such as valve stroke timing. The licensee wrote a condition report to evaluate all j
applications where an uncalibrated stopwatch might be used.
1
The inspectors also noted a weakness ir. that procedures 2RMP 9071 1 and 2RMP
90712 listed the stopwatch under " Tools" rather than as " Measurement and Test
Equipment."
The failure to use a calibrated stopwatch during the performance of these surveillances
is considered a violation of 10 CFR Part 50, Appendix B, Criterion Xil " Control of
Measuring and Test Equipment" (50-301/97023-02(DRS)).
c. Conclusions
l
The inspectors concluded that the licensee failed use calibrated t3st equipment,
controlled by a measuring and test equipment control program, to measure timed
acceptance limits in a technical specification monthly hurveillance.
.
M3 Maintenance Procedures and Documentation
M3.1 Review of Maintenance Procedurejii
a. inspection Scooe (40500)
The inspectors reviewed a number of maintenance procedures to verify that the licensee
included appropriate restoration steps foilowing maintenance,
b. Observations and Findinos
The inspectors noted that the procedures conformed with TS Section 15.6.8. The
procedures contained the steps to perform post maintenance testing (PMT) with blanks
for signature and date. In a few instances, the procedures were comprised entirely of
PMT requirements, The inspectors found that the maintenance procedure disascembly
and restoration reassembly steps were reasonably detailed. The steps included
diagrams and pictures of an exploded view of the assembly. There were foreign
material exclusion (FME) and cleanliness sign-offs before closure of the equipraent was
performed. The l&C maintenance procedures' PMT sections Vere considered to be the
"as left" data readings. When a step was not used during the maintenance, the step
was required to have "NA" written in the step to prevent confusion.
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The most recently approved procedures required verification that lie procedure was
current and any temporary changes were included. Additionally, tae procedures had a
section added for work scope, which was to be used to record the (ontrolling work
document numbers. The inspectors noted that the addition of a work scope block
provided the capability to trace other related work " packages' when the maintenance job
was completed and the procedure and other work documents were separated for
storage.
The inspectors ascertained that the procedures were classified into three levels for use
by the worker as follows: continuous use, eference use or information uso. The
continuous use procedure was required to be with worker at all times work wac being
performed. The reference use procedure was requ: red to be within easy access of the
workers at the job site. The information use procedures could be left at the shop after
the procedure was read. The level was printed on the bottom of each sheet in the
procedure as a reminder to the workers. The inspectors noted that all maintenance
procedures were appropriately labeled as either continuous or reference. Maintenance
workers stated that the recently rewritten maintenance procedures were more
comprehensive than the previous procedures,
c. Conclusions
The recent revisions to the maintenance procedures were determined to provide
sufficient restoration steps for reassembly and post maintenance testing.
M8 Miscellaneous Malntenance issues
M8.1 [Goted) Violatl0Dj0 266/94013-03: Actions Not Sufficient to Prevent Recurrence of
Broken Containment Integrity. The issue involved a repeat failure to prevent
containment integrity from being violated during testing of safety injection valves. To
resolve this issue, the licensee revised the testing procedures to ensure that testing
steps did not result in breaking containment integrity, as well as cautioning the
performers on the need to maintain containment integrity. The inspectors verified that
the procedures had been revised and that the problem had not recurred. The inspectors
concluded that this item was adequately resolved. This item is closed.
M8.2 (Closed) insoection Follow uo item 50-266/94013-04: Temporary Change Not Always
Generated to Correct Test Procedure Problems. The issue involved a temporary
procedure change not being issued, resulting in a repeat occurrence of the above event.
The inspection follow up item was for the inspectors to review future licensee event
reports to ensure that a similar event did not occur in the future. The inspectors verified
that events had not been repeated due to lack of procedure changes. The inspectors
noted that the licensee appeared to issue temporary changes appropriately. The
inspectors concluded that this item was adequately resolved. This item is closed.
M8.3 (Closed) Violation 50-266/95015-01: 50-301/95015-01: Reactor Vessel Head Removal
Procedure Did Not Contain Foreign Material Exclusion Closure Inspection Signoffs. The
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inspectors verified that procedure had been revised to include several hold points to
verify cleanliness as required by the FME procedure. This violation is closed.
M8,4 (Closed) Violation 50-301/96004 06: Failure to Follow Procedure for Temporary
Modification for 2MS2016. A blank flange was installed for work on the main steam
dump. Other recent performances of this same activity were handled correctly as a
temporary modification. The licensee briefed first line supervisors on temporary change
issues. The inspectors concluded that the licensee had taken appropriate actions. This
item is closed.
111. Engineeririg
E1 Conduct of Engineering
E1.1 Review of Ooerabi!ity Determinations (40500)
a. lDspection_ Scoce
The inspector reviewed approximately 40 recent operability determinations for scope,
content, and conclusions. The specific operability determinations reviewed are included
in the List of Documents Reviewed, at the end of this inspection report. The inspector
also reviewed NP 5.3.7 " Operability Determinations."
b. Observations and Findhgs
The inspectors did not find any operability determinations that appeared to reach an
incorrect conclusion. The overall quality of the operability determinations was good,
and, in some cases, the inspectors noted the operabili!y determinations to be quite
detailed. However, the inspectors had the following observations:
. Operability determinations were not stand alone documents. The associated
condition report listed the condition being evaluated and documented the
conclusion (whether the SSC was operable or inoperable.) Without the condition
report, it was not possible to determine what condition was being evaluated, and,
in some cases, it was difficult to ascertain the conclusion. The ability to
determine the conclusion reached was aggravated by the format of the prompt
operability determination: Question 6 on the foim stated " Basis for Declaring the
SSC Operable." This gave the impression that there was only one possible
response it an operability determination - that the SSC was operable. The
inspector reviewed two operability determinations where the prompt operability
determination appeared to provide actions that needed to be taken to ensure
operability, rather than describing why the SSC was operable. In both of these
cases (CRs 97-1918 and 97-2848) the inspectors determined that the condition
report described the SSC as inoperable.
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. In one example (CR 07 2802), the inspectors were unable to determine the basis
for the licensee's conclusion, since the operability determination stated that the
maximum neutron source term exceeded that in the cask certificates of
compliance; The inspectors disctssed the operability determination with the
responsible ongineers and learned that the licensee had concluded that the
casks were eperable, because only two assemblies (representing 4 percent and
33 percent of the respective cask loading) exceeded the limit. Since the average
neutron source limit for each cask was below the limit and radiation readings
taken at the time of loading did not show excessive neutron doses, the I!censee
concluded that the casks were operable. Based on this additional information,
the inspectors agreed with the licensee's conclusion.
. The inspectors identified a case where nine walkdown condition reports were
generateo and operability determinations were completed within a very short
time frame (all nine operability determinations were signed off within a few
minutes of each other). The inspectors found that four of the nine evaluations
were duplicates of the other five. The inspectors questionod the need for the
multiple evaluations and the overall quality of the evaluations, given the short
time taken to evaluate the issues. The inspectors were concemed that the
involved individuals did not have an appropriate appreciation for when separate
operability determinations were necessary and when issues could appropriately
be combined. This concern was heightened by the apparent lack of time spent
in generating the written determinations. The inspectors did not have any
concerns with the final conclusions reached on any of the evaluations, but were
concerned over the apparent process issues. In conversations with licensee
management, the licensee stated that these issues were reviewed and that they
had determined that separate operability determinations were appropriate;
however, the licensee was unable to justify why half the evaluations were
duplicates of the others.
- The inspectors noted that the Operability Determination procedure, NP 5.3.7,
stated that a log of operability determinations would be kept in the control room.
