ML040360104
| ML040360104 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 02/04/2004 |
| From: | Caldwell J Region 3 Administrator |
| To: | Vanmiddlesworth G Nuclear Management Co |
| References | |
| EA-02-031, EA-03-057, EA-03-059, EA-03-181, IR-01-017, IR-02-015 IR-03-007 | |
| Download: ML040360104 (133) | |
See also: IR 05000266/2003007
Text
February 4, 2004
EA-03-057
EA-03-181
Mr. Gary Van Middlesworth
Acting Site Vice-President
Point Beach Nuclear Plant
Nuclear Management Company, LLC
6610 Nuclear Road
Two Rivers, WI 54241-9516
SUBJECT: POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2
95003 SUPPLEMENTAL INSPECTION
NRC INSPECTION REPORT 05000266/2003007; 05000301/2003007
Dear Mr. Van Middlesworth:
On December 16, 2003, the results of a three-phase supplemental inspection conducted at
the Point Beach Nuclear Plant in accordance with NRC Inspection Procedure (IP) 95003,
Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded
Cornerstones, Multiple Yellow Inputs, or One Red Input, were discussed with Messrs. John
Paul Cowan, Douglas Cooper, and Fred Cayia, and members of the Point Beach staff at a
public meeting at the Holiday Inn in Manitowoc, Wisconsin. A summary of the public meeting
on December 16, 2003, was documented in a letter to Mr. Cayia, dated December 31, 2003.
The inspection was an examination of activities conducted under your license as they relate to
safety and to compliance with the Commissions rules and regulations and with the conditions
of your license. Within these areas, the inspection consisted of a selective review of
procedures and representative records, observations of activities, and interviews with
personnel.
In a letter dated May 9, 2003, we informed Mr. Cayia of our decision to conduct the IP 95003
supplemental inspection. The inspection was conducted to review your corrective actions for
the Red inspection finding associated with the auxiliary feedwater and instrument air systems
(AFW/IA) and for the inspection finding associated with the potential common mode failure of
the AFW pumps because of plugging of the recirculation line pressure reduction orifices. This
second finding associated with the AFW system was subsequently determined to be a Red
finding for Unit 2, and a Yellow finding for Unit 1. Details of these findings are provided in
Inspection Reports (IRs) 50-266/01-17(DRS); 50-301/01-17(DRS), dated April 3, 2002, and
50-266/02-15(DRP); 50-301/02-15(DRP), dated April 2, 2003, and in Final Significance
Determination letters dated July 12, 2002, and December 11, 2003. The inspection also
assessed your performance in the Reactor Safety Strategic Performance Area, which included
detailed inspections of the effectiveness of your corrective action, emergency preparedness,
and engineering programs.
G. Van Middlesworth -2-
From our inspection, we concluded that your evaluation of the causes of the significant AFW
inspection findings was adequate and your proposed corrective actions were reasonable.
Though we concluded that generally your planned corrective actions were adequate to prevent
problem recurrence, the implementation of some of the corrective actions was weak as
reflected in repeated extension of due dates and the lack of quality in the implementation of
identified corrective actions. For example, the IP 95003 inspection was extended for one week
because of inconsistent quality of your implementation and documentation of corrective actions
which resulted in several corrective actions involving the AFW system not being completed.
The NRC determined that additional review of corrective actions related to the AFW system
was warranted to gain assurance that the system was operable. The NRC subsequently
concluded that the AFW system was operable; however, extensive inspection effort was
required to verify that previous corrective actions adequately addressed historic AFW system
performance problems.
Regarding our assessment of your performance in the Reactor Safety Strategic Performance
Area, the NRC determined that the plant is being operated in a manner that ensures public
safety. However, the NRC also identified several performance issues which warrant increased
attention to ensure continued plant safety. Specifically: (1) the quality of your implementation
of programs and processes related to the identification and resolution of problems was
inconsistent, resulting in inadequate or incomplete corrective action, (2) we identified multiple
findings and violations related to emergency preparedness which indicated that Point Beach
management and staff did not have a good understanding of license and regulatory
requirements, (3) electrical design basis calculations were poorly controlled, and (4) ineffective
communication between engineering and operations contributed to the lack of a common
understanding of some system design basis and operational practices.
The NRC determined that your performance improvement plan (Excellence Plan) provides an
adequate framework for the improvement of station performance. However, the success of this
Plan is contingent on the adequate commitment of resources, the timely and quality
implementation of the Plan, and the establishment of measures or indicators of successful
completion at various stages during Plan implementation, including when all necessary action
steps of the action plans in the Excellence Plan and effectiveness reviews for the actions have
been completed. Additionally, we determined that the Excellence Plan did not completely
address all problem areas. The Plan required changes to ensure that problems associated with
implementation of the corrective action and emergency preparedness programs, engineering
design basis calculation adequacy, and organizational effectiveness, are adequately addressed
to affect and sustain long-term improvement in these areas.
You are requested to respond to this letter by February 13, 2004, and describe the actions that
you will take to address the issues raised during this inspection, and your schedule for
submission of your revised Excellence Plan. The NRC will review the adequacy of the revised
Excellence Plan and its implementation. The NRC will continue to provide increased oversight
of activities at Point Beach until you have demonstrated that your corrective actions are lasting
and effective. Consistent with Inspection Manual Chapter (IMC) 0305 Operating Reactor
Assessment Program, guidance regarding the oversight of plants in the multiple/repetitive
degraded cornerstone column of the Action Matrix, the NRC will continue to assess
performance at Point Beach and will consider at each quarterly performance assessment
G. Van Middlesworth -3-
review the following options: (1) declaring plant performance to be unacceptable in accordance
with the guidance in IMC 0305; (2) transferring to the IMC 0350 Oversight of Operating
Reactor Facilities in a Shutdown Condition with Performance Problems process; and (3) taking
additional regulatory actions, as appropriate. Until you have demonstrated lasting and effective
corrective actions, Point Beach will remain in column four of the Action Matrix.
During the inspection, an apparent violation of 10 CFR 50.54(q) and 50.47(b) was identified
for changes Point Beach made between October 1998 and December 1999 to the previously
NRC-approved Emergency Action Level scheme. This apparent violation is described in
Section 3.6 of the enclosed inspection report and in a letter sent to Mr. Cayia, dated
December 2, 2003. It was also discussed with Point Beach management during a technical
debriefing by the emergency preparedness inspectors on August 8, 2003; at the conclusion of
the onsite portion of the emergency preparedness phase of the inspection on August 27; during
a preliminary exit meeting for all three phases of the IP 95003 inspection on November 17;
during a telephone conference on December 1; and during the public final exit meeting for the
IP 95003 inspection on December 16. As discussed in the December 2nd letter, this apparent
violation is being considered for escalated enforcement action in accordance with the General
Statement of Policy and Procedure for NRC Enforcement Actions (Enforcement Policy),
NUREG-1600. The current Enforcement Policy is included on the NRCs website at
www.nrc.gov. A predecisional enforcement conference was held on January 13, 2004, in the
Region III office. From the information presented at the conference, it was apparent that
corrective actions taken, thus far, have been less than fully effective. On January 16, after
further discussions between the NRC and NMC representatives about the need to take
corrective actions to return to compliance, NMC representatives informed the NRC that the
EALs had been changed. A summary of the predecisional enforcement conference was
provided to you in a letter dated January 27, 2004. You will be notified by separate
correspondence of the results of the NRCs deliberations on the apparent violation and the
adequacy of your corrective actions.
In addition to the apparent violation, the NRC identified that your Emergency Plan and
implementing procedures did not provide a range of protective action recommendations as
required by NRC regulations. The only protective action recommendation that would have been
given to State and local officials by your staff in the event of an emergency at Point Beach was
evacuation. This issue is being treated as an unresolved item while the NRC evaluates the
potential generic implications. We confirmed by direct observation that the Emergency Plan
and implementing procedures have been changed since the inspection was completed to
provide an appropriate range of recommendations.
Based on the results of this inspection, ten NRC-identified violations of very low safety
significance (Green) and one NRC-identified Severity Level IV violation were identified.
Additionally, a licensee-identified violation is listed in Section 5 of this report. These violations
are being treated as Non-Cited Violations (NCVs) consistent with Section VI.A of the
Enforcement Policy. These NCVs are described in the subject inspection report. If you contest
the severity level or significance of these NCVs, you should provide a response within 30 days
of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a
G. Van Middlesworth -4-
copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 801
Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement, U.S. Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
Point Beach Nuclear Plant facility.
In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter, its
enclosure, and any responses you provide will be made available electronically for public
inspection in the NRC Public Document Room or from the Publicly Available Records System
(PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC
Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
James L. Caldwell
Regional Administrator
Docket Nos. 50-266; 50-301
Enclosure: Inspection Report 05000266/2003007; 05000301/2003007
w/Attachment: Supplemental Information
cc w/encl: R. Kuester, President and Chief
Executive Officer, We Generation
John Paul Cowan, Chief Nuclear Officer
D. Weaver, Nuclear Asset Manager
Plant Manager
Regulatory Affairs Manager
Training Manager
Jonathan Rogoff, Vice-President, Counsel & Secretary
D. Cooper, Senior Vice-President
K. Duveneck, Town Chairman
Town of Two Creeks
A. Bie, Chairperson, Wisconsin
Public Service Commission
J. Kitsembel, Electric Division
Wisconsin Public Service Commission
State Liaison Officer
DOCUMENT NAME: C:\MYFILES\Copies\Poi 2003 007 DRP 95003 Suppl.wpd
To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy
OFFICE RIII RIII RIII RIII
NAME MKunowski:dtp JLara KRiemer AVegel
DATE 01/26/04 01/26/04 01/27/04 01/28/04
OFFICE RIII NRR RIII RIII
NAME BClayton SRichards SReynolds JCaldwell
DATE 01/28/04 01/28/04 01/28/04 01/30/04
OFFICIAL RECORD COPY
G. Van Middlesworth -5-
ADAMS Distribution:
WDR
DNS
RidsNrrDipmIipb
GEG
PGK1
C. Ariano (hard copy)
C. Pederson, DRS (hard copy)
DRPIII
DRSIII
PLB1
JRK1
FJC
JGL
JLD
OEMAIL
OEWEB
RJS2
RWB1
MRJ1
MAS
JRJ
RML2
BAB2
WMD
LSG
WHR
DWW
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-266; 50-301
Report No: 05000266/2003007; 05000301/2003007
Licensee: Nuclear Management Company, LLC
Facility: Point Beach Nuclear Plant
Location: 6610 Nuclear Road
Two Rivers, WI 54241
Dates: Corrective Action Inspection, July 28 - August 8, 2003
Emergency Preparedness Inspection, August 4-15, 2003
Engineering, Operations, and Maintenance Inspection,
September 8 - October 3, 2003
Preliminary Exit Meeting, November 17, 2003
Public Final Exit Meeting, December 16, 2003
Personnel: A. Vegel, 95003 Team Leader; Chief, Branch 7,
Division of Reactor Projects (DRP), Region III
M. Kunowski, 95003 Assistant Team Leader; Project
Engineer, Branch 7, DRP, Region III
Corrective Action Inspection
L. Kozak, Inspection Leader, Project Engineer, DRP,
Branch 6, Region III
J. Lenahan, Senior Engineering Inspector, Division of
Reactor Safety (DRS), Region II
R. M. Morris, Resident Inspector, Point Beach
J. Chiloyan, NRC Contractor
K. Elsea, NRC Contractor
D. Baxley, Administrative Assistant, Office of Nuclear
Reactor Regulation (NRR)
Enclosure
(Cover page cont)
Emergency Preparedness Inspection
R. Lantz, Inspection Leader; Senior Emergency
Preparedness (EP) Inspector, Region IV
T. Blount, Senior EP Analyst, NRR
R. Kahler, Senior EP Analyst, NRR
T. Ploski, Senior EP Inspector, Region III
R. M. Morris, Resident Inspector, Point Beach
Engineering, Operations, and Maintenance Inspection
A. Vegel, Inspection Leader
S. Burgess, Senior Reactor Analyst, Region III
L. Kozak, Project Engineer, Branch 6, Region III
D. Pelton, Senior Resident Inspector, Vermont Yankee,
Region I
R. Daley, Reactor Inspector, DRS, Region III
M. Maymí, Reactor Inspector, DRS, Region II
C. Baron, NRC Contractor
G. Skinner, NRC Contractor
S. Billings, Administrative Assistant, NRR
P. Krohn, Senior Resident Inspector, Point Beach
R. M. Morris, Resident Inspector, Point Beach
Approved by: Anton Vegel, Chief
Branch 7
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1. Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2. Corrective Action Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2.1. Review of Significant Performance Deficiencies . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2 Effectiveness of Audits and Assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
2.3 Employee Concerns Program and Safety Conscious Work Environment . . . . 21
2.4 Licensee Performance Goals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.5 Allocation of Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
2.6 Use of Industry Operating Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
2.7 Conclusions of the Corrective Action Program Phase of the IP 95003 Inspection
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
3. Emergency Preparedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.1 Correction of Weaknesses and Deficiencies . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2 ERO Readiness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.3 Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
3.4 Procedure Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
3.5 ERO Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
3.6 In-Depth Review of RSPSs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
3.7 Conclusions of the Emergency Preparedness Phase of the IP 95003 Inspection
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
4. Engineering, Operations, and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
4.1 Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4.1.1 125-VDC System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
4.1.2 Design Basis and As-Built Review of AC Systems, Including the Offsite
Electrical Distribution Grid and Plant Electrical System Interface . . . . . 51
4.1.3 Component Cooling Water (CCW) System . . . . . . . . . . . . . . . . . . . . . 57
4.1.4 Corrective Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
4.1.5 Procedure Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
4.1.6 Human Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
4.1.7 Miscellaneous Issue - Appendix R Concern for Speed Controllers for the
Charging Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
4.2 Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
4.2.1 Control Room and In-Plant Observations . . . . . . . . . . . . . . . . . . . . . . . 72
4.2.2 Time-Critical Operator Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
4.2.3 System Walkdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
4.2.4 Operator Interactions with Engineering and Maintenance Personnel . . 75
4.2.5 Distribution of Temporary Changes to EOPs . . . . . . . . . . . . . . . . . . . . 75
4.3 Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
4.3.1 Maintenance Work Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
Enclosure
4.3.2 Equipment Performance for the 125-VDC, CCW, and AFW Systems
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
4.4 Extension of the Engineering, Operations, and Maintenance Inspection . . . . . 77
4.5 Conclusion of the Engineering, Operations, and Maintenance Phase of the IP
95003 Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
5. Licensee-Identified Violation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
6. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Enclosure
SUMMARY OF FINDINGS
IR 05000266/2003-007, 05000301/2003-007; 7/28/2003 - 12/16/2003; Nuclear Management
Company, LLC; Point Beach Nuclear Plant, Units 1 and 2. Supplemental inspection 95003 was
performed to evaluate corrective actions for a Red inspection finding pertaining to the auxiliary
feedwater and instrument air systems, and for a Red inspection finding pertaining to the
potential for a common mode failure of the auxiliary feedwater pumps because of the plugging
of the recirculation line pressure reduction orifices. The inspection also reviewed the corrective
action, emergency preparedness, and engineering programs.
The Nuclear Regulatory Commission (NRC) began the three-phase supplemental inspection on
July 28, 2003. At that time, the orifice plugging finding was still considered a preliminary Red
finding. However, because the licensee had completed the root cause investigation and had
developed and began implementation of corrective actions for the preliminary Red finding
before the completion of the inspection, the IP 95003 inspectors reviewed the adequacy of
these corrective actions. The Final Significance Determination of the orifice plugging issue was
subsequently completed and transmitted to the licensee in a letter dated December 11, 2003.
The NRC concluded that this issue was appropriately characterized as Yellow for Unit 1and
Red for Unit 2. The difference in significance is a result of the longer time that the orifices were
installed in Unit 2.
This inspection was conducted in accordance with NRC Supplemental Inspection
Procedure 95003, Inspection for Repetitive Degraded Cornerstones, Multiple Degraded
Cornerstones, Multiple Yellow Inputs, or One Red Input. In the first phase of the inspection,
the licensees corrective action program was reviewed, with a focus on problem identification,
in general, and implementation of corrective actions for the two AFW issues, in particular.
On August 4, 2003, the second phase of the inspection, a review of the emergency
preparedness program, began. An apparent violation was identified during this phase for
changes made to the Emergency Action Level scheme that decreased the effectiveness of the
Emergency Plan and did not receive prior NRC approval. The licensee was informed of this
apparent violation in a letter dated December 2, 2003, and a predecisional enforcement
conference to discuss this issue was conducted on January 13, 2004.
On September 8, 2003, the final phase of the inspection began. The focus of this phase was
the licensees engineering program, particularly design engineering, and additional review of
implementation of corrective actions for the two AFW issues. Plant operations and
maintenance, as they interact with engineering, were also reviewed. This phase of the
inspection was extended an extra week because of problems identified by the inspectors with
AFW system corrective actions.
The licensees corrective action program was adequate. Examples of poor implementation
continue to exist despite licensee efforts to improve overall implementation. Identified program
weaknesses that could contribute to implementation problems included the potential for issues
to be categorized and analyzed at too low a level and a weak trending process. Recently
implemented program improvements were good initiatives but were not formalized.
1 Enclosure
The overall root and contributing causes for the two AFW Red findings were the lack of
understanding of the design, corrective action program weaknesses, and poor
operations/engineering interface. And while overall, corrective actions taken for the findings
were adequate, several important corrective actions to prevent recurrence had not been
adequately implemented.
In emergency preparedness (EP), the inspectors concluded that the licensees program was
adequate. Program challenges and areas needing improvement included EP staff experience
level and training, maintenance of EP design bases and understanding of EP regulatory
guidance documents. An apparent violation was identified for the failure to maintain a standard
emergency action level scheme, and an unresolved item whose significance is greater than
Green was identified for a lack of range of protective actions in the Emergency Plan and
implementing procedures.
In engineering, the inspectors concluded that the CCW system design and licensing basis were
understood and adequately supported by controlled testing and calculations. The 125-volt
direct current (VDC) system design basis calculations, however, were poorly controlled and
design basis calculations related to several alternating current (AC) systems were poorly
understood by engineers. The operability of the electrical systems were verified through
calculations by the inspectors. The inspectors determined that communications between
operations and engineering staff regarding the understanding of system design and operating
practices was not consistently effective.
This report covers a 5-month period of supplemental inspection by NRC contractors and NRC
inspectors from all four NRC Regional offices and from Headquarters. Ten Green findings,
which were associated with Non-Cited Violations, one Severity Level IV Non-Cited Violation,
one apparent violation, and one unresolved item of significance to be determined were
identified. The significance of most findings is indicated by their color (Green, White, Yellow,
Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process
(SDP). Findings for which the SDP does not apply may be Green or be assigned a severity
level after NRC management review. The NRCs program for overseeing the safe operation of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 3, dated July 2000.
A. NRC-Identified and Self-Revealing Findings
Cornerstone: Emergency Preparedness
- Green. The inspectors identified a Non-Cited Violation of emergency planning standard
10 CFR 50.47(b)(2) because the licensee failed to assign onshift responsibilities for
reading facility seismic monitors, thereby affecting the ability to timely classify certain
seismic emergency events.
This finding is greater than minor because it was associated with a cornerstone attribute
and affected the emergency preparedness cornerstone objective to ensure the
adequate protection of the public health and safety. This finding is of very low safety
2 Enclosure
significance because it was a degradation in the emergency response organization
(ERO) onshift staffing and did not represent a planning standard function failure.
(Section 3.2.b.2)
- Severity Level IV. The inspectors identified a Severity Level IV Non-Cited Violation of
10 CFR 50.9 because the licensee failed to provide complete and accurate information
in the submittal of information for the emergency response organization (ERO)
performance indicator (PI). Twenty-three onshift communicators should have been
tracked and reported in the ERO PI, but were not. The licensee has subsequently
submitted corrected PI data to the NRC.
This issue is greater than minor because it caused the PI to cross the Green-to-White
threshold for the 3rd quarter of 2001. Because this issue affected the NRCs ability to
perform its regulatory function, it was evaluated with the traditional enforcement
process. (Section 3.2.b.3)
- Green. The inspectors identified a Non-Cited Violation of emergency planning standard
10 CFR 50.47(b)(16) because the licensee failed to develop and implement an
emergency planning staff training program to ensure that emergency planners were
properly trained.
This finding is greater than minor because it was associated with a cornerstone attribute
and affected the emergency preparedness cornerstone objective to ensure the
adequate protection of the public health and safety. This finding is of very low safety
significance because lack of a staff training program presented a potential degrading
condition for the level of qualification and proficiency of the emergency preparedness
staff, but did not represent a failure of the planning standard function. (Section 3.5)
- To Be Determined. The inspectors identified an unresolved item for the lack of a range
of protective actions in the Emergency Plan and implementing procedures. This issue is
being treated as an unresolved item while the NRC evaluates the industry-wide generic
implications of this issue. Since the identification of the issue by the inspectors, the
licensee has revised the Emergency Plan and implementing procedures to include the
appropriate range of protective actions. (Section 3.6.b.1)
- To Be Determined. The inspectors identified an apparent violation of 10 CFR 50.54(q),
associated with emergency planning standard 10 CFR 50.47(b)(4), which will be subject
to the NRC traditional enforcement process not the revised Reactor Oversight Process.
Specifically, the licensee failed to maintain a standard scheme of emergency action
levels (EALs). Eight EALs were changed in 1998 and 1999. The changes decreased
the effectiveness of the Emergency Plan in that emergency conditions that would have
resulted in classifications at the General Emergency (GE), Alert, and Notification of
Unusual Event (NOUE) levels would result in a lesser classification under the current
EAL scheme. Approval of the NRC was not obtained prior to the changes being made.
Since the identification of the issue by the inspectors, the licensee has revised the eight
EALs to be equivalent with those approved by the NRC in 1984. (Section 3.6.b.2)
3 Enclosure
- Green. The inspectors identified a Non-Cited Violation of emergency planning standard
10 CFR 50.47(b)(4) because the licensee failed to properly calibrate the facility seismic
monitors to ensure they were capable of supporting implementation of a Notice of
Unusual Event EAL.
This finding is greater than minor because it was associated with a cornerstone attribute
and affected the emergency preparedness cornerstone objective to ensure the
adequate protection of the public health and safety. This finding is of very low safety
significance because a Notice of Unusual Event could still be declared based on ground
shaking. (Section 3.6.b.3)
Cornerstone: Mitigating Systems
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, because Technical Specification Surveillance
Requirement 3.8.4.6 for testing the safety-related battery chargers was non-
conservative in relation to the design basis calculation for battery charger sizing.
This finding is greater than minor because it affected the mitigating systems cornerstone
objective. This finding is of very low safety significance because it was a design
deficiency that did not result in the loss of function. (Section 4.1.1.1.b.1)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, because the licensee failed to maintain the 125-volt direct
current (VDC) voltage drop calculations accurate and up-to-date.
This finding is greater than minor because it affected the mitigating systems cornerstone
objective. This finding is of very low safety significance because it was a design
deficiency that did not result in the loss of function. (Section 4.1.1.1.b.2)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XVI, Corrective Action. Specifically, the licensee failed to implement timely
corrective action (for over 5 years) for safety-related electrical equipment in the primary
auxiliary building (PAB) that was not environmentally qualified, a condition adverse to
quality.
This finding is greater than minor because if left uncorrected, the finding would become
a more significant safety concern and have adverse effects on the capability to prevent
or mitigate the consequences of accidents. The finding is of very low safety significance
because it was a design deficiency that did not result in the loss of function.
(Section 4.1.2.b.2.1)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR 50.49(f). Specifically,
the licensee identified equipment important to safety located in the primary auxiliary
building that would be susceptible to a harsh environment during a postulated high-
energy line break but failed to environmentally qualify that equipment.
4 Enclosure
This finding is greater than minor because if left uncorrected, the finding would become
a more significant safety concern and have adverse effects on the capability to prevent
or mitigate the consequences of accidents. The finding is of very low safety significance
because it was a design deficiency that did not result in the loss of function.
(Section 4.1.2.b.2.2)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings. Specifically, the licensee failed to
include appropriate quantitative setpoint values for the minimum low head safety
injection A train flow in plant emergency operating procedures (EOPs).
This finding is greater than minor because it could have affected the mitigating
cornerstone objective of ensuring the availability of the low head safety injection system
when required to respond to the initiating event. The finding is of very low safety
significance because it did not represent an actual loss of safety function.
(Section 4.1.5)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,
Criterion XI, Test Control, because the licensee failed to include in the inservice testing
program manual component cooling water (CCW) valves that were required to perform
a safety function.
This finding is greater than minor because it could have affected the mitigating
cornerstone objective of ensuring the availability of the CCW or residual heat removal
(RHR) systems when required to respond to the initiating event. The finding is of very
low safety significance because it did not represent an actual loss of safety function.
(Section 4.1.3.2)
- Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix R,
Section III.L.1.c. Specifically, the licensee failed to ensure, without the need for hot
standby repairs, adequate control air to the speed controllers for the charging pumps
during a postulated fire requiring an alternative shutdown method.
This finding is greater than minor because the finding would become a more significant
safety concern if left uncorrected. The finding is of very low safety significance because
it is likely that the licensee would have been successful in completing the repairs and
allowing the plant to be maintained in hot standby until cold shutdown could be
achieved. (Section 4.1.7)
B. Licensee-Identified Violation
A violation of very low safety significance, which was identified by the licensee, has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. The violation and the
licensees corrective action tracking number are listed in Section 5 of this report.
5 Enclosure
REPORT DETAILS
1. Background
In a letter dated July 12, 2002, the NRC issued a Final Significance Determination,
classifying a licensee-identified issue with the auxiliary feedwater and instrument air
systems (the AFW/IA issue) as a Red finding. The letter also discussed the NRCs
decision to perform additional inspection to determine whether the issue should be
treated as an old design issue (ODI). The ODI designation referred to the exemption in
NRC Inspection Manual Chapter 0305, Operating Reactor Assessment Program, that
allowed the NRC to not take actions specified in the Action Matrix for certain findings.
An initial inspection was conducted, by two inspectors, from September 23 - 26, 2002, to
review the ODI question.
On October 29, 2002, while the results of the September inspection were being
reviewed by Region III management, the licensee notified the NRC of a potential for a
common mode failure of the AFW pumps from the plugging by debris of the pressure
reduction orifices in the AFW minimum flow recirculation lines. Flow through the
recirculation lines is required to prevent damage to the pumps when flow to the steam
generators is stopped or significantly reduced by reactor operators. An NRC special
inspection team was dispatched to the site on October 30 to review this issue and its
relation to the original AFW/IA issue. From its review of the orifice plugging issue, the
licensee concluded that the source of the rust-like debris found in the orifice was AFW
discharge piping high-point vent valves and pump casing vent valves that had been
manipulated during system maintenance. On February 21, 2003, studies conducted at
an independent laboratory for the licensee indicated that the sand, silt, and zebra
mussel shell debris normally found in plant service water (SW), the safety-related water
source for the AFW system, would quickly plug the orifices. The NRCs conclusions
from the inspection that the AFW/IA did not qualify as an ODI and that the AFW orifice
plugging issue was preliminarily a Red inspection finding were subsequently
documented in Inspection Report (IR) 50-266/02-15(DRP); 50-301/02-15(DRP), issued
on April 2, 2003.
On May 9, 2003, the NRC issued an Annual Assessment Follow-up Letter, which
documented the results of the April 22, 2003, annual Agency Action Review Meeting,
including the NRCs decision to perform a supplemental inspection at Point Beach
Nuclear Plant (PBNP), using IP 95003, Supplemental Inspection for Repetitive
Degraded Cornerstones, Multiple Degraded Cornerstones, Multiple Yellow Inputs, or
One Red Input.
On June 6, 2003, a Regulatory Conference was held to discuss the orifice plugging
issue. At that conference, the licensee stated that the results of the analysis of risk from
internal events for the issue would be completed later in June and that the analysis of
risk from fire would be completed in August 2003. Information related to the risk from
internal events was subsequently submitted to the NRC in a letter dated June 27, and
information related to the risk from fire was submitted on September 18. The licensees
analysis indicated that the AFW orifice plugging issue was an issue with high
importance to safety, a Red inspection finding, for Unit 2, and an issue with substantial
6 Enclosure
importance to safety, a Yellow inspection finding, for Unit 1. The difference in
significance between the Units is a result of the longer time that the orifices were
installed in Unit 2.
In a letter dated July 18, 2003, the licensee submitted to the NRC selected action plans
from its Point Beach Nuclear Plant Excellence Plan, a site-wide, long-term performance
improvement plan. In a letter dated December 11, 2003, the NRC issued a Final
Significance Determination, classifying the orifice issue as a Red finding.
On July 28, 2003, the NRC commenced the IP 95003 inspection at Point Beach. The
IP 95003 inspection was conducted in addition to the scheduled baseline inspections.
The intent of IP 95003 is to allow the NRC to obtain a comprehensive understanding of
the depth and breadth of safety, organizational, and performance issues at facilities
where data indicates the potential for serious performance degradation. The objectives
of this inspection procedure are to: (1) provide additional information to be used in
deciding whether the continued operation of the facility is acceptable and whether
additional regulatory actions are necessary to arrest declining performance, (2) provide
an independent assessment of the extent of risk significant issues to aid in the
determination of whether an acceptable margin of safety exists, (3) independently
evaluate the adequacy of licensee programs and processes used to identify, evaluate,
and correct performance issues, (4) independently evaluate the adequacy of programs
and processes in the affected strategic performance areas, and (5) provide insight into
the overall root and contributing causes of identified performance deficiencies.
As prescribed by IP 95003, the scope of NRC inspection activities at Point Beach
included the assessment of performance in the Reactor Safety Strategic Performance
Area, including the inspection of key attributes, such as design, human performance,
procedure quality, configuration control, and emergency response organizational
readiness. Also, the 95003 inspection reviewed the control systems for identifying,
assessing, and correcting performance deficiencies (essentially, the corrective action
program) to evaluate whether programs are sufficient to prevent further declines in
safety that could result in unsafe operation. In developing the scope of this inspection,
the NRC considered the results of licensee self-assessment activities and licensee
progress in addressing the substantive cross-cutting issue in the area of problem
identification and resolution. This issue was discussed in the Annual Assessment
Letter, dated March 4, 2003.
As explained in IMC 0305, plants in the multiple/repetitive degraded cornerstone column
of the Action Matrix are given consideration at each quarterly performance assessment
review for (1) declaring plant performance to be unacceptable in accordance with the
guidance in IMC 0305, (2) transferring to the IMC 0350, Oversight of Operating Reactor
Facilities in a Shutdown Condition with Performance Problems, process, and (3) taking
additional regulatory actions, as appropriate.
2. Corrective Action Program
Recent NRC inspections have identified problems with the licensees corrective action
program. Inspection Report 50-266/02-05; 50-301/02-05, dated May 14, 2002, and
7 Enclosure
Final Significance Determination Letter, dated June 13, 2002, discuss the corrective
action program aspects of a White inspection finding related to the self-revealed failure
of a safety injection pump due to gas binding. Inspection Reports 50-266/01-17(DRS);
50-301/01-17(DRS), dated April 3, 2002, and 50-266/02-15(DRP); 50-301/02-15(DRP),
and Final Significance Determination Letters dated July 12, 2002, and
December 11, 2003, discuss the corrective action program aspects of the Red
inspection finding for the AFW/IA issue and of the Red inspection finding for the AFW
orifice plugging issue. Additional problems with the corrective action program, which
resulted in the NRC identification of a substantive cross-cutting issue in the area of
problem identification and resolution, were discussed in the Annual Assessment Letter
to the licensee, dated March 4, 2003.
With consideration of these recent problems, the NRC reviewed the corrective action
program using the guidance of IP 95003 to evaluate whether the program was sufficient
to prevent further declines in safety that could result in unsafe operation. This
evaluation was made following inspection of the following six areas:
a. Licensee evaluations of, and corrective actions to, significant performance
deficiencies (such as the two Red inspection findings),
b. effectiveness of audits and assessments performed by the quality assurance
group, line organizations, and external organizations,
c. process for allocating resources and management of backlogs and workarounds,
d. licensee performance goals and congruence with corrective actions needed to
address the documented performance issues,
e. employee willingness to use and effectiveness of the employee concerns
program, and
f. effectiveness of the licensees use of industry information (operating experience)
for previously documented performance issues.