In actual practice, the log was kept in the work control center, adjacent to the
control room, and only logged those items which were considered " operable but
degraded," ratner than listing all operability determinations done. To obtain a log
of operability determinations completed, the inspectors had to contact an
individualin the licensing group. The licensee stated that they were aware of
this procedura! discrepancy. The licensee was in the process of revising NP
5.3.7, and stated that this problem, along with several other discrepancies, would
be addressed,
c. Conclusiqa
The inspectors concluded that the operability determinations reviewed were good, and,
in some cases, quite detailed. However, this was not true in all cases and a wide quality
spectrum was observed.
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E2 Engineering Support of Facilities and Equipment
E2.1 Utilization of Design Information in 10 CFR 50.59 Safety Evaluations
a. Insoection Scoce
The inspectors reviewed and evaluated the effectiveness of the licensee's process to
ensure that design information necessary for preparing adequate 10 CM 50.59 safety
evaluations was available to licensee personnel that prepared the safety evaluations,
b; Observations and Findings
The inspectors noted that the licensee's procedure, NP 10.3.1 defined the current
licensing basis (CLB) to include the final safety analysis report (FSAR), the facility
operating license and TS, the fire protection evaluation report, NRC safety evaluation
reports, and regulatory commitments. This list was considered to be a comprehensive
compilation of documents that encompassed the licensing basis. However, the design
bases documents (DBDs) were not specified as part of the CLB, although the inspectors
deemed that the DBDs "/ould be a va'uable tool for performing design information
search and evaluation.
The inspectors noted that the CLB and DBDs were availaole for review as part of the
licensee's electronic database and could be accessed. The inspectors observed a
demonstration of the electronic database and noted that, to obtain the most meaningful
data, some skill in defining the keyword searches was required since nomenclature was
not necessarily consistently used in documents developed over the history of the plant.
However, overall plant information was available on the computer,
c. Conclusions
The inspectors concluded that the licensee's 10 CFR 50.59 procedure contained a
comprehensive listing of licensing basis documents which would allow preparation of
adequate 50.59 safety evaluations.
E2.2 Safetv Evaluation Review
a. 10sprrtion Scoon (37001)
The inspectors reviewed a sampling of 11 screenings and 11 safety evaluations
performed in accordance with 10 CFR 50.59 since July 1997.
b. Observatiori 'nd Fladings
Overall, the ir.spectors considered the quality of the screenings and safety evaluations
to be good. The inspectors did not ident!fy any screenings where safety evaluations
were required, nor did the inspectort find any unidentified unreviewed safety questions
(USO).
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Th'e inspectors identified two safety evaluations where the quality was considerably
- above average. These safety evaluations did a meticulous review of the design bases
of the systems and thoroughly evaluated the impact of the change. The preparers
l answered each of the questions posed in 10 CFR 50.59 in sufficient detail to ensure that
- an USQ did not exist. For each question, ample information was pr /lded to enable an
- independent reviewer to reach the same conclusion.
I
However, the inspectors did identify a case where the FSAR should have been updated,
but hadn't been. Screening 97-1352 made a change to the procedure for releasing
- liquid radioactive discharges from the chemical volume and control system (CVCS)
'
holdup tanks. In reviewing the screening, the inspectors identified that the FSAR
section 11.1 discussed discharging radioactive releases from the CVCS. The FSAR
stated that all routine liquid radioactive releases were made from waste disposal system
waste condensate /oistillate tanks or from CVCS monitor tanks. Instead, the licensee
l
l was releasing directly from the holdup tanks. The inspectors determined that the .
- licensee altered the release method in 1988, due to their no longer recycling borated
,
water. At that time, a full safety evaluation was performed, which concluded that
dischargw.g directly from the "B" holdup tank was acceptable, as the discharge path was
monitored and contained automatic isolation valves. However, the licensee failed to
,'
ensure that the FSAR was revised to reflect the new release path.
The inspectors determined that, although the 97-1352 screening was titled as a
! complete rewrite of the procedure, the screening preparer had narrowly focused on the
specific changes being made and had not looked at the actual FSAR description of how
the discharge was performed. Therefore, the screening pieparer did not write a
j condition report or otherwise identify that the FSAR had not been updated. Violation
! 50-266/96002-05(DRP); 50-301/96002-05(ORP) previously identified that changes to
- the plant, systems and parameters were not routinely updated into the FSAR. The
,
failure to identify during the 1997 screening review that the FSAR was incorrect is an
j example of the failure to affect long term corrective actions for a previously identified
programmatic weakness with the performance of updating the FSAR. This is
l considered an example of a 10 CFR Part 50, Appendix B, Cri'erion XVI " Corrective
j Actions" violation (VIO 50-266/97023-03a(DRS); 50-301/97023-03a(DRS)).
c. Conclusions
t
l The inspectors concluded that the safety evaluations and screenings being performed
'
were of good quality and some were considerably above average. However, one
screening failed to identify that the FSAR did not reflect the current plant procedures,
r
a
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! E3 Engineering Procedures and Documentation
.
E3.1 Programmatic Review of the FSAR including the Uodate Prooram and Resoonsibilities
,
a. Insoection Scoco (37001)
.
The instactors evaluated the effectiveness of the licensee's formal procedural guidance
established icr arsigning responsibility for preparing and submitting the periodic update
of the FSAR. Ado;hally, the inspectors reviewed and evaluated the effectiveness of
the process by the whirA licensee was updating its FSAR and reviewed selected
'
changes in the facility and proceoures made in accordance with 10 CFR 50.59.
4
b. Observations and Findings
,
The inspectors noted instances of imprecise wording for the procedure guidance as
developed from the regulation. Procedure NP 5.2.6,"FSAR Updates," Section 1.3 -
stated "The NRC 10 CFR 50.71(c) requires that revisions be filed no less frequently
than annually ..." and Section 4.2 states "As required by 50 CFR 71(e) ... the FSAR is
updated on at least an annual basis to include all changes necessary to reflect
i
information and analyses submitted to the NRC since the last update of the FSAR."
However,10 CFR 50.71(e) actually required that subsequent revisions be filed either
annually or 6 months after each refueling outage provided the interval between
successive updates did not exceed 24 months. Further, procedure NP 5.2.6 was not
clear on how the submittal of changes under 50.5?, which were not otherwise submitted,
was assured, in accordance with 10 CFR 50.71(e)(2). The inspectors determined that,
l although not referenced in procedure NP 5.2.6, the licensee did make a 50.59 annual
submittal under the 50.59 program using another procedure, IJP 10.3.1. As the
submittal appeared to be properly made, the inspectors considered this to be a
procedural weakness, in another example, NP 5.2.6, Section 4.12 stated. "The revision
package shall be sent to the NRC, in accordance with 10 CFR 50.4." Although not
incorrect, the procedure would be more accurate to state "... In accordance with 10 CFR 3 50.71(e)."
The inspectors noted instances where the !.:vnse's program appeared to have failed to
ensure that the FSAR would be updated. For example, the licensee failed to prepare a
FSAR change request (FCR) for FSAR Tables 8.21 and 8.2-?, diesel generator load
values for conditions following a loss of coolant accident. Engineering Calculation
N 91-016, Rev. 2, which had been revie,ved and accepted in June 1997, changed
important accident condition load values in these tables. The inspectors determined
that one of the reasons for a FCR not being generated was a lack of specific procedural
requirement as to an acceptable time frame to generate the FCR. In this case, the
inspectors determined that the responsible engineer knew that the FSAR renuired
updating, and had a personal action item to eventually ensure the update occurred.
However, there was no corrective action tracking item or other formal tracking
mechanism to ensure that the update was completed on a schedule commensurate with
the next FSAR 7pdate. The inspectors considered the lack of procedural guidance on
tracking of known changes needed to the FSAR a programmatic weakness.
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c. Conclusions
lhe inspectors identified that formal procedural guidance had been established, but was
imprecisely worded. The procedure assigned primary responsibility for preparing and
submitting the periodic update of the FSAR to an individual without any guidance on
timeliness.
E3.2 Safetv Evaluation Proaram Resoonsibilities and Procedural Guidance
a. Insoection Scooe
The inspectors evaluated the formal procedural guidance implementing the
requirements of 10 CFR 50.59 for proposed changes, tests and experiments (CTEs).
Additionally, the inspectors reviewed the responsibilities that the licensee's 50.59
procedure assigned to individuals, including assessing and documenting whether a
change to the plant TS or an USQ was involved, procedural guidance for maintaining
50.59 records of CTEs and for formally reporting to the NRC the CTEs made in
accordance with 50.59.
b. Observations and Findinas
The licensee staff had conducted a thorough review of the program and had recently
recommended changes based on that review. In May 1997, the licensee issued a
detailed rewrite of procedure, NP 10.3.1 " Authorization of Changes, Tests, and
Experiments," and revbed the procedure again in September 1997. The inspectors
noted that NP 10.3.1 had expanded attachments which provided more details and a
clearer definition of safety evaluation expectations, prescreening applicability guidance
screening guidance, and safety evaluation preparation guidance. Formal training was
given to staff designated to perform screenings and staff assigned to perform both
screenings and safety evaluations. The training acquainted the staff with industry
practices, higher expectations in proposed industry standards and in the changes to the
NP 10.3.1 procedure with emphasis on historically weak areas, such as what constituted
an USQ or TS change, This is described in more detailin Section E5.1.
The inspectors noted that the licensee's 10 CFR 50.59 procedure effectively assigned
responsibility for key areas including applicability, review and approval of 10 CFR 50.59
applicability determinations, preparation of safety evaluations for CTEs that required
them, review and approval of safety evaluations as required by the TS and the
NRC-approved operational quality assuranec program, formally reporting to the NRC
CTEs made in accordance with 10 CFR 50.:i4, and maintaining records of CTEs made
in accordance with 10 CFR 50.59.
The inspectors noted that the existing procedure stated the requirements for maintaining
records within the existing files in accordance with applicable records retention
requirements. The inspectors successfully retrieved a number of records to confirm the
retrieval capability.
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- c. _ Conclusions
. The inspactors concluded that recent changes to NP 10.3.1 have resulted in improved
procedural guidance for screening ar.d writing 10 CFR 50.59 safety evaluations. The
inspectors concluded the 10 CFR 50.59 procedure effectively assigned responsibility for
!
key areas to assure that 50.59 safety evaluations were effectively prepared, reviewed
and approved. Additionally, the inspectors concluded the necessary procedural
guidance existed for maintaining records of CTEs and for formally reporting to the NRC
j the CTEs made in accordance with 10 CFR 50.39.
a
E5 Engineering Staff Training and Qualification
- E5.1 Review of Engineering Training on Preoaration of Safety Evaluations
a. insoection Scoce
The inspectors reviewed the licensee's training and qualification program requirements
- for licensee personnel that prepared, reviewed, or approved t;afety evaluations.
b. Findings and Observations
,
The review showed that the Safety evaluation training was provided to the plant staff in a
, two day session with the usual class size of approximately 20 stt.de:its. Training was
provided by an outside contractor, who also wrote the training manual used in the
course. The students were provided a copy of the trairing manual at the completion of
i
the course and were encouraged to use it as a reference. The students were taught
how to differentiate between CLB design information and FSAR/10 CFR 50.2 design
basis criteria. The lesson plans emphasized the fact that the evaluation was performed
- to identify any USQs, The training emphasized that some changes required prior NRC
review; but that did not necessarily mean that the change should not be made.
,
During the course the students had workshop sessions for writing and reviewing
50.59/72.48 screenings and safety evaluations. The examples used for practice were
situations that may have occurred at the site or from other sources. The students
practiced using the CLB electronic database. Satisfactory completien of the course
required passing a written examination and performing on-the-job screenings and
evaluations on actual plant conditions under the instruction of a qualified screening and
safety evaluation evaluator,
i
The licensee did not have a formal method for controlling what discipline performed the
evaluation. The system that was being used was the evaluator determined if he was
qualified to perform the evaluation, and if not, passed the task to one that was qualified.
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The inspectors ascertained that most of tht, plant engineering and licensing staff have
been tralned and qualified to perform safety evaluation screenings and safety
evaluations. A portion of the operations group had been trained and qualified, with more
scheduled for a future class.
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4 c. Conclusions
l The training and qualification of licensee personnel to perform screenings and safety
'
evaluations appeared to be comprehensivo and met the licensee's commitments to the
NRC foll wing the operational safety team inspection conducted in late 1996.
E5.2 Cnnalitency Between Plant Safety Evaluation Procedures and Training ,
k
The inspectors leviewed the tralning materials to ensure they were consisteni w'th the
,
licenree's current procedural guiuance for preparing safety evaluations. The inspectors
'
confirmed that lesson plans referred to the course book, and the most recent revis'.on of
NP 10.3.1. The lesson pbns emphasized that NP 10.3.1 provided controls for the
preparation of screenings and safety evaluations at Point Beach. The inspectors
concluded that there was consistency between the training and procedural requirements
for preparing safety evaluations.
E5.3 Iralning EHecilysncis
The inspectors reviewed the licensee's process for assessing training effectiveness and
determined that the licensee did not have formal method for evaluating 50.59/72.48
4 training. instead the licensee used the quality of the evaluations that had been written
4
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as a quality control check on the training effectiveness. The licensee considered the
recently performed screenings and safety evaluations to be of high quality. The
,'
inspectors concluded that the currently in use tralning evaluation method appeared
salit. factory as of the time of the inspection.
I E8 Miscellaneous Engineering issues
E8.1 (Closed)_Wolation 50-20D/94016-01; 50-301/94016-01: Foreign Materials Exclusion
- Controls / Failure to include Assumptions and inputs. The issue involved two examples
of a procedural violation. The first issue dealt with a FME Inspection being conducted by
a worker, rather than a supervisor. To resolve this issue, the licensee reiterated the
expectations for FME closecut inspections. However, these corrective actions were not
entirely effective, as evidenced by repeat violations in 1995 anel 1996. While the
corrective actions to the 1996 violation were still underwry, the actions were identical to '
those 6ddressing violation 50 26P/96008-02. Therefore, these actions will be tracked by
50 266/96008-02. The second issue dealt with calculations not containing assumptions
or design inputs. The licensee revised their calculation program to specifically require
doc" mentation of design inputs ano sssumptions. The licensee also confirmed that
design :nputs and assumptions were in the calculations cited in the violation, although
not clearly defined, During the inspection, the Inspectors reviewed EDG calculation
N-91016 " Diesel Generator Loading Analysis," and verified that design inputs and
O-
.
24
w - v pv - e , cy_____. _ _ 4 ~ -* -e -
__ __. _ _ _ _ _ _ _ _ . _ __ _ _ _ _ _ _ _ _ - _ _ . _ _ __ __ __ _ _ _ _ _ _ . . _ _ _
. .
.
assumptbns were clearly documented, in accordance with the calculation procedure.
Based on the procedural controls and the example reviewed, the inspectors concluded
that this issue was resolved. This item is closed.