In addition to this specific review of the corrective action program, the two other phases
of the IP 95003 inspection reviewed corrective action program aspects related to the
emergency preparedness area (Section 3 of this report) and the engineering,
operations, and maintenance areas (Section 4 of this report).
2.1. Review of Significant Performance Deficiencies
a. Inspection Scope
The inspectors reviewed the licensees assessments of the two Red findings, focusing
on the corrective actions that were identified to prevent recurrence. The inspectors also
reviewed the Excellence Plan action plans (11 plans designated as OP-10-001 through -
011) to improve corrective action program implementation. Ineffective corrective action
had contributed to the AFW findings and was also identified during a recent licensee
organizational effectiveness assessment as a key area needing improvement to support
8 Enclosure
overall improvement in plant performance. The inspectors evaluated the corrective
action program to identify any weaknesses contributing to ineffective implementation.
b. Observations and Findings
Auxiliary Feedwater System Findings
Overall, the inspectors found the licensees final evaluation of the two AFW Red findings
to be acceptable. However, the inspectors noted that each finding required a revision to
the root cause evaluation (RCE), with the AFW/IA Red finding requiring a second
revision. This second revision was performed because the initial evaluation and first
revision were too narrowly focused.
While the inspectors found that many corrective actions for the AFW findings had been
completed, there remained a number of outstanding corrective actions, including
corrective actions to prevent recurrence (CATPRs). For these CATPRs, little progress
had been made, to date, and for some corrective actions the due dates had been
significantly extended. The inspectors also found weak implementation of several
corrective actions. Also, many actions related to the AFW safety system functional
assessment (SSFA), which was performed as a corrective action to the AFW/IA Red
finding, were not complete.
Finally, changes required to important documents, including the AFW design basis
document (DBD), final safety analysis report (FSAR), calculations, and inservice test
program (IST) bases, and others had been identified as necessary but were not yet
completed. Only some of the outstanding actions associated with the AFW system were
captured in the Excellence Plan (in action plans OP-13-008, Gain Additional Design
Margin in the Auxiliary Feedwater System, OP-14-008, AFW Design Basis Validation
Project, EQ-15-014, Auxiliary Feedwater Orifice Replacement, and EQ-15-015,
Auxiliary Feedwater Electrical Modifications), others were captured in the corrective
action program. Some of the actions in the Excellence Plan had completion dates in
2005 and 2006, which the inspectors considered to be untimely. The inspectors
determined that, overall, the actions taken to prevent recurrence related to the two AFW
findings were adequate though some specific actions were not consistently implemented
in a timely and effective manner.
A detailed review of the corrective actions to prevent recurrence for each of the AFW
findings follows.
b.1 AFW Orifice Plugging
The inspectors reviewed RCE 191, Possible Common Mode Failure of Aux Feed
Recirculation Lines, Revision 1. This revision was based on a request from the
Corrective Action Review Board (CARB) to include the management oversight element
as an organizational root cause. The report was completed approximately six months
after the event. The RCE was performed by a team and aided by an independent
review. Two root causes were identified. The direct root cause was the failure of the
design engineer to properly evaluate within the design process the potential for orifice
plugging. The organizational root cause was less than adequate management oversight
9 Enclosure
of the design modification process. Several contributing causes were also identified,
including inadequate knowledge of AFW recirculation line design functions,
misapplication of vendor information, omission of information on design functions from
the safety evaluation, and inadequate independent verification.
An extent of condition assessment of other flow-restricting orifices in the plant was
conducted to determine if the potential for plugging and impacting other system safety
functions existed. No other safety-related flow restriction devices were found to be
susceptible. The licensee did not perform a separate extent of condition for the root
causes. The report stated, "The extent of condition or generic implications of the
organizational root cause (less than adequate management oversight of the design
modification process) has been addressed through the Organizational Effectiveness
Assessment." The organizational effectiveness assessment was completed early in
2003 prior to the completion of the RCE. Because the assessment was very broad and
did not specifically evaluate which parts of the assessment addressed the extent of
cause for the AFW issue, the inspectors could not determine which issues identified in
the organizational effectiveness assessment were related to the causes of the AFW
orifice plugging issue.
The inspectors reviewed the implementation of the CATPRs specified in RCE 191. Four
CATPRs were specified. A review of the implementation and effectiveness of each
action follows:
- CATPR #1: Implement periodic reviews of Engineerings products by the Quality
Review Team to identify and address human performance related issues.
The inspectors found that this action had been inconsistently implemented. The
Quality Review Team (QRT) was formed in November 2002. Between
November 2002 and September 2003, a total of 64 engineering products had
been reviewed and graded for quality. However, a significant number of the
reviews (28) were conducted in January, shortly after the process was
implemented. From February through June, QRT reviews of engineering
products was sporadic, ranging from 1 product reviewed to 8 products reviewed
per month. No engineering products were reviewed in July or August 2003. The
licensee indicated that the reviews were not conducted due to other higher
priority work but that the QRT would review a larger than normal sample in
September. In response to the inspectors questions regarding QRT reviews,
the licensee identified that corrective action program problem identification
documents (CAPs) had not been written for engineering products that were
graded 3." A grade of 3" indicated minor errors and per the guidance of
Nuclear Plant Business Unit Procedure (NP) 7.1.7, Quality Review Team,
should have been documented in a CAP. The CAPs were subsequently
generated to capture the results of the reviews.
- CATPR #2: Increase engineering management involvement in the approval and
oversight of modifications.
10 Enclosure
The action was implemented through the creation of the Design Review Board
(DRB) process. The DRB process included both a review of the modification in
the conceptual phase and a review of the final design. The DRB included staff
from various departments and was intended to provide a comprehensive multi-
disciplined review of the modification. The inspectors attended two DRB
meetings and reviewed the meeting minutes for all other meetings. The
meetings appeared to have been productive and clearly increased the
involvement of departments other than engineering. In all but one DRB, the
chairman was the Manager of Design Engineering, consistent with the intent of
the CATPR to increase engineering management involvement in the approval
and oversight of modifications; however, the DRB Procedure (NP 7.2.12, Design
Review Board) allowed a design engineering supervisor (first-line supervisor) or
designee to chair the DRB. The inspectors were concerned that without specific
procedural guidance to ensure (upper) management involvement in the DRB
process, this involvement could not be assured. The licensee wrote CAP050120
to review management participation in DRBs.
- CATPR #3: Present lessons learned from this event to all engineering personnel
stressing the importance of following the Design Process.
A lessons-learned session had been recently conducted through continuing
training for the engineering staff. The inspectors reviewed LP ESC-03-LP016,
Lessons Learned from Possible Common Mode Failure of the AFW System,
and discussed the sessions with engineering staff who had attended. The
lesson plan accurately described the AFW issues and the results of the root
cause evaluation. Personnel interviewed indicated that the training was
informative and useful.
- CATPR #4: Implement FP-E-MOD-07, Design Verification and Technical
Review, dated December 27, 2002, in accordance with normal implementation
process.
The action specified was to implement the NMC or fleet modification
procedure. This had not yet been completed at the time of the inspection but
was planned for the end of September 2003. The inspectors reviewed a draft of
the new procedure and the existing Procedure NP 7.2.2, Design Control, and
determined that there was no substantial difference in the requirements for
design verification. As a result, the inspectors concluded that this action was not
a corrective action that would prevent recurrence of the AFW orifice plugging
event. The inspectors observations on the two procedures and the inspectors
conclusion were included in CAP050177, and the licensee subsequently wrote a
Point Beach-specific procedure (NP 7.2.15, Fleet Modification Process), with
improvements, to implement the fleet procedure. The licensee also revised
existing modification/design-related procedures, including NP 7.2.2, to
incorporate similar improvements.
11 Enclosure
b.2 AFW Instrument Air Finding
The inspectors reviewed the second revision of the RCE for the AFW/IA finding.
RCE000202, Potential AFW Pump Damage Due to Low Flow That Results in Increased
Core Damage Frequency, contained the following statement:
On or about 3/7/03, station management concluded that the problem statement
(and therefore the identification of the root cause) for RCE 01-069, Revision 1
was narrowly focused. Management considered that the RCE focused on
procedural inadequacies and did not sufficiently consider potential system design
problems. As a result, other issues that could impact minimum recirculation flow
requirements were not identified. Management commissioned an independent
root cause evaluation team to perform RCE000202 with the following problem
statement:
RCE000202
Problem Statement
The purpose of this investigation is to determine the root and
contributing causes of potential Auxiliary Feedwater Pump
(AFWP) damage due to low flow that results in increased Core
Damage Frequency (CDF).
Revision 2 of RCE000202 was dated April 9, 2003, which was 1 year and 4 months after
the event. Two root causes were identified. The first root cause was the failure to
consider the integration of AFW system design and accident progression. The second
root cause was less than adequate knowledge of the safety significance of the AFW
recirculation line in protecting the pumps. Three contributing causes were identified and
included a lack of problem and issue ownership, less than adequate
engineering/operations interface, and less than adequate management of the
interrelationship of documents.
Overall, the inspectors found the final root cause evaluation to be adequate. However,
a shortcoming in addressing the extent of cause similar to the AFW orifice plugging
issue was identified. In addressing a contributing cause of "Lack of problem and issue
ownership," the report stated:
The RCE Team considers that, in addition to the specific actions
identified above, improvements in the Corrective Action Process are
desired. No specific corrective actions are necessary because recent
initiatives should meet that goal.
Similar to the AFW orifice plugging extent of cause, no specific evaluation was
conducted. Instead the licensee credited a separate initiative without ensuring that the
initiative truly addressed the extent of cause. The inspectors could not determine if the
recent corrective action program initiatives addressed improvements identified by the
RCE team because they were not specified.
12 Enclosure
The inspectors reviewed the implementation and effectiveness of the eight CATPRs
(designated by the licensee as corrective actions (CAs):
- CA29830: Revise Design Input Checklist
This corrective action was initially closed without revising the checklist. The
failure to complete the action as specified was identified by the Technical Review
Panel, a newly formed group that reviewed completed corrective actions. The
checklist was then revised.
- CA29831: Upgrade the EOP/AOP [Emergency Operating Procedure/Abnormal
Operating Procedure] change process to ensure the steps to mitigate the
accident are not in conflict with the design and current licensing basis.
The action was completed as specified.
- CA29832: Develop a strategy and schedule to train individuals on the
interrelationship between system design and current licensing basis.
(Operations)
CA29833: Develop a strategy and schedule to train individuals on the
interrelationship between system design and current licensing basis.
(Engineering)
These two actions were the same for two different groups, operations and
engineering. The intent of the actions was to cover systems other than AFW.
The action for the operations department was extended to July 2004 to allow
time for the reconstitution of the current licensing basis (CLB). Reconstitution
of the CLB was specified in a non-docketed Excellence Plan action plan
(OP-14-004, Reduce Ambiguity of Current Licensing Basis for User) and was a
long-term project extending out several years, with the first set of systems to be
completed in 2004.
The action for the engineering department was complete, although a firm
schedule and strategy had not yet been developed and approved by CARB. The
closure was based on an internal memo from the engineering department to the
training department with a recommended approach to the training which included
a focus group effort to determine the topics for training. This memo also
indicated that a finalized detailed class schedule would be developed by
January 21, 2004. The inspectors reviewed the engineering training schedule for
2004 and determined that this training had not yet been incorporated into the
schedule. The licensee acknowledged that the training would have to be added
to the schedule once the training was developed.
The inspectors considered these actions to be among the most important
corrective actions to prevent recurrence as they directly addressed both of the
root causes identified and extended beyond the AFW system to other important
systems. However, licensee action, to date, had not been timely or sufficient to
ensure that the training specified by this CATPR would be conducted and would
13 Enclosure
be effective to prevent recurrence. The licensee wrote CA053525, 053526, and
053527 to address the timing of the training.
- CA29834: Conduct a detailed review of the AFW system to identify what
modifications must be performed to ensure minimum flow is always available in
all modes for pump protection. Operator action should be minimized if not
eliminated.
The inspectors considered that this detailed review was not really a CATPR, but
that the actions taken to address problems identified by the review were actually
CATPRs. Many of these actions were not yet completed. The licensee had an
external, independent team conduct a safety system functional assessment
(SSFA) of the AFW system and also performed an internal review focusing on
electrical power supplies to AFW system components. The SSFA identified
some issues with the AFW system that required correction but determined that
the system remained operable. The inspectors reviewed a sample of issues
identified by the SSFA and the planned corrective actions.
Prior to the SSFA, and as a result of questions from NRC inspectors
during the special inspection conducted in 2002 (IR 50-266/02-15(DRP);
50-301/02-15(DRP)), the licensee identified an issue with common power
supplies to the SW valves to the AFW pump suction. Under certain plant
electrical configurations, the potential existed for a common mode failure of
three of four SW motor-operated valves (MOVs) during a postulated seismic
event. This operable but degraded condition required compensatory measures,
including additional required operator action outside the control room. An
electrical modification was planned to eliminate the problem and was included in
an Excellence Plan action plan (EQ-15-015, Auxiliary Feedwater Electrical
Modifications); however, the installation of the modification was not scheduled to
be completed until the 4th quarter of 2005. In response to the inspectors
questioning the timeliness of this action, the licensee moved up the scheduled
installation of the modifications and completed the last one in December 2003.
The SSFA identified that the motor-driven AFW pumps were operable but
degraded because of nonconservative IST test criteria for pump differential
pressure. The test criteria had been developed assuming a main steam safety
relief valve setpoint tolerance of 1 percent, when the Technical Specifications
(TSs) allowed 3 percent. The licensee determined that the motor-driven pumps
did not have enough hydraulic margin to overcome the additional pressure.
The pumps were considered operable but degraded because recent main
steam safety valve testing had shown the valves lifting within 1 percent of the
setpoint. The licensee identified several corrective actions, including calculation
revisions and potential capacity upgrades to the AFW system, to restore the
pumps to fully operable. None of the actions had been completed at the end of
the inspection. The capacity upgrades were tracked in an Excellence Plan
action plan (OP-13-008, Gain Additional Design Margin in the Auxiliary
Feedwater System) that was not docketed. The other corrective actions were
tracked only in the corrective action program.
14 Enclosure
- CA29835: Develop a lesson plan to train individuals on the safety-related
functions of the AFW system.
CA29836: Develop a schedule to train individuals on the safety-related functions
of the AFW system.
Both of these CATPRs were extended until mid-2004, as with CA29832,
because of the need to first reconstitute the CLB. The inspectors questioned the
timeliness of this training given that the reviews of the AFW design and licensing
basis were complete. The inspectors considered these actions to be untimely as
the actual training would not likely occur until late in 2004, while the first AFW
issue was identified in 2001 and the second AFW issue was identified in 2002.
The licensee wrote CAP050108 in response to this concern and initiated
CA052332 to reevaluate the due date of the action. The training was
subsequently completed in early December 2003.
- CA29837: Assign an Issue Manager to coordinate the implementation of
changes to DBD-01, FSAR, IST basis, TSs, TRQM [Technical Requirements
Manual], and EOPs to ensure consistency in Safety-Related Function
descriptions related to the AFW system include the appropriate reference(s) for
all of the safety-related components and functions in DBD-01.
This action was closed and the supervisor of the newly developed Configuration
Management group was assigned as the Issue Manager. The inspectors noted
that the assignment of an Issue Manager was not really a CATPR, but rather the
actual correction of the information in the documents was the corrective action to
prevent recurrence. The licensee identified the need to make changes to these
documents through several different efforts, including the RCEs, the AFW SSFA,
and the AFW system self-assessment report. However, there was no single
tracking system or method in place to ensure that all of the required changes
would, in fact, be made. Many of the changes needed were identified in CAPs
and assigned to various people, some of whom were outside of the Issue
Managers department. During an interview, the Issue Manager indicated that
many of the changes would be coordinated through Excellence Plan action plan
OP-14-008, AFW Design Basis Validation Project, but that some of the issues
would be addressed through the corrective action program. The Excellence Plan
action plan had one outstanding action item (OP-14-008.7) to revalidate the
AFW design basis, which was due in the third quarter of 2006. There was a
similar Excellence Plan action plan OP-14-003, Validate Design Bases for High
Risk Systems, which called for the validation of the design basis for seven
different systems, including AFW. Step 14-003.6, which was the actual
validation effort was scheduled to start in the third quarter of 2004 and finish in
the third quarter of 2006. Because of the lack of a detailed plan with due dates,
the inspectors could not conclude that the updates would be completed prior to
2006, which was not considered to be timely corrective action for the AFW
issues that occurred in 2001 and 2002.
During the inspectors review of AFW issues, it became apparent that the Issue
Manager was not consistently aware of activities related to the AFW system.
15 Enclosure
Subsequently, the inspectors determined that no specific guidance or
expectations regarding Issue Manager duties and responsibilities existed. The
licensee wrote CAP050590 to document and track corrective actions related to
the failure to provide formal guidance that defines management expectations
regarding Issue Manager duties and responsibilities. Overall, the inspectors
determined that the licensee had not defined the responsibilities of an issue
manager, and that this CATPR had not been effectively implemented.
b.3 Corrective Action Program Issues
The inspectors reviewed the Excellence Plan action plans (OP-10-001 through -011) for
improving the corrective action program. Many improvement initiatives had only recently
been implemented and the long-term effectiveness of the initiatives could not yet be
determined. In addition, most of the initiatives had not been proceduralized and,
therefore, the inspectors concluded that sustained improvement to the corrective action
program effectiveness could not be fully assured.
The inspectors identified a number of weak areas that may have contributed to the
ineffective implementation of the corrective action program associated with the
significant performance deficiencies. Overall, the inspectors found the program to be
designed to achieve flexibility and management discretion. The program was
implemented in a manner that maximized reporting of problems and did not overextend
resources to resolve them. According to licensee personnel, the number of CAPs was
expected to rise from about 3500 - 4000/year to 7000 - 8000/year. The flexibility of the
corrective action program came with the many procedularized recommendations for
assigning significance levels, performing evaluations, and implementing corrective
actions and a limited number of requirements. As the program had so few
requirements, there were risks of inappropriately limiting the extent of analysis and
correction of the identified issue.
The inspectors had additional observations of the corrective action program, as
discussed below. These observations were documented by the licensee in CAP050177.
Significance Level. Four significance levels (A, B, C, and D) were specified with
examples listed in a matrix to help assign the level. Level A (significant) issues included
significant conditions adverse to quality, level B (moderate) issues included conditions
adverse to quality, level C (minor) issues were other problems, while level D issues were
improvements. Moderate and minor were not defined. The inspectors noted that the
examples listed in the matrix were generally event- or outcome-based. That is, if a
significant plant effect occurred, the issue would be assigned a higher significance level.
Potentially significant issues, if they did not result in a plant effect, were likely to be
considered a level C or minor issue. Applying the criteria in this manner could result in
missed opportunities to proactively evaluate and correct issues and conditions before a
plant effect was seen. As an example, there were no specific criteria to evaluate the
significance of a failure to implement a corrective action or of a engineering problem
such as a deficient calculation. Based on the inspectors observations, these types of
issues would generally be considered minor, or not conditions adverse to quality, unless
there was a plant effect.
16 Enclosure
Five activity types or evaluations were used: RCE, apparent cause evaluation (ACE),
condition evaluation (CE), maintenance rule evaluation (MRE), and operability request
(OPR). RCEs were expected for level A CAPs and justification was required for
exceptions. No causal analysis (RCE or ACE) was required for any significance level
below A.
While onsite, the inspectors observed that a CE was used for some level B issues. The
licensee recently wrote CAP034566 to document that compared to industry norms, the
number of RCEs and ACEs had been very low as related to site performance. Overall,
the inspectors concluded that the licensee identified a lot of issues but did not always
evaluate them at a high enough level. The inspectors did not identify any specific
examples where an issue was not adequately evaluated, though the process could allow
for a review to be performed that was not commensurate with the potential significance
of an issue.
Change Provisions. The procedural requirement to document the justification to not
perform a RCE for a level A CAP was not always followed. At a CARB meeting on
August 4, 2003, the inspectors noted that three of four evaluation reports did not have
the required justification. The licensee wrote CAP034598 to document this problem.
While changes in evaluation to raise the level of evaluation must be approved, there
were no lower level activities upgraded to an RCE observed by the inspectors. Changes
from an ACE to a CE and vice versa were observed.
Automatic Triggers. There are no automatic triggers defined by the corrective action
program to escalate evaluation levels (for example, three level C CAPs on the same
issue within a month moves the latest of the three CAPs to a level B). Consequently,
the risk of missing an adverse performance trend was increased. The lack of automatic
triggers to escalate an issue may also contribute to the potential for issues to be under
analyzed.
Analytical Methods. Only level A issues received an RCE, the only activity level for
which use of analytical cause evaluation methodology was expected. Section 4,
Requirements, of OEG 001, Root Cause Evaluation Manual, the licensees guidance
document, consistently applied the term "should." In fact, the use of the manual itself
was "recommended, but not mandatory. For ACEs, no formal cause evaluation
methods were required to be used, although the program provided that lower level
analytical methods may be used for ACEs. The 2-5 hours estimated level of effort for
an ACE was inconsistent with the suggested guidance to use an analytical method and
perform an extent of condition review. In summary, only about 1 percent of all CAPs
received any level of evaluation through an analytical method.
Teams. There was no requirement to have investigative teams, even for an RCE. As a
part of the recent corrective action program improvement initiatives, the licensee began
to emphasize the use of teams, including interdisciplinary teams. However, use of a
team was not required. The inspectors noted that a recently formed RCE team to
review an issue (CAP033997, Unit 2 Main Feed Pump Trip Results in a Unit 2 Reactor
Trip) consisted of team members only from the engineering department.
17 Enclosure
Independence. There was no requirement for independence anywhere in the process.
In fact, issues were routinely assigned to the department most closely associated with
the issue. For example, an engineering issue would be assigned to the engineering
department and a maintenance issue to the maintenance department for action. While
this approach may encourage ownership, it did not provide the independence needed
for a different, more impartial perspective. The inspectors did recognize that the
Technical Review Board, though not a requirement, involved staff from various
departments which provided effective independent assessments of the adequacy of
corrective actions.
Training. Training was not required but was expected for root cause evaluators.
Licensee management expectation was that each RCE team should have at least one
member trained in analytical cause evaluation techniques. The charter for RCE000205
(for level A, CAP033889, Unit 1 Flux Map Detectors Failing) listed a team lead who
was not on the qualified lead investigator list although the team lead had attended
equipment root cause training in June 2003. Two other members were assigned,
neither of whom appeared on the training or RCE qualified lists. Recently, RCE
refresher training was conducted as part of the corrective action program improvement
initiatives, although there was no requirement for refresher training.
Training was not required for conducting ACEs and there were no qualification
requirements included in the procedures for conducting ACEs. However, ACE training
was conducted recently also as part of the corrective action program improvement
initiatives.
Corrective Action Program and Work Order Process. The inspectors reviewed the
corrective action program and the work order (WO) process to determine the
relationship between the two. The corrective action program was controlled by an
NMC procedure and the WO process was controlled by a Point Beach procedure; the
procedures contradicted each other. The WO procedure (NP 10.2.4) allowed a CAP
to be closed to a WO when the WO was initiated. The corrective action program
procedure (NP 5.3.1, Attachment 6) indicated that the CAP could not be closed until
the actual work was complete. The inspectors noted that the procedures did not
require feedback to the CAP process if a WO was closed that was associated with a
level B CAP, a condition adverse to quality. The licensee wrote CA052067 to resolve
the discrepancy between the two procedures and NP 5.3.1 was subsequently revised
on October 29, 2003, to bring the two procedures into agreement.
Effectiveness Review. Effectiveness reviews were expected, per procedure, for a
majority of RCEs. However, there were eight justifications for not doing one, including
having no corrective actions to prevent recurrence (CATPRs). There was no mention of
effectiveness reviews for any other type of corrective actions or for any activity type
other than RCE. The inspectors determined that the requirements to perform
effectiveness reviews were limited. Considering the number of observations regarding
ineffective corrective action implementation documented in this report this is an area
warranting additional emphasis by the station.
Trending. The corrective action program depended upon trending of items below level
A (and for A level issues not subject to RCEs) to identify in aggregate those things not
18 Enclosure
individually meriting an RCE. Given the increase in CAPs generated and the lowered
threshold for reporting issues, the licensee was relying on trending to identify when to
perform a causal analysis and take additional corrective action. However, the inspectors
found that the trending program was not adequately serving the intended purpose.
Each department performed trending, with some departments trending what happened,
and other departments trending causal and human performance information. The ability
of the trending function to provide a trigger to identify issues or conditions requiring
additional evaluation was diminished by several factors. The method for coding a CAP
only allowed one entry for each of the coding areas; therefore, all of the information,
particularly causes discussed in the ACE/RCE, were not being trended. To the extent
that ACEs (for which an apparent, not a root cause, was expected) did not provide valid
causal information, the trending of causes was suspect. The licensee recently identified
in CAP034566 that for the 2nd quarter of 2003 only about 50 conditions were coded in
the "why" codes. This amount of data would not be meaningful for trending. The
inspectors found several examples where causes identified did not match the cause
code applied:
- RCE000182/CAP002968: The CAP indicated that the Human Performance
Failure Mode was K6 - Inadequate Standards Knowledge. The RCE Human
Performance Failure Modes were: 1. Inadequate Communications; 2. Tunnel
Vision; 3. Wrong Assumptions; 4. Inadequate Verification. Of these reasons,
only Tunnel Vision was Knowledge based. As a result, the three other human
performance failure modes identified in the RCE were not captured in the
trending program.
- RCE000192/CAP030002: The CAP indicated that the Human Performance
Failure Mode was Unknown. The RCE stated that the cause was Lack of
ownership and a flawed mental model of the Cold Weather Preparations
process. There were several Significant Contributing Causes: 1. Inadequate
Understanding of the Programs Scope; 2. Inadequate Implementation of
Corrective Actions From Previous Events and Assessments; 3. Ineffective Use
of Operational Experience (OE); 4. Inadequate Work Control/Management of
Cold Weather Preparations.
In addition to the process weaknesses noted above, work load may hamper the
effectiveness of the corrective action program. There were a number of indications that
the corrective action program-related workload was heavy. The Performance
Assessment Department had routinely worked 60-hour weeks for about 6 months.
Except for filling a position vacated by retirement, the inspectors were not made aware
of any plans to increase the number of personnel in the department, despite a
significant increase in the number of CAPs being generated and additional corrective
action program-related duties that had been added as part of the improvement
initiatives.
19 Enclosure
2.2 Effectiveness of Audits and Assessments
a. Inspection Scope
The inspectors reviewed several Nuclear Oversight (NOS-quality assurance) quarterly
reports from 2002 to present, focusing on NOS findings related to the effectiveness of
the corrective action program. The inspectors also reviewed a recent self-assessment
of NOS effectiveness and interviewed the NOS manager. The Excellence Plan
contained an action plan (OR-02-001, Nuclear Oversight Effectiveness) for improving
NOS effectiveness, but many of the action steps had not yet been completed.
b. Observations and Findings
Based on review of the reports and interviews, the inspectors concluded that the
NOS reports had identified numerous problems with the Point Beach corrective action
program. Specifics of the problems identified are discussed below.
1Q2002 - NOS assessed the overall effectiveness of the Quality Assurance Program
(which included the corrective action program) at Point Beach as adequate/attention
warranted for the first quarter of 2002. NOS identified multiple examples of untimely
corrective actions such as 14 operability determinations greater than 2 years which
were still open. NOS wrote CAP002777, Untimely Corrective Actions - Failure to
Establish Qualification Files for Equipment Credited for Operating in a High Energy
Line Break (Operability Determination 98-0164), which was classified as a significant
QA finding to document and disposition the concern regarding untimely corrective
actions. RCE000051 was conducted from April 8 through June 13, 2002, as part of
CAP002777. The purpose of the RCE was to determine why it was taking more than
4 years to resolve outstanding operable but nonconforming issues. The untimely
corrective actions for the original high energy line break issue are discussed further in
Section 4.1.2 of this report.
4Q2002 - NOS assessed the overall effectiveness of the Quality Assurance Program at
Point Beach as adequate/attention warranted for the fourth quarter of 2002. NOS
continued to identify problems with implementation of the corrective action program,
particularly with the timeliness of corrective actions. A comment in the report stated:
From CA program problems identified, NOS concluded that they had been inconsistent
in getting line management to fully understand significance of issues, and resolving the
issues in a timely manner. NOS wrote CAP030664 to document its findings of untimely
corrective actions.
1Q2003 - NOS assessed the overall effectiveness of the Quality Assurance Program at
Point Beach as adequate/attention warranted for the first quarter of 2003. NOS
identified weaknesses in almost every phase of the operating experience program.
Assessment PBSA NOS-03-03 - This assessment was performed to determine the
effectiveness of NOS. There were several recommendations in the report to improve
performance of NOS. This assessment stated that NOS reports did not pursue major
20 Enclosure
weaknesses they identified, such as the corrective action program deficiencies. An
issue identified in the assessment was that NOS did not adequately Drill Down into
identified issues to adequately identify causes.
The inspectors concluded that NOS had been ineffective in resolution of their findings
concerning inadequate implementation of the corrective action program at Point Beach.
The majority of the untimely corrective actions addressed in RCE000051 remain
unresolved, more than 1 year after the RCE was issued. Proposed improvements to
NOS were addressed in Excellence Plan action plan OR-02-001. The majority of the
improvements will not be implemented until late 2003 and 2004.
2.3 Employee Concerns Program and Safety Conscious Work Environment
a. Inspection Scope
The inspectors reviewed the program requirements, interviewed the employee concerns
program (ECP) site contact, and reviewed several recent ECP files to assess the safety
conscious work environment and to determine if safety-significant issues in the ECP
program received the proper level of attention. The inspectors also reviewed the results
of a site culture survey conducted in late 2002. Also, the inspectors interviewed plant
personnel to assess the safety conscious work environment.
b. Observations and Findings
The ECP files reviewed did not involve safety-related plant systems and did not reveal
any issues that would indicate safety conscious work environment problems. Individuals
interviewed did not express any concerns regarding the work environment and all
indicated that they felt comfortable with raising issues to plant management; however,
there was a perception that corporate management was too involved in the
characterization of risk-significant issues.
The results of the culture survey did not identify any issues with the safety conscious
work environment but did reveal that there was a lack of employee confidence in the
effectiveness of the corrective action program. The survey also found that there were
some issues with the general work culture, including workload and priorities. The
inspectors also reviewed the corrective action program self-assessment results from
mid-2002 which stated that 12 percent of employees interviewed indicate some
reluctance to initiate CAPs. Further follow-up by the ECP staff found that the reluctance
to write a CAP was not a reluctance to identify safety issues but rather resulted from the
boomerang effect in which the employee who initiated a CAP was assigned the CAP
for resolution, thus adding to the employees workload. The follow-up interviews also
found that the reluctance was related to employees not wanting to get their co-workers
in trouble by writing CAPs for low-level errors that they may have committed.
The licensee factored the results of the culture survey and the 2002 corrective action
program self-assessment into the Excellence Plan action plans to address changes in
the ECP (action plan OR-03-001, ECP Integrated Program Improvements) and in the
corrective action program (action plans OP-10-001 through -011, Corrective Action
21 Enclosure
Program). The licensee stated that another site culture survey will be conducted in
late-2004 to measure the results of these changes, as well as the other significant
organizational changes at the site.
2.4 Licensee Performance Goals
a. Inspection Scope
The inspectors reviewed the licensees business plan and incentive program for
2003-2004 to determine if the goals in these plans conflicted with the required
activities outlined in the Excellence Plan to improve plant performance (action plans
OR-06-001, Five Year Strategic Planning Process, and OR-06-002, 2003 Business
Plan and Excellence Plan Rollout).
b. Observations and Findings
The inspectors reviewed the licensees business plan and incentive program and
determined that there did not appear to be any conflict between the goals of these
programs and the actions needed to correct the identified performance issues. In fact,
the business plan was used as an input into the development of the Excellence Plan.