E8.2 (QQsed) Inspection FollOYLMD ltem 50 266/95004-07: 50d01/95004-01: Mitigating
Actions for Grid Instability Concems. The issue involved the control room receiving a
draf t copy of proposed actions to be taken in response to various grid instability
situations. In response to the item, the licensee pulled the draft information from the
control room. The licensee also made some changes to an operating procedure,
although it still remained more limiting than the draft information. The system engineer
and operating personnel stated that future plans to resolve this issue included
replacement of the original plant voltage regulators, which should result in less plant
perturbations due to grid instabilities. The licensee had also identified that the FSAR
section on grid instabilities needed clarifying, based upon an action item in the nuclear
tracking system. The inspectors determined that, although the FSAR changes were
known for several years, the responsible 8ndividuals had not yet submitted a FSAR
update form to the FSAR coordinator nor had constraints been placed in the corrective
action tracking system to ensure the change was incorporated. The inspectors
discussed the issue with the responsible engineer, who stated that the FSAR
coordinator would send out a memo requesting FSAR changes just prior to each
update, and that he planned on respondir'g to that memo; hc vever, he acknowledged
that he had missed previous opportunities to update the FSAR, due to this being a " low
priority item." Violation 50 266/96002-05(DRP); 50 301/96002-05(DRP) previously
identified that changas to the plant, systems and parameters were not routinely updated
into the FSAR This was another example of the failure to affect long term corrective
actions for a previously identified programmatic weakness with the performance of
updating the FSAR (VIO 50 266/97023 03b(DRS); 50 301/97023 03b(DRS)). The
inspection follow up item is closed.
E8.3 [QQaed) Insoection Follow uo item 50 266/96002 03: 50-301/95002-Q: Under Severe
Cold Weather 345 kV Breakers Lost Compressed Air Pressure Needed for Arc
Quenching. Cold weather differential shrinking of the materials used in the air tank,
gasket and access cover, resulted in cover leaks and loss of air pressure. In February
1996, three breakers lost sufficient air pressure to change state and remained locked in
the closed position. This condition reduced electrical coordination and limited flexibility
to respond to external difficulties on the grid. The licensee implemented a work around
by bringing in additional air compressors. To remedy th!s issue, the licensee replaced,
or was in the process of replacing, the six most irrportant 345 kV breakers with another
design which suppressed the are usin0 sulfur he'<afluoride (SF ) rather than compressed
air. By utilizing the air compressors whic.h formarly supplied the six breakers now using
SF., the remaining old style General Electric breakers will have dual air compressors
lessening their vulnerability. Additionally, the licensee revised abnormal operating
procedure AOP 13C " Severe Weather Conditions" to provide a more detailed response.
The inspectors concluded that these actions effectively addressed the issue. This item
is closed.
25
__ _ _ - _ _ __ _ __ -_ ___ .-_-- _ _ _ _ _ _
_
. .- - - - . - .. - - _. - - - - - - - _ - - . -
,.--
E8.4 (Closed) Violation 50401/96004 05: Failure to Perform Safety Evaluation for 2MS2016
Temporary Modification. When performing a maintenance activity involving installing a
blank flange while the steam dump valve was being repaired, the safety screening
improperly concluded that a 10 CFR 50.59 was not required. C'ther recent
'
performances of this same activity were handled correctly with a safety evaluation. The
licensee has briefed the Maintenance Department on 10 CFR 50.59 and temporary
change issues. Additionally, the licensee has conducted training for all safety screeners
and safety evaluators in early 1997 to upgrade the skilllevel and understanding of the
requirements of 10 CFR 50.59. The inspectors concluded that the licensee had taken
q appropriate actions. This item is closed.
E8.5 (Closed) Violation 50 266/06012-07: 50 301/96012 07: Repositioning of the Boric Acid
Storage Tank to Safety injection Pump Valve 1SI 826A Without a Safety Evaluation.
The issue inwived a change to the plant which revised a FSAR drawing. Following ,
issuance of the violation, the licensee prepared a safety evaluation, which determined
that no unreviewed safety questions existed. Additionally, the licensee has conducted
training for all safety screeners and safety evaluators in early 1997 to upgrade the skill
level and understanding of the requirements of 10 CFR 50.59. The inspectors reviewed
the safety evaluation and found it acceptable. This item is closed.
E8.6 (Closed) Violation 50 266/96018 20: 50-301/96018 20: No Licensee Event Report
. (LER) for Missed Leakage Tests. The issue involved an LER not being issued for a
reportable event. To resolve this issue, the licensee revised procedure NP 5.3,1
" Condition Reporting System" to require that an action item be specifically generated to
remind licensing personnel that an LER was required. The inspectors verified that the
procedure was revised. This item is closed.
IV. Plant Sunged
R8 Miscellaneous Radiation Protection issues
R8.1 (Closed) Violation 50-266/96003-05: Unauthorized Entry into Posted High Radiation
Area. The Unit 1 Containment was posted as a high radiation area in anticipation of
changing radiological conditions due to the imminent reactor head lift, A within plant
announcement declared the containment access restriction, but the worker apparently
did not hear the message. The worker entered the containment with several authorized
workers while the radiation boundary rope was temporarily raised and apparently did not
read the high radiation posting attached to the rope. A health physics (HP) technician
soon discovered the worker was not signed on to the appropriate radiation work permit
and did not have the required dosimetry. To resolve this issue of worker awareness of
entry into high radiation area boundaries, the licensee added temporary swing gates and
containment third doors. Additionally, electronic bulletin boards at the normal entrance
to the radiologically controlled area and bulletin boards at the HP station provided
information on radiological condition or posting changes. The inspectors concluded that
the licensee had taken appropriate actions. This item is closed.
26
,
r y - . . , - ~ -
-_ -
, . , , . . -
. ~ . - - - , , - - . , . . . , , - - . ~ _ , , . . . _ - ._e, _ , . ~ , -
. -_ -_ _-
, o
,
R8.2 LQosedLMolation 60 266/96004-02: 50-301/96004 02: Failure to Folicw Contamination l
Control Procedures. A worker passed a wrench from the contaminated area to a HP
technician in the uncontaminated area who was not wearing gloves. After wiping the
wrench the HP technician passed the wrench to another worker also not wearing gloves
who stored the wrench in the potentially contaminated tool box. The wrench was not
surveyed or controlled until routinely surveyed as required by procedures. In response
to this issue, the licensec discussed the event with HP technicians and the HP support
staff. Additionally, the licensee recognized the need for heightened attention and
designated " Health Physics . improve radiation workers standards and performance" as
item #4 on the Near Term Station Focus List. The inspectors concluded that the l
licensee had taken reasonable action to resolve this issue. This item is closed. :
F8 Miscellaneous Fire Protection issues
F8.1 LQnen) Violation 50-266/94015-01: 50-301/94015-01: Combustible Controls for Hot
Work. The issue involved observation of combustible material within 35 foot of grinding
activities (a poterillal fire source). In response, the licensee revised the procedure to
provide better control over hot work preparation. The inspectors reviewed the
'
procedure and discussed hot work preparation activities with the responsible fire
protection individual. The inspectors noted that the procetJte used the words "should"
frequently, although *shall" was used in some places. The inspectors questioned
various licensee personnel about the intended meaning of these two words. Licensee
management replied that the intention was that both words should be treated the same:
as a requirement. The responsible individual stated that personnel preparing to perform
hot work were supposed to follow the procedure, and, generally did so. Because the
procedural controls were somewhat lax, this item will remain open, pending inspector
observation of actual hot work preparation.
F8.2 (Gosed) Violation 50-266/96007-03: 50-301/96007-03: Inadequate Test
Documentation. The issue involved improper performance of a fire damper test. The
licensee revised the procedure, PC 75, Parts 6 and 7, " Semi-Annual Diesel Generator
Fire Damper and Ventilation Surveillance Test" to require additional operators to ensure
that all dampers could be observed, so that an accurate closure time could be obtained.
The inspectors reviewed the guidance and concluded that it was acceptable. This issue
is closed.
L.Manasement Me.gtinga
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on November 7,1997. 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.
27
.- - _ . - - - _ _ - . _ - - .- - . - - _ - - - . . _ .- .- .
,.* *
1
'
PARTIAL LIST OF PERSONS CONTACTED
,
(
Licensas .