Overall, there appeared to be alignment of the goals in the plans reviewed.
2.5 Allocation of Resources
a. Inspection Scope
The inspectors reviewed corrective action items, attended plant meetings, interviewed
staff and management, and reviewed the Excellence Plan action plans to assess if the
licensee had appropriately allocated resources to correct the identified performance
deficiencies (action plans EQ-15-001 through -018, Equipment Reliability; OP-10-001
through -011, Corrective Action Program; and OP-14-001 through -008, Configuration
Management).
b. Observations and Findings
The inspectors found many indications of competing priorities and a large workload that
affected the quality and timeliness of some licensee corrective actions. For example, in
the interviews conducted by the licensee for the root cause evaluation for possible
common mode failure of the AFW recirculation lines (RCE000191), several engineers
indicated that time and schedule pressure contributed to the inadequate design review
associated with upgrading the safety classification of the recirculation lines. Further
information from the interviews indicated that this situation was not unique and that
other modifications had been similarly hurried. Additionally, one of the corrective actions
to prevent recurrence was to establish the DRB to review engineering products.
However, during the inspection, the licensee identified that the DRB had been canceled
on several recent occasions due to the lack of availability of the assigned staff. The
inspectors noted cancellations of other meetings and numerous examples of missed
training that appeared also to be indicative of a lack of effective prioritization and
allocation of resources.
22 Enclosure
2.6 Use of Industry Operating Experience
a. Inspection Scope
The inspectors reviewed the licensees industry operating experience (OE) program
and interviewed the OE coordinator and plant staff to assess the use of OE. The
inspectors also reviewed the Excellence Plan action plan for improving the OE program
(OP-10-010, Operating Experience (OE) Improvement Plan).
b. Observations and Findings
The inspectors interviewed plant personnel to understand the use of OE, and noted that
the various departments at Point Beach (maintenance, operations, chemistry, and
radiation protection) had incorporated OE into their morning meeting schedules.
The interviews included discussions of the transmittal of OE to the maintenance craft
and engineering personnel.
Based on interviews and review of the Excellence Plan, the inspectors concluded that
the OE program was not formalized in procedures, instead relying mainly on the efforts
of the newly appointed OE coordinator. The Excellence Plan had provisions to develop
procedures to ensure that the program would continue if personnel changes occur. The
inspectors noted during the interviews that some of the personnel assigned as OE
liaisons expressed a concern about the increase in workload and the ability to perform
effectively as the number of tasks they were assigned increased.
2.7 Conclusions of the Corrective Action Program Phase of the IP 95003 Inspection
The inspectors concluded that the licensees control systems for identifying, assessing,
and correcting problems were adequate. However, implementation issues clearly
contributed to the significant AFW findings and examples of poor implementation
continued to exist despite licensee efforts to improve overall implementation. In
particular, the inspectors concluded that several important corrective actions to prevent
recurrence for the AFW findings had not been adequately implemented. These
inadequately implemented corrective actions included the failure to adequately and
consistently implement the Quality Review Team and the failure to conduct training
specified as a result of the AFW findings. Several other actions were specified as
corrective actions to prevent recurrence but the inspectors concluded that the actions
themselves were not corrective actions and would not prevent recurrence. These
included the CATPR specified to implement the fleet modification process for design
verification and the CATPR to assign an issue manager. Overall, the inspectors
determined that short-term corrective actions were adequate to prevent recurrence of
the two specific AFW findings. However, weaknesses in the implementation of some
long-term corrective actions indicated that continued attention was warranted to ensure
that performance improvements related to the corrective actions could be sustained.
While the inspectors concluded that the corrective action program was adequate, there
were weaknesses identified that could contribute to implementation problems.
Examples of those weaknesses included a process that potentially categorized and
analyzed issues at too low of a level and a weak trending process. Recent
23 Enclosure
improvements to the corrective action program were good initiatives, but had not been
formalized and, as a result, long-term improvement could not be assured.
The Excellence Plan addressed a number of significant problems at the plant, including
some AFW-specific corrective actions and corrective action program problems.
However, many of the actions were not completed and in fact, little work had begun.
Examples included improvements in NOS effectiveness, AFW corrective actions,
operating experience program, and design basis validation projects.
Cornerstone: Emergency Preparedness (95003.01)
During a baseline inspection in February 2002 (IR 50-266/02-04(DRS);
50-301/02-04(DRS)), the inspectors identified concerns regarding the adequacy of the
licensees critique of two performance issues during the biennial emergency
preparedness exercise. In a letter dated September 12, 2002, the NRC issued a Final
Significance Determination of White for a finding encompassing both issues. An
additional problem was identified by the inspectors concerning the critique for the
August 1, 2002, emergency preparedness drill (IR 50-266/02-10; 50-301/02-10).
In November 2002, the NRC began a supplemental inspection to review the licensees
root cause evaluation (RCE) for the White finding; however, the inspectors determined
that the RCE (RCE000187) was inadequate. In response, the licensee revised the
RCE. This revision was subsequently reviewed in March 2003 by the NRC and found to
be acceptable (IR 50-266/02-14; 50-301/02-14(DRS)).
In early 2003 (IR 50-266/03-02; 50-301/03-02), the inspectors identified one finding of
very low risk significance (Green) for inadequate configuration control and insufficient
drawings and instructions provided to maintenance and operations personnel during an
emergency notification telephone system battery charger failure and subsequent
replacement activities.
Because of these recent findings and the turnover of upper management in the
emergency preparedness/emergency planning (EP) group at Point Beach, it was
decided to review EP as part of the IP 95003 supplemental inspection. For this effort,
Attachment 95003.01, Emergency Preparedness, was used. This Attachment had four
objectives:
a. To gather information in support of the determination whether the licensee is
capable of implementing adequate measures to protect the public health and
safety in the event of a radiological emergency.
b. To verify that the EP program complies with applicable NRC regulations.
24 Enclosure
c. To verify that the licensee is complying with commitments made in the
d. To verify, to the extent practical, the absence of findings greater than White by
determining the extent of condition of problems in the EP Cornerstone. (The risk
significant planning standards (RSPSs) have the highest priority for inspection
activities.)
These objectives were satisfied during the inspection through the review of the following
six focus areas:
a. Correction of Weaknesses and Deficiencies
b. Emergency Response Organization (ERO) Readiness
c. Facilities and Equipment
d. Procedure Quality
e. ERO Performance
f. In-Depth Review of Risk Significant Planning Standards
3.1 Correction of Weaknesses and Deficiencies
a. Inspection Scope
The inspectors reviewed emergency preparedness/emergency planning (EP)-related
CAPs, 10 CFR 50.54(t) audits, and outside and self-assessments for the last 2 years.
All open EP CAPs and corrective actions related to the March 4, 2002, declaration of an
Unusual Event and those associated with RCE 000194, RCE 000187 Did Not Meet
Standards to Close NRC Inspection, were reviewed to determine if reasonable progress
was being made toward completion. The inspectors reviewed a sample of minutes from
meetings with local, state, and federal officials (offsite agencies), plan change
concurrence documentation, and communication testing results to evaluate the
adequacy of the interface with offsite agencies. The inspectors reviewed media training
conducted for 2002 and 2003 against the requirements in the Emergency Plan in
Section EP 8.0, paragraph 3.3.3, and Appendix E to 10 CFR Part 50. The inspectors
reviewed all Letters of Agreement (LOAs) identified in Appendix D of the Emergency
Plan to verify they supported Emergency Plan commitments. The inspectors reviewed
Procedure NP 5.3.2, Operating Experience (OE) Review Program, a sample of
working copies of ERO training lesson plans on topics associated with risk significant
planning standards, and the ERO training program description to evaluate the
effectiveness of the OE program. The inspectors reviewed medical response
capabilities against the requirements in the Emergency Plan, and the LOAs for medical
facility support. The inspectors interviewed EP management and staff and training
personnel to determine their knowledge of the corrective action program and gain
25 Enclosure
insights concerning implementation of the EP program. The inspectors also reviewed
some past Emergency Preparedness Advisory Committee meeting minutes and
attended one meeting during the inspection.
b. Observations and Findings
In general, self-assessments were adequate; however, in two instances, CAPs were not
written for the improvement recommendations provided in the self-assessments nor
were other means provided to address the recommendations.
The inspectors reviewed CAP032422, A Formal Method For Scheduling Ingestion
Exercises With the State Is Needed. Condition evaluation (CE) 011554 was initiated as
a result of the CAP to determine if a formal method for scheduling ingestion exercises
with the State of Wisconsin was needed. The CE determined that a formal method
already existed in the conduct of a regional scheduling meeting hosted by the Region V
office of the Federal Emergency Management Agency (FEMA). The CAP was closed as
a result. The inspectors were concerned that the resolution of the CAP accepted
reliance on an outside agency to ensure a licensee requirement (10 CFR Part 50,
Appendix E,Section III.F.2 and 2.d; and Section 3, page 73 of NUREG-0654) was met.
The inspectors reviewed the licensees evaluation of and associated corrective actions
for a declaration of a Notice of Unusual Event (NOUE) on March 4, 2002, because of a
low pressure propane gas leak near the protected area fence. The licensee determined
that the classification of the event was untimely (31 minutes, compared to the limit of
Appendix E of 10 CFR Part 50 of 15 minutes); however, this conclusion was not made
until April 2003. This is a licensee-identified Green finding due to the untimely
classification of a NOUE, and is described further in Section 5.
The inspectors identified that numerous opportunities to identify the untimely
classification were missed by licensee evaluations of the NOUE. Each of the following
licensee documents evaluated the timeliness of the classification and concluded that it
was performed in a timely manner: (1) Nuclear Plant Memorandum (NPM) 2002-0016,
Report of Unusual Event Prepared Per NP 1.8.2"; (2) NPM 2002-0158, Report of
Unusual Event Prepared Per NP 1.8.2"; (3) CAP030381, written December 11, 2002, to
evaluate if the March 4, 2002, Unusual Event declaration was timely; (4) ACE01112,
written December 13, 2002, as part of CAP030381; (5) CA027674, initiated January 14,
2003, to revise NPM 2002-0158 to more accurately reflect actual events surrounding the
classification and declaration of the Unusual Event; (6) CA027675, initiated
January 14, 2003, to annotate station log entries for the Unusual Event such that no
confusion existed about when certain events occurred; (7) RCE000187, Failure of the
Emergency Planning Critique Process to Identify Drill/Exercise Weaknesses, (this RCE
identified the Unusual Event declaration as timely); and (8) RCE000194, RCE 187 Did
Not Meet Standards to Close NRC Inspection, (this RCE also identified the Unusual
Event declaration as timely).
The EP staff initiated corrective action document [Other] OTH029034 on April 8, 2003,
to compare the time-line of the Unusual Event with industry guidance in Nuclear Energy
Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 2. It was this document that identified the classification was not timely. The
26 Enclosure
performance indicator (PI) data was recalculated to indicate the drill and exercise
performance (DEP) PI as having a failed classification opportunity. The inspectors
determined that although the RCE determined that event start time for determination of
timely classification was not well understood among both the operators and the facility
EP staff, the licensee did not perform a thorough evaluation to determine if any crew
performance deficiencies contributed to the late emergency classification.
The inspectors also noted that RCE000187 and the RCEs for the Unusual Event missed
an opportunity to evaluate EAL 6.3.1.1 and its history. Recognition of the change from
an earlier version that included the terminology on-site may have indicated that the
EAL committed to was changed in error. The inspectors identified an apparent violation
related to EAL changes, of which this EAL was one example of an EAL change that was
made that decreased the effectiveness of the Emergency Plan. The apparent violation
is discussed in Section 3.6.b.2 of this report.
3.2 ERO Readiness
a. Inspection Scope
The inspectors reviewed a sample of CAPs related to facility staffing/augmentation to
determine adequacy of the corrective actions. The inspectors reviewed onshift staffing
commitments in the Emergency Plan, Section 5, Figure 5-1, and Part 2.0, Normal Plant
Organization, to verify those commitments were met by shift staffing schedules. The
inspectors reviewed procedure Operations Manual (OM) 3.1, Section 5.2, to determine
the composition of normal shift staffing schedules. The inspectors reviewed ERO
augmentation drill records against the response criteria for minimum staffing for
emergency facility activation in the Emergency Plan. The inspectors reviewed data to
determine if the ERO PI was properly evaluated, key responders were identified, drill
credit was properly assessed, and equivalent positions defined against the standards in
NEI 99-02, Revision 2. The inspectors also reviewed protective action recommendation
(PAR) opportunities that contributed to the DEP PI from the 2nd quarter of 2001 through
the 1st quarter of 2003 (8 quarters) to verify proper implementation of the NEI 99-02
guidance.
b. Observations and Findings
The inspectors identified two findings that were characterized as Non-Cited Violations.
The first finding involved the licensees failure to assign onshift staffing for an ERO
function, which was determined to be of very low safety significance (Green). The
second finding was the failure to accurately evaluate and report the ERO PI, a Severity
Level IV violation.
b.1 Review of Onshift Staffing Requirements
The inspectors reviewed the onshift staffing requirements and normal plant organization
as described in Section 5, Figure 5-1, and in Part 2.0, Normal Plant Organization, of
the Emergency Plan. The inspectors determined that the emergency plan required that,
in addition to operations personnel, a qualified Radiation Protection Technologist,
Radiation-Chemistry Technician, and Security Shift Commander be assigned to each
27 Enclosure
shift. The inspectors reviewed actual onshift staffing of the Radiation Protection
Technologist and Radiation-Chemistry Technician positions for Memorial Day weekend
and the month of July 2003. All shifts during this time were staffed. Staffing of the
Radiation Protection Technologist position was controlled in NP 4.2.28, Health Physics
Represented Personnel Assignment and Scheduling Policy. Staffing of the Radiation-
Chemistry position was scheduled via the Chemistry Work Plan. Although the current
procedures staff these positions consistent with Emergency Plan requirements, neither
procedure referenced those requirements. The inspectors identified the lack of
reference to the Emergency Plan requirement as a potential vulnerability in the
continued adequacy of NP 4.2.28 and the Chemistry Work Plan.
b.2 Failure To Assign Onshift Staff For ERO Function
Introduction: A Green, Non-Cited Violation associated with emergency planning
standard 10 CFR 50.47(b)(2) was identified. Specifically, the licensee failed to assign
onshift responsibilities for reading facility seismic monitors, thereby affecting the ability
to timely classify certain seismic events.
Description: The EALs for operational basis and safe shutdown earthquakes
(Alert EAL 6.1.1.2 and Site Area Emergency (SAE) EAL 6.1.1.3) required declaration of
an emergency event when one of the four installed seismic monitors exceeded the event
thresholds defined in the EAL. The monitors were located in various buildings, including
the #3 warehouse, the Unit-1 façade, the drum preparation room, and between the vital
switchgear room and the auxiliary feedwater tunnel. Currently, the warehouse seismic
monitor (SEI-6211) was being calibrated in Sweden. Laptop computers were used to
access and read the level of seismic activity sensed by the monitors. The inspectors
identified that only Instrument and Control (I&C) technicians were trained to use the
portable laptop computers to read the seismic monitors; however, I&C technicians were
not assigned onshift at the facility, and were therefore not immediately available during
off-normal working hours.
The I&C technician staffing was established in the 1984 Emergency Plan change as a
30-minute emergency responder, and allowed use of onshift auxiliary operators in lieu of
onshift I&C technicians. At that time, the seismic monitors did not require the use of a
laptop computer to retrieve the seismic data, and auxiliary operators could read the
seismic monitors. Some time after 1984, the seismic monitors were replaced with the
current monitors, which required use of a laptop computer to retrieve the seismic data.
The licensee failed to identify that the change in seismic monitors would require that an
I&C technician (or an appropriately trained auxiliary operator) be onshift to read the
monitors after a seismic event to ensure a timely declaration of an emergency condition.
The inspectors concluded that during off-normal working hours, the licensee would not
be able to assess in a timely manner the level of seismic activity using the monitors,
which could delay the declaration of the associated Alert or Site Area Emergency.
Analysis: The failure to assign adequate staffing to perform an emergency response
organization function is a performance deficiency that is more than minor because it is
associated with a cornerstone attribute and affected the EP cornerstone objective (to
ensure the adequate protection of the public health and safety). The finding involved
28 Enclosure
the failure to ensure adequate staffing was assigned to be able to implement emergency
action levels in a timely manner. When processed through the EP Significance
Determination Process (SDP), the finding was found to have very low safety significance
because it was only a degradation in the ERO onshift staffing, and therefore did not
represent a planning standard function failure. The inspectors identified this finding
while questioning the ability of control room personnel to receive necessary information
to implement a sampling of EALs.
Enforcement: 10 CFR 50.54(q) provides in part that A licensee authorized to possess
and operate a nuclear power reactor shall follow and maintain in effect emergency plans
which meet the standards in §50.47(b). . . 10 CFR 50.47(b) requires that the onsite
emergency response plans for nuclear power reactors meet each of 16 planning
standards, of which, planning standard 2 states, in part: On-shift facility responsibilities
for emergency response are unambiguously defined, adequate staffing to provide initial
facility accident response in key functional areas is maintained at all times... Contrary
to this, the licensee failed to maintain onshift staffing at all times to be able to read the
facility seismic monitors. Failure to be able to read the monitors during or immediately
following a seismic event would prevent timely implementation of the emergency plan
and is a violation. Because the finding was determined to be of very low safety
significance and was entered into the corrective action program as CAP034693, this
violation is being treated as a Non-Cited Violation, consistent with Section VI.A of the
NRC Enforcement Policy (NCV 50-266/03-07-01; 50-301/03-07-01).
b.3 Failure To Report Accurate ERO PI Information
Introduction: A Severity Level IV Non-Cited Violation of 10 CFR 50.9 was identified
because the licensee failed to provide complete and accurate information to the NRC.
Specifically, the inspectors identified that the ERO drill participation PI was not being
properly evaluated by the licensee and that when the PI was recalculated with the
complete and accurate data, the PI crossed the Green-to-White threshold for the 3rd
quarter of 2001 (and subsequently returned to Green in the 4th quarter of 2001).
Description: The inspectors identified that an onshift communicator had not been
designated in the Emergency Plan, and was not being tracked in the ERO drill
participation PI. The onshift and Emergency Operations Facility (EOF) communicator
positions were designated as key ERO positions in NEI 99-02, and must therefore be
evaluated and tracked in the ERO drill participation PI.
Three onshift positions were trained to complete the emergency notification form: Shift
Manager, Operations Supervisor, and Shift Technical Advisor. None of these positions
were being tracked in the ERO drill participation PI. The EOF emergency notification
procedure, emergency plan implementing procedure (EPIP) 2.1, Notifications - ERO,
State and Counties, and NRC, Revision 26, directed the Emergency Director to perform
the notification task or delegate that function, but did not identify which position in the
EOF was qualified to perform that function. Currently, the EOF communicator, EOF
Manager, and the Emergency Director were the three EOF positions trained to complete
the emergency notification form. Only the EOF communicator was being tracked for the
ERO drill participation PI as a communicator.
29 Enclosure
The licensee evaluated the condition and identified 23 qualified onshift communicators
that should have been tracked and reported in the ERO drill participation PI. After
reevaluating the PI, the indicator would have been White (<80 percent) for the third
quarter of 2001, then Green for all subsequent quarters, including the current quarter.
The inspectors also noted that the onshift Security Commander was designated in
EPIP 2.1 as an onshift communicator, but that position was not trained to complete the
emergency notification form. The inspectors concluded that this designation of the
Security Commander as an onshift communicator indicated a further misunderstanding
of the guidance in NEI 99-02.
Analysis: The failure to accurately track and report the ERO drill participation PI was a
performance deficiency that was more than minor because it was associated with a
cornerstone attribute and affected the EP cornerstone objective (to ensure the adequate
protection of the public health and safety). The finding involved the failure to accurately
report PI data, which, if accurately calculated and reported, would have caused the NRC
to perform additional inspection activities in the fourth quarter of 2001. This issue was
not suited for SDP analysis and was evaluated with the traditional enforcement process.
Enforcement: 10 CFR 50.9 requires in part that Information provided to the
Commission by ... a licensee ... shall be complete and accurate in all material
respects. Contrary to this, the licensee failed to report in the 3rd quarter of 2001
that the ERO drill participation PI crossed the significance threshold to White. The
NRC considered errors in PI data reporting which cause the PI to cross the Green-to-
White threshold to be more than minor because they have the potential for impacting
the NRCs ability to perform its regulatory function, in this case, to have performed a
supplemental inspection. In the traditional enforcement process, this violation is
classified as a Severity Level IV violation, and because it was entered into the
licensees corrective action program (as CAP034650), it is being treated as a
Non-Cited Violation, consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50-266/03-07-02; 50-301/03-07-02). The licensee has since submitted the
complete and accurate PI data to the NRC.
3.3 Facilities and Equipment
a. Inspection Scope
The inspectors reviewed recent CAPs related to emergency facilities and equipment.
The inspectors reviewed the emergency alert siren design basis in the FEMA-approved
Alert and Notification System (ANS) design report. The inspectors reviewed the
designation and capabilities of offsite assembly areas to meet decontamination needs,
status of radiation monitoring equipment, and ability to handle evacuation vehicles
against the criteria of the Emergency Plan. The inspectors toured the Technical
Support Center (TSC) and EOF to determine the adequacy of those facilities to meet
selected design standards in NUREG-0696, Functional Criteria for Emergency
Response Facilities, February 1981.
30 Enclosure
The inspectors reviewed Emergency Plan Maintenance Procedure (EPMP) 5.0,
Post-TMI Meteorological Monitoring Program Design, Operation, and Maintenance,
a 2003 self-assessment of the plants meteorological monitoring program, a sample
of monitoring system calibration records, and a sample of corrective action and other
program records against the program requirements of Section 7 of the Emergency Plan.
The inspectors reviewed a 1982 edition of the meteorological monitoring system
descriptive manual and observed a periodic surveillance of both onsite monitoring
stations. The inspectors observed an August 5 meeting of the monitoring system
upgrade project team that involved representatives of several plant departments,
including I&C, engineering, procurement, and EP. The inspectors also discussed the
meteorological monitoring program with several EP staff members. The inspectors also
reviewed relevant portions of the Emergency Plan, a 2003 White Paper on
Configuration Management licensee document on equipment configuration
management at the Site Boundary Control Center (SBCC) that housed the onsite EOF
and the Offsite Radiation Protection Facility. The inspectors reviewed a sample of
emergency facility-related corrective action program documents, and reviewed a sample
of heating, ventilation, filtration, and air conditioning equipment maintenance records to
determine operability of the emergency facilities against the standard in NUREG-0696
and the requirements and commitments in the Emergency Plan.
b. Observations and Findings
The inspectors reviewed meeting minutes of the Plant Health Committee from
May 9, 2003. The minutes indicated that meteorological monitoring equipment issues
included shortages of spare sensors and other electronic components, degrading wiring,
and recognition of the potential adverse impact on the capability to perform offsite dose
projections using data from this monitoring system. The meeting minutes also
described the status of the meteorological monitoring system as a major issue and a
vulnerability, and that upgrading this system was one of the plants top three priorities.
Following the Plant Health Committee meeting discussions, the licensee established a
multi-disciplinary team for a meteorological monitoring system upgrade project. The
inspectors reviewed meeting minutes from the project teams initial meeting of
July 29, 2003, and attended the second meeting on August 5. Discussion topics
included worker safety concerns, the obsolescence and long-term reliability of the
instrumentation, and availability of spare electrical components for about another year of
service. The project team decided to develop a range of monitoring system upgrade
options to present to senior management for consideration by early September 2003.
The inspectors concluded that appropriate attention was being applied to currently
identified material condition and aging concerns for the emergency facilities and the
meteorological monitoring equipment. As part of Revision 2 of the Excellence Plan,
scheduled to be effective in mid- to late-January 2004, the licensee developed action
plan OP-09-005, Control/Maintenance of EP Required Equipment, to address long-
term EP equipment reliability.
The inspectors reviewed the actions that had been taken for Unresolved Item
(URI) 50-266/03-02-02; 50-301/03-02-02. The URI encompassed the following
concerns: (1) the licensees 50.59 process did not refer EP issues to 10 CFR 50.54(q)
31 Enclosure
for further screening; (2) there were insufficient instructions, procedures, or drawings to
help technicians assess communications equipment problems in emergency response
facilities; (3) equipment in the EOF or Joint Public Information Center (JPIC) could be
replaced by non-licensee personnel without the licensees knowledge; and (4) the ability
to remotely monitor Emergency Notification System (ENS) operability was lost since
January 17, 2003.
The inspectors determined that the fourth concern was not significant given that the
licensee maintains an onsite telephone line having a long distance calling capability. To
address the third concern, the inspectors toured the onsite EOF and discussed the URI
with licensee staff. The inspectors also reviewed the minutes of a Plant Health
Committee meeting conducted on August 1, 2003. Several corrective actions to
address EOF configuration management concerns were initiated, and many of the short-
term corrective actions had not yet been completed. For example, a corrective action
had not yet been completed to install postings at the EOF to warn non-licensee
equipment service providers not to work on EOF equipment without prior coordination
with the licensees work control center. The inspectors reviewed the licensees White
Paper on Configuration Management. The inspectors observed that the white paper
did not address potential equipment and material condition concerns at the JPIC.
During interviews with members of the EP staff, the inspectors noted that one of the four
station seismic monitors used for assessment in the category 6.1 EALs, Natural
Destructive Phenomena, had been sent to Sweden for calibration. The inspectors
determined that the unavailability of the monitor was not evaluated for the affect on the
Emergency Plan or the ability to implement the associated EALs, and no compensatory
measures were put in place. The inspectors determined that loss of one seismic
monitor would not prevent implementation of the associated EALs, but did represent a
degradation in the reliability of the seismic monitoring system. Emergency Plan
Section 7, Table 7-1, identified the seismic monitoring equipment as "4 strong motion
accelerographs," used for assessment provided in 4 plant locations. The inspectors
questioned the EP staff on control of equipment important to EP functions. The staff
indicated that corrective action CA029777, Create A Procedure To Follow When
EP-Related Equipment Is OOS, May 14, 2003, had been written to address the lack of
a program to identify EP-related equipment and the need to contact the EP staff when
that equipment was affected. An appropriate program had been partially drafted at the
end of this inspection.
Based on the status of several open CAPs associated with the URI, future NRC
inspection will be required to gather additional information to assess the adequacy of
licensee actions related to URI 50-266/03-02-02; 50-301/03-02-02.
The inspectors identified an inconsistency between the Emergency Plan and the
FEMA-approved ANS Design Report. Tone alert radio pagers (Section E.6.2.3 of the
design report) were noted as being part of the primary alert notification system, but were
not currently referenced in the Emergency Plan. The inspectors determined that only
one tone alert pager was currently in use, south of the plant at the Point Beach State
Forest park, and procedures were in place to ensure it could perform its notification
function. The inspectors noted that Appendix V of the design report was referred to in
context with the park emergency procedures, but Appendix V no longer existed in the
32 Enclosure
design report. All other areas of the emergency planning zone (EPZ) were notified
through emergency sirens, and tone alert radios were not required.
The inspectors reviewed the designation of and procedures associated with the
offsite assembly areas for exclusion area evacuation. Emergency Plan Section 6.0,
paragraph 5.1.1.d.2(d) and (e), stated that individuals were to proceed to a designated
offsite assembly area when a plant and exclusion area assembly, release, or
evacuation was ordered. These designated offsite assembly areas were the SBCC, the
Two Creeks Town Hall, and the Two Rivers National Guard Armory, as identified in
Table 6-2 of the Emergency Plan. The Emergency Plan contained letters of agreement
with two locations, Two Creeks Town Hall and the Two Rivers National Guard Armory.
The SBCC was a licensee-controlled building located within the owner-controlled area
and, as such, did not require a LOA. The inspectors reviewed EPIP 6.1, Assembly and
Accountability, Release and Evacuation of Personnel, Revision 24, and determined that
although it provided direction on performance of radiological monitoring and
decontamination at the SBCC, it did not provide specific guidance for the other two
offsite assembly areas. In addition, the inspectors noted that EPIP 6.1 stated that an
offsite assembly area could be located "along the evacuation route, if appropriate."
However, the procedure did not provide direction on how this location was to be
determined or established to provide radiological monitoring and decontamination
efforts. The inspectors determined that these procedure weaknesses could potentially
impact the ability to efficiently establish an offsite assembly area.
The inspectors concluded that the licensee had identified and was pursuing correction of
emergency facility and equipment problems, and that the licensee had identified where
some significant challenges remained in this area. The inspectors also concluded that
development and implementation of an effective procedure to identify and track plant
equipment maintenance that could affect emergency preparedness was essential to
ensure that problems, such as the lack of control of seismic monitor and emergency
facility maintenance, were not repeated. In addition, the licensees development and
successful implementation of an Excellence Plan action plan item to address long-term
EP equipment reliability could result in performance improvements in this area.
3.4 Procedure Quality
a. Inspection Scope
The inspectors reviewed the administrative procedure for the corrective action program
(NP 5.3.1) to determine the threshold for addressing EP issues in the corrective action
program. The inspectors sampled recent Emergency Plan changes to determine if
those changes were correctly translated into appropriate procedures. The inspectors
reviewed a sample of EPIPs to determine consistency with Emergency Plan
requirements. The inspectors also reviewed the Emergency Plan against the
requirements in 10 CFR Part 50, Appendix E, Emergency Planning and Preparedness
for Production and Utilization Facilities. The inspectors reviewed public information
brochures provided by the licensee to members of the public living and visiting in the
EPZ, and the Emergency Alert Pre-Scripted Message Manual For Point Beach Nuclear
Power Plant, December 26, 2001, against the requirements in 10 CFR 50.47(b).
33 Enclosure
b. Observations and Findings
The inspectors did not identify any significant procedure quality concerns. In general,
when emergency preparedness problems were identified, they were appropriately
characterized in the corrective action system. The inspectors concluded that the most
significant challenge in this area was implementation of a procedure to control
emergency preparedness related equipment maintenance, which is discussed in this
section and Section 3.3 of this report. The inspectors identified one minor violation
while comparing portions of the Emergency Plan against the requirements of 10 CFR
Part 50, Appendix E.
10 CFR Part 50, Appendix E, Section IV.B, Assessment Actions, states, in part, that
... emergency action levels shall be discussed and agreed on by the applicant and
State and local government authorities ... . The inspectors determined that seven EAL
changes had been made since 1999, but that records of State and local governmental
authority review were unavailable for changes made on February 6, July 7, and
November 15, 2002. Also, the inspectors determined that the licensee did not have a
system in place to prompt a review of EAL changes during other than the end of year
annual review. Because reviews of the EAL changes were conducted annually, and
monthly meetings with local authorities routinely discussed issues, such as EAL
changes, prior to the scheduled annual review, this violation of Section IV.B was
considered a violation of minor significance, not subject to enforcement action in
accordance with Section IV of the NRCs Enforcement Policy.
The inspectors reviewed CAP030938, FT-3299B, DAVS Isokinetic Sampler Flow
Channel Failed High, and CAP032427, U2 Condenser Air Removal Oscillations Affect
On Primary To Secondary Leak Detection. The subject equipment in both of these
CAPs provided indication for emergency assessment/classification; however, neither
CAP assessed the impact of the equipment failures on emergency classification
capability. During a review of capability to implement EALs, the inspectors also
identified that although the four seismic monitors used at the facility were identified as
EP assessment equipment, the laptop computers that were necessary to obtain the
seismic readings from the monitors were not controlled equipment and the EP staff was
not procedurally informed when the equipment was taken out of service. The licensee
had identified this generic weakness and wrote corrective action CA029777, Create A
Procedure To Follow When EP-Related Equipment Is OOS, May 14, 2003. The
inspectors questioned the licensee on the status of completion of the corrective action.
The licensee stated that a matrix of EP-related equipment had been developed, but
other procedural changes to implement the matrix had not been completed. The
inspectors determined that reasonable progress had been made to address CA029777.
3.5 ERO Performance
a. Inspection Scope
The inspectors observed two crews during licensed operator requalification (LOR)
simulator scenario evaluations on July 28 and August 4, 2003. The inspectors observed
34 Enclosure
one limited scope emergency exercise, which involved all emergency response facilities,
except the JPIC, and simulated offsite and NRC participation. The inspectors evaluated
crew performance during the drill, and compared that evaluation with the evaluation
performed by facility drill controllers and evaluators. The inspectors evaluated the
crews performance against facility operating, abnormal, and emergency procedures, as
well as the Emergency Plan and the EPIPs. The inspectors evaluated the ERO training
program against 10 CFR 50.47(b)(15) and (16), and 10 CFR Part 50, Appendix E,
Section IV.F. The inspectors compared a sample of EP-related lesson plans with the
Emergency Plan, EPIPs, and the regulations. The inspectors reviewed a sample of
CAPs related to EP training. The inspectors interviewed training and EP staff to
evaluate management support of ERO training. The inspectors reviewed the EP
training programs against the requirements of the Emergency Plan.
The inspectors reviewed Revision 45 of Chapter 8 of the licensees Emergency Plan, the
1984 revision of this Chapter, the Training Departments August 1, 2003, revision of the
ERO training program, and a sample of master copy and working copy ERO lesson
plans.
The inspectors reviewed a random sample of 25 ERO members computerized training
records in order to determine whether these persons were considered to be currently
trained in accordance with the EP training programs criteria. The inspectors reviewed
self-contained breathing apparatus (SCBA) qualification records of a sample of 70 ERO
members. The inspectors reviewed the most recent medical response drill involving
simulated contaminated, injured victim(s), which was conducted in August 2002, and the
related corrective action program documents. The inspectors interviewed the lead EP
training instructor and reviewed relevant training records of a sample of ERO members
to determine if their training was current.
b. Observations and Findings
b.1 Training
The inspectors identified one finding that was characterized as a Non-Cited Violation of
very low safety significance (Green). The finding was a failure to establish a training
program for the emergency planning department staff.
Introduction: A Green, Non-Cited Violation associated with planning standard
10 CFR 50.47(b)(16) was identified. Specifically, the licensee failed to develop and
implement an EP staff training program to ensure that planners were properly trained.
Description: In NRC supplemental IR 50-266/02-14(DRS); 50-301/02-14(DRS), the
NRC identified that a formal training program had not been developed to ensure that
emergency planners were properly trained. The licensee wrote CAP029492, which
was closed after development of a training program in April, 2003. Subsequently, in
July 2003, the recently appointed EP manager evaluated the training program as
inadequate and canceled the training program procedure (as documented in
CAP033979). After completion of the onsite portion of this inspection, Section 5.0,
35 Enclosure
EP Staff Training, was developed (as part of CA032011) and added to
Procedure EPMP 3.2, Offsite Personnel and Emergency Preparedness Staff
Training, Revision 10, on August 27, 2003.
Analysis: The failure to develop and implement an EP staff training program was a
performance deficiency that was more than minor because it was associated with a
cornerstone attribute and affected the EP cornerstone objective (to ensure the adequate
protection of the public health and safety). The finding involved the failure to ensure
that the EP staff was properly trained. When processed through the EP SDP, the
finding had very low safety significance because lack of a staff training program
presented a potential degrading condition for the level of qualification and proficiency of
the EP staff, but did not represent a failure of the planning standard function. The
inspectors identified this finding while interviewing the EP staff and reviewing corrective
actions associated with IR 50-266/02-14(DRS); 50-301/02-14(DRS).
Enforcement: 10 CFR 50.54(q) provides in part that A licensee authorized to possess
and operate a nuclear power reactor shall follow and maintain in effect emergency plans
which meet the standards in §50.47(b). . . 10 CFR 50.47(b) requires that the onsite
emergency response plans for nuclear power reactors must meet each of 16 planning
standards, of which, planning standard 16 states, in part: ...[Emergency] planners are
properly trained. The Point Beach Emergency Plan, Section 8.0, paragraph 3.1.4,
states, in part: EP staff training required as appropriate. Contrary to this, the licensee
failed to develop and implement an emergency planning staff training program, and
therefore could not ensure that the planners were properly trained. Because the finding
was determined to be of very low safety significance and was entered into the licensees
corrective action program as CAP033979, this violation is being treated as a Non-Cited
Violation, consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50-266/03-07-03; 50-301/03-07-03).
The inspectors identified an inconsistency between the Emergency Plan and EP-TP,
(EP Training Program), on requalification training requirements. EP-TP stated that an
ERO member could acceptably complete all requalification training requirements by
participating in an EP drill or exercise, but the Emergency Plan, Section 8, stated that
requalification training for the ERO shall be a combination of drills and exercises,
classroom and reading training relevant to the ERO position assignment. The
inspectors determined that the inconsistency represented a potential vulnerability to
keeping ERO members training up-to-date on changes to the Emergency Plan, the
EPIPs, associated regulatory guidance, and relevant industry OE.
During the evaluation of the LOR drills, the licensee determined that interpretation of the
Alert EAL for failure of the reactor protection system was inconsistent among the
operating shift crews. The licensee entered the observation in the corrective action
process as CAPs 034364, 034387, and 034547 and the Plant Manager issued a
memorandum to all operators to clarify the EAL. The inspectors independently
evaluated the LOR scenarios, and agreed with the licensees conclusions and corrective
actions.
36 Enclosure
b.2 Exercise Performance
The inspectors observed a limited-scope emergency exercise, August 14, 2003, which
involved use of all the licensee emergency facilities, and simulation of offsite facilities
and governmental agencies. The simulated emergency involved an escalation of
emergency conditions through each of the four emergency classification levels,
beginning with a NOUE due to abnormally high activity in the reactor coolant. Next, an
Alert was required due to a large increase in reactor coolant activity, then a Site Area
Emergency was required due to a reactor coolant leak into the containment. Finally, a
General Emergency was required due to a large break in the reactor coolant system and
a sudden failure of the containment. The simulated release of radioactivity to the
environment then required evaluation and issuance of protective action
recommendations to local government officials for the protection of the public near the
facility.
The inspectors independently assessed the onshift crew response in the simulator
control room, as well as the performance of the augmenting emergency response
organization in the EOF, TSC, and Operations Support Center (OSC). The inspectors
then compared that assessment to the licensees self-critique of its performance which
was presented to the inspectors on August 15, 2003. The licensees assessment of
performance, related to the emergency planning standards in 10 CFR 50.47(b), was
consistent with the inspectors assessment.
Overall, performance by the onshift and the augmenting emergency responders was
adequate and demonstrated successful implementation of the Emergency Plan.
The licensee identified several areas requiring corrective action during the critique and
entered the observations in the corrective action program. The inspectors determined
that none of the performance deficiencies identified were significant and did not impact
the ability of the licensee to adequately respond to an emergency. The inspectors did
not identify any additional performance deficiencies and concluded that the licensees
critique of the exercise was thorough and self-critical. In the control room simulator,
proper actions were taken to mitigate the events and the associated classifications and
notifications to offsite agencies were performed within required time limits.
Communications between the control room, OSC, TSC, and EOF were adequate. Good
command and control was observed in each of the emergency facilities, and emergency
classifications and notifications were completed successfully.
The inspectors observed the post-exercise self-critiques in each of the emergency
facilities. Each of the critiques was self-critical and focused on performance issues. In
the EOF, the inspectors observed a health physics technician question the
appropriateness of the protective action recommendation following the General
Emergency declaration. This emergency responder stated that due to the very short
duration of the release, a shelter protective action recommendation may have been
more appropriate than an evacuation recommendation. This comment was
acknowledged by the EP staff leading the critique, but it was also stated that the current
procedures did not allow a shelter recommendation. The inspectors concluded that the
protective action recommendation was consistent with the requirements in the Point
Beach Emergency Plan. The adequacy of the Emergency Plan and procedures in not
37 Enclosure
allowing a shelter recommendation was identified as an unresolved item and is
discussed in Section 3.6 of this report.
Overall, the inspectors concluded that the exercise was a successful demonstration of
the licensees ability to implement the Emergency Plan to protect public health and the
environment.
3.6 In-Depth Review of RSPSs
a. Inspection Scope
The inspectors performed a detailed review of the licensees compliance with
10 CFR 50.47(b)(4) and (10). The inspectors reviewed NUREG-0654/FEMA-REP-1,
Revision 1,Section II.D., Planning Standards and Evaluation Criteria-Emergency
Classification System, as informing criteria to determine compliance with the planning
standard. The inspectors reviewed EPIP 1.2, Emergency Classification,
Revisions 20-33, and Appendix B to the Emergency Plan, and compared the current
EALs against the criteria in NUREG-0654, Revision 1, Appendix 1. The inspectors also
reviewed NUMARC/NESP-007, Methodology for Development for Emergency Actions
Levels, Revision 2, and Regulatory Guide 1.101, Emergency Planning and
Preparedness for Nuclear Power Plants, Revision 3, as informing guidance for review
of the EALs. The inspectors conducted a facility and simulator control room walkdown
to verify that indications required for implementation of a sample of 17 EALs were
available in a timely manner to the control room staff. The inspectors also reviewed a
sample of CAPs related to event classification.
b. Observations and Findings
The inspectors identified three findings. The first finding was characterized as an
unresolved item (URI) related to the failure to establish a range of PARs associated with
RSPS 10. The second finding was characterized as an apparent violation (AV) involving
a failure to maintain a standard scheme of EALs, associated with RSPS 4. The third
finding was characterized as a Non-Cited Violation of very low safety significance
(Green) involving a failure to maintain the ability to implement a Notification of Unusual
Event (NOUE) EAL, also related to RSPS 4.
b.1 Failure to Establish a Range of Protective Action Recommendations
Introduction: A finding associated with emergency planning standard
10 CFR 50.47(b)(10) was identified. Specifically, the licensee failed to ensure that
a range of PARs was established for state and local governmental authorities. This
finding is characterized as a URI pending further regulatory review of the potential
generic aspects of this finding, including the review of the current regulations and
regulatory guidance for providing PARs.
Description: The inspectors reviewed the Emergency Plan and noted a statement in
Chapter 6.0, Emergency Measures, Section 5.1.2.a.5 (a): Although the State of
Wisconsin and the counties could implement sheltering, and because sheltering has
different meanings for NRC and FEMA, Point Beach Nuclear Plant will only recommend
38 Enclosure
evacuation as a protective action for the public. The inspectors noted that this
statement was inconsistent with federal guidance issued in a combined FEMA and NRC
document, NUREG-0654/FEMA-REP-1, Revision 1, Supplement 3, Criteria for
Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants. The subtitle of this guidance
document was Criteria for Protective Action Recommendations for Severe Accidents.
Section II of NUREG-0654, Supplement 3 stated, in part, The guidance emphasizes
that the preferred initial action to protect the public from a severe reactor accident is to
evacuate immediately about 2 miles in all directions from the plant and about 5 miles
downwind from the plant. In addition, shelter may also be the appropriate protective
action for controlled releases of radioactive material from the containment if there is
assurance that the release is short term (puff release) and the area near the plant
cannot be evacuated before the plume arrives.
The inspectors reviewed facility emergency notification forms, notification procedures,
and the emergency director checklists. None of the documents reviewed contained
guidance nor supported issuing other than an evacuation recommendation to the offsite
government authorities. The inspectors also observed a limited scope emergency
exercise during which a large, short duration initial release of radioactivity was
simulated, followed by an almost complete cessation of the release. During the critique
of the exercise, the individual who had acted as the emergency director in the EOF
stated that he had not made a shelter recommendation because it would have violated
the Emergency Plan.
The inspectors reviewed the change package for Revision 5 to EPIP 1.1.2, Plant
Operations Manager, General Emergency - Protective Actions; Revision 17 to
EPIP 9.3, Protective Action Evaluation; and Revision 30 to the Emergency Plan.
These changes were made in January 1994 to ensure consistency of these procedures
with the licensees interpretation of the U.S. Environmental Protection Agency guidance
in EPA-400-R-92-001, Manual of Protective Action Guides And Protective Actions For
Nuclear Incidents, May 1992. Notification forms that were to be filled out according to
EPIP 2.1, Notifications - ERO, State and Counties, and NRC, were also revised to
remove sheltering as a licensee recommendation. Revision 17 of EPIP 9.3, Protective
Action Evaluation, changed the minimum protective action for a general emergency
from sheltering to evacuation. The inspectors noted that Revision 30 of the Emergency
Plan discussed sheltering as an option, but the supporting EPIPs as changed in
January 1994 did not support issuing a shelter recommendation. The inspectors
reviewed NRC correspondence and determined that no NRC review of Revision 30 to
the Emergency Plan was documented.
The inspectors reviewed Revision 33 to the Emergency Plan. This revision, made in
January 1997, incorporated guidance in NUREG-0654, Supplement 3, by adding
Figure 1, Severe Core Damage or Loss of Control of Facility, Public Protective Actions,
as Table 4-1 in the Emergency Plan. With this revision to the Emergency Plan, all
discussion of sheltering as a PAR option was removed. NRC Region III letter dated
March 27, 1997, stated, in part, In late January, 1997, Region III received individually
numbered revisions to the Point Beach Nuclear Plants emergency plan, which were
dated January, 1997. Our initial review of these changes indicates them to be in
accordance with 10 CFR 50.54(q). Implementation of these changes will be subject to
39 Enclosure
inspection to confirm that they do not decrease the effectiveness of your emergency
plan.
The inspectors also reviewed Revision 35 to the Emergency Plan. This revision,
dated October 28, 1998, added the current statement that only an evacuation PAR
would be given to the state and local governmental agencies. This plan change was
submitted to the Region III office as required, but was not submitted for preapproval.
NRC IR 50-266/98020(DRS); 50-301/98020(DRS), which was an evaluated exercise
report, stated, in part, in Section P3, that The inspectors reviewed a sample of ...
emergency plan sections, including those related to the October 28, 1998, Emergency
Plan Revision. The observations and findings section does not address any
conclusions specifically for the Emergency Plan revisions. This scope statement in the
1998 report was the most specific reference to some level of review of the October 1998
changes, but did not specifically state that the change was reviewed for a decrease in
effectiveness. NRC Region III letter dated March 26, 1999, stated, in part, In
November 1998, Region III received various changes to portions of the Point Beach
Nuclear Plant Emergency Plan. Our initial review of these changes will be subject to
inspection to confirm that they have not decreased the effectiveness of your Emergency
Plan. The inspectors determined that review of Revision 35 to the Emergency Plan had
been documented, but approval of the changes had not been given in the inspection
report nor the March 26, 1999, letter. During the 95003 inspection, the inspectors
determined that the change constituted a decrease in effectiveness of the plan and
should have been submitted to NRC for review and pre-approval.
Analysis: The failure to ensure that a range of PARs had been developed to protect the
public is a performance deficiency that is more than minor because it is associated with
a cornerstone attribute and affected the EP cornerstone objective (to ensure the
adequate protection of the public health and safety.) The finding involved the failure to
ensure that a range of PARs was developed and would be given to state and local
government authorities as appropriate for the associated emergency conditions. When
processed through the EP SDP, the finding was found to have a potential significance of
greater than very low significance because it represented a potential failure of the RSPS
10 function of providing a range of PARs. The inspectors identified this finding while
reviewing the Emergency Plan and EPIPs. The licensee entered the finding in their
corrective action process as CAP034785.
Enforcement: 10 CFR 50.54(q) provides, in part, that a licensee authorized to possess
and operate a nuclear power reactor follow and maintain in effect emergency plans
which meet the standards in §50.47(b). The nuclear power reactor licensee may make
changes to the plans without NRC approval only if the changes do not decrease the
effectiveness of the plans and the plans, as changed, continue to meet the standards of
§50.47(b). Proposed changes that decrease the effectiveness of the approved
emergency plans may not be implemented without application to and approval by the
NRC.
10 CFR 50.47(b) requires that the onsite emergency response plans for nuclear power
reactors meet each of 16 planning standards, of which, planning standard 10 states, in
part, that a range of protective actions be developed for the plume exposure pathway
EPZ for the public, and in developing this range of actions, consideration be given to
40 Enclosure
evacuation and sheltering and that guidelines for the choice of protective actions also be
developed and put in place. Contrary to this, the Point Beach Emergency Plan,
Chapter 6.0, Emergency Measures, Section 5.1.2.a.5 (a), states, in part, Although the
State of Wisconsin and the counties could implement sheltering, and because sheltering
has different meanings for NRC and FEMA, Point Beach Nuclear Plant will only
recommend evacuation as a protective action for the public. As a result, the facility has
not developed a range of PARs. The finding was determined to be an unresolved item
pending further regulatory review of the potential generic aspects of this issue, including
a review of past correspondence and generic communications with the industry
regarding PARs (URI 50-266/03-07-04; 50-301/03-07-04).
b.2 Failure to Maintain a Standard Scheme of Emergency Action Levels
Introduction: A finding and apparent violation of 10 CFR 50.54(q), associated with
RSPS 4 of 10 CFR 50.47(b), was identified. Specifically, the licensee failed to maintain
a standard scheme of EALs, as defined in Regulatory Guide 1.101, Emergency
Planning and Preparedness for Nuclear Power Plants.
Description: The inspectors identified a significant deviation in the EAL scheme used at
Point Beach from the version approved in 1984 via a Safety Evaluation Report (SER)
after NRC review of a revision of the Emergency Plan. As discussed in Revision 4 of
Regulatory Guide 1.101, the EAL schemes in the following documents were acceptable
for meeting 10 CFR 50.47(b)(4) and 10 CFR Part 50, Appendix E requirements:
NUREG-0654/FEMA-REP-1; NUMARC NESP-007; and the most recently approved,
Nuclear Energy Institute (NEI) 99-01, Methodology for Development of Emergency
Action Levels, Revision 4, January 2003.
Chapter 4 of the Emergency Plan (Revision 38, dated February 6, 2002) stated that the
emergency classification system was based on NUREG-0654, Revision 1, Appendix 1.
In 1984, NRC reviewed revisions of the Emergency Plan using the criteria of the
16 emergency planning standards as stated in NUREG-0654. The NRCs conclusions
were transmitted to the licensee as SER 50-266/83-25 and 50-301/83-23, dated
February 2, 1984. The licensees emergency classification procedure, EPIP 1.2,
Revision 39, and the Emergency Plan, Appendix B, contained the EALs for Point Beach.
The inspectors compared EPIP 1.2, Emergency Classification, Revision 39, to
NUREG-0654 and determined that the Point Beach EAL scheme was missing the
following initiating conditions that were in NUREG 0654: NOUE 1, 4, 6, 8, and 9;
Alerts 2, 3, and 9; Site Area Emergencies (SAEs) 1, 2, 8, 10, 13b, and 13c; and General
Emergencies (GEs) 1a, 5a, 5c, 5d, and e. The inspectors also noted that the EAL
scheme used a fission product barrier table that was not consistent with NUMARC-007
in that the "barrier challenged" column was not used to escalate the classification at the
SAE level.
The inspectors also compared the current EALs in EPIP 1.2, Revision 39, to the 1984
version of EALs. The inspectors determined that there were 7 EALs missing in the
current version. The current format of the EALs was significantly changed on
December 29, 1999, with Revision 33 to EPIP 1.2, when the Fission Product Barrier
41 Enclosure
table was incorporated. Change documents also removed 3 specific EALs that were
derived from the FSAR. Another EAL was reduced from an Alert to an NOUE.
The inspectors determined that many of the changes were in agreement with changes
that would be found acceptable as described in NRC guidance in EPPOS-1,
Emergency Preparedness Position (EPPOS) On Acceptable Deviations From
Appendix 1 of NUREG-0654 Based Upon The Staffs Regulatory Analysis of
NUMARC/NESP-007, Methodology For Development of Emergency Action Levels;
however, a number of other changes, as summarized below, should have been
submitted to NRC for prior approval. Regulatory Guide 1.101, Section C, indicated that
using portions of both EAL methodologies was not acceptable. EPPOS-1 allowed use
of the basis of the NUMARC scheme to enhance and clarify some site-specific EALs
developed from NUREG 0654; however, it stated that the scheme must remain internally
consistent.
The inspectors identified eight EALs that had been changed from the 1984-approved
EAL scheme that should have been submitted to the NRCs Office of Nuclear Reactor
Regulation for review and approval prior to implementation. The inspectors determined
that the eight EAL changes, discussed below, decreased the effectiveness of the
Emergency Plan in that emergency conditions that would have resulted in classifications
at the GE, Alert, and NOUE levels would result in a lesser classification under the
licensees current EAL scheme.
GENERAL EMERGENCY: EAL GE-1, as approved in 1984, required, in part,
the declaration of a GE if a field dose rate corresponding to a 5 Rem committed
dose equivalent to the thyroid (for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of inhalation) was measured. With the
revision of this EAL on October 28, 1998, in Revision 32 to EPIP 1.2, the current
EAL wording does not require a GE declaration directly from a field dose rate
measurement corresponding to a 5 Rem committed dose equivalent to the
thyroid (for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of inhalation). This revision resulted in a less conservative
criterion for a GE declaration.
EAL GE-5(b), as approved in 1984, required, in part, the declaration of a GE for
a transient causing loss of all feed/condensate and all AFW for greater than
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. With the revision of this EAL on December 29, 1999, in Revision 33 to
EPIP 1.2, the current EAL required a loss of vital alternating current for greater
than 15 minutes, and replaced the greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> loss of all
feed/condensate requirement with steam generator level and AFW flow criteria
that would indicate a significant loss of feed. The addition of the loss of vital
electrical power criterion is a more restrictive condition.
ALERT: EALs A-18a and A-18b involved other hazards being experienced or
projected. The first EAL involved an aircraft crash in the protected area, and the
second involved a missile impact from any source by visual observation. Both
EALs had a more restrictive condition added to say that the hazard was
affecting operability of one (1) train of a safety system.
42 Enclosure
These two EALs were revised on December 29, 1999, in Revision 33 to
EPIP 1.2, which was also part of Revision 14 to the Emergency Plan Index.
NOUE: EALs UE-14c and UE-14d, involved other hazards, including explosion
and toxic/flammable gas release. While the original EALs included the owner
controlled area, the EALs were changed to exclude areas of the site outside the
protected area, resulting in a more restrictive condition.
EAL UE-13 involved a tornado sighting. While the original EAL was applicable if
a tornado was visible from the site, the EAL was changed to make it applicable
only if a tornado was within the protected area or switchyard, resulting in a more
restrictive condition.
The EAL scheme approved by the NRC in 1984 included an NOUE
(Category 18a) for uncontrolled control rod withdrawal. This EAL was removed
from the EAL scheme with an explanation that an uncontrolled rod withdrawal
event was encompassed in the Alert EAL for a Reactor Protection System (RPS)
failure. However, the inspectors concluded that this explanation was incorrect,
since EALs for RPS failure did not address an uncontrolled rod withdrawal. The
inspectors concluded that there were no EALs in the current EAL scheme for an
uncontrolled control rod withdrawal.
The four NOUE EALs were revised on December 29, 1999, in Revision 33 to
EPIP 1.2, which was also part of Revision 14 to the Emergency Plans Index.
The licensee entered the inspectors preliminary finding (current EAL scheme not
in accordance with one of the standard EAL schemes endorsed by Regulatory
Guide 1.101) in its corrective action process as significant condition report CAP034784,
which required a formal root cause analysis and identification of corrective actions.
Analysis: Point Beachs EP program failed to maintain the Emergency Plans scheme of
EALs such that all initiating conditions, which had been assumed in the licensees
approved EAL basis (NUREG-0654, Revision 1, as amended in NRCs 1984 SER),
would result in emergency classifications at appropriate levels. Specifically, two GE, two
Alert, and four NOUE EALs were changed, resulting in decreases in effectiveness of the
Emergency Plan without a commensurate decrease in the approved basis of the
Emergency Plan. As a result, the licensee might not have classified several emergency
events at the same level that would have resulted from use of the 1984 NRC-approved
EAL scheme. A decrease in the GE level of classification would result in decreased
protective action recommendations for the offsite authorities, and potentially a reduction
in the level of protective action decisions forwarded to the public by offsite authorities. A
decrease in the Alert and NOUE levels of classification could also have resulted in a
reduced level of response by offsite authorities if their level of response was based to
some extent on which of the four emergency classes was associated with the licensees
emergency declaration.
Enforcement: 10 CFR 50.54(q) provides, in part, that a licensee shall follow and
maintain in effect emergency plans which meet the standards in §50.47(b). The
licensee may make changes to the emergency plans without NRC approval only if the
43 Enclosure
changes do not decrease the effectiveness of the plans and the plans, as changed,
continue to meet the standards of §50.47(b). Proposed changes that decrease the
effectiveness of the approved emergency plans may not be implemented without
application to and approval by the NRC.
10 CFR 50.47(b) requires that the onsite emergency response plans for nuclear power
reactors meet each of 16 planning standards, of which, planning standard 4 states, in
part, that a standard emergency classification and action level scheme is in use.
Chapter 4 of the Emergency Plan (Revision 38, dated February 6, 2002) stated that the
licensees emergency classification system was based on NUREG-0654, Revision 1,
Appendix 1.
Contrary to the above, from October 1998 through December 1999, the licensee made
changes without NRC approval to the EALs in Appendix B of its Emergency Plan that
decreased the effectiveness of the Plan and resulted in use of a non-standard scheme
of EALs. For example, as discussed above, the licensee made significant changes to
both the content and format of its EAL scheme, with resultant decreases in
effectiveness of 8 EALs. The licensee wrote CAP034784 for this finding. Also,
ACE001405, associated with CAP034833, Inconsistency In Evaluation/Interpretation of
EAL, was initiated. The failure to receive NRC approval prior to changing the EAL
scheme is an Apparent Violation of 10 CFR 50.54(q), associated with emergency
planning standard 10 CFR 50.47(b)(4) (AV 50-266/03-07-05; 50-301/03-07-05). The
details of this apparent violation were communicated to the licensee in a letter dated
December 2, 2003, and a predecisional enforcement conference to discuss it further
was conducted on January 13, 2004.
b.3 Failure To Maintain Ability To Implement An NOUE EAL
Introduction: A Green, Non-Cited Violation associated with emergency planning
standard 10 CFR 50.47(b)(4) was identified. Specifically, the licensee failed to ensure
that the facility seismic monitors were capable of supporting implementation of an
Description: EAL 6.1.1.1 required declaration of an NOUE if ground shaking was felt or
if an indicator light (set to actuate at greater than or equal to .01g) was observed on two
or more of the four seismic monitors. The seismic event indicating lights actuate when
sensed ground motion exceeded the setpoint, then extinguish when ground motion was
reduced to below the setpoint. The as-found setpoint for all three seismic monitors (one
monitor, SEI-6211, had been sent to Sweden for repair) exceeded .03g. The licensee
discovered the incorrect setpoints in response to the inspectors questions regarding the
seismic EALs. The licensee determined that the setpoint control document, STPT 22.1,
dictated a correct setpoint of .01g. However, the only test conducted to verify
functionality of the seismic monitors, the imbalance test, did not verify the setpoint and
would not have indicated a failed test for a setpoint above .01g. Additionally, there was
no system or procedure to periodically verify the accuracy of the as-found setpoints.
The inspectors determined that the failure to maintain the setpoints created a condition
such that NOUE EAL 6.1.1.1 could not be implemented using the seismic monitor
indications.
44 Enclosure
Analysis: The failure to ensure that EP equipment was maintained ready to support
implementation of the Emergency Plan was a performance deficiency that was more
than minor because it was associated with a cornerstone attribute and affected the EP
cornerstone objective (to ensure the adequate protection of the public health and
safety.) The finding involved the failure to ensure that seismic monitoring equipment,
necessary for implementation of NOUE EAL 6.1.1.1, remained functional with
reasonable assurance. When processed through the EP SDP, the finding was found to
have very low safety significance because a NOUE could be declared based on ground
shaking. Consequently, the lack of accurately set seismic monitors only degraded the
capability to implement EAL 6.1.1.1, and was therefore not a planning standard function
failure. The inspectors identified this finding during review of CAPs that were written
during the inspection as a result of the inspectors concerns with the seismic monitors.
The licensee wrote CAP034787 for the setpoint control concerns.
Enforcement: 10 CFR 50.54(q) provides, in part, that a licensee shall follow and
maintain in effect emergency plans which meet the standards in §50.47(b). 10 CFR
50.47(b) requires that the onsite emergency response plans for nuclear power reactors
meet each of 16 planning standards, of which, planning standard 4 states, in part, that a
standard emergency classification and action level scheme, the bases of which include
facility system and effluent parameters, is in use. The Point Beach Emergency Plan,
Appendix B, contains EALs, including EAL 6.1.1.1, which must be implemented based
on in-plant parameters. Contrary to this, the licensee failed to maintain the seismic
monitors in a functional condition such that EAL 6.1.1.1 could be implemented.
Because the finding was determined to be of very low safety significance and was
entered into the licensees corrective action program as CAP034787, this violation is
being treated as a Non-Cited Violation, consistent with Section VI.A of the NRC
Enforcement Policy (NCV 50-266/03-07-06; 50-301/03-07-06).
The inspectors reviewed a sample of 17 EALs to determine if the indications would be
available in the control room in a reasonable time for operators to implement the EALs.
During this review, the inspectors identified that indications for two seismic activity
EALs, 6.1.1.2 and 6.1.1.3, would not be available in a timely manner during a seismic
event due to inadequate shift staffing. The inspectors determined this was a violation of
NRC regulations, which is described in Section 3.2.b.2 of this report.
3.7 Conclusions of the Emergency Preparedness Phase of the IP 95003 Inspection
In summary, although the EP program at Point Beach has several challenges to
address in both the immediate and near-term, the inspectors concluded that Point
Beach can implement its EP program adequately to protect the public health and safety
and the environment. This conclusion is largely based on the observation of the
August 14, 2003, drill, where the licensee demonstrated that they could implement the
Emergency Plan in a manner commensurate with protecting public health and safety.
The positive results of this exercise were consistent with observations of prior drills in
November 2002 and June 2003. The Apparent Violation associated with the failure to
maintain a standard scheme of Emergency Action Levels, the Unresolved Item and drill
critique observations associated with protective action recommendations, and the NCV
associated with accurate reporting and tracking of the control room communicator in the
emergency preparedness performance indicators, were all indications of potentially
45 Enclosure
significant misunderstandings of EP regulations and guidelines. The NCVs associated
with seismic monitors, ability to implement the EALs, and lack of a formal EP staff
training program were examples of inadequate licensee processes for maintaining the
EP program. The inspectors concluded that implementation of the corrective action
program for the EP area was adequate, but that the evaluation of extent of condition of
problems continued to show some challenges. The inspectors noted that many of these
problems originated under previous EP department management, and that the current
staff and managers, while relatively inexperienced, were dedicated to the identification
and correction of those problems.
4. Engineering, Operations, and Maintenance
As discussed in Inspection Reports 50-266/01-17(DRS); 50-301/01-17(DRS), dated
April 3, 2002, and 50-266/02-15(DRP); 50-301/02-15(DRP), dated April 2, 2003, and
Final Significance Determination Letters dated July 12, 2002, and December 11, 2003,
the Red inspection finding for the AFW/IA issue and the Red inspection finding for the
AFW orifice plugging issue were caused by design process weaknesses and faulty
knowledge of the design basis of a risk-significant system, AFW. Consequently, the
focus of the third and final phase of the IP 95003 was design engineering. To assess
this area, the inspectors conducted a vertical slice of two risk significant systems:
component cooling water (CCW) and 125-volt direct current (VDC). The inspectors also
reviewed AFW corrective actions and, in response to the electrical grid disturbance in
the eastern United States on August 14, 2003, the design basis, licensing basis, and as-
built configuration of several AC electrical distribution systems.
And lastly, the inspectors reviewed selected aspects of the operations and maintenance
areas, with an emphasis on the interface of engineering with these areas.
To meet the five overall objectives of the 95003 inspection, as listed in Section 1 of this
report, the inspectors used the guidance of IP 95003 and reviewed the following key
attributes during this phase of the inspection:
a. Design
b. Human Performance
c. Procedure Quality
d. Equipment Performance
e. Configuration Control
As with the review of the corrective action program aspects of problems in the EP area
during the EP phase of the inspection, the inspectors reviewed the corrective action
program aspects of problems in engineering during this phase of the 95003 inspection.