'
Wisconsin Electric Power Comoany (WEPCO)
G. L. Boldt, Special Assistant to the Site Vice President
J. B. Brander, Senior Project Specialist Maintenance Services
A. J. Cayla, Plant Manager
-
i F. A. Flentje, Regulatory Specialist '
,
W. B. Fromm, Maintenance Manager
,
R. K. Hanneman, Senior Project Eng:neer, Continuous Saf6ty & Performance Assessment
- F. P. Hennessy, Corrective Action Program Maneger
N. L. Hoefert, Continuous safety and Performance Assessment Manager
,
R. F. Hornak, Senior Project Engineer Site Engineering l
" 1
D. F. Johnson, Regulatory Services & Licensing Manager '
-
J. E. Knorr, Regulation & Compilance Manager
O. W. Krause, Project 8 Engineer - Nuclear Engineering
R. G. Mende, Operations Manager
S. A. Pfaff, Operating Experience Coordinator
M. E. Reddemann, Quality Assurance Manager
J. G. Schweitzer, Site Engineering Manager
1- G. R. Sherwood, Malntenance Field Services Manager
P. J. Smith, Operations Training Coordinator
J. S. Stanford, Operations Consultant
- J. G. Thorgersen, Senior Project Engineer - Quality Verification
Nuclear Regulatory Commission
F. D, Brown, Senior Resident inspector
P. L. Louden Resident inspector
A. C. McMurtray, Senior Resident inspector
INSPECTION PROCEDURES USED
IP 37001 10 CFR 50.59 Safety Evaluation Program
IP 40500 Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing ;
Problems
IP 93802 Operational Safety Team inspection (OSTI) ,
,
6
28
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2
ITEMS OPENED AND CLOSED
l Ooened
50 266/301 97023-01 . VIO Two Examples of Failure to Follow Procedures
50 301 97023 02 VIO Use of Uncalibrated Stop Watch During Surveillance
50 266/301 97023 03 VIO T wo Examples of Failure to Ensure FSAR Updated
G u ttd
50 266 94013 03 VIO Actions Not Sufficient to Prevent Recurrence of Broken
Containment Integrity
50 266 94013 04 IFl Temporary Change Not Always Generated to Correct Test
Procedure Problems
50 266/301 94016-01 VIO Foreign Materials Exclusion Controls / Failure to include
Assumptions and inputs
50 266/301 95004 07 IFl Mitigating Actions for Grid Instability Concerns
50 266/301 95015-01 VIO No Foreign Materials Exclusion Requirements or Closure
inspection Sign off
50 266/301 96002 03 IFl Severe Weather Conditions
50 266/301 96003 01 VIO Procedures for Surveillance and Testing of Safety Related
Equipment
50 266 96003-05 VIO Unauthorized Entry into Posted High Radiation Area
50 266/301 96004 02 VIO Failure to Follow Contamination Control Procedures
50 301 96004 05 VIO Failure to Perform Safety Evaluation for 2MS2016
50 301 96004-06 VIO Failure to Follow Procedure for Temporary Modification for
2MS2016
50 266/301 96006-02 VIO Inadequate Control Room Log Entries
50 266/301 96007 03 VIO Inadequate Test Documentation
50 266/301 96012-07 VIO Repositioning of the Boric Acid Storage Tank to Safety
injection Pump Valve 1SI 826A Without a Safety
Evaluation
50 266/301 96018-01 VIO Failure to Follow TS 15.6.8.1 Procedures
50 266/301 96018-02 IFl Fire Brigade and Control Room Staffing
50 266/301 96018 20 VIO No Licensee Event Report for Missed Leakage Tests ,
Disnuuttd
50 266/301 94015-01 VIO Combustible Controls for Hot Work.
29
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LIST OF ACRONYMS USED .
AOP Abnormal Operating Procedure !
CAP Corrective Action Program .
CLB Current Licensing Basis .
CO Control Operator
CR Condition Report .
'
CTE Changes, Tests, and Experiments
CVCS Chemical, Volume and Control System r
DBD Design Basis Document -
DOS Duty Operating Supervisor
DSS Duty Shift Superintendent
EDG Emergency Diesel Generator j
FCR FSAR Change Request
FME Foreign Material Exclusion
FSAR Finst Safety Analysis Report
HP Health Phyelcs
ICP Instrumentation and Control Procedures (Licensoe Procedure)
INPO Institute of Nuclear Power Operations
IST Inservice Testing -
lT Inservice Test (Licensee Procedure)
LED Licensee Event Report 7
'
LTOP Low Temperature Overpressure Protection
NUTRK Nuclear Tracking (Computer Program acronym)
OEC Operating Experience Coordinator
OP Operating Procedure (Licensee Procedure)
PC Periodic Checks (Licensee Procedure)
POD Prompt Operability Determination
PMT Post Maintenance Testing
'
PSIG Pounds per Square Inch, Gage
QA Quality Assurance
OCR Quality Condition Report
RCP Reactor Coolant Pump
RMP Routine Maintenance Procedure (Licensee Procedure).
SCR Safety Evaluation Screenings
SE Safety Evaluations
SOER Significant Operating Event Reports i
SRO Senior Reactor Operator
SSC System, Structure or Component
TS Technical Specification
VIO Violation
USQ Unreviewed Safety Question
,
3-
30-
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LIST OF DOCUMENTS REVIEWED ,
1
The following is a list of licensee documents reviewed during the inspection, including
I
documents prepared by others for the licensee, inclusion on this list does not imply that NRC
inspectors reviewed the documents in their entirety, but, rather that selected sections or
portions of the documents were evaluated as part of the overallinspection effort inclusion of a
i document in this list does not imply NRC acceptance of the document, unless specifically stated
j in the body of the inspection repor'. ,
I
- Abnormal Ooerating Procedures
'
AOP 13C Severe Weather Conditions, Rev. 6
i !
Administrative Procedules (NPs) y
1.9.13 Ignition Control Procedure, Rev.2,8/29/97 '
1.9.15 Danger Tag Procedure, Rev. 3
5.2.6 FSAR Updates Rev. 2
5.2.7 Technical Specification and Bases Change Preparation Review and Approval, .
Rev.2
Condition Reporting System, Rev 6,9/24/97 ;
5.3.1
5.3.2 Industry Operating Experience Review Program, Rev,4,7/25/97
5.3.7 Operability Determinations, Rev. 2,7/3/97
4
7.3.1 Temporary Modifications, Rev. 5
9.3.3 Spare Parts Equivalency Evaluation, Rev.1,8/25/95
10.3.1 Authorization of Changes, Tests, and Experiments (10 CFR 50.59 and 72.48
Reviews), Rev. 5 and 7
11.2.4 Self Assessment Guideline, Rev. O,1/31/97 -
Calculatl0DS i
N 91016 Diesel Generator Loading Analysis, Rev. 2,6/18/97
NPM 97 0329 Stroke Time Performance Requirements for Valves in the IST Program,5/22/97
.
Condition Reoorts (CRs)
2
(Note: Some of these CRs may have prompt operability determinations (PODS); however, the
PODS were not reviewed.)
91 0351 - Unresolved Q-List Project Seismic Classification,9/17/91
92 0261 Operation of Either or Both Units with Degraded Transmission Configurations,
5/19/92
96-0071 Actual Mechanical Seal Leakage from the RHR, SI, and CS Pumps Does Not
Meet the FSAR Requirements,2/20/96
96 0072 EOP 1.3 " Transfer to Containment Sump Recirculation" Does Not Allow Actions
Assumed in FSAR Containment Integrity Analysis,2/21/96
. 96 0719 Piping Analyses Contain improper Temperatures,9/6/96
31
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. _ , _
,.. '
96 0879 Potential improper Evaluation of 1(2) RH 715D for Boundary Leakage Tests,
9/20/96
96-0936 Unit 1 RHR Pump Suction RTD Blocked by I Beam Support,9/26/96
96-0977 Between Train Leakage is Not Qualified,10/4/96
96 1072 Unit 2 RHR Piping Support Has Broken Tack Welds,10/10/96
96 1109 Component Cooling Water Leak on Unit 2 RHR Heat Exchanger Outlet,10/10/96
98 1292 NP 3.1.1 Chemical Contamination Control for Corrosive Resistant Alloys,11/1/96
96 1501 Second Instance of Kerotest Valve Failures,11/24/96
96 1746 RHR Pump Operated with No Recirc Path,12/16/96
96 1794 There is No Plant Procedure for Placing the Alternate Seal Cooling in Operation,
12/19/96
96 1844 OP 7A&B, IT 03 and IT-04, RHR System, 12/19/96
97-0130 RHR Pump Casing Drain Plug Shows Signs of Boric Acid Buildup,1/15/97
97 0199 Pressure Indicators Overranged During Test Performance,1/22/97
97-0217 NP 3.1.1 Duct Tape on Stainless Steel Piping,1/21/97
97 0246 . During Danger Tag Removal, Valves Discovered Mis positioned,1/24/97
97 0321 increased Radiation Doses to Equipment Outside of Containment,1/30/97
97-0376 RHR Pump Operated at less than Minimum Total Flow,2/5/97
97 0539 Unanticipated Load Shedding,2/16/97
97 0649 Potential Leakage Past Check Valve 1SI 867B,2/26/97
97-0684 CCW Heat Exchanger High Temperature Alarm Received,3/2/97
97 0685 Service Water Flow Line Up,2/28/97
97-0741 Danger Tag Missing,3/5/97
97-0857 RH 720 Failed to Operate as Expected 3/15/97
97-0878 RHR Pressure Gages Overranged During Test,3/18/97
97-0921 RHR Recirculation Line Flow Indicator out of Calibration,3/21/97
97 1076 Potential to Overpressurize a Portion of the RHR System,4/3/97
97 1117 Received "D 01/D 03125V DC Bus Under/Over Voltage" Alarm During
Performance of TS 81,4/7/97
97 1141 Unisolated Flow Path,4/11/97
97 1261 Calculation 95107 has Numerous Discrepancies
97 1295 RMP-9096 Debris Screen Installation Conditions,4/21/97
97-1302 Calculation P89 06."G01 Fuelline Wear Stress Calculation" Has Various Errors
97 1303 Simulator Testing Showed That the EDG Would Be Overloaded During a
Simultaneous LOOP /LOCA
97 1341 Emergency Lighting Test Requirements May Not Satisfy Technical Specification
Testing Requirements
97-1345 Design Guideline DG E06 * Design Guide to Evaluate Changes for Effect on
Diesel Loading" Does Not Provide Specific Criteria on Determining Which Loads
Should Be Evaluated
97-1357 Operability Determination Performed under CR 97 0017 May Not Be Valid
97-1412 There Does Not Appear to Be Any Integrated Functional Testing of EDG '
Ventilation
97 1446 ECCS Use Described in FSAR Does Not Agree with Procedures,4/29/97
,- 97 1454 - -RMP Mot Reflecting Manufacturer's Recommended Installation Instructions,
5/2/97
97-1599- Isolation Boundary Was Red Locked Versus Danger Tagged Shut,5/19/97
97 1699 Control Room Annunciator Supply Breaker Operates incorrectly,5/27/97
97-1735 Inadequate Maintenance Procedure, S/30/97
32
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,
. . *
97 1989 Valve Repositioned Resulting in Loss of Status 5/12/97
97 2212 RHR Operability vs. SW Outlet Valves on CCW Heat Exchanger,7/20/97
97 2310 Component Cooling Water Leak on Unit 2 RHR Heat Exchanger Outlet,8/8/97
97 2351 RHR Pump Seal Leakage,8/4/97
97 2388 RHR Pump Seal Leakage Increases,8/5/97
97 2439 Errors Discovered in CR 971918 Operability Determination,8/7/97
97 2588 U2 R22 Restart Commitment Not Adequately Resolving ECC Commitment,
9/1/97
97 2629 RHR Pump Has a Seal Leak,8/3/97
97 2661 Poor Radiological Practice with Plastic Bags on Test Connections,8/29/97
97 2895 Started 2P10B RHR Pump with No Discharge Pressure on 2PI 629,9/16/97
97 3290 Work Outside of Scope of Approved Procedure,10/10/97
97 3330 Inadequate Surveillance of Reactor Trip Breakers,10/13/97
97 3341 Inadequate Prompt Operability Determination (POD) for CR 97 3324,10/15/97
Condition Reports with Anociated Promot Ooerability Determinations
97 1361 Calculation N 91016 " Diesel Generator Loading Analysis" Has Several Unclear
Assumptions or Bases,4/23/97; POD,4/25/97
97 1918 Auxiliary Feedwater System Low Pump Suction Pressure Trip Does Not Provide
Required Protection to the AFW Pumps,10/19/97; POD, Rev.0,7/14/97 and
Rev 1,8/8/97
97 2347 Differential Relay Test Curve Calibration at Higher Point,8/1/97; POD,8/2/97
97 2406 NDE Examination insufficient,8/8/97; POD,8/8/97
97 2413 Service Air (SA)Intercooler Pressure Design Requirements,8/8/97; POD,8/8/97
97 2416 IT 04 Low Head Safety injector Flow Indicator,8/10/97
97 2440 Upper Condensing Pot Vibrations,8/11/97; POD,8/12/97
97 2458 STPT 19.1 Procedure Discrepancies,8/13/97; POD,8/13/97
97 2483 Service Water Hydraulic Model Configuration Error; 8/18/97; POD,8/15/97
97 2493 Morrison Knudsen Welds on U2 Steam Generator Replacement Project,8/13/97;
FOD, 8/14/97
97 2522 D-305 Voltages Found Outside of Tolerance,8/18/97; POD,8/19/97
97 2559 Over Compensated Spring Hanger Rod Realignment,8/22/97; POD,8/22/97
97 2562 10 CFR Part 21 on Molded Case Circuit Breakers,8/22/97; POD,8/23/97
97 2664 Common 125V DC Circuits with AFW Low Suction Trip,8/26/97; POD, Rev 0,
8/29/97, Rev.1,9/29/97
97-2714 Quarterly Callup for 5 Cells of D-06 Battery Found Out-of Spec,9/3/97; POD,
9/5/97
97-2755 Pilot Cell #44 Specific Gravity for D 305 Battery Found Out of Spec,9/8/97;
POD,9/8/97
97 2802 ORIGEN2 Software Fuel Assembly Burnup Values for Dry Fuel Storage,9/8/97;
POD,9/8/97
97 2829 QA Equipment Calibrated with Non-QA Cal Gas,9/12/97; POD,9/12/97
97 2847 Reconcile dP Testing of MOVs with CMP 2.2.8 Design Basis Cales,9/13/97;
POD,9/13/97
97 2848 1 CV 112C Operator Housing Cover Hold Down Bolts Loose,9/12/97; POD,
9/17/97
97 2851 Voltage Dips During EDG Transient Safeguards Load Sequencing,9/11/97;
POD,9/14/97
4
33
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97 2862 Unit 2 "A" Train RHR Piping Overpressuritation during IT 536,9/15/97; POD,
,
9/15/97
- 97 3082 ASME Section XI Preservice Volumetric Exam Requirement,9/25/97: POD,
! 9/26/97 <
l 97-3084 Appendix R Spare CCW Pump Motor Coupling,9/25/97; POD,9/26/97 j
'
'
97 3117 Blockwall Crack 44 Foot Elevation at SFP Northside Walkway,9/30/97; POD,
t 9/30/97 !
i 97 3118 Crack in Turbine Building Block Wall,9/30/97; POD,9/30/97
97 3119 Northwest Corner of Unit 2 Facade Roof Leaking,9/30/97; POD,0/30/97 ,
97 3120 Cracks in Blockwallin Gas Compressor Room,9/30/97; POD,9/30/97
,
97 3121 Spalls on Gas Compressor Room Wall,9/30/97; POD,9/30/97
i 97 3122 Steel Channels Corroded,9/30/97; POD,9/30/97
2
97 3123 Concrete Spalls on Circulating Water Pump House,9/30/97; POD,9/30/97
4
97 3124 Unit 2 Containment Lir:er Scrape,9/30/97; POD,9/30/97
!