4.1 Engineering
46 Enclosure
4.1.1 125-VDC System
4.1.1.1 Design Basis, Licensing Basis, and As-Built Review
a. Inspection Scope
The inspectors reviewed the design basis, licensing basis, as-built design features, and
several recent modifications of the 125-VDC system to determine if the system was able
to perform the intended safety functions with a sufficient margin. Included in this review
was a detailed walkdown to determine if the system was in a configuration to support its
safety function. The inspectors reviewed a sample of corrective actions involving design
control issues, the control of design and licensing input and output information, the
adequacy of design modifications, and selected 10 CFR 50.59 evaluations related to
design and procedure changes, and compared the as-built design with the current
design and licensing basis.
b. Observations and Findings
For the review of the 125-VDC system using the five key attributes of IP 95003, no
findings of greater than very low safety significance (Green) were identified and the
system was found to be operable. As discussed in Section 4.1.4, minor corrective
action program problems were identified. Of greater concern, discussed below, were a
non-conservative TS surveillance requirement for the safety-related battery chargers, a
high work load in engineering that has resulted in engineering staff frequently being
reactive to plant issues (instead of pro-active), and a failure to maintain system
calculations up-to-date.
Although the licensee had identified the need to update the calculations, the licensee
had not fully evaluated the extent of the problem nor aggressively pursued its resolution.
As of the end of the inspection, the licensee appropriately reassessed the priority
assigned to updating the calculations.
b.1 125-VDC TS Surveillance Requirement
Introduction: The inspectors identified that the TS surveillance requirement (SR) for
testing the battery chargers was non-conservative in relation to the design basis
calculation for battery charger sizing. This failure to assure that the regulatory
requirements and the design basis of the plant were accurately maintained was
determined to be of very low safety significance and was dispositioned as a Green,
Non-Cited Violation. Additionally, the TS bases for the SR did not agree with the FSAR.
Description: Calculation 2003-0046, Battery Chargers Sizing and Current Limit
Setpoint, Revision 0, established a minimum battery charger size (minimum current
limit setpoint) for the D-07, D-08, D-09, D-107, D-108, and D-109 battery chargers of
293 amps (amperes) DC. This value was calculated using the FSAR Section 8.7.2
description of the battery charger as an acceptance criterion. The FSAR stated, The
battery chargers have been sized to recharge any of their respective partially discharged
batteries within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while carrying normal load. The licensee then established the
minimum current value by conservatively establishing current output for both the normal
47 Enclosure
DC load and the discharged battery.
Technical Specification SR 3.8.4.6, however, tested the batteries by verifying that
battery chargers D-07, D-08, and D-09 each supply $ 203 amps at $ 125 V for $
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and battery chargers D-107, D-108, and D-109 each supply $ 273 amps at $
125 V for $ 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The TS bases stated, These requirements are based on the
design capacity of the chargers. According to Regulatory Guide 1.32 [Criteria for
Safety-Related Electric Power Systems for Nuclear Power Plants], the battery charger
supply is required to be based on the largest combined demands of the various steady
state loads and the charging capacity to restore the battery from the design minimum
charge state to the fully charged state, irrespective of the status of the unit during these
demand occurrences. The minimum required amperes and duration ensures that these
requirements can be satisfied. These requirements did not reflect both the FSAR
description and the battery charger sizing calculation which appeared to support a
requirement of 293 amps at $ 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Based upon the inspectors finding, the licensee wrote CAP050366 and reviewed the
surveillance procedures for the battery chargers. In this CAP, the licensee attempted to
demonstrate that the existing surveillance test adequately ensured that the battery
chargers could recharge the batteries in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> while supporting DC loads. By taking
advantage of existing conservatisms in the battery charger sizing calculation and
comparing these new required outputs for the chargers to the surveillance test
procedure, the licensee was able to conclude that the battery chargers were operable.
Although the licensee had been able to demonstrate by calculation the operability of the
battery chargers, the licensee had failed to maintain an accurate design basis and
license basis for the chargers.
The inspectors also determined that TS SR 3.8.4.6 appeared to be non-conservative in
relation to the design basis calculation for battery charger sizing.
Analysis: This failure to assure that the regulatory requirements and the design basis of
the plant were accurately maintained is a violation of the requirements in 10 CFR
Part 50, Appendix B, Criterion III, Design Control. This finding was determined to be
more than minor because it affected the mitigating systems cornerstone objective. The
finding screened as Green in the SPD Phase 1, Mitigation Systems, question 1.
Because this issue was a design deficiency that was confirmed not to result in the loss
of function in accordance with GL 91-18, Information to Licensees Regarding NRC
Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions,
Revision 1.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in
part, that measures shall be established to assure that applicable regulatory
requirements and the design basis are correctly translated into specifications, drawings,
procedures, and instructions.
Contrary to this, the licensee failed to assure that the design basis of the safety-related
48 Enclosure
battery chargers was accurately translated into TS SR 3.8.4.6. This violation was
determined to be of very low safety significance because the licensee was able to
subsequently demonstrate, through calculation, that the battery chargers were operable.
Since this design control violation was captured in the licensees corrective action
program (CAP050366), it is considered a Non-Cited Violation (NCV 50-266/03-07-07;
50-301/03-07-07), consistent with Section VI.A.1 of the NRC Enforcement Policy.
b.2 125-VDC System Calculations
Introduction: The voltage drop, baseline cable ampacity, and short-circuit calculations
needed revision and no longer reflected the configuration of the 125-VDC system at
Point Beach Nuclear Plant (PBNP). The battery sizing and 125-VDC loading calculation
had been revised but was still in draft form and the calculation of record no longer
reflected the present plant configuration. The inspectors identified that the licensee had
performed modifications to electrical equipment in the 125-VDC system without updating
affected design basis calculations. This left the plant in a configuration that was not
supported by an updated design basis. This failure to maintain the design basis of the
plant was determined to be of very low safety significance and was dispositioned as a
Green, Non-Cited Violation.
Description: Design change package MR 97-014 documented a plant modification that
was designed to improve selective coordination; to provide better independence
between Unit 1, Unit 2, and common loads; to remove some nonsafety-related loads
from the safety-related buses; and to reduce the loading on certain safety-related buses.
The modification changed loads fed from both the D-01 and D-02 125-VDC buses.
To support this modification, the licensee issued calculation addendum E-09334-472-
DC.3 to address voltage drop. This calculation provided a justification that the terminal
voltage for the relocated loads was acceptable; however, it did not evaluate voltage for
loads that were not relocated. Also, the calculation provided a qualitative analysis of
voltage drop, but it did not provide a true design basis calculation for voltage drop in the
125-VDC system. This was recognized within the calculation by a statement in the
background section that A formal revision of WE [Wisconsin Electric] calculations
N-93-056 and N-93-057, Battery D05 (D06) DC System Sizing, Voltage Drop, and Short
Circuit Calculations, is required.
The inspectors determined that for a major realignment of loads, such as that performed
by MR 97-014, the design basis voltage drop calculation should have been revised to
reflect the new loading configuration. While calculation addendum E-09334-472-DC.3
addressed voltage drop considerations qualitatively, it was used more as a justification
for operability rather than as a true design basis calculation. Additionally, the licensee
implemented the modification in seven separate phases over several years. Each
phase was implemented similarly to a completed modification. Calculation addendum
E-09334-472-DC.3 addressed the MR 97-014 as a complete design change but there
were no calculations to support the interim changes made by each phase of the
modification. The inspectors determined that this was another instance of the licensee
operating in a design configuration that was not supported by a design basis voltage
drop calculation. The inspectors reviewed calculation addendum E-09334-472-DC.3
and determined that the calculation was adequate. As a result, although the licensee
49 Enclosure
had qualitatively determined that the loads in the 125-VDC system were operable, the
design basis of the plant was not being maintained even though major configuration
changes had been made.
The inspectors also reviewed design change package MR 03-005, implemented in
May 2003. This modification repowered the turbine-driven AFW pump recirculation
valves 1AF-4002 and 2AF-4002. For this design change, the licensee performed a
more thorough analysis; however, the calculation was embedded within the modification
and was not a stand-alone calculation as required by the current plant procedure,
NP 7.2.1, Plant Modifications. The inspectors noted that this was another example of
the licensees failure to update the design basis calculations. However, since the
analysis contained within MR 03-005 determined that the change was technically
acceptable and that no operability concerns existed, there was no loss of function
associated with this issue.
Although the licensee was able to determine the operability and functionality of DC loads
for both MR 97-014 and MR 03-005, the existing design basis calculations had not been
adequate. This was further compounded by the failure of the licensee to update the
design basis calculations since MR 97-014 was implemented.
Analysis: This failure to assure that the design basis of the plant was accurately
maintained in regard to the 125-VDC voltage drop calculations is a violation of the
requirements in 10 CFR Part 50, Appendix B, Criterion III, Design Control. This finding
was determined to be more than minor because it affected the mitigating systems
cornerstone objective.
The finding screened as Green in the SPD Phase 1, Mitigation Systems, question 1.
This issue was a design deficiency that was confirmed not to result in the loss of
function in accordance with GL 91-18.
Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in
part, that measures shall be established to assure that applicable regulatory
requirements and the design basis are correctly translated into specifications, drawings,
procedures, and instructions.
Contrary to this, the licensee failed to assure that the design basis of the 125-VDC
system was correctly translated into specifications when major configuration changes
were made to the system and the system voltage drop calculations were not revised to
reflect these changes. This violation was determined to be of very low safety
significance (Green), because the licensee was able to demonstrate, through analysis,
that the effects of the modifications did not affect functionality of equipment powered by
the 125-VDC system. And because this design control violation was captured in the
licensees corrective action program (CAP002410, CAP034396, CAP050403), it is
considered a Non-Cited Violation (NCV 50-266/03-07-08; 50-301/03-07-08) consistent
with Section VI.A.1 of the NRC Enforcement Policy.
The licensees overall efforts to improve calculations were included in Excellence Plan
action plan OP-14-005, Validate and Integrate Calculations and Setpoints. As with
inspectors observations about the timeliness of action plan actions for setpoints
50 Enclosure
(discussed in Sections 4.1.4 and 4.1.5), the due dates of action plan actions for
reviewing and revising calculations were not timely. The licensee subsequently revised
the due dates. The revised dates were appropriate.
4.1.2 Design Basis and As-Built Review of AC Systems, Including the Offsite Electrical
Distribution Grid and Plant Electrical System Interface
a. Inspection Scope
As part of the review of the 125-VDC system and in response to the electrical grid
disturbance in the eastern United States on August 14, 2003, the inspectors reviewed
the design basis, licensing basis, and as-built configuration of several AC systems at
Point Beach. In addition, some recent CAPs related to the AC systems were reviewed.
b. Observations and Findings
As with the review of the 125-VDC system using the five key attributes of IP 95003, no
findings of greater than very low safety significance were identified during the review of
the AC systems and the systems were found to be operable. As discussed below, minor
problems were identified with calculations, procedures, and corrective actions. Of more
concern was the inspectors observations that engineering staff had a weak
understanding of system design basis. In addition, the inspectors determined that
issues involving high-energy line break/equipment qualification were not resolved in a
timely manner.
b.1 Offsite Electrical Distribution Grid Issues
The inspectors reviewed licensee documentation and held discussions with operations
and engineering staff to assess the adequacy of plant systems and procedures to
ensure the availability of offsite power. As a result, the inspectors made the following
observations.
- The TS basis for Limiting Condition for Operation (LCO) 3.8.1, AC Sources,
stated that the plant could withstand a Design Basis Accident with only one
offsite source without losing offsite power. The inspectors questioned this
statement and the licensee subsequently determined that it was incorrect and
would have to be changed. The problem with the basis required no change to
the LCO.
- Fast Transfer of 13.8-Kilovolt (kV) Station Buses. The inspectors identified that
the licensee did not have a documented analysis that verified that the safety-
related electrical buses would remain connected to the offsite source following
the failure of one of the two station high voltage auxiliary transformers. Also,
there were no procedures in-place to alert operators of the increased risk of grid
separation for certain allowable onsite electrical system alignments. This risk
would be increased if one or both of the unit auxiliary transformers (UATs) were
already out-of-service prior to the transfer, because loading on the operating
51 Enclosure
high voltage transformer after the transfer would be considerably more than
when the UAT(s) was/were in-service.
The failure to analyze the electrical distribution system for limiting alignments
that could lead to the complete loss of offsite power to the safety-related buses is
a violation 10 CFR Part 50, Appendix B, Criterion III, Design Control. However,
this issue did not have a significant impact on safety because the failure of a
high voltage transformer concurrent with an accident was highly unlikely. In
addition, failure of a high voltage transformer with two UATs out-of-service was
considered very unlikely. Consequently, the issue is considered minor, and thus,
it is not subject to enforcement action in accordance with Section IV of the
NRCs Enforcement Policy. The licensee wrote CAP050414 to address this
issue.
- Procedure for Assuring Acceptability of Grid Voltages. During the initial part of
the inspection, plant engineers were unaware of operations procedures and
controls for assuring the acceptability of grid voltages. About 2 weeks later
during the inspection and in response to inspectors questions, licensing
engineering staff were informed by operators that Procedure OP-2A, Normal
Power Operation, addressed this issue and that, in addition, measures had
been implemented by the grid operator, American Transmission Company
(ATC), in 1997 to preclude spurious separation of the Point Beach buses from
offsite power. These measures consisted of software with a real time
contingency alarm that would alert ATC personnel if grid conditions were such
that a single contingency, such as the trip of a Point Beach unit or a transmission
line failure, would cause Point Beach switchyard voltage to decrease too low.
ATC personnel would then notify the Point Beach control room. The measures
by ATC appeared to be appropriate, but were not in OP-2A, so the Point Beach
operator response to such a notification was uncertain. In response, the
licensee wrote CAP050227 and initiated actions to revise Procedure OP-2A.
After engineering personnel became aware of ATCs measures, they were not
able to retrieve an analytical basis for the contingency alarm setpoint.
Calculation N-93-098 determined the reset setpoint for the degraded voltage
relays, but it did not determine tolerances associated with this parameter so that
the maximum value was not determined.
A maximum value was needed to compare with available bus voltage to verify
that the degraded voltage relays would reset under worst case grid and plant
loading conditions. In addition to the lack of a maximum reset value, there was
no calculation that determined the safety-related 4160-V bus voltage that would
result from the minimum grid voltage of 348.5 kV used as the alarm setpoint by
ATC. The inspectors attempted to estimate the relationship between 4160-V bus
voltage and switchyard voltage using Calculation N-93-002, but due to significant
errors in the calculation, this was not successful. The inspectors were
subsequently able to determine from engineering evaluations performed by the
licensee during this inspection that the ATC setpoint was conservative relative to
maintaining the availability of the offsite source.
52 Enclosure
The failure to implement adequate procedures to enable operators to determine
the operability of the offsite power source is a violation 10 CFR Part 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings. However,
this issue was of minor safety significance because available data indicated that
grid availability at Point Beach was very high. The licensee had not received any
notifications of actual alarms from ATC for potentially unacceptable voltages
since the implementation of the real time network analyzer in 1997. Because
this issue was minor, and adequate measures were now in-place to ensure the
availability of the offsite source to mitigate an accident, it is not subject to
enforcement action in accordance with Section IV of the NRCs Enforcement
Policy. The licensee wrote CAP050227 to address this issue.
These three issues with the offsite power supplies (the inaccurate TS basis statement,
lack of analysis of limiting grid alignments, and weak procedure guidance for assuring
acceptability of grid voltage) were not operability concerns but did demonstrate
weaknesses in engineering communication with operators, lack of clear understanding
of the design basis for degraded voltage protection, and lack of rigor in the degraded
grid calculation.
b.2 Environmental Qualification of Electrical Equipment
1. The inspectors identified a Green, Non-Cited Violation of 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, for the licensees failure to
implement timely corrective actions for safety-related electrical equipment in the
primary auxiliary building (PAB) that was not environmentally qualified.
Description: On January 18, 1998, the licensee identified (CAP001559) that the
stations newly revised HELB analysis had identified areas in the PAB that had
previously been considered as mild environments but were now considered as
harsh environments. The licensee documented this issue in CAP001559. The
postulated HELB that could cause these harsh environments in the PAB was the
potential rupture of the 3-inch line in the PAB supplying steam to the radioactive
waste system and to the turbine-driven AFW pumps. The licensee determined
that because of these harsh environments there was electrical equipment
important to safety that was not evaluated in the environmental qualification (EQ)
program, a condition adverse to quality. At the time, the licensee performed an
operability determination (OD) and concluded that electrical equipment needed
to shut down the plant if the 3-inch steam line break were to occur was operable
but degraded.
As a corrective action, the licensee installed HELB wall barriers and a blow-off
panel in the CCW heat exchanger room to protect the non-EQ electrical
equipment.
In June 2003, the inspectors reviewed CAP001559 and the associated OD. The
OD had been revised 12 times since 1998, but the corrective action for this
condition adverse to quality had still not been completed. Additionally, the
inspectors determined that the current OD had not adequately evaluated
environmental effects on all electrical equipment that potentially could be subject
53 Enclosure
to a harsh environment. The inspectors concluded that the licensee had failed to
correct this condition adverse to quality for over 5 years and had failed to
adequately address operability concerns associated with the environmental
qualification of affected electrical equipment. After communicating this finding to
the licensee, the OD was again revised. The inspectors reviewed the new
evaluation and again determined that the OD did not adequately address the
environmental qualification of affected electrical equipment.
In August 2003, the licensee completed the corrective action by erecting HELB
wall barriers and installing a blow-off panel in the CCW heat exchanger room.
This corrective action eliminated the EQ concerns associated with the potential
rupture of the 3-inch steam line in the PAB.
Analysis: The failure to correct this condition adverse to quality was more than
minor because if left uncorrected, it would become a more significant safety
concern. Failure to correct problems with environmental qualification of electrical
equipment could potentially have adverse effects on the capability to prevent or
mitigate the consequences of accidents. However, the inspectors determined
that this finding was of very low significance and screened this finding as Green
in the SPD Phase 1, Mitigation Systems, question 1. The corrective action issue
was associated with a qualification deficiency that did not result in a loss of
function per GL 91-18. Additionally, in August 2003, the licensee completed the
corrective action for this condition by erecting HELB wall barriers and installing a
blow-off panel in the CCW heat exchanger room. This eliminated the EQ
concerns associated with the potential rupture of the 3-inch steam line in the
PAB.
Enforcement: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
requires, in part, that conditions adverse to quality, be identified and corrected.
Contrary to this, as of June 2003, the licensee had not corrected a condition
adverse to quality associated with safety-related electrical equipment in the PAB
that was not environmentally qualified. Specifically, for over 5 years, the
licensee relied on an OD that did not adequately evaluate environmental effects
on all electrical equipment instead of correcting the existing condition.
Because the finding was in the licensees corrective action program
(CAP001559), this violation is being treated as a Non-Cited Violation
(NCV 50-266/03-07-09; 50-301/03-07-09) consistent with Section VI.A.1
of the NRC Enforcement Policy.
2. The inspectors also identified a Green, Non-Cited Violation of 10 CFR 50.49(f)
for the failure to environmentally qualify the equipment.
Description: As discussed previously, when the inspectors reviewed the OD
associated with CAP001559 in June 2003, it had been revised 12 times.
Revision 12 identified all equipment evaluated for harsh conditions in the PAB:
54 Enclosure
- Equipment That Could Adversely Affect Reactor Coolant Pump Seal
Cooling,
- Safety-Related MCCs,
- Electrical Cables,
- Charging Pump Motors, and
- CCW Pump Motors.
The inspectors reviewed the evaluation for this equipment and did not identify
any major discrepancies. However, the licensee could not provide a list of all
required equipment for safe shutdown of the plant in the case of the 3-inch
steam line rupture. Additionally, the inspectors determined that several items
were not evaluated by the OD. Specifically, the licensee had not evaluated the
following for a harsh environment:
- electrical terminal connection boxes,
- electrical pull boxes,
- electrical junction boxes, and
- nonsafety-related MCCs that could prevent satisfactory accomplishment
of safety functions.
In response to the inspectors concern regarding Revision 12 of the OD, the
licensee revised the OD. The inspectors reviewed this updated OD and
determined again that the evaluation did not address their concerns.
Specifically, while the licensee attempted to address the potential effects of a
harsh environment on electrical enclosures (terminal boxes, etc.), the licensee
relied on EQ evaluations performed by other nuclear power plants for their plant
specific configurations. The inspectors determined that the licensees evaluation
did not bound the configurations at Point Beach.
As discussed earlier in this report, the licensee completed the corrective action
for this condition in August 2003 by erecting HELB wall barriers and installing a
blow-off panel in the CCW heat exchanger room. This corrective action
eliminated the EQ concerns associated with the potential rupture of the 3-inch
steam line in the PAB. However, the licensee had failed to adequately
environmentally qualify electrical equipment important to safety in accordance
with the requirements in 10 CFR 50.49(f).
Analysis: The failure to correct this condition adverse to quality is more than
minor because it affected the mitigating systems cornerstone. Failure to
environmentally qualify electrical equipment could potentially have adverse
effects on the capability to prevent or mitigate the consequences of accidents.
However, this finding screened as Green in the SPD Phase 1, Mitigation
Systems, question 1. This issue was a design deficiency that did not result in
the loss of function per GL 91-18.
Enforcement: 10 CFR 50.49(f) states, in part, that electrical equipment
important to safety must be qualified by one of the following methods:
55 Enclosure
- testing an identical item of equipment under identical conditions with a
supporting analysis to show that the equipment to be qualified is
acceptable,
- testing a similar item of equipment with a supporting analysis to show that
the equipment to be qualified is acceptable,
- experience with identical or similar equipment under similar conditions
with a supporting analysis to show that the equipment to be qualified is
acceptable, and
- analysis in combination with partial type test data that supports the
analytical assumptions and conclusions.
Contrary to this, the licensee had identified that equipment important to safety
located in the PAB would be susceptible to a harsh environment during a
postulated HELB, but failed to environmentally qualify this electrical equipment.
Therefore, because this violation of 10 CFR 50.49(f) was captured in the
licensees corrective action program (CAP001559), it is considered a
Non-Cited Violation (NCV 50-266/03-07-10; 50-301/03-07-10) consistent with
Section VI.A.1 of the NRC Enforcement Policy. The licensees overall efforts for
the high energy line break issue was contained in Excellence Plan action plan
EQ-15-006, High Energy Line Break Project.
b.3 Miscellaneous AC Electrical Distribution System Issues
During the inspectors review of licensee documentation related to the design and as-
built configuration of the electrical distribution system, the following additional
observations regarding licensee design control practices were made.
- MOV Voltage Calculation Used Non-Conservative Methodology. Calculations
used non-conservative methodology for determining voltage at motor control
centers (MCCs) serving motor-operated valves (MOVs). Calculation N-94-009
determined the minimum voltage at MCCs based on the results of Calculation
N-93-002, which determined steady state voltages on the safety-related buses.
Calculation N-93-002 treated MOVs as intermittent loads and considered them to
be off for steady-state conditions. This resulted in a non-conservative result for
use in MOV voltage calculations because there would be an additional voltage
drop in the circuit elements upstream of the MCCs when the MOVs were
operating. In response to the inspectors question, the licensee issued
CAP050174, which evaluated additional margins showing that MOV voltage was
acceptable. Because MOV operability was not compromised, this design control
violation constitutes a violation of minor significance, not subject to enforcement
action in accordance with Section IV of the NRCs Enforcement Policy.
However, it is another example of a design control weakness.
- The inspectors identified that the transfer setpoint for the vital inverter static
transfer switches was not periodically calibrated to assure premature transfer
would not occur and that some setpoints were not contained in the stations
56 Enclosure
setpoint document. The vital inverters may be powered from a nonsafety-related
480-V source if the safety-related 125-VDC source became unreliable. The
automatic transfer to the nonsafety-related source was accomplished through a
static transfer switch that monitored inverter output. The transfer to the
nonsafety-related source was a nonsafety-related function, but preventing
spurious transfer was a safety-related function and depended on voltage and
time delay setpoints. In response to the inspectors inquiries, the licensee
identified that these setpoints were not periodically calibrated. In addition, the
slow transfer time delay setpoints for the red channel and blue channel inverters
were not listed in the setpoint document. Because maintenance records
indicated that there had been no spurious transfers due to setpoint errors, this
design control and procedure violation constitutes a violation of minor
significance, not subject to enforcement action in accordance with Section IV of
the NRCs Enforcement Policy. It indicated weaknesses in the licensees
maintenance and configuration control programs. The licensee wrote
CAP050164 to document this issue and track associated corrective actions.
Though the safety consequences of the above examples were minor, the examples
indicate a lack of attention to detail by the engineering staff in assessing issues related
to plant configuration and design control in the electrical area.
4.1.3 Component Cooling Water (CCW) System
4.1.3.1 Design Basis, Licensing Basis, and As-Built Review
a. Inspection Scope
The inspectors reviewed the design basis, licensing basis, as-built design features, and
several recent modifications of the CCW system to determine if the system was able to
perform the intended safety functions with a sufficient margin. Included in this review
was a detailed walkdown to determine if the system was in a configuration to support its
safety function. The inspectors reviewed a sample of corrective actions involving design
control issues, the control of design and licensing input and output information, the
adequacy of design modifications, and selected 10 CFR 50.59 evaluations related to
design and procedure changes, and compared the as-built design with the current
design and licensing basis.
The inspectors reviewed CCW system calculations; related CAPs; system drawings; and
design basis documents, including the FSAR, TSs, the licensing basis summary, and
the CCW DBD, to determine if the CCW system was able to perform its intended safety
function. The inspectors reviewed CCW heat exchanger thermal performance, design
temperature, and CCW surge tank minimum volume calculations to determine the
adequacy of assumptions and methodology used. These were also reviewed to
determine if calculations were consistent with design basis documents.
The inspectors also reviewed the CCW system training lesson plan for consistency with
current design basis and parameters. The lesson plan included major system
components, objectives, and operating parameters.
57 Enclosure
The inspectors also reviewed some recent CCW-related CAPs to assess whether
design and licensing operating parameters were being controlled. Corrective actions
were reviewed to assess the effectiveness of maintaining CCW system design. The
inspectors reviewed some recent CAPs related to design basis temperature and flow
limits and requirements, heat exchanger tube plugging limits, and calculation
deficiencies.
b. Observations and Findings
For the review of the CCW system using the five attributes of IP 95003, no findings of
greater than very low safety significance (Green) were identified and the system was
found to be operable. As discussed below, the inspectors identified a minor violation for
inadequate control and evaluation of relief valve setpoint changes; a Green, NCV for the
failure to include certain manual CCW valves in the inservice testing program; and a
minor procedure violation regarding an Appendix R replacement CCW pump motor
b.1 CCW Relief Valve Setpoint Changes
The inspectors reviewed calculation N-93-71, 1(2)CC-754A, 754B, 1(2)CC-759A, 759B
(Group 11) MOV Differential Pressure Calculation, Revision 0, dated February 1, 1994.
A portion of this calculation determined the most limiting pressure in the CCW system
occurred upstream of reactor coolant pump CCW outlet valves 1(2)CC-759A and
1(2)CC-759B. The calculation stated that this system pressure would be limited to
145 pounds per square inch - gauge (psig) based on the setpoint of CCW relief valves
1(2)CC-763A and 1(2)CC-763B. This value was used to determine the maximum
differential pressure across the MOVs when they were required to be closed. Valves
1(2)CC-759A and 1(2)CC-759B were manual containment isolation valves, as shown on
FSAR Figures 5.2-17 and 5.2-18, dated June 2002.
The inspectors questioned the basis of the 145 psig upstream pressure value. It was
the inspectors understanding that the setpoints of CCW relief valves 1(2)CC-763A and
1(2)CC-763B had been increased to 150 psig. In addition, the setpoint value used in
the calculation did not appear to account for relief valve accumulation.
In response to these questions, the licensee stated that the setpoints for relief valves
1(2)CC-763A and 1(2)CC-763B had been changed from 145 psig to 150 psig as a result
of CAP002914. However, the inspectors noted that this setpoint change had failed to
consider the impact of the change on the inputs to calculation N-93-71 and on the
isolation function of valves 1(2)CC-759A and 1(2)CC-759B. In addition, calculation
N-93-71 did not include any additional allowances for relief valve setpoint uncertainty or
accumulation. The licensee wrote CAP050229 on September 17, 2003, to address
these issues. The licensee also verified that valves 1(2)CC-759A and 1(2)CC-759B had
sufficient margin to close and remained operable.
After additional investigation, the licensee identified that the 10 CFR 50.59 evaluation
associated with the relief valve setpoint change (SCR 2002-0184, dated April 26, 2002)
did not adequately address the impact of the relief valves 25 percent accumulation
value on the system piping. CAP050367 was written on September 23, 2003, to
address this issue. This CAP identified actions to revise the 50.59 evaluation, establish
58 Enclosure
the extent of condition, and review the control of the setpoint change process. The
inspectors also noted that the PBNP self-assessment earlier in 2003 had not identified
this concern.
Although the failure to adequately control and evaluate the relief valve setpoint change
had been identified during the inspection, the licensee verified that valves 1(2)CC-759A
and 1(2)CC-759B had sufficient margin to close and remain operable. The inspectors
determined that this issue was not a precursor to a significant event, this issue would
not become a more significant safety concern if left uncorrected, this issue was not
related to performance indicators, and it did not directly affect any of the cornerstone
attributes. Therefore, the failure to adequately control and evaluate the relief valve
setpoint change was a violation of minor significance that was not subject to
enforcement action in accordance with Section IV of NRCs Enforcement Policy. The
licensee documented this failure in CAP050229 and CAP050367. Licensee overall
efforts to improve relief valve performance were part of Excellence Plan action plan
EQ-16-010, Make Improvements in the Relief Valve Program.
During the review of this area, the inspectors also identified a problem with the setpoints
in several EOPs. This issue is discussed in Section 4.1.5.
b.2 Appendix R Replacement CCW Pump Motor
Routine Maintenance Procedure RMP 9006-4, Component Cooling Water Pump Motor
Emergency Replacement, Revision 2, Section 2.4, listed two motors as available
spares (Lot Numbers 9101179 and 9100242). The inspectors asked the licensee to
verify the availability and acceptability of these two motors. The licensee verified that
the motor located in Warehouse 3 (Lot Number 9100242) was correct. However, the
licensee found that the lot number of the other spare CCW motor had been changed
from 9101179 to 9033181, and that the motor was located in the West Quonset Hut at
the time of the inspection. The licensee also stated that this spare motor (Lot
Number 9033181) had a higher locked rotor current rating (kVA (kilovolt-ampere)
Code G) than the installed CCW pump motors (kVA Code D), notwithstanding a
licensee evaluation performed per CA018346 that determined the motor was acceptable
for use as an Appendix R spare. The licensee wrote CAP050276 on September 18,
2003, to correct the lot number listed in RMP 9006-4.
The inspectors then questioned the acceptability of using the spare motor with the
higher locked rotor current rating (kVA Code G) without resetting the affected motor
supply breaker. The licensee performed an additional evaluation and concluded that
this motor should not be used as a spare CCW motor. The licensee then wrote
CAP050398 to supersede CAP050276 and remove the reference to the second spare
motor from Procedure RMP 9006-4.
The inspectors noted that the use of this spare motor had been previously questioned
during the 1999 CCW system self-assessment (S-A-ENG-99-007). It appeared that
Spare Parts Equivalency Evaluation Document (SPEED)99-003 had been initiated to
approve the use of this motor as an Appendix R spare, but the SPEED had not been
approved at the time of the 1999 self-assessment. The resolution of this self-
assessment issue was documented in Engineering Work Request S-A-ENG-99-007,
59 Enclosure
Action Number 6, on December 22, 1999, which concluded that this motor could not be
used without modifications to the electrical switchgear, and SPEED 99-003 would be
canceled.
The inspectors did not determine why Procedure RMP 9006-4 included a reference
to an inappropriate motor for use as a CCW spare. However, Engineering Work
Request S-A-ENG-99-007, Action Number 9, issued a temporary change to
Procedure RMP 9006-4 on September 21, 1999. Therefore, it appeared that the
procedure was updated to reference this second spare motor prior to the cancellation of
SPEED 99-003, and that the procedure was not corrected after the SPEED was
canceled. The inspectors also noted that the PBNP self-assessment earlier in 2003 had
not identified this concern.
The failure to adequately control the reference to spare CCW motors in Procedure
RMP 9006-4 was a violation of minor significance, not subject to enforcement action in
accordance with Section IV of NRCs Enforcement Policy. The licensee documented
this failure in CAP050398.
4.1.3.2 Equipment Performance
a. Inspection Scope
The inspectors evaluated the adequacy of the maintenance, operation, and testing of
the CCW system. The inspectors reviewed CCW surveillance testing and calibration
records, related CAPs, heat exchanger testing and inspection results, CCW system
health reports, and CCW pump vibration and differential pressure trending data to
determine if CCW system equipment was being adequately maintained, operated, and
tested. The inspectors also reviewed CCW pump and valves surveillance testing and
CCW surge tank lever switch calibration records to determine if the acceptance criteria
were consistent with design basis requirements.
Heat exchanger performance testing results, the GL 89-13 (Service Water System
Problems Affecting Safety-Related Equipment, July 18, 1989) program document,
related CAPs, and heat exchanger visual inspection results were also reviewed to
assess whether heat exchangers were being maintained and operated per system
design requirements. Radiography results for the EDG heat exchanger alternate supply
were also reviewed to determine if CCW lines were being maintained and available.
Equipment performance-related CAPs, such as CAPs related to CCW pump vibration,
valve stroke time testing, and surge tank level transmitter operation, were reviewed to
determine if system operability was degraded and corrective actions were effective in
maintaining system design.
b. Observations and Findings
Testing of Manual CCW System Valves
Introduction: The inspectors identified a finding of very low safety significance (Green)
involving a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XI, Test
60 Enclosure
Control. Specifically, the licensee failed to include in the inservice testing program
manual CCW valves that were required to perform a safety function.
Description: The inspectors reviewed the resolution of CAP028946 written on
August 5, 2002, during the NRC Safety System Design and Performance Capability
Inspection (IR 50-266/02-09(DRS); 50-301/02-09(DRS)), in response to questions
regarding the testing of manual CCW valves that were required in EOPs to be operated.
The CAP indicated that the valves should not be included in the inservice testing (IST)
program based on Section 4.4.6 of NUREG-1482, Guidelines for Inservice Testing at
Nuclear Power Plants, April 1985. Instead, the CAP recommended establishing a non-
IST program to periodically cycle the valves. The valves in question were included in
Attachment A of both EOP-1.3, Transfer to Containment Sump Recirculation - Low
Head Injection, Revision 30, and EOP-1.4, Transfer to Containment Sump
Recirculation - High Head Injection, Revision 10. After an accident, these valves were
to be closed to isolate nonessential CCW loads and ensure adequate cooling water flow
to the RHR heat exchangers.
The inspectors questioned this interpretation of NUREG-1482. In response, the
licensee reevaluated the function of the valves and concluded that they were required
to support the PBNP safety analysis. The licensee wrote CAP050340 on
September 22, 2003, to address the omission of these valves from the IST program. In
addition, the licensee prepared an OD on September 24, to address the capability of
these valves to perform their safety function. This operability review verified that all but
1 of the 36 manual valves had been exercised within the previous 3 years or were
normally closed. This provided reasonable assurance of operability. The inspectors
noted that the PBNP self-assessment earlier in 2003 had not identified this concern.
Analysis: The failure to account for these valves in the IST program was more than
minor because it affected the mitigating systems cornerstone. However, this finding
screened as Green in the SDP Phase 1, Mitigation Systems, question 1, because the
valves were considered capable of performing their safety function per GL 91-18.
Enforcement: 10 CFR Part 50, Appendix B, Criterion XI, Test Control, states, in part,
that a test program shall be established to assure that all testing required to
demonstrate that safety-related structures, systems, and components will perform
satisfactorily in service is identified and performed in accordance with written test
procedures. Contrary to this, the licensee failed to perform all testing required to
demonstrate that components would perform satisfactorily in service. Specifically,
several manual CCW valves that were required to perform a safety function were not
included in the IST program. As a result, the potential existed that these valves could
have failed to operate when required. After the identification of this issue by the
inspectors, the licensee implemented appropriate corrective actions. The PBNP staff
wrote CAP050340, entering this issue into the corrective action program.
Because of the very low safety significance of the finding and because the licensee had
entered this issue into their corrective action program, it was considered a Non-Cited
Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy
(NCV 50-266/03-07-11; 50-301/03-07-11).
61 Enclosure
4.1.4 Corrective Actions
a. Inspection Scope
The inspectors reviewed various corrective action program and engineering-specific
documents and interviewed plant personnel to assess the effectiveness of corrective
actions for deficiencies involving design of the 125-VDC and CCW systems specifically,
and other systems in general.
b. Observations and Findings
The inspectors identified numerous, minor examples where corrective actions were not
timely or thoroughly implemented or the issues for which corrective actions were taken
were not thoroughly evaluated. Although these examples were not found to be
significant or to result in operability concerns, they supported an observation by the
inspectors that the engineering group was challenged by limited resources and
competing priorities. Several of the examples are discussed below.
- Several CAPs were written as a result of the licensees self-assessment of the
125-VDC system to address concerns with the lack of updated calculations.
However, these CAPs did not address the larger issue of design basis and
configuration control. Major modifications to the 125-VDC system were
performed by the licensee even though no accurate, updated design basis
calculations to support even the present configuration existed. This issue is
discussed further in Section 4.1.1.1.b.2.
- A self-assessment of the emergency diesel generators identified that Calculation
N-93-002 for degraded voltage analysis did not include acceptance criteria for
the minimum alternating current (AC) input voltage to safety-related battery
chargers. Subsequently, one battery charger was identified as having voltage
below its specified rating, and factory test results were used to justify acceptable
performance. However, a CAP was not written to identify and correct the
inadequate acceptance criteria in the calculation. In response to the concern,
CAP050211 was written but it cited the original evaluation of factory tests as a
justification for operability. The inspectors noted that both the original
assessment evaluation and the CAP assumed that the minimum voltage
requirement for the battery chargers was 414 volts (V) (90 percent of 460 V). In
response to the inspectors inquiry, it was discovered that the actual rating of the
chargers was 480 V so that the correct acceptance criteria should have been
432 V (90 percent of 480 V). This did not affect the previous evaluation of the
charger, but upon further review of Calculation N-93-002, the licensee
discovered that two other battery chargers (from a different manufacturer) also
failed to meet the revised acceptance criteria by a small margin. The licensee
then issued CAP050430 and provided a reasonable justification for the
operability of these two battery chargers.
The failure to include acceptance criteria in Calculation N-93-002 for the
safety-related battery chargers was a violation 10 CFR Part 50, Appendix B,
Criterion III, Design Control. The failure to write a CAP upon the discovery of
62 Enclosure
this omission and the use of inappropriate criteria to evaluate it were violations of
10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. Although these
issues should be corrected, they are minor and, thus, not subject to enforcement
action in accordance with Section IV of the NRCs Enforcement Policy. These
issues were entered into the licensees corrective action program as CAP050211
and CAP050430.
- The licensees vendor failed to write a CAP to capture multiple (minor) drawing
errors identified during the preparation of 125-VDC calculations. The vendor had
accumulated a list of several dozen discrepancies over the period of several
months but had failed to provide this list to the licensee or initiate other corrective
action until questioned by the inspectors. Although this corrective actions issue
should be corrected, it constitutes a violation of minor significance, not subject to
enforcement action in accordance with Section IV of the NRCs Enforcement
Policy. The issue did indicate a weakness in the licensees vendor control and
corrective action programs. The licensee subsequently wrote CAP050258 to
address the specific drawing discrepancies.
- The PAB battery room and inverter rooms ventilation system was installed via
modification M-784 in 1991. However, prior to the installation, changes to the
design were approved involving the omission of thermostatically controlled
solenoid valves. CAP000729 required revision to battery ventilation system
drawings to reflect the as-built condition but was canceled due to an
inappropriately classified corrective action, prior to the work being done.
Although this corrective actions issue should be corrected, it constitutes a
violation of minor significance, not subject to enforcement action in accordance
with Section IV of the NRCs Enforcement Policy. This issue did indicate a
weakness in the licensees corrective action program. It was documented in
CAP050096, which provided a new corrective action to revise the drawings.
Also regarding the inverters, FSAR Section A.1-7 stated that during a station
blackout event, the heatup of the instrument inverter rooms would reach a
maximum temperature of 115 degrees Fahrenheit in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. This description did
not match the most recent design basis heatup calculation associated with the
inverter room which established a maximum temperature of 120 degrees in
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. After questioning by the inspectors, the licensee initiated a CAP and
determined that the FSAR was incorrect and needed revision.
- Inadequate Justification for Failure to Evaluate Replacement Motor Electrical
Characteristics. The licensee failed to perform an adequate technical evaluation
of a replacement motor after discovering that the original modification also failed
to perform an adequate evaluation. Modification 97-107 installed an Appendix R
spare CCW pump motor as a permanent replacement for the existing CCW
pump motor. CAP031241 identified that the modification did not reference
calculations that needed to be updated or discuss the differences in electrical
parameters that were evaluated in SPEED 97-084. The SPEED evaluated the
use of the motor as an Appendix R spare only. The justification in the CAP
regarding operability of the motor discussed the non-conservative effects of the
motors short circuit characteristics, and the improved full load current, but did
63 Enclosure
not evaluate the larger starting current for the replacement motor. This
parameter had an adverse impact on the starting voltage calculated in
Calculation N-93-002 so it should have been evaluated in the CAP. In response
to the inspectors question, the licensee revised CAP031241 to evaluate the
motor starting current, which the inspectors subsequently determined to be
acceptable. Because the replacement motor was acceptable in its application,
this failure to take the appropriate corrective action (conduct an adequate
evaluation) constitutes a violation of minor significance, not subject to
enforcement action in accordance with Section IV of the NRCs Enforcement
Policy. The issue did indicate weaknesses in the licensees corrective action and
design control programs.
- Inadequate Procedures to Prevent Re-Racking of Breakers Following Failure to
Operate on Demand. CAP031069 was written following failure of a safety-
related breaker (a condition adverse to quality) but it did not identify a deficiency
relating to re-racking prior to troubleshooting the cause of failure. Interviews with
operators indicated that it was station policy to have maintenance perform
troubleshooting before trying to operate a breaker that had failed to operate on
demand, but that this policy had not been formalized in plant procedures.
Re-racking a failed breaker could destroy information needed to ascertain the
cause of the failure. When a breaker was racked into a switchgear cubicle,
levers in the cubicle sensed the breaker position and repositioned contacts in
control circuits for the breaker. If these switches failed to reposition properly due
to misalignment of the breaker in the cubicle, re-racking may simply achieve the
proper alignment and solve the problem. However, re-racking may also mask an
intermittent failure in another part of the circuit, or prevent detection of excessive
wear, or damage to the position switch mechanism. The breaker position
switches could then fail in-service due to slight movement caused by operating
the breaker, or experience a repeat failure of an unrelated circuit element.
The licensee was not able to identify similar instances of re-racking failed
breakers without troubleshooting so this failure to adequately identify and correct
the problem with the breaker constitutes a violation of minor significance, not
subject to enforcement action in accordance with Section IV of the NRCs
Enforcement Policy. This issue represented weaknesses in station procedures
for not prohibiting re-racking of failed breakers and in the corrective action
program for not identifying an inadequate station practice. The licensee wrote
CAP050390 to evaluate the issue.
- CAP049868 was written on September 4, 2003, for a weakness in an emergency
diesel generator (EDG) transient loading calculation. Specifically, this CAP
identified that a potentially incorrect value of 4160 V was used in the calculation
for the initial starting voltage. Instead, the actual value used should have been
the more conservative, and therefore bounding, value of 3744 V. The licensee
originally asserted that the EDG was operable because of the successful
completion of the 18-month functional test and that this issue was merely an
administrative issue pertaining to the calculation.
64 Enclosure
The licensee identified that a review by a senior reactor operator had not even
been obtained for this issue when it was initially assessed by the licensee. The
licensee wrote CAP05348 to address this issue.
The inspectors questioned the validity of the operability determination and were
concerned that an evaluation of adverse effects due to the lower voltage was
needed to ensure operability. The major concern was the effects on voltage due
to the block loading of engineered safety feature loads on the EDG with this new
lower value for voltage (3744 V). The temporary voltage drop due to block
loading would cause control circuit contactors to momentarily drop out until
adequate voltage was recovered. The licensee stated that this issue was
discussed when the CAP was initiated, but was not documented in the CAP.
The concern with the calculation was being addressed through CE012276,
DG Loading Calculation Weakness.
Although the equipment was determined to be operable, this issue is an example
of an equipment deficiency that was inadequately resolved initially through the
licensees corrective action program. The concern identified in the initial CAP
was not properly resolved, and a formal OD was not performed. The issue
constitutes a violation of minor significance, not subject to enforcement action in
accordance with Section IV of the NRCs Enforcement Policy.
- CAP028994, dated August 8, 2002, was written during the NRC Safety
System Design and Performance Capability Inspection (IR 50-266/02-09(DRS);
50-301/02-09(DRS)) in response to inspectors questions regarding the duration
of containment spray operation after a postulated accident. An operability
determination was completed on August 9, 2002 and EWR026103 was initiated
on August 16, 2002, to resolve the issue. However, at the time of this inspection
(September 2003), the due date for this activity had been extended twice and the
most recent entry in the CAP indicated that the activity would be reassigned
when supplemental staff was hired. After completion of the current inspection,
the licensee indicated that a meeting of engineering personnel was held in
December 2003 to discuss the issue and CA054169 was subsequently written to
update the calculation pertaining to the duration of containment spray operation.
The due date for the corrective action was June 23, 2004, and appeared
reasonable to the inspectors.
- CAP028992, dated August 8, 2002, was written, also during the NRC Safety
System Design and Performance Capability Inspection, in response to
inspectors questions regarding an inappropriate setpoint included in EOP 1.3,
Large Break LOCA, Revision 27. During the 2002 inspection, Revision 28 was
issued to remove the step containing the setpoint. However, EOP 1.4, Small
Break LOCA, was issued with this setpoint still included. An operability
determination, based on an informal analysis, determined that this setpoint did
not result in an operability concern for a small-break LOCA. CA026038 was
initiated on August 12, 2002, to formally analyze the issue and remove the
setpoint from EOP 1.4. At the time of this inspection (September 2003), the due
date for this activity had been extended several times and EOP 1.4 (Revision 10)
still contained the inappropriate setpoint. After completion of the current
65 Enclosure
inspection, the licensee indicated that EOP 1.4 had been revised to address the
issue (the current revision of EOP 1.4 was 13).
- CE010524 was initiated on August 12, 2002, to perform an extent of condition
review for the EOP 1.3 and EOP 1.4 issues. The scope of this activity indicated
that an extensive review of both the EOP alignments and EOP setpoints were
required. This activity was closed to CA026250, which was initiated on
September 6, 2002. CA026250 stated that the scope was significantly smaller
than that originally proposed in the parent CAP.
This activity was extended twice, then completed by the nuclear oversight
organization (quality assurance) on June 24, 2003. However, the scope of the
review did not appear to include an extensive review of either the EOP
alignments or the EOP setpoints. On August 12, 2002, CA026045 was initiated
by design engineering to perform a similar EOP review. This activity was
completed on September 9, 2003, after an extensive review of EOP 1.3 and
EOP 1.4 alignments by a contractor. CA033093 was initiated to resolve several
minor concerns identified by this review. However, none of these activities
appeared to address EOP setpoints, as identified in the original scope. After
completion of the inspection, the licensee indicated that a full review of the EOPs
was being conducted per step 2.A of OP-14-005, Validate and Integrate
Calculations and Setpoints.
- The inspectors reviewed the I&C Calculation Update Program Project Plan,
Revision 0, dated June 6, 2003. This plan was associated with Excellence Plan
action plan OP-14-005, Validate and Integrate Calculations and Setpoints.
Section 1 of the I&C plan described problems associated with past programs
implemented to establish design basis I&C calculations. This section stated, in
part, that some of these initiatives were not fully implemented as financial and
manpower resources were directed to other projects. Updates to design basis
calculations were performed on a just-in-time, as-needed basis and other critical
calculations have lain dormant for several years. Many calculations were never
reviewed and approved, and others were maintained outside the design control
process. The problems and issues discussed in the plan was consistent with the
inspectors observations.
4.1.5 Procedure Quality
a. Inspection Scope
The inspectors evaluated the role of procedures in the performance deficiencies in
corrective actions and engineering. Specifically, selected operating, maintenance, and
testing procedures were reviewed to ensure the incorporation of appropriate design
basis information.
The inspectors reviewed CAPs and surveillance and calibration procedures to ensure
incorporation of appropriate design information. Specifically, the inspectors reviewed
CCW surge tank lever channel calibration procedures, CCW pump and valves
surveillance testing, and CCW heat exchanger performance testing data collection
66 Enclosure
procedures. These procedures were reviewed to determine the technical adequacy of
the acceptance criteria and that the CCW system was operated in accordance with
system design.
Corrective action program documents related to inadequate procedures were reviewed
to assess if corrective actions were effective and to ensure that the procedures were
corrected. Specifically, the inspectors reviewed CAPs related to CCW pump post-
maintenance testing procedures and procedure feedback backlog issues.
The inspectors also reviewed the resolution of CAP028998, written on August 8, 2002,
in response to deficiencies identified in EOPs by the NRC during the NRC Safety
System Design and Performance Capability Inspection (IR 50-266/02-09(DRS);
50-301/02-09(DRS)).
b. Observations and Findings
Introduction: The inspectors identified a finding of very low safety significance involving
a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings. Specifically, the licensee failed to include appropriate
quantitative setpoint values in plant EOPs. Two examples of non-conservative setpoint
values were identified during the inspection.
Description: The inspectors reviewed selected EOPs and EOP setpoints and noted
that the EOP setpoint basis document for the minimum low head safety injection B train
flow (EOPSTPT L.3, Revision 1, dated March 25, 1992) appeared to contain an informal
instrument uncertainty calculation. The inspectors questioned the accuracy of the EOP
setpoint value of 275 gallons per minute (gpm) developed by this document.
In response to this question, the licensee investigated the L.3 EOP setpoint and found it
to be non-conservative. The licensee stated that the L.3 setpoint value should have
been 400 gpm. The 275-gpm value did not account for instrument uncertainties. In
addition, the licensee investigated the EOP setpoint for the minimum low head safety
injection A train flow (EOPSTPT L.13, Revision 0, dated March 25, 1992) and
determined that it was also non-conservative. The 450-gpm L.13 setpoint value should
have been 650 gpm to appropriately account for instrument uncertainties. The licensee
identified 34 EOP steps that included these setpoint values, and wrote CAP050388 on
September 24, 2003, to address this issue. The licensee determined that this was not
an operability concern because these setpoint values were not the sole indication
used to verify adequate safety injection flow. The CAP also stated that the potential
for the discovery of this condition had been identified in Excellence Plan action plan
OP-14-005, Validate and Integrate Calculations and Setpoints.
Based on these examples, the inspectors questioned the timeliness of the extent of
condition review associated with action plan OP-14-005, which was scheduled for
completion by 2006. In response to this concern, the licensee wrote CAP050429 on
September 25, 2003, to perform an extent of condition evaluation on all EOP setpoints
and consider accelerating the appropriate steps of action plan OP-14-005.
67 Enclosure
The inspectors noted that the vendor calculation that addressed the instrument
uncertainties associated with EOP setpoints L.3 (WEP-SPT-34a, Revision 0) had been
approved by the licensee on April 30, 2000, but had not been incorporated into the EOP
setpoint basis document or the EOPs. Discussions with licensee personnel indicated
that the update of the EOP setpoint bases had not been completed due to resource
limitations.
The inspectors also identified incorrect values in two other EOP basis documents
(EOPSTPT V.14, Revision 1, dated November 29, 1994, and EOPSTPT V.35,
Revision 0, dated November 29, 1994). In these cases, the actual EOP setpoint values
agreed with the engineering analyses, but the EOP setpoint basis documents were
incorrect. The licensee initiated CAP050192 on September 15, 2003, to address this
issue.
Analysis: The failure to account for instrument inaccuracies for EOP setpoints was
considered more than minor because it affected the mitigating systems cornerstone.
However, this finding screened as Green in the SDP Phase 1, Mitigation Systems,
question 1. Although this issue could have resulted in challenges to the operators, the
inspectors considered the redundancy of flow indication adequate for system availability
per GL 91-18.
Enforcement: Criterion V, Instructions, Procedures, and Drawings, of 10 CFR Part 50,
Appendix B, states, in part, that instructions, procedures, or drawings shall include
appropriate quantitative or qualitative acceptance criteria for determining that important
activities have been satisfactorily accomplished. Contrary to this, the licensee failed to
include in procedures appropriate quantitative acceptance criteria for determining that
important activities were satisfactorily accomplished. Specifically, several plant EOPs
included non-conservative setpoint values. As a result, the operators could have
isolated one train of low head safety injection flow while the other train was not providing
adequate post-LOCA flow. After the identification of this issue by the inspectors, the
licensee entered this finding into its corrective action program as CAP050388 and
implemented appropriate corrective actions.
Because of the very low safety significance (Green) of the finding and because the
licensee has entered this issue into its corrective action program, the failure of the
licensee to include the appropriate setpoints in EOPs is considered as a Non-Cited
Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy
(NCV 50-266/03-07-12; 50-301/03-07-12).
4.1.6 Human Performance
a. Inspection Scope
The inspectors evaluated the role of human performance attributes, such as group
organization, training and qualifications, communications, and the human-system
interfaces in the corrective action and engineering programs. This was accomplished
through document review, interviews with plant staff and management, and attendance
at various plant meetings, including the daily engineering department meeting. The
inspectors evaluated a sample of corrective actions related to deficiencies involving
68 Enclosure
human performance and identified one CAP regarding the leak-before-break analysis of
record that warranted further review.
b. Observations and Findings
Of the CAPs that were reviewed for the 125-VDC system, none specifically identified
human performance as a deficiency; therefore, no corrective actions for deficiencies
involving human performance were identified. The inspectors noted that there appeared
to be a propensity at PBNP to regard technical issues that result in CAPs as significant
only if equipment was inoperable (an observation also noted during the corrective action
phase of the inspection--see Significance Level, in Section 2.1.b.3 of this report). As a
result, some technical issues without immediate operability ramifications but with
possibly important ramifications under slightly different circumstances appeared to be
treated with less significance in the corrective action program. This would appear to be
consistent with the observation that engineering issues do not seem to get as high a
priority as they should merit.
The inspectors concluded that the daily morning engineering department meeting
appeared to be effective. Again, it was apparent that the engineering department was
focused on addressing emergent plant issues. However, this focus on emergent issues
has resulted in long-term design engineering work, such as re-establishing an accurate
and up-to-date design and licensing basis being treated as low priority work. By being
primarily operations focused, the engineering department appeared to be in the habit of
putting out fires rather than preventing the fires from occurring. The inspectors
recognized that safe operation of the plant was the appropriate priority, but that
maintaining the design bases of the plant also required attention to ensure that the plant
was operated within design limitations.
Individual engineer work hours per week were limited to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, unless there was
signed approval from the Director of Engineering to exceed this limit; based on
interviews with engineers, the average work week was approximately 50 to 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />.
However, as noted by the inspectors and in assessments of engineering done for the
licensee in early 1998 and 2003, the engineering organization was often in a reactive
mode because of a heavy work load.
b.1 Leak-Before-Break Analysis of Record
On June 16, 2003, the licensee wrote CAP033580 to address concerns related to the
PBNP leak-before-break (LBB) analyses. The original plant design basis required
consideration of the dynamic affects resulting from non-mechanistic breaks in class 1
piping systems. In addition, new industry concerns regarding asymmetrical blowdown
loads were identified subsequent to the original PBNP design (NRC Unresolved Safety
Issue A-2, Asymmetric Blowdown Loads on Reactor Primary Coolant Systems). This
Unresolved Safety Issue was addressed by Westinghouse on a generic basis. The
NRC reviewed and approved the generic Westinghouse LBB analysis (GL 84-04,
Safety Evaluation of Westinghouse Topical Reports Dealing With Elimination of
Postulated Pipe Breaks in PWR Primary Main Loops, February 1, 1984) as a basis to
remove (or not install) protection against asymmetrical dynamic loads. In 1986, the
NRC stated that PBNP was bounded by the generic Westinghouse LBB analysis;
69 Enclosure
however, a plant-specific LBB analysis (WCAP-14439, Revision 0) was subsequently
performed for PBNP Units 1 and 2 by Westinghouse. This analysis included
parameters associated with the Unit 2 steam generator replacement, partial power
uprate conditions, and a 40-year operating period.
The plant specific analysis was not submitted to the NRC for review and approval as
required by 10 CFR Part 50, Appendix A, Criterion 4, Environmental and Dynamic
Effects Design Basis. This plant specific analysis was credited in SER 96-084-02,
PBNP Unit 2 Replacement Steam Generator Design, and SE 2001-0007, Component
Cooling System Closed Loop Inside Containment.
CAP033580 evaluated the condition and, on June 17, 2003, incorrectly determined that
NRC review and approval was not required for the plant-specific LBB analysis. On
August 1, 2003, the licensee reevaluated the condition and determined that NRC review
was required. As a result, OD OPR000072 was performed, and concluded that the
reactor coolant systems of both Units were operable, but non-conforming. CAP034513
was initiated on August 1 to address the failure to recognize the NRC submittal
requirement during the June 17, 2003, screening. CAP034513 concluded that this was
a knowledge-based error, apparently due to reliance on a dated piece of
correspondence rather than on the current regulatory requirements.
Based on discussions with PBNP personnel, the inspectors determined that the plant-
specific LBB analysis (WCAP-14439, Revision 0) had not been submitted to the NRC at
the time of the inspection. Instead, the licensee intended to submit Revision 1. The
revised analysis incorporated parameters associated with the proposed full power
uprate and a 60-year operating period. The licensee stated that it was working with
Westinghouse to incorporate corrections into WCAP-14439, Revision 1, prior to the
submittal. These activities were being tracked by OPR000072.
The licensee-identified failure to submit the plant-specific LBB analysis to the NRC for
review and approval as required by 10 CFR Part 50, Appendix A, Criterion 4, constitutes
a violation of minor significance, not subject to enforcement action in accordance with
Section IV of NRCs Enforcement Policy. The licensee documented the failure to submit
the analysis in CAP034513.
4.1.7 Miscellaneous Issue - Appendix R Concern for Speed Controllers for the Charging
Pumps
a. Inspection Scope
While reviewing corrective actions for the AFW/IA Red finding, the inspectors identified
a finding related to Appendix R and the speed controllers for the three per Unit positive
displacement charging pumps.
b. Observations and Findings
Introduction: The inspectors identified a Green, Non-Cited Violation of 10 CFR Part 50,
Appendix R, III.L.1.c, for not ensuring adequate control air to the speed controllers for
70 Enclosure
the charging pumps during a postulated Appendix R fire event requiring an alternative
shutdown method.
Description: For certain postulated fire scenarios that required the use of an alternative
shutdown method, instrument air to the charging pump speed controllers would be lost
and the controllers would then fail to slow speed. For certain alternative shutdown
scenarios, where only one charging pump was available, the pump was required to be
operating in fast speed to ensure adequate makeup to the RCS.
A 12-pack of nitrogen bottles that were hard-piped to the speed controller instrument air
header served as a backup. However, the capacity of the backup was 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. As
compensatory measures, the licensee staged a dedicated air compressor, electrical
cables, hoses, and fittings so that if the postulated fire were to occur, operators could
assemble the equipment and supply air to the controllers. These actions were
necessary for the plant to maintain hot standby conditions.
The inspectors concluded that this compensatory measure was a repair activity required
to maintain hot standby conditions, that is hot standby repairs, and as such were not
allowed by 10 CFR Part 50, Appendix R.
Analysis: This failure to ensure that control air to the speed controllers for the charging
pumps would be maintained during a postulated Appendix R fire event is a violation of
10 CFR Part 50, Appendix R, Section III.L.1.c. This finding is more than minor because
if left uncorrected, the finding would become a more significant safety concern. Without
control air available for the charging pump speed controllers, operators would not have
been able to maintain adequate makeup to the RCS. However, the inspectors
determined that even though the operators would have been challenged by this type of
hot shutdown repair, the operators most likely could have performed the necessary
actions to assemble the staged equipment (air compressor, electrical cables, hoses, and
fittings) so that the temporary air compressor could supply the required control air to the
charging pump speed controllers.
This violation had no significant impact on the cornerstone because it did not involve the
impairment or degradation of a fire protection feature. Therefore, this finding was
considered to be a Green finding.
Enforcement: 10 CFR Part 50, Appendix R, Section III.L.1.c states, in part, that
alternative shutdown capability shall be able to achieve and maintain hot standby
conditions for a pressurized water reactor (such as Point Beach).
Contrary to this, the licensee could not maintain hot standby conditions, because for an
alternative shutdown scenario, control air to the charging pump speed controllers could
have been lost. This could have resulted in insufficient makeup to the RCS. The results
of this violation were determined to be of very low safety significance. Therefore,
because this violation of 10 CFR Part 50, Appendix R, Section III.L.1.c, was captured in
the licensees corrective action program (CAP050456), it was considered a Non-Cited
Violation (NCV 50-266/03-07-13; 50-301/03-07-13) consistent with Section VI.A.1 of the
71 Enclosure
4.2 Operations
4.2.1 Control Room and In-Plant Observations
a. Inspection Scope
The inspectors performed extended observations of licensed operator crews on both
operating Units over multiple shifts to assess whether the operators were proactive in
assessing plant conditions that may have indicated a safety concern and effectively
communicating these issues to engineering. The inspectors interviewed individual
operators while onshift, observed responses to expected and unexpected annunciators,
observed log taking activities, observed verbal communication methods, observed crews
perform reactivity changes on both Units, and observed periodic testing of the gas
turbine (the station blackout power source). The inspectors also accompanied auxiliary
(non-licensed) operators on daily plant tours. The inspectors evaluated operator
performance against requirements contained in station Procedures OM 1.1, Conduct of
Plant Operations, PBNP Specific, Revision 13, and NP 2.1.1, Conduct of Operations,
Revision 1. Additionally, the inspectors discussed expectations for the conduct of
operations with operations department management.
b. Observations and Findings
No findings of significance were identified. In general, the performance of control room
operating crews was in accordance with station procedures and department
management expectations. Communications between operators and engineers on day-
to-day issues was adequate. During interviews with operators, it was clear that the
operators recognized some differences in the level of formality exhibited from crew to
crew. These differences did not appear to be significant and the Shift Managers
interviewed by the inspectors acknowledged the need to establish uniformity between
the crews in regards to formality and control room conduct (the Shift Manager was the
senior reactor operator who supervised the onshift crews of licensed and non-licensed
operators).
4.2.2 Time-Critical Operator Actions
a. Inspection Scope
The inspectors reviewed actions taken by the licensee to validate time-critical operator
actions (such as, operator response to a steam generator tube rupture, post-accident
alignment of the RHR system, containment sump recirculation initiation time, and post-
accident alignment of the containment fan coolers) as documented in Nuclear Plant
Memorandum (NPM) 2003-0646, Time-Critical Operator Actions. The inspectors
reviewed EOPs, AOPs, the FSAR, and DBDs. The inspectors performed job
performance measure (JPM)-style timed walk-downs of time-critical operator actions
related to the restoration of safety-related battery chargers, response to Appendix R
fires, operation of the gas turbine, switchover from refueling water storage tank injection
to containment sump recirculation, and manual switchover from the condensate storage
tank to the SW system for AFW system suction. The inspectors interviewed licensed
72 Enclosure
and non-licensed operators and reviewed CAPs and ODs related to time-critical
operator actions.
b. Observations and Findings
No findings of significance were identified. Overall, the licensees review of time-critical
operator actions was thorough and time-validation bases were well founded in the
DBDs. The original charter from the Site Vice-President to the Time Validation Team
(dated August 18, 2003) included a requirement to identify time-dependent maintenance
actions that analyses were dependent on, such as replacement of a CCW pump for
Appendix R or station blackout scenarios. However, the licensee team did not validate
the availability and suitability of equipment staged to support safe shutdown of the
reactor concurrent with a fire in the area of the CCW pumps. As a result, the licensees
Time Validation Team missed the opportunity to identify several issues later identified by
the inspectors, including the failure to evaluate the locked rotor current and/or starting
current requirements for a replacement CCW pump motor (as discussed in
Section 4.1.3.5).