] 07 3125 Concrete Degradation in Unit 2 Tendon Gallery,9/30/97; POD,9/30/97
'
97 3120 Circulating Water Pump House Floor Plates Missing Screws,9/30/97; POD,
9/30/97
-
97 3291 1P-4A Operability Questioned Based on Cracking in Pump iP-48,10/9/97; POD,
10/10/97
97 3293 Appendix R Ventilation Equipment Does Not Meet Expected Flow Rates, ;
i 10/13/97; POD,10/10/97
' 97 3311 Piping Support Problem,10/9/97; POD,10/12/97
97 3324 1P 029 T AFP Overspeed Trip Linkage Socket Joint Cracked,10/13/97; POD,
! 10/14/97
l 97 3338 G91 Operation with No Oil Residue on South Bedplate Starting Air Motor,
i 10/14/97; POD,10/14/97
97 3391 Overthrust Limits in CMP 2.2 MOV Cale per Limitorque Technical Update
- 92 01,10/15/97; POD,10/15/97
l
97 3392 .
inadequate POD for CR 97 2848,10/16/97; POD,10/16/97
2
97 3399 Relay Uncertainty Values Nonconservative,10/16/97; POD,10/17/97
97-3424 Bearing Clamps Securing Control Board Subpanel,10/17/97; POD,10/17/97
'
97 3445 Modifications with Calculation N94-168,10/17/97; POD,10/20/97 ,
97 3524 All Portions of Reactor Trip Breaker Survel!!ance Not Completed,10/30/97; POD
- 10/30/97 ;
Control Room Narrative Loos
Volume IX Pages 1708 - 1730 (Covers dates 7/4 7/12/97)
Volume XI Pages 2030 2054 (Covers dates 7/2 7/12/97)
Inservice Tests (ITs)
i High Head Safety injection Pumps and Valves (Quarterly), Unit 1, Rev 35,
01-
6/27/97
02- High Head Safety injection Pumps and Valves (Quarterly), Unit 2, Rev,39,
, .
7/7/97 .
.
03 Low Head Safety injection Pumps and Valves (Quarterly), Unit 1, Rev. 31,3/7/97
. 04 Low Head Safety injection Pumps and Valves (Quarterly), Unit 2, Rev. 35,4/7/97
34
-
+pi-- y-p--9 p.-.y- og ve, yr-min-J-que g +i p y- =, y qrpyy.-y&--we.p y e,symm e, w y,'emgg- 9g$me----= g.y- ywp=.e-7i gwuurgg- ppy-M-upe----- m--w-- gewww*m-wme-em.-+--c-re.--wwm+ . , , -.wg& mwe*- w v=t--------*+u-u--.e
,i*
05 Containment Spray Pumps and Valves (Quarterly), Unit 1, Rev. 34,6/27/97
06 Containment Spray Pumps and V Aves (Quarterly), Unit 2, Rev. 40,6/27/97
40 Safety injection Valves (Quarterly't, Unit 1, Rev 33,10/10/97
45 Safety injection Valves (Quarterty), Unit 2, Rev. 32,10/10/97
Instrumentation and Control (l&C) Procedures (ICP,3)
02.003B.1 Reactor Protection System Logic Train B Monthly Surveillance Test, Rev.12,
9/22/97
02.008 Nuclear Instrumentation Power Range Axial Offset Calibration Rev. 2,7/8/97
02.008 1 Nuclear instrumentation Power Range Channels Axial Offset Initial Calibration,
Rev. 7,9/25/97
02.018 2 Reactor Trip Breaker and Turbine Trip Circuit Trains A&B Shutdown Surveillance
Test, Rev. 1,8/02/97
02.020 Post Refuel Pre Startup Reactor Protection System and Engineered Safely
Features Analog Surveillance Test, Rev.1,9/30/97
04.002-1 Reactor Coolant Flow Transmitters Outage Calibration,5/13/97
04.003 1 Pressurizer and Pressurizer Relief Tank Level Transmitters Outage Calibration,
Rev. 4,9/29/97
04.003 5 Auxiliary Feedwater Flow instruments Outage Calibration Rev. 2,5/13/97
04.004 3 SI Accumulator Pressure Transmitter Outage Calibration Rev. 2,5/13/97
04.004 6 Overpressure Mitigation Pressure Transmitters Outage Calibration (LTOP) Rev.
3,9/22/97
04.006 3 Aux. Feedwater Flow and Pressure Instrument Outage Calibrations, Rev. 2,
5/12/97
04.023 1 Reactor Vessel Level Outage Calibration, Rev. 2,5/13/97
05.063 RCP A&B Seal Water and Letdown Flow Instruments Outage Calibration, Rev. O,
9/30/97
06.021 Chemical and Volume Control (Non Outage), Rev.18, 8/05/97
. 06.021C Chemical and Volume Control System (Non Outage, Common Equipment),
Rev.18,5/19/97
06.017 Safety injection System (Non Outage) with temp, change, Rev.18, 9/29/97
06.066A' Train A RHR Heat Exchanger Valve and Controller Calibration,9/29/97
06.066B Train B RHR Heat Exchanger Valve and Controller Calibration, 9/30/97
09.013 Replacement of Safeguards or Protection Relays,9/29/97
10.002 Removal of Safeguards of Protection Sensor form Service, Rev. 23,7/15/97
10.022A . Unit i l&C Involvenwnt in ORT 3A: Sefety injection Actuation with Loss of
Engineered Safeguards AC, Unit 1, Rev. 2,9/23/97
13.008 Auxiliary Feedwater System, Rev 1,9/30/97
Optrating Exoerience Reoorts
Semi annual Operating Experience Report Program Status,2/18/97
Licensee review of the following industry Operating Exp9rience documents:
GL 97 04 Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling
and Containment Heat Removal Pumps
35
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,.. '
IN 97 31 Failures of Reactor Coolant Pump Thermal Barriers and Check Valves in Foreign
Plants
IN 97 040 Potontial Nitroger. Accumulation Resulting from Back leakage from Safety
injection Tanks
IN 97-41 Potentially Undersized EDG Oil Coolers
CPS 0002 Mounting Screws for Secondary Contact Blocks for Class 1E 480 VAC ABB
Circuit Breakers
STP97002 Fire During Steam Leak Sealing Process
SEN 167 Recurring Event, Loss of Reactor Coolant System Inventory Resulting from
Nitrogen Accumulation
SER 9015 Unrecognized Reactivity Mismanagement While Performing a Reactor Shutdown
SER 97 011 High Pressure injection Pumps Unavailable for Emergency Core Cooling
Operation
'
Operatina Procedures (ops)
1A Cold Shutdown to Hot Shutdown, Rev. 59
2A Normal Plant Operation, Revs. 23,24,25 & 26,4/28/95,9/7/95,10/13/95 & 5/9/97
4A Filling and Venting the RCS, Rev. 44
Doerations Checkiist Procedures
CL 100 Service Water Safeguards Lineup, Rev. 35
CL 11A G 02 Diesel Generator Checklist, Rev.17
-
Opmahons Manual
OM1.1 Conduct of Operations, Rev. 8
QMudit Reoorts
A P 90 03 Quality Assurance Audit Report Corrective Action and Operating Experience,
3/27/96
A P 97-0; Ouality Assurance Audit Report Corrective Action and Operating Experience,
7/18/97
A P 97 21 Quality Assurance Audit Report Operations,6/4/97
A P 97 07 Quality Assurance Audit Report- Configuration Management and Licensing
Basis,9/5/97
A-P 9713 Quality Assurance Audit Report In Service Test (IST) Evaluation and
Implementation,8/26/97
Quality Condition Reports (OCRs)
97 0065 Control Switch for the Backup Control Room Recire Fan Was in the off Position
Instead of its Required Auto Position,5/5/97
97 0067 Flow Rate Through Charcoal Filters Questioned,6/11/97
97-0076 OM 1,1 Requirements Are Not Being Followed During Simulator Training,5/6/97
97-0084 Untimely Corrective Maintenance Associated with the EDG RPM Indicator,
7/2197
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97 0085 Audit of Operability Determination Process,5/13/37 !