The inspectors walkdowns indicated that required auxiliary equipment was available;
required components, such as valves and breakers, were easily accessible; and times
established for the completion of time-critical operator actions were realistic and
achievable. However, the inspectors identified multiple examples of auxiliary equipment
that was poorly labeled which could slow the operators response times. The licensee
wrote CAP050523 for the labeling issues. Efforts to improve equipment labeling were
part of Excellence Plan action plan OP-13-002, Equipment Label and Operator Aid
Improvement.
4.2.3 System Walkdowns
a. Inspection Scope
The inspectors performed extensive walkdowns of the in-plant and main control room
portions of the 125-VDC, CCW, and AFW systems. The inspectors reviewed the
individual system electrical and mechanical lineups, the FSAR sections and applicable
TSs for each system, and radiographs of AFW pump suction piping. The inspectors
reviewed CAPs and open ODs regarding problems noted with these systems. The
inspectors noted the material condition of system pumps, valves, and installed freeze
protection (if applicable), as well as piping hangers and other supports. In the vicinity of
these systems, the inspectors checked for unanalyzed flammable materials, general
cleanliness and lighting, the condition of scaffolding, and the temporary storage of
material and equipment.
The inspectors reviewed Procedures NP 2.1.4, Operator Workarounds, Revision 1;
OM 1.1, Conduct of Plant Operations, PBNP Specific, Revision 13; NP 2.1.1, Conduct
of Operations, Revision 1; and OM 5.4.4, Control of Posted Plant Information. The
inspectors assessed the aggregate impact on control room operators imposed by
alarms taken out of service, the posting of temporary instructions, open temporary
modifications, and conditions resulting in operator burdens or workarounds. The
inspectors reviewed the Operator Work Around Summary Report, minutes from periodic
73 Enclosure
Operator Work Around Meetings, the Operator Work Around Aggregate Impact
performance indicator data contained in the Point Beach Nuclear Power Plant
Performance Indicator Monthly Reports, and CAPs related to operator workarounds and
burdens.
The inspectors reviewed EOPs and AOPs for proceduralized workarounds. Finally,
the inspectors interviewed licensed operators, non-licensed operators, and operations
department management. Efforts by the licensee to further reduce operator burdens,
including workarounds, were captured in Excellence Plan action plan OP-13-001,
Reduce Total Operator Burden.
b. Observations and Findings
No findings of significance were identified. In general, the inspectors found that the
125-VDC, CCW, and AFW systems were aligned to support their safety functions and
appeared to be of good material condition. During the walkdown of the AFW system,
the inspectors noted that the licensees Master Data Book had not been updated to
reflect power supply changes made as a result of a recent modification to the differential
pressure indicating switch (DPIS) power supplies that provide for open and closed
indication for the AFW pump recirculation line isolation valves. The licensee wrote
CAP050641 for this issue. Additionally, the inspectors identified an empty CCW system
pump bearing oiler. The licensee refilled the oiler and wrote CAP050094 to determine
why the oiler was not identified earlier.
The licensee appeared to effectively manage the aggregate impact of workarounds on
control room operators. Operations department management were cognizant of current
operator workarounds and sensitive to the need to monitor, prioritize, and workdown the
total number. The licensee maintained several databases containing information
regarding total numbers of equipment issues contributing to operator burdens and
workarounds and appeared to be effectively managing the workdown of those lists. A
review of CAPs indicated that the licensee was identifying workarounds and assigning
appropriate corrective actions to minimize impact. The licensees efforts appeared to be
effective in minimizing the aggregate impact of workarounds on the control room
operators ability to operate the plant in a safe manner and in minimizing the impact on
the operators ability to respond to events.
The inspectors identified an example of a proceduralized operator workaround
involving the cross-tie capability of the Unit 1 and Unit 2 CCW systems described in
AOP-10B, Safe to Cold Shutdown in Local Control, Revision 5. As originally designed,
the CCW systems could be cross-tied by opening two valves: CC-722A (suction) and
CC-722B (discharge). Because of a history of excessive seat leakage on CC-722B,
AOP-10B was modified to cross-tie the discharge side of one CCW system directly at
the CCW heat exchangers; requiring the opening of five valves instead of one. The
licensee wrote CAP050465 to address this inspector-identified proceduralized
workaround.
74 Enclosure
4.2.4 Operator Interactions with Engineering and Maintenance Personnel
a. Inspection Scope
The inspectors reviewed ODs and CAPs and interviewed operations and engineering
personnel to determine if operations, engineering, maintenance, and affected support
groups were involved in evaluation and concurrence process for approving:
(1) performance of non-routine maintenance activities, (2) temporary modifications, and
(3) field change requests.
The inspectors reviewed a sample of planned and emergent on-line maintenance
activities including readjustment of current limiters in the safety-related battery chargers.
The inspectors also reviewed currently open temporary modifications; reviewed station
Procedure NP 7.3.1, Temporary Modifications, Revision 13; and a sample of recently
installed permanent plant modifications made to the AFW system.
b. Observations and Findings
No findings of significance were identified. Operations department communications and
interaction with the engineering department appeared to be effective for dealing with
day-to-day and emergent equipment availability or operability issues. No problems were
noted with the involvement of operations, engineering, maintenance, and affected
support groups in evaluation and concurrence process for approving: (1) performance
of non-routine maintenance activities, (2) temporary modifications, and (3) field change
requests.
4.2.5 Distribution of Temporary Changes to EOPs
a. Inspection Scope
During the special inspection to review the AFW orifice plugging issue
(IR 50-266/02-15(DRP); 50-301/02-15(DRP), a problem was identified regarding the
inadequate distribution of temporary changes of EOPs to the appropriate emergency
response facilities. The operations department, as the owner of the EOPs, was
responsible for determining the distribution of temporary changes. During the current
inspection, the inspectors reviewed recent changes made to EOPs (and AOPs) to
ensure controlled copies of these documents in various emergency response facilities
were updated as required. The inspectors reviewed station Procedure NP 1.2.3,
Temporary Procedure Changes, Revision 12, and NP 1.1.3, Procedure Preparation,
Review, and Approval, Revision 12. The inspectors also reviewed CAPs documenting
previous issues regarding untimely or incomplete incorporation of changes for EOPs
and AOPs.
b. Observations and Findings
No findings of significance were identified. The licensee appeared to be effectively
incorporating temporary and permanent changes to AOPs and EOPs into controlled
copies of these procedures in the various emergency response facilities.
75 Enclosure
4.3 Maintenance
4.3.1 Maintenance Work Control
a. Inspection Scope
The inspectors reviewed the licensees process for planning work, including the
assessment of risk and the inclusion of new emergent work into the schedule. Also
reviewed was the licensees approach for reviewing aggregate risk of long-term
deficiencies, such as tagouts, control room deficiencies, and operator workarounds.
The inspectors also evaluated the licensees methodology for ensuring component
out-of-service time with respect to updating the Probabilistic Risk Assessment (PRA).
b. Observations and Findings
The inspectors reviewed the licensees 12-week cycle schedule and determined that it
adequately grouped plant systems into a rotating set of work weeks based on the
intervals for performing TS surveillances. At least weekly, the installed temporary
modifications, operator workarounds, control board deficiencies, and lit annunciators
were reviewed to ensure these items were scheduled as soon as practical. Risk
assessments, using Safety Monitor, were performed at 5 weeks prior, 2 weeks prior,
and immediately prior to the start of the execution week to ensure maintenance did not
elevate risk unnecessarily, determine risk categories, and develop appropriate
compensatory measures prior to performing work activities. Proposed work week
schedules were compared with the actual completed work week to evaluate the actual
risk level compared to the average and for a lessons-learned opportunity. Overall, the
control of plant risk and configuration were appropriately controlled using risk insights to
minimize the plants aggregate risk.
The inspectors also reviewed a sampling of emergent maintenance activities and
determined that the activities were adequately planned and controlled to avoid causing
initiating events to occur or affect the functional capability of mitigating systems.
The plant highlighted the aggregate impact of items such as operator workarounds,
temporary modifications, and control board deficiencies during the Plan of the Day
meeting. Using the PRA, total system deficiencies in these categories were given a
relative importance. The report effectively highlighted the impact of these somewhat
less-significant items.
The inspectors reviewed the operational performance history for selected components in
the 125-VDC and CCW systems and compared it with the assumed out-of-service times
in the licensees updated PRA. The licensee appropriately used component failure rates
and test and maintenance unavailabilities developed from plant-specific data and
generic nuclear industry data. Similar to industry practices, the licensee updated the
PRA model every 3 years. The licensees upgrade of the PRA model was part of
Excellence Plan action plan OP-13-003, Probabilistic Risk Assessment (PRA) Program
Upgrade. The inspectors determined that the licensees PRA group was very
76 Enclosure
knowledgeable and was actively involved in assessing day-to-day plant operations and
emergent issues with respect to the impact of these activities on the plant risk model.
4.3.2 Equipment Performance for the 125-VDC, CCW, and AFW Systems
a. Inspection Scope
The inspectors reviewed maintenance rule (10 CFR 50.65) scoping information for the
125-VDC, CCW, and AFW systems and compared it to the safety functions of each
system as described in the DBDs. The inspectors reviewed the current maintenance
rule designations ((a)(1) or (a)(2)) for the above systems. The inspectors reviewed a
sample of CAPs documenting equipment problems with the systems and compared the
information to current licensee listings of problems considered to constitute maintenance
rule or maintenance preventable functional failures for each system.
The inspectors reviewed a sample of corrective actions taken for documented
equipment problems to ensure actions taken were commensurate with the problems
identified.
b. Observations and Findings
No findings of significance were identified.
4.4 Extension of the Engineering, Operations, and Maintenance Inspection
a. Inspection Scope
On September 24, 2003, while reviewing information to respond to a question from
the inspectors, the licensee identified concerns with the closure in early 2003 of an
operability determination (OPR 000040, AFW Pump Silting Due to SW Debris,
Revision 1). This OD had been written in January 2003 during the AFW orifice plugging
special inspection (IR 050050-266/02-15(DRP); 50-301/02-15(DRP)) after the licensee
identified that a turbine-driven AFW (TDAFW) pump failed in 1974 after being operated
with service water. As documented in CAP050404, Concerns With Closure of
OPR 00040 Rev 1 (AFW Pump Silting Due to SW Debris), the licensee identified four
issues: 1) The operability determination was closed with the non-conformance
described in the operability determination still in existence since the compensatory
measures were not evaluated for use as permanent Appendix R compliance strategies;
2) In an alternate shutdown scenario, the compensatory measures needed to ensure
availability of the TDAFW pumps would not have been available to the operators;
3) Revisions 0 and 1 OPR 000040 identified two corrective actions involving increased
reliability and potential improvements; however, no actions were found tracking
resolution of these issues; and 4) The feasibility of the compensatory measures
described in Revision 1 of OPR 00040 which were to be taken to ensure condensate-
grade water was available following exhaustion of the CST water supply was not fully
documented. Since these four concerns were identified by the licensee in response to
the inspectors questions, and the resultant questions regarding the ability of the AFW
system to perform its safety function, the IP 95003 inspection was extended a week
from September 29,2003, to October 3, 2003.
77 Enclosure
During the additional week of inspection, the inspectors focused on the following areas
related to the AFW system:
- Adequacy of operability determination
- Verify completion of AFW corrective actions: procedures, physical plant
changes
- Adequacy of AFW corrective actions
- Assess timeliness of planned AFW corrective actions, plant
modifications, RCE corrective actions, and excellence plan items.
- Assess overall operability of AFW system.
The inspectors reviewed selected procedures, corrective action program documents,
operability determinations, and drawings; interviewed engineering, operations, and
maintenance personnel; and conducted a detailed walkdown of the AFW system.
These actions were in addition to those actions taken by the inspectors during the
review of AFW issues during the corrective action phase of the IP 95003 inspection and
in the as-scheduled engineering, operations, and maintenance phase.
b. Observations and Findings
b.1 Adequacy of Operability Determination
The inspectors reviewed open operability evaluations related to the AFW system,
reviewed the disposition of related CAPs, and reviewed the recently approved 50.59
evaluation on operating the AFW system with new orifices. In addition, the inspectors
verified that compensatory measures identified in degraded but operable evaluations
were adequate and that these actions could be performed. Based on review of licensee
documents and discussions with licensee engineering and operations staff, the
inspectors determined the following:
- The revised operability determination regarding the 1974 TDAFW pump silting
issue (OPR 82, Revision 1) was considered to be much improved in providing
the support documentation and engineering judgement needed to determine
operability without the compensatory measures with respect to Appendix R
concerns. Inspectors reviewed SW pipe radiographs and agreed that the
condition of the SW system in 2003 was much different and improved with
respect to the amount of sand/silt contained in the system. Implementation of
the GL 89-13 program, which included monthly flushing, accounted for much of
the credit in minimizing the amount of debris in the SW system.
- In addition, other AFW-related operability determinations reviewed provided
adequate engineering analysis to support operability.
78 Enclosure
b.2 Verify Completion of AFW Corrective Actions: Procedures, Physical Plant Changes
The inspectors conducted in-plant inspections and reviewed licensee documentation to
validate that completed corrective actions related to AFW have actually been
accomplished. Based on review of licensee documents and inspections the inspectors
determined the following:
- AFW system procedures and changes to procedures supporting modifications
that were reviewed appeared to be appropriately implemented or were being
tracked to ensure completion.
- Outstanding AFW modifications were reviewed and determined to be adequately
dispositioned and appropriately scheduled. In fact, the modification to repower
one of the SW MOVs to AFW was rescheduled to be completed approximately
6 months earlier than originally scheduled.
- The 50.59 evaluation regarding the full implementation of the new recirculation
line orifices was reviewed and determined to be adequate. Shift briefings were
considered appropriate based on review of the briefing package and attendance
at the briefings.
b.3 Adequacy of AFW Corrective Actions
The inspectors conducted in-plant inspections and reviewed licensee documentation,
including a sample of approximately one-hundred corrective action documents (CAPs),
to validate that planned and completed corrective actions related to the AFW system
provided reasonable assurance that the problems have been adequately addressed.
Based on review of licensee documents and inspections, the inspectors determined the
following:
actions were not complete or inappropriate. However, the licensee did identify
instances of incomplete corrective actions during a review of corrective action
documents performed in response to the issues identified in CAP050404.
CAPs with incomplete corrective actions were identified in many disciplines
(i.e., training, operation procedures, and engineering). These incomplete
corrective actions, which involved primarily administrative issues, did not impact
the operability of the AFW system. The inspectors determined that the quality
review and closure of CAPs was an area needing improvements.
b.4 Timeliness of Planned AFW Corrective Actions, Plant Modifications, RCE Corrective
Actions, and Excellence Plan Items
The inspectors reviewed licensee documentation, including related Excellence Plan
action items, modifications, and CAPs associated with the AFW Red finding root cause
evaluations to validate that these actions were scheduled to be completed in a
reasonable time. Based on review of licensee documents, the inspectors determined
the following:
79 Enclosure
- As discussed in Sections 2.1, 4.1.1.1.b, and 4.1.5 of this report, the inspectors
were concerned with some Excellence Plan completion dates with respect to
corrective actions associated with the AFW significant findings root cause
evaluations and design basis calculation and setpoint reviews. In particular, the
inspectors noted that the AFW system Issue Manager was not cognizant of the
concerns regarding AFW operability documented in CAP050404 until notified by
the inspectors several days after the CAP was issued. The inspectors
determined that the lack of Issue Manager involvement in initially resolving this
issue was due in part to the lack of documented guidance on Issue Manager
responsibilities (Section 2.1.b.2).
b.5 Assess Overall Operability of AFW System
The inspectors conducted in-plant inspections, including a detailed AFW system
walkdown. In addition, the inspectors reviewed licensee documentation, including the
results of recent licensee self-assessment efforts focused on AFW operability. Based
on review of licensee documents and inspections, the inspectors determined the
following:
- Hand-over-hand AFW walkdowns (mechanical and electrical) verified agreement
between plant drawings and the current system configuration. Also, recent
modifications to the AFW system were observed and appeared to be installed in
accordance with modification packages. The inspectors did not identify any
significant issues that challenged the licensees determination that the AFW
system was operable.
c. Conclusions
Based on the results of the additional week of inspection focused on AFW system
operability, the inspectors determined that the AFW was capable of performing its
required safety functions. In addition, the licensee established 11 teams to review the
following areas related to AFW system operability: operability determinations, AFW
procedures and surveillances, corrective action documents, electrical and mechanical
modifications, independent assessment results, work orders, AFW pump silt operability
verification, improved TS impact, Appendix R and compensatory measures, and
training. The inspectors reviewed some of the results of the licensees reviews and
determined that the reviews were comprehensive. The inspectors determined that
extensive licensee effort was needed to verify that the AFW system was operable
because previous efforts in this area were either poorly implemented or documented.
The licensees failure to clearly demonstrate the operability of AFW system until an
extensive review was conducted reflects on several performance areas needing
improvement, including corrective action implementation and organizational
effectiveness. In the area of corrective action implementation, the licensees failure to
complete corrective actions associated with Revision 1 of OPR 00040 (AFW Pump
Silting Due to SW Debris) resulted in the operability of the AFW system being
questioned. In addition, though the licensee created the Issue Manager position as a
corrective action for the AFW RED findings, the poor implementation of this initiative
rendered the Issue Manager as only partially effective in tracking and coordinating the
resolution of AFW issues. In the area of organizational effectiveness, poor
80 Enclosure
communication and coordination between engineering and operations staff resulted in
corrective actions being ineffectively implemented, including Appendix R compensatory
measures not being fully implemented. Though the inspectors concluded that the AFW
system was operable, extensive inspection effort was required to verify that previous
licensee corrective actions adequately addressed historic AFW system performance
problems due to the inconsistent quality of the licensees documentation and
implementation of corrective actions.
4.5 Conclusion of the Engineering, Operations, and Maintenance Phase of the IP 95003
Inspection
The engineering organization was often in a reactive mode because of a heavy work
load, a condition that has persisted since at least early 1998, when an assessment was
performed of the Milwaukee-based design engineering group for the licensee. The high
engineering work load was exacerbated by a loss of electrical system design information
and experienced personnel when the design function was moved from Milwaukee to the
site several years ago (1998-1999) and by turnover in plant management, particularly
engineering upper management, in the past several years. Design engineering issues,
including the existence of longstanding operability determinations, inexperienced staff
engineers, and the reliance on out-of-date, inaccurate, or incomplete calculations, were
identified during the review of the AC and 125-VDC systems.
Problems with individual calculations and control of calculations in general were
previously identified by a third-party assessment early in 1998 and in 2003, and by the
licensees self-assessment in mid-2003. Confirmatory calculations by the inspectors
confirmed that the electrical systems, which were relatively robust, were operable.
Similar problems were not identified during the review of CCW, AFW, and other
systems; however, several examples were identified by the inspectors of incorrect or
narrowly focused evaluations by engineers of issues in the corrective action program.
For AFW in particular, these corrective action problems resulted in the inspection being
extended an additional week for the inspectors to gain assurance that the system was
operable. The inspectors confirmed that based on their review of licensee
documentation, various independent calculations, and system walkdowns, the 125-VDC,
CCW, and AFW systems were operable and capable of performing their safety
functions.
The inspectors found the operations and maintenance programs that were reviewed to
be adequate. The operations/engineering interface warranted additional licensee
attention.
5. Licensee-Identified Violation
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which meets the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited
Violation.
81 Enclosure
Failure To Declare An NOUE In a Timely Manner
10 CFR 50.54(q) requires, in part, that licensees follow and maintain in effect
emergency plans which meet the standards in § 50.47(b) and the requirements in
Appendix E of Part 50. 10 CFR 50.47(b)(4) states, in part, that a standard emergency
classification and action level scheme will be in use. Appendix E, paragraph IV.D.3,
states, in part, that a licensee shall have the capability to notify responsible State and
local governmental authorities within 15 minutes after declaration of an emergency.
EPIP 1.2, Emergency Classification, Step 5.1.5, NOTE states that "classifications are
to be made consistent with the goal of 15 minutes once plant parameters reach an
Emergency Action Level (EAL), are first indicated in the Control Room." Contrary to
this, on March 4, 2002, the licensee took approximately 31 minutes to notify responsible
State and local governmental authorities of a liquified propane gas leak which met the
criteria for declaration of an NOUE given in EAL 6.3.1.1, "A toxic or flammable gas
release in or near the Protected Area." The licensee entered this failure to timely notify
in their corrective action program as CAP034652. The violation is considered to be of
very low safety significance because the state and local authorities were notified of the
event and there was no affect on protective action recommendations to the public.
6. Management Meetings
Exit Meeting Summary
The inspectors presented the preliminary results of the inspection to Messrs.
M. Sellman, P. Cowan, D. Cooper, A. Cayia and other members of licensee
management on November 17, 2003. The licensee acknowledged the findings
presented. No information reviewed during the inspection and likely to be included in
the inspection report was identified as proprietary.
On December 16, a public exit meeting was held at the Holiday Inn in Manitowoc,
Wisconsin, with Messrs. Cowan, Cooper, and Cayia and other members of licensee
management to discuss the results of the inspection. The licensee acknowledged the
findings presented. A summary of the meeting, a list of principal NRC and NMC
attendees, and copies of the overhead slides used at the meeting were issued in a letter
dated December 31, 2003.
On January 13, 2004, a predecisional enforcement conference was held to discuss the
apparent violation regarding the EALs. A summary of that meeting and the results of
the NRCs enforcement deliberation regarding that apparent violation will be issued in
separate correspondence.
ATTACHMENT: SUPPLEMENTAL INFORMATION
82 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
R. Amundson Operations Training Specialist
G. Arent Kewaunee/Point Beach Regulatory Affairs Manager (former)
A. Cayia Site Vice-President
J. Connolly Regulatory Affairs Manager
J. Cowan Senior Vice-President - Operations (NMC)
D. Fadel Engineering Director (former)
F. Flentje Senior Regulatory Compliance Specialist
J. Flessner Engineering Projects Supervisor (Root Cause Team Leader)
D. Hettick Performance Improvement Manager
R. Hopkins Kewaunee-Point Beach Oversight Supervisor
J. Jensen Plant Manager (former)
T. Kendall Engineering Analysis Supervisor
J. Masterlark PRA Engineer
J. McCarthy Site Director
R. Milner Emergency Preparedness Manager
L. Peterson Engineering Projects Manager
K. Peveler Kewaunee-Point Beach Nuclear Oversight Manager
S. Pfaff Corrective Action Program Supervisor
J. Pruitt Nuclear Oversight Assessor
M. Reddemann NMC Vice-President - Engineering
E. Schmidt AFW System Engineer
D. Schoon Training Manager
J. Schweitzer Engineering Director
P. Smith Operations Training Coordinator
J. Strharsky Production Planning Manager
T. Vandenbosch EOP Coordinator
R. Wood Engineering Programs Supervisor
T. Taylor Site Assessment Manager
S. Thomas Radiation Protection Manager
T. Webb Regulatory Affairs Manager
E. Weinkam NMC Director of Regulatory Services
W. Zipp System Engineering Supervisor
1 Attachment
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-266/03-07-01 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-01 Failure To Assign Adequate Emergency Response
Organization Staffing. (Section 3.2.b.2)
50-266/03-07-02 NCV 10 CFR 50.9 Violation For Failure To Report In The
50-301/03-07-02 Third Quarter Of 2001 That The Emergency
Response Organization Performance Indicator
Crossed The Significance Threshold From Green To
White. (Section 3.2.b.3)
50-266/03-07-03 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-03 The Failure To Develop And Implement A Training
Program For The Emergency Planning Staff.
(Section 3.5)
50-266/03-07-04 URI A Range Of Protective Action Recommendations Was
50-301/03-07-04 Not Established For State And Local Governmental
Authorities. (Section 3.6.b.1)
50-266/03-07-05 AV 10 CFR 50.54(q) and 10 CFR 50.47(b) Apparent
50-301/03-07-05 Violation For Failure To Maintain A Standard Scheme
of Emergency Action Levels. (Section 3.6.b.2)
50-266/03-07-06 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-06 Failure To Ensure That The Facility Seismic Monitors
Could Support NOUE Declaration. (Section 3.6.b.3)
50-266/03-07-07 NCV Design Control Violation For The Failure To Assure
50-301/03-07-07 That The Regulatory Requirements And The Design
Basis Were Accurately Maintained For The Battery
Chargers. (Section 4.1.1.1.b.1)
50-266/03-07-08 NCV Design Control Violation For The Failure To Revise
50-301/03-07-08 Voltage Drop Calculations. (Section 4.1.1.1.b.2)
50-266/03-07-09 NCV Corrective Action Violation For Untimely Correction of
50-301/03-07-09 Equipment Not Environmentally Qualified.
(Section 4.1.2.b.2.1)
50-266/03-07-10 NCV 10 CFR 50.49(f) Violation For Equipment Not
50-301/03-07-10 Environmentally Qualified. (Section 4.1.2.b.2.2)
50-266/03-07-11 NCV Test Control Violation For Not Including Several
50-301/03-07-11 Manual CCW Valves In The Inservice Testing
Program. (Section 4.1.3.2)
50-266/03-07-12 NCV Inadequate Procedure Violation For Inaccurate
50-301/03-07-12 Setpoints in EOPs. (Section 4.1.5)
2 Attachment
50-266/03-07-13 NCV Appendix R Violation For Failure To Ensure Air Would
50-301/03-07-13 Be Available to Charging Pumps. (Section 4.1.7)
Closed
50-266/03-07-01 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-01 Failure To Assign Adequate Emergency Response
Organization Staffing. (Section 3.2.b.2)
50-266/03-07-02 NCV 10 CFR 50.9 Violation For Failure To Report In The
50-301/03-07-02 Third Quarter Of 2001 That The Emergency
Response Organization Performance Indicator
Crossed The Significance Threshold From Green To
White. (Section 3.2.b.3)
50-266/03-07-03 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-03 The Failure To Develop And Implement A Training
Program For The Emergency Planning Staff.
(Section 3.5)
50-266/03-07-06 NCV 10 CFR 50.54(q) and 10 CFR 50.47(b) Violation For
50-301/03-07-06 Failure To Ensure That The Facility Seismic Monitors
Could Support NOUE Declaration. (Section 3.6.b.3)
50-266/03-07-07 NCV Design Control Violation For The Failure To Assure
50-301/03-07-07 That The Regulatory Requirements And The Design
Basis Were Accurately Maintained For The Battery
Chargers. (Section 4.1.1.1.b.1)
50-266/03-07-08 NCV Design Control Violation For The Failure To Revise
50-301/03-07-08 Voltage Drop Calculations. (Section 4.1.1.1.b.2)
50-266/03-07-09 NCV Corrective Action Violation For Untimely Correction of
50-301/03-07-09 Equipment Not Environmentally Qualified.