97-0086 EDG Corrective Maintenance Concern,7/2/97
97-0118 NP 5.4.1 Does Not Adequately Address Expectations for T: nely Disposition of i
Actions in the Open item Tracking System
'
97-0119 NP 5.3.2 Does Not Reflect Current Practices
97-0120 OE Evaluations Are Not Always Completed Within Prescribed Time
97-0121 OE Close out Packages Are Not Being Forwarded to NIMS <
97 0127 Corrective Actions Are Not Being Assigned Due Dates in a Timely Manner
97 0128 Condition Report identified Without Documented SRO Screening
97-0129 Timeliness of CR Screenings
97 0148 [ Relief) Valves May Not Be Tested As Required,7/18/97
97 0150 AFW IST Process Does Not Address AFW Pump Speed,7/15/97
97 0153 IST Technical Review Concern,7/18/97
97 0154 IST Program Missin0 Some Valves With Safety Functions,7/17/97
97 0155 Root Cause Recommended Corrective Actions Not Documented Correctly
97 0181 Hydrostatic Test Not Properly Documented,8/19/97 ,
Eclipdic Checks (PCS)
75, Part 6 Semi Annual G 01 Diesel Generator Fire Damper and Ventilation Surveilance
Test, Rev. 1, 1/30/97
75, Part 7 Semi Annual G-02 Diesel Generator Fire Damper and Ventilation Surveillance ;
Test, Rev. 1,1/30/97
Routine Maintenance Procedures (RMPs)
26 Reactor Trip and Bypass Breaker Maintenance, Rev 15, 5/28/97
143 Maintenance of 2SI 830A 2T 34 Relief Valve Unit 2, Rev. 2,4/9/97
152 installation and Removal of Penetration 67 Foam Assembly for Steam Generator
Eddy Current Cables, Rev. 3,4/9/97
175 ICV 209, Letdown Relief Valve Testing and Repair, Rev. 1,4/09/97
178 Maintenance of 1CV 257 VCT Relief Valve, Rev,2, 4/09/97
'
9006 2 CCW Pump Mechanical Seal (John Crane) Overhaul, Rev. 3,8/07/97
,
9043 13 Emergency Diesel Generator G-01 Two Year Mechanical inspect;on, Rev. O,
'
2/7/96
9043 14 Emergency Diesel Generator G-01/G 02 6 and 12 Year Electrical & Mechanical
inspection, Rev. 1,10/3/97
'
9043 23 Emergency Diesel Generator G 02 Two Year Mechanical Inspection, Rev. O,
9/16/97
0043-27 Emergency Diesel Generator G 02 Post Maintenance Testing, Rev. 1, 9/22/97
9071 1 A05 4160/480 Degraded and Loss of Voltage Relay Monthly Surveillance,
Rev.10
9071 2 A06 4160/480 Degraded and Loss of Voltage Relay Monthly Surveillance,
Rev.10
- .9302 1 A 01 Arnual Time Delay Relay Calibration and RCP Bus Stripping Surveillance,
i Rev. 4, W10/97 :
j 9358 Auxilia' _ Redwater Pump Motor Maintenance, Rev. O,5/24/97
1
37
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,..b
Safely Evaluation SriceningsRGBs)
97 1060 Unit i HP Crossunder Pipin9 Replacement,9/9/97
97 1077 ARB 1C031D 3 2 and 3 3 on Unit 1 and ARB 2003 2D 3 9 and 310 on Unit 2,
9/8/97
97 1079 Replacement of SKF 7230 GM ABEC3 Service Water Pump Motor Upper Thrust
Bearings with SKF 230 N2MA for Point Bearing,8/22/97
97 1118 OP 3B Shutdown Margin Calculation,6/10/97
97 1124 Temporary Change to IT 515B LPRM Program Test cf Safety injection Test Line
(Unit 2)
97 1145 Removal of Spare Breakere from DC Panels,9/22/97
97 1159 Verification of AFW Low Suction Pressure Time Delays,7/11/97
97 1217 Temporary Change to 1 RMP 9056 2 Calibration and Testing of Safety Related
Protective Relays A06,9/30/97
97 1241 Rev 8 to Safety injection Checklist Unit 1, CL 7A and 7B,10/31/97
97 1242 PC-39 Part 2, Steam Trap Inspection,8/21/97
97 1243 PC 77 Part 4, Minor Annual Auto Dry Pipe Fire Protection System Valve Test,
10/2/97
07 1352 OP IOE * Discharge of BCVCS HUT" Complete Rewrite,10/1/97
Safely.Eyaluations (SEs)
95-058-01 Revise Turbino Load Limit (When Crossover Steam Dump is !noperable),
10/11/95
97 137 Revision to EOP 0 (MAJOR), " Reactor Trip or Safety injection," Unit 1, Rev. 21,
Unit 2, Rev. 22,7/15/97
97 146 Temporary Resolution of Overpressurization of RHR Gate Valves 1RH 700,701,
& 720 & Piping Between 1RH 700 and 1RH 701,7/24/97
97 147 Temporary Modification to Heating Boilers Condensato Supply,7/29/97
97-151 Conduct of OP 1 A Heatup to 350 Deg F with 2P 10A Inoperable,8/8/97
97-151 01 Conduct of OP 1 A Heatup to 350 Dog F with 2P 10A Inoperable, Rev.1,8/9/97
97 153 Installation of Hydrogen Monitoring Systems for MSB Monitoring,8/8/97
97 154 EOPSTPT K.13 & K.15 Criteria for Securing Last Sl Pump,8/7/97
97-158 Weld Closed Containment Penetrations P12b and P30a,9/22/97
97-164 DCN to Show BS 331 Open Rather than Shut,9/11/97
97 165 MR 95-024 Unit 1 Safety injection (SI) Accumulator Level injection Modification,
9/11/97
97-107 Rebuild Si Test Line Relief Valvo 1/2SI 887
97-170 Unit 1 & 2 HDTP's (Heater Drain Tank Pumps) Mechanical Seal Replacement
and Seal Coolant / Flush injection Line Installation,9/19/97
97 175 Replacement of Unit % Charging Pamp Discharge Valves,9/26/97
Self -Assessments
NPM 97-0275 Self Assessment of NPBU Operability Determination Process,5/12/97
SAE/FSE- Point Beach Unit 1 and 2 Emergency Diesel Generator Safety System Functional
WEP 0122 Assessment,6/27/97
38
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T_ echnleml Snacification Tant Procedure .
.TS 82 Emergency Diesel Generator G-02 Monthly, Rev. 49
,
5
Trainino Lammon Plans
,
.
2538 10CFR50.59/72.48 Screenings, Rev.1,5/12/97 !
2539 10CFR50.59/72.48 Safety Evaluations, Rev.1,5/12/97 l,
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