(Section 4.1.2.b.2.1)
50-266/03-07-10 NCV 10 CFR 50.49(f) Violation For Equipment Not
50-301/03-07-10 Environmentally Qualified. (Section 4.1.2.b.2.2)
50-266/03-07-11 NCV Test Control Violation For Not Including Several
50-301/03-07-11 Manual CCW Valves In The Inservice Testing
Program. (Section 4.1.3.2)
50-266/03-07-12 NCV Inadequate Procedure Violation For Inaccurate
50-301/03-07-12 Setpoints in EOPs. (Section 4.1.5)
50-266/03-07-13 NCV Appendix R Violation For Failure To Ensure Air Would
50-301/03-07-13 Be Available to Charging Pumps. (Section 4.1.7)
Discussed
3 Attachment
50-266/03-02-02 URI Emergency Planning Organization 10 CFR 50.54(q);
50-301/03-02-02 Technician Instructions, Procedures, And Drawings;
Emergency Response Facility Equipment
Replacements Without Licensee Knowledge; And
Remote Emergency Notification Telephone System
Monitoring Capability Issues. (Section 3.3)
LIST OF DOCUMENTS REVIEWED
CORRECTIVE ACTION PROGRAM
Corrective Action Program Documents
ACE001251, SOER 02-04 Evaluation: Underground Cables - Water Intrusion
CA030587, Excellence Plan - ACE & CE Skills, June 6, 2003
CA052332, Review Due Date Associated With CA029836 (From RCE 202),
September 15, 2003
CAP002220, Procedure Marked Up, February 15, 2002
CAP002777, Untimely Corrective Actions - Failure to Establish Qualification Files for Equipment
Credited for Operating in a High Energy Line Break (Operability Determination 98-0164),
April 8, 2002
CAP002968, Work Performed on SI-878B While Valve Was Energized, April 22, 2002
CAP026410, AOP-9A Has Little Guidance for System Blockage, September 21, 2002
CAP028270, Inadequate Procedure Temp Change Process, May 20, 2002
CAP029952, Possible Common Mode Failure of Aux Feed Recirculation Lines,
October 29, 2002
CAP030002, PBNP Facility Not Prepared For Cold Weather on 1 November 2002,
November 5, 2002
CAP030040, Power Supply to AFW Pump Recirc Valves not Safety Related, November 7, 2000
CAP030236, SGTR Timing Scenario Results, November 25, 2002
CAP030664, Corrective Actions Not Timely, January 9, 2003
CAP031858, OPR-000038 Failed to Address Two Issues, March 27, 2003
CAP031860, NP 5.3.1 Requirement for CAQ Issue Resolution, March 27, 2003
4 Attachment
CAP031894, Validation of New Manual Operator Actions Credited as Compensatory Measure,
March 28, 2003
CAP033062, Improvements for NOS Processes Identified in Self-Assessments, May 23, 2003
CAP033681, NOS Self-Assessment PBSA-NOS-03-03 Improvement Item Assessment
Process, June 20, 2003
CAP033889, Unit 1 Flux Map Detectors Failing, July 2, 2003
CAP033997, Unit 2 Main Feed Pump Trip Results in a Unit 2 Reactor Trip, July 10, 2003
CAP034489, Management Exception Evaluation Omitted Some CA Items, August 1, 2003
CAP034564, CA Items Outside Expected Completion Dates Require Detailed Review for
Approvals, August 5, 2003
CAP034566, Low Amount of Site Data to Perform trending on HU [Human Performance],
Process and Organization/Management Issues, August 5, 2003
CAP034598, No Documented Justification For Non-Performance of RCEs For Level A CAPs,
August 6, 2003
CAP034626, MR 03-0656 Design Description Doesn't Reference Foxboro CIM, August 3, 2003
CAP050026, Corrective Action Due Date Extension Not Properly Approved, September 9, 2003
CAP050060, CAPs Not Initiated on QRT Reviews Graded as 3, September 10, 2003
CAP050108, Review Due Date Associated With CA029836 (From RCE 202),
September 11, 2003
CAP050114, AFW RCE202 Requires a Revision, September 11, 2003
CAP050120, Management Support of the DRB, September 11, 2003
CAP050143, The Quality Review Team Has Not Been Effectively Implemented,
September 12, 2003
CAP050177, 95003 EOM [Engineering, Operations, and Maintenance] Inspection Technical
Debrief CAP Issues, September 15, 2003
CAP050350, Perform New Review of AFW System to Support Recirc AOV Safety Function
Upgrade, September 23, 2003
CAP050509, Incorrect Closure of CAP 32355, September 29, 2003
CAP050590, Apparent Lack of Guidance for Duties and Responsibilities of an Issue Manager,
October 1, 2003
5 Attachment
CAP AR Screen Team - Screening Process, Revision 2
CAP Meeting Schedules
CAP Trend Code Manual, January 17, 2003
CARB Agenda for Tuesday, August 5, 2003 at 1:00PM
CARB Charter
CARB Training
Condition Evaluation and Apparent Cause Evaluation Techniques
Corrective Action Program User Aid - CA Closure Guide, June 2003
RCE000044, U2 Safety Injection Pump "Gas Bound" During Routine Preventive Maintenance,
April 13, 2002
RCE000051, Untimely Corrective Action - Failure to Establish Qualification Files for Equipment,
June 13, 2002
RCE000179, PB Corrective Action Program Performance Indicator Turned RED, June 13, 2002
RCE000182, U2R25 Maintenance Valve Team Personnel Repack a Non-Electrically Isolated
Motor Operated Valve, August 26, 2002
RCE000191, Possible Common Mode Failure of Aux Feed Recirculation Lines, April 10, 2003,
Revision 1
RCE000192, PBNP Facility Not Prepared For Cold Weather on 1 November 2002,
May 14, 2003
RCE000202, Potential AFW Pump Damage Due to Low Flow that Results in Increase Core
Damage Frequency, April 9, 2003
RCE000205, Unit 1 Flux Map Detectors Failing, September 15, 2003
RCE000206, Unit 2 Main Feed Pump Trip Results In a Unit 2 Reactor Trip, July 11, 2003
RCE 01-069, Increase CDF in AFW PRA Model Due to Procedural Inadequacies Related to
Loss of Instrument Air, February 28, 2002
RCE Casual Assessment Guideline
RCE Certification Card
RCE Team Lead Certification Card
6 Attachment
Drawings
Drawing EAPK00000317, Single Line Diagram Station Connections, June 28, 2003
Drawing EDCK00000142, Single Line Diagram 125V DC Dist. System, December 22, 2001
Drawing EDCK00000215, Single Line Diagram 125 Volt D. C. System, July 14, 2001
Drawing EDCK00000303, Single Line Diagram 125V DC System (Non-1E), June 18, 2003
Drawing EDCK00000402, Single Line Diagram 125V DC Dist, System, January 20, 1996
Drawing EDGK00000112, Logic Diagram Emergency Generator Starting, August 5, 2000
Drawing EDGK12800105, Train B Emergency Generator Starting, August 12, 2000
Procedures
AM 3-15, Work Control Manual
1ICP 04.003-5, Auxiliary Feedwater Flow Instruments Outage Calculations, July 30, 2002
ESG 1.7, Expectations for Use of Human Performance Tools in Engineering, July 17, 2003
ESG 1.8, Engineering Human Performance Improvement Team Charter, June 20, 2003
NP 1.1.3, Procedure Preparation Review and Approval, Revision 17
NP 1.6.5, Plant Operations Review Committee and Qualified Reviewer, August 6, 2003
NP 5.3.1, Action Request Process, April 23, 2003
NP 5.3.2, Industry Operating Experience Review Program, November 12, 2002
NP 5.3.3, Incident Investigation and Post Trip Review, February 12, 2003
NP 7.1.7, Quality Review Team, Revisions 0 and 1
NP 7.2.1, Plant Modifications, March 12, 2003
NP 7.3.1, Temporary Modifications, June 26, 2002
NP 9.3.3, Spare Parts Equivalency Evaluation, April 3, 2002
NP 10.2.4, Work Order Processing, June 4, 2003
ESC-030LP012, Equipment Failure Root Cause Analysis, June 4, 2003
FP-T-SAT-60, SAT Overview Procedure, June 13, 2003
7 Attachment
OEG 001, Root Cause Evaluation, June 28, 2002
OEG 005, Equipment Root Cause Evaluation, June 13, 2003
OR 2003-002-3-031, Management Systems, June 8, 2003
ORI-01-LPARP, Action Request Process, June 11, 2003
Control of PBNP IP 95003 Inspection Guidelines, May 20, 2003
CP 0041, Integrated Planning Process (IPP), July 27, 2001
Other Documents
Condition Assessment of Several Primary Cables for PBNP, May 2003
DBD-01, Auxiliary Feedwater System, March 31, 2000
DBD Validation Procedure, June 2003
DRB Meeting on Tuesday, August 5, 2003 at 11:00PM, 99-036*A, Upgrade U-2 Containment
Airlock Operating Mechanism (C-1)
DRB Meeting on Tuesday, August 5, 2003 at 11:00PM, 99-036*A, Upgrade U-2 Containment
Airlock Operating Mechanism (C-2)
Engineering CAP Action Backlog Listing
ICAM 1.6, I&C Minimum Staffing, August 16, 2002
IWP 01-128*J-3F, 2SI-856A RHR Pump Suction Isolation MCC Bucket 2B52-323F
Replacement, June 19, 2003
List of Design Basis Documents, July 1, 2003
List of Design Changes in Progress DCNs, August 1, 2003
List of Drawing Change Notices, August 1, 2003
List of System Abbreviations
Management Review Meeting Expectations, October 4, 2002
N-97-0154-00-A, Refinements to Electrical AC Power Distribution System Short Circuit Analysis
Outstanding Drawing Changes as of July 28, 2003
Plant Health Committee, FP-E-PHC-01, December 11, 2002
8 Attachment
Plant Modification (MR) 01-128*C, Replace 1B-42 Outage Related Breakers (24 Total)
MR 01-128*D, Replace MCC 1B-42 Non-Outage Breaker Buckets to Resolve Bolted Fault
Issues
MR 01-128*J, Resolve Bolted Fault Concerns Associated with MCC 2B-32
MR 03-006, Repower AFW Pump Recirculation Valve DPIS Devices from Safety Related Power
Supplies, January 22, 2003
Plant Modification Flow Chart
Plant Modification Review Committee, Meeting Agenda
POD Management Update, Bolted Fault Project
Point Beach Organizational Effectiveness Assessment, Conducted December 9, 2002 -
January 17, 2003
Program Health Process, August 4, 2003
Q List
System Health Report, May 23, 2003
480 V Breaker Overloads, Protective Relay Setpoints
ACE Training Module
Action Plan for Optimizing the Corrective Action Program at Point Beach, April 7, 2003
Action Plan OP-10-006, Effective Root Cause Evaluations, July 7, 2003
Attendance Record for the ACE Briefing
Attendance Record for the RCE Refresher Training
Charter for the Corrective Action Program Technical Review Panel, May 16, 2003
Charters for all RCE for 2003
Common Factors Assessment, May 28, 2003
CP0026, Change Management Process, September 12, 2001
Current Organizational Chart
Employee Orientation Flow Charts
9 Attachment
KPB [Kewaunee/Point Beach] RCE Preparation Checklist
KPB-SA-Corrective Action-2002-01, Kewaunee - Point Beach Assessment of the Corrective
Action Program, June 2002
License Renewal Assessment/Engineering Recovery Plan, March 19, 2003
NPM 2002-0240, Minutes from the May 1, 2002 CARB Meeting, May 7, 2002
NPM 2003-0432, Minutes from the June 17, 2003 CARB Meeting, June 18, 2003
NPM 2003-0522, Minutes from the July 22, 2003 CARB Meeting, July 22, 2003
NRC 2003-0065, PBNP Excellence Plan, July 18, 2003
Numbers of CAPs sorted by Significance Level
PBNP Corrective Action Effectiveness Review Job Aid, July 16, 2003
PBNP Corrective Action Program, The Why and How of the Corrective Action Program (CAP)
PBNP Corrective Action Review Board Charter
PBSA-CAP-03-01, Point Beach Corrective Action Program Self-Assessment Report,
July 7- 11, 2003
Personnel Who Attended Equipment Root Cause Training from PII (2003)
Point Beach Corrective Action Program Managers Workshop, Course Notes
Point Beach Corrective Action Program Supervisor Review/Approval Guide, June 2003,
Point Beach Corrective Action Review Board Workshop, Course Notes
Point Beach Nuclear Plant 2003-2007 Business Plan
Point Beach Nuclear Plant, 2003 - 2007 Business Plan Briefing Slides
Point Beach Nuclear Plant, 95003 CAP Inspection Entrance Briefing, July 28, 2003
Point Beach Nuclear Plant, Assessment of Potential Vulnerabilities for License Renewal,
Martin/Sigmon Consulting Services Inc., March 2003
Qualified RCE Evaluator Roster
RCE Training Module
Request Not to Perform Corrective Actions for Screening Meeting on August 7, 2002 RE:
CAP000594
10 Attachment
Root Cause Investigation Charter
Root Cause Lead Investigators 2002-2003
SAT Overview Procedure
Schedule for 2003 General CAP Training
CAPs Screening Tool
Design Review Board Charter
Desktop Guide to Assist Supervisors With Review and Closeout of Caps -Excellence Plan
10-004.8
Guideline for Identification and Verification of Issues Related to the Site Excellence Plan,
June 12, 2003
Improved Guidance for EOC Assessments
IP 95003, Assessment Guideline, June 12, 2003
IP 95003, Requirements Review Guideline
Method for Trending and Monitoring Equipment - Excellence Plan 10-005.7
PBSA-PBNP-03-01, Point Beach Organizational Effectiveness Assessment, Conducted July 14
- July 18, 2003
Site Excellence Plan Guideline, July 28, 2003
Assessment of Nuclear Engineering Services, Martin/Sigmon Consulting Services Inc.,
February 1998
FP-E-MOD-07, Design Verification and Technical Review, December 27, 2002
OPR 000070, CAP 034430, Operability Determination Part I, Revision 0
OR 2003-002-3-007, Emergent Assessment, August 5, 2003
OR 2003-002-3-015, Maintenance and Work Control, August 4, 2003
OR 2003-002-3-016, Management Systems, August 5, 2003
OR 2003-002-3-036, Emergent Assessment, August 5, 2003
OR 2003-003-3-022, Training, August 5, 2003
Action Items Older Than 300 days That Remain Open Priority 1, 2, and 3
11 Attachment
Documentation of Abbreviations on Modification Lists
Level "A" Apparent Cause Investigation, Inadequate Danger Tagging Clearance for G02 RMP,
Completed January 25, 2002
List of Conditions Adverse to Quality CAPS Closed to Work Orders
List of Work Orders That Are Closed Without or Canceled From Priority 4 CAPS or Work Order
C or Z
List of Work Orders That Are Closed Without Work
MM Corrective Non-Outage Work List
NMC Trend Code Manual, January 17, 2003
Operating Experience (OE) Improvement Plan
Procedure Periodic Review Backlog
Correction of Weaknesses and Deficiencies
SA-Ops-01-06, Gap Analysis, August 2001
Self-Assessment Report, KPB-EP-02-01, April 2002
Self-Assessment Report, KPB EP 02-02, June 18, 2002
Focused Self-Assessment Report KPBNP-EP-02-02, Kewaunee/Point Beach Emergency
Preparedness Program Audit of May 28 Through 30, 2002, June 18, 2002
Self-Assessment Report, PBSA-EP-03-01, EP Staffing and Shift Augmentation Requirements,
January 31, 2003
Quarterly Effectiveness Review Report, Emergency Preparedness, 1st and 2nd Quarters 2003
PBNP NRC EP Readiness Assessment, January 30, 2003
ERO Training Program Description, August 2003
RCE000187, Failure of the EP Critique Process To Identify Drill/Exercise Weaknesses,
Revisions 0, 1, and 2
RCE000194, RCE000187 Did Not Meet Standards to Close NRC Inspection,
Revisions 0 and 1
12 Attachment
ACE000662, Wellhouse Propane Tank Leak, March 6, 2002
ACE001112, March 4, 2002 - UE Declaration May Not Be a Timely Declaration (CAP030381),
December 13, 2002
OTH028187, Four Measures to Improve RCE Quality, February 18, 2003
OTH029034, Compare Timeline of March 4, 2003 Event With NEI 99-02 for PI Requirements,
April 8, 2003
OTH029037, Review Documentation of March 4, 2003 Event For Inconsistencies Between
Reports, CAPs, Control Room Logs and Other Reports, April 8, 2003
NPM 2002-0116, Report of Unusual Event, March 4, 2002
NPM 2002-0158, Emergency Preparedness Response to March 4, 2002 Unusual Event,
March 27, 2002
NPM 2002-0612, Minutes From the November 15, 2002 Corrective Action Review Board
(CARB) Meeting, November 18, 2002
NP 5.3.2, Industry Operating Experience Review Program, Revision 12
CAP002385, March 4, 2002 Wellhouse Propane Tank Leak and Unusual Event, March 4, 2002
CAP028396, EP Documentation of 2001 Annual EAL Review With State/Counties Not
Available, June 5, 2002
CAP030381, March 4, 2002 Unusual Event Declaration May Not Be A Timely Declaration,
December 11, 2002
CAP031099, 2002 EAL Review With State and Counties Not Formally Documented With
Signatures, February 12, 2003
CAP031548, Focused Self-Assessment KPBNP-EP-02-02 Not Distributed in a Timely Manner -
Date Completed in Question, March 10, 2003
CAP032422, A Formal Method For Scheduling Ingestion Exercises With the State Is Needed,
April 28, 2003
Effectiveness Review (EFR)028122, Excellence Plan CA2, Ensure That Multi-Discipline Teams
Perform Team Investigations, February 18, 2003
EFR028123, Excellence Plan CA3, Ensure Adequate Number of RCE-Qualified Personnel Are
at Point Beach, February 18, 2003
CA027674, Revise the Report of the March 4, 2002, Propane Tank Leak Unusual Event
Documented in NPM 2002-0158, January 14, 2003
13 Attachment
CA027675, Annotate the Station Log Entries for the March 4, 2002, Unusual Event Declaration,
January 14, 2003
CA028117, Direct the Performance of a RCE for Any NRC Finding That is Worse Than Green,
February 18, 2003
CA028118, Increase the Number of RCE-Qualified Personnel, February 18, 2003
CA028119, Develop a Minimum Set of Requirements or Qualifications to Function as a RCE
Team Leader, February 18, 2003
CA028120, Develop a Standard Review/Grading Checklist for CARB Use When Reviewing
Completed RCE, February 18, 2003
CA028121, Develop a Management Expectation for the RCE Management Sponsor to Provide
RCE Status Updates to the CARB, February 18, 2003
CA028285, Strengthen the Roles and Responsibilities of the Management Sponsor of a RCE,
February 26, 2003
CA028286, Establish a RCE Mentor Position to Aid RCE Investigators, February 26, 2003
CE011554, A Formal Method For Scheduling Ingestion Pathway Exercises With the State Is
Needed, April 28, 2003
NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2,
November 2001
ERO Readiness
CAP034650, Potential Enhancement Needed For ERO Participation PI Key Position Tracking,
August 7, 2003
CAP034652, Inadequate Communication of UE Evaluation Results in Inaccurate Declaration,
August 7, 2003
CAP034693, Evaluate the Availability of Seismic Monitor Data Computers and Seismic
Monitors, August 8, 2003
1984 E-Plan and Safety Evaluation Report
NP 4.2.28, Health Physics Represented Personnel Assignment and Scheduling Policy,
August 18, 2001
Facilities and Equipment
NUREG 0696, Functional Criteria for Emergency Response Facilities, February 1981
FEMA-Approved Alert and Notification System Design Report, 1982
14 Attachment
Plant Health Committee Meeting Minutes, May 9, 2003, and August 1, 2003
White Paper on Configuration Management, 2003
Letter to NRC Region III Regional Administrator from Assistant Vice President, Emergency
Preparedness Confirmation of Action, Point Beach Nuclear Plant, Units 1 and 2,
February 18, 1982
Emergency Plan Chapter 7, Emergency Facilities and Equipment, Revisions 45 and 46
Instructions for Modular Meteorological System with Telemetry, Climatronics Job Number 7381,
May 13, 1982
Vendor Inspection Report on Condition of Meteorological Towers, June 26, 2000
Emergency Plan Maintenance Procedure (EPMP) 5.0, Post-TMI Meteorological Monitoring
Program Design, Operation, and Maintenance, Revisions 4, 5, and 7
Instrument and Control Procedure (ICP) 6.55, Meteorological Instrumentation Calibration,
Revisions 5, 6, 7, 8, and 9
Sample of ICP 6.55 Calibration Records, November 1994, June 1999, July 2000, July 2001,
July 2002, and May 2003
10 CFR 50.59 Screening Record 2003-0184, Meteorological Instrumentation Calibration
Procedure ICP 6.55, May 2, 2003
ICP 7.30, Meteorological Monitoring System (Bi-monthly Surveillance Checklist), Revision 4
Excerpts of Control Room Log Entries on Placing Onsite and Inland Meteorological Monitoring
Systems Out of Service Due to Being Out of Calibration, May 2, 2003
Excerpts of Control Room Log Entries on Placing Certain Onsite Meteorological Monitoring
System Components Back in Service Following Re-calibration, May 3, 2003
CAP030676, Loss of Direct Current Power to the SBCCs Emergency Notification System
Telephone, January 10, 2003
CAP032129, Proceduralized Backup Sources for Wind Speed Indications, April 9, 2003
CAP032232, Assess Use of the SBCC Data Centers Propane-Powered Generator as Backup
Power Supply for EOF Equipment, April 14, 2003
CAP032569, Primary Towers 45 Meter Wind Direction Indicator is Occasionally Inaccurate,
April 30, 2003
CAP032593, Meteorological Measurement Tolerances Are Not in Accordance With NRC
Commitments, May 1, 2003
15 Attachment
CAP032877, Meteorological System Alarm Setpoints Not Properly Configured on Plant Process
Computer System, May 14, 2003
CAP034511, Adequacy of Work Control for Phone Systems at the SBCC, August 1, 2003
CA029777, Create Instructions to Follow When Equipment Referenced in EALs Is Out of
Service, May 14, 2003
Assessment of the Point Beach Meteorological Equipment Following the Ice Storm of April 3
and 4, 2003, August 4, 2003
2003 White Paper on Configuration Management of the EOF in the Site Boundary Control
Center (SBCC), undated
Plant Health Committee Meeting Minutes on SBCC/EOF Modifications Control, August 1, 2003
OTH029216, Assessment of SBCC Data Centers Propane-Powered Generator as a Backup
Power Supply for EOF Equipment, July 24, 2003
WO 0203763-001, Inspect and Maintain SBCCs Air Conditioning System
WO 0203774, Inspection and Maintain SBCCs Air Filtration System
In-Place Test Reports for TSCs Air Filtration and Adsorber Bed Systems, June 11, 2003
NP 4.2.28, Health Physics Represented Personnel Assignment and Scheduling Policy,
April 18, 2001
Procedure Quality
CA029777, Create a Procedure to Follow When EP-Related Equipment Is OOS, May 14, 2003
CAP030938, FT-3299B, DAVS Isokinetic Sampler Flow Channel Failed High, January 30, 2003
CAP032427, U2 Condenser Air Removal Oscillations Affect On Primary to Secondary Leak
Detection, April 24, 2003
PBNP Excellence Plan, July 11, 2003
NP 1.8.3, 10 CFR 50.54(q) Evaluations, Revision 1
ERO Performance
July 31, 2003, Off-hours Emergency Facility Activation Drill Results
August 14, 2003 Emergency Preparedness Exercise Scenario, Notification Forms, Facility
Logs, Dose Assessment Evaluations, and Final Drill Critique
EPMP 3.2, Offsite Personnel and Emergency Preparedness Staff Training, Revisions 10 and 11
16 Attachment
July 28 and Aug 4, 2003 Licensed Operator Requalification Drills
CA026651, Revise EPIP 11.2 and EPMP 1.3e to Reflect Changes Made to Medical Kits in
Control Room, October 9, 2002
CA027769, CATPR #3: Develop Program to Address Training and Development Needs of EP
Staff, January 22, 2003
CA032011, CATPR #3 of RCE000187 Closed With Incomplete Actions - Review CAP033979
and Implement Recommendations, July 14, 2003
CAP028952, August 1 Drill EAL for Site Emergency, August 5, 2002
CAP029232, Reassess Number of Medical Emergency First Responder Kits in Control Room,
September 6, 2002
CAP029492, White Finding in EP Following the 2002 Graded Exercise, September 23, 2002
CAP029814, Radiation Protection Staff Lacked Familiarity with Aurora Medical Facility and
EPIP 11.2, October 15, 2002
CAP029816, Radiation Protection Staff Needed Prompting to Complete Hallway Survey and
Decontamination Tasks During Medical Drill, October 15, 2002
CAP032488, AR Due to EPIP Entry, April 26, 2003
CAP033206, EPIP 1.1 Entry Due to Propane Type Smell Non Classifiable, June 1, 2003
CAP033979, CATPR #3 of RCE000187 Closed With Incomplete Actions, July 10, 2003
CAP034364, Question on Classification Generated During LOR Session, July 28, 2003
CAP034387, Additional Information Requested on an EAL, July 29, 2003
CAP034531, Adequacy of Work Control for Plant Phone Numbers, August 1, 2003
CAP034547, Failed DEP Performance Indicator Opportunity, August 4, 2003
CAP034644, NRC Document Request by 95003 Inspection Team, August 7, 2003
Emergency Plan Section 8, Maintaining Emergency Preparedness, May 9, 2003
Emergency Plan Section 8, Maintaining Emergency Preparedness, 1984
Emergency Response Training Program (TRPR) 34.0, November 28, 2000
Point Beach EP Training Program (EP-TP) Description, August 1, 2003
NP 5.3.2, Industry Operating Experience Review Program, November 12, 2002
17 Attachment
Form FP-T-SAT-40, Management Observation of Training Form, Revision 3
Computerized EP Training Records of a Random Sample of 25 Personnel Assigned to Key and
Support ERO Positions
Random Sample of 70 ERO Members Records Indicating Status of Their Qualifications to Use
Self-Contained Breathing Apparatus, July 28, 2003
Kewaunee/Point Beach Nuclear Emergency Telephone Directory, June 30, 2003
EPG 1.0, Emergency Preparedness Drill Guideline, October 18, 2002
August 20, 2002, Medical Drill Critique Report, October 17, 2002
Lesson Plan 2300 (master copy), Emergency Preparedness Overview, November 17, 2000
Lesson Plan 3015 (master copy), Emergency Classification, January 25, 2000
Lesson Plan 3017 (master copy), Notifications, November 17, 2000
Lesson Plan 3018 (master copy), Assembly and Accountability, Release and Evacuation of
Personnel, January 31, 2000
Lesson Plan 3019 (master copy), Dose Projection Theory, March 19, 2001
Lesson Plan 3020 (master copy), Protective Action Determination, March 23, 2001
Lesson Plan 3021 (master copy), Tools for Dose Assessment, January 10, 2002
Lesson Plan HPC-02-LP004 (master copy), Control Room Accident Assessment, Revision 0
Lesson Plan EPI-02-LP001 (working copy), Emergency Classification
Lesson Plan 3017 (working copy), Notifications
Lesson Plan 3018 (working copy), Assembly and Accountability, Release and Evacuation
Lesson Plan 3020 (working copy), Protective Action Determination
EPIP 1.1, Course of Action, Revision 43
EPIP 1.3, Dose Assessment and Protective Action Recommendations, Revision 30
EPIP 1.4, Credible High or Low Security Threat, Revision 2
EPIP 2.1, Notifications - ERO, State and Counties, and NRC, Revision 26
EPIP 6.1, Assembly and Accountability, Release and Evacuation of Personnel, Revision 24
18 Attachment
EPIP 11.2, Medical Emergency, September 20, 2002
In Depth Review of RSPS
Emergency Plan, Revisions 32, 33, 35, and 39
Emergency Plan, Appendix B, Revision 2
Emergency Plan, Section EP 6.0, Emergency Measures, Revisions 21 and 42 - 46
ACE001405, Inconsistency In Evaluation/Interpretation of EAL, August 15, 2003
CA053364, Update EP, EPIPs, PIMs - Ability to Recommend Sheltering, October 23, 2003
CAP030161, Large Scale EPIP 2.2 Attachment A EAL Matrix Not Printed From,
November 16, 2002
CAP032977, Emergency Plan Classification Times, May 19, 2003
CAP033031, NARS Form Not Filled Out Correctly, May 22, 2003
CAP033034, Tracking of Multiple EALs, May 22, 2003
CAP034364, Question on Classification Generated During LOR (Licensed Operator
Requalification) Session, July 28, 2003
CAP034784, NRC 95-003-1 Inspection Team Questions on EALs, August 12, 2003
CAP034785, NRC 95-003-1 Inspection Team Questions on Approval Process for PAR
Discussion, August 12, 2003
CAP034787, Seismic Event Monitor Set-Points Not In Accordance With STPT 22.1 or EPIP 1.2,
August 12, 2003
CAP034833, Inconsistency In Evaluation/Interpretation of EAL, August 13, 2003
CAP051288, Sheltering Not Included As Part of Protective Action Recommendations for EP,
October 21, 2003
EPIP 1.1, Course of Action, Revision 43
Change Package for EPIP 1.1.2, Plant Operations Manual, General Emergency-Protective
Actions, January 1, 1994
EPIP-1.2, Emergency Classification, Revisions 20 - 39
EPIP 9.3, Protective Action Evaluation, Revision 17
19 Attachment
Point Beach Presentation at NRC Region III Office of Proposed EAL Changes, July 29, 1999
NUMARC/NESP-007, Methodology for Development for Emergency Actions Levels, Revision 2
NUREG-0654/FEMA-REP-1, Criteria for Preparation and Evaluation of Radiological Emergency
Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1
Regulatory Guide 1.101, Emergency Planning and Preparedness for Nuclear Power Plants,
Revision 3
EPPOS-1, Emergency Preparedness Position (EPPOS) On Acceptable Deviations
From Appendix 1 of NUREG-0654 Based Upon The Staffs Regulatory Analysis of
NUMARC/NESP-007, Methodology For Development of Emergency Action Levels,
June 1, 1995
ENGINEERING, OPERATIONS, AND MAINTENANCE
Electrical Systems
Calculations
E-09334-472-DC.3, DC Panel Voltage Drop for MR 97-014*E and *F, Revision 2
N-93-056, Battery D05 DC System Sizing, Short Circuit Calculations, Revision 2
N-93-056, Battery D05 DC System Sizing, Voltage Drop and Short Circuit Calculations, Draft
Revision 4
N-93-058, Battery D105 DC System Sizing, Voltage Drop and Short Circuit Calculations, Draft
Revision 3
Calculation 2003-0046, Battery Charger Sizing and Current Limit Set Point, Revision 1
Calculation N-93-098, Degraded Grid Voltage Relay Settings, Revision 6
Calculation N-93-002-03-A, Determination of Minimum Sustained Voltage Required on 4160
VAC Safeguards Buses, Revision 3, Addendum A
Calculation N-93-002-03-B, Effects of CR 94-270 on Calculation N-93-002, Revision 3,
Addendum B
Calculation N-93-002-03-C, OWA 1-99R-006, EWR 99-105, Revision 3, Addendum C
Calculation N-93-002-03-D, Determination of Minimum Sustained Voltage Required on 4160V
Safeguard Buses with Modification MR 03-014, Revision 3, Addendum D
Calculation N-94-076, Use of a Fluke 8505A-09A Multimeter to Calibrate the Degraded Grid
Voltage Relays, Revision 0
20 Attachment
Calculation N-94-009-01-A, Determination of Minimum Voltage at Safety-Related MCCs with
Modification MR 03-014, Revision 0
Calculation N-94-081, AC Distribution System Maximum Voltage, Revision 0
Calculation 95-0040, Determination of Voltage Drop in Safety-Related MCC Control Circuits,
Revision 0
Calculation 95-0040-00-A, Effects of Bolted Fault Bucket Replacement, Revision 0
Calculation 95-0040-00-B, Effects of Bolted Fault Bucket Replacement, Revision 0
Calculation 2003-0015, PRA Evaluation for Missed Surveillance of A05 and A06 Degraded
Voltage Relays, April 4, 2003
Calculation N-97-0154-00-A, Refinements to Electrical AC Power Distribution System Short
Circuit Analysis, Revision 0, Addendum A
Engineering Evaluation 2003-003, Minimum Required 345-kV System Voltage,
September 24, 2003
Drawings
E-6, Sheet 1, Single Line Diagram 125 VDC Distribution System, Revision 42
E-6, Sheet 2, Single Line Diagram 125 VDC Distribution System, Revision 15
E-6, Sheet 4, Single Line Diagram 125 VDC DC System (Non-1E), Revision 3
Elementary Wiring Diagram EAPS 240009, 4160V Switchgear Bus 1A05 Undervoltage and Diff.
L.O. Relays Point Beach Unit 1, Revision 06
Elementary Wiring Diagram EAPS 241010, 4160V Switchgear Bus 1A05 Undervoltage and Diff.
L.O. Relays Point Beach Unit 2, Revision 05
Elementary Wiring Diagram, EAPS 031018, Alternate Supply 1P-11A/B Breaker B-52-55C,
Revision 3
Elementary Wiring Diagram, EAPS 0000187, Component Cooling Pump, Revision 13
Elementary Wiring Diagram, EDCS 068010, D-05 DC Station Battery Charger Supply D-07
Point Beach Units 1 and 2, Revision 6
Elementary Wiring Diagram, EDCS 068011, D-06 DC Station Battery Charger Supply D-08
Point Beach Units 1 and 2, Revision 5
Panel Layout, Graphics, Nameplates & Bill of Materials Drawing MVAG 037001, HVAC Control
Panel Battery Room, Revision 6
21 Attachment
Wiring Diagram Johnson Controls 8401-WD, Battery Room HVAC [Heating, Ventilation, and Air
Conditioning] Control Panel, Revision 8
Elementary Wiring Diagram, E242024001, Battery Room HVAC System 499B46 Sheet 1653,
Revision 6
Elementary Wiring Diagram, EAPS 000108, Battery Room HVAC System 499B46 Sheet 1656,
Revision 6
Elementary Wiring Diagram, PAB Battery and Inverter Room Ventilation Fan W-85, Revision 7
Elementary Wiring Diagram, EAPS 241023, 1B03 480V Undervoltage Scheme, Revision 19
Elementary Wiring Diagram, EAPS 241024, 1B03 480V Undervoltage Scheme, Revision 16
Schematic Diagram ERPS 141078, SI Logic Engineered Safety Features (ESF) Systems Train
A Reactor Safeguards Systems, Revision 18
Logic Diagram EAPK 1410021, 480 Bus Schemes, Revision 10
Schematic Diagram ERPS 000002, Safeguard System, Revision 16
P&ID MRML 000002, Battery & EE Room MS VAC Point Beach Units 1 and 2, Revision 18
Modifications
MR 96-032, Replace Control Power Transformers in 1B32 and 1B42, October 28, 1997
MR 97-014*C, Transfer Loads from D-40 to D-14, Install D-27 and 1D-202, Provide Temporary
Power to Inverters DY-OD & 2DY-04, Revision 0
MR 97-107, CCW Pump Motor Replacement, October 22, 1997
MR 99-003, HELB Wall Barriers and Blow-Off Panel in CCW HX Room, August 28, 2002
MR 01-128*C, Replace MCC 1B-42 Breaker Buckets to Resolve Bolted Fault Issues,
June 24, 2002
Spare Parts Equivalency Evaluation Document (SPEED)97-084, 1 or 2P11B Spare Motor,
January 7, 1988
Setpoint Document and Setpoint Change Sheet STPT 21.1 Sheet 10, Change High Side Fixed
Tap of 1X-04 Low Voltage Station Auxiliary Transformer, add this information to STPT,
March 22, 1994
Setpoint Document and Setpoint Change Sheet STPT 21.1 Sheet 11, Protective Relay
Setpoints: Transformer 2X-04, January 25, 1998
Self-Assessments
22 Attachment
Point Beach Self-Assessment Report, 125-VDC System Self-Assessment, PBSA-ENG-03-03,
September 8, 2003
Training
RFT010190, Request for Training, OP-2A Temp Change, September 24, 2003
LP0121, Training Lesson Plans, DC Distribution, Revision 4
Procedures
NP 1.1.8, Complex Troubleshooting, Revision 0
NP 2.1.5, Electrical Communications, Switchyard Access and Work Planning, Revision 2
NP 7.2.4, Calculation Preparation, Review, and Approval, Revision 7
NP 8.5.2, CHAMPS Equipment Database Usage and Control, Revision 4
AOP 0.1, Declining Frequency on 345 kV Distribution System, Revision 6
0-TS-EP-001, Weekly Power Availability Verification, Revision 4
OP-2A, Normal Power Operation, Revision 49
2003-0486, Temporary Change Review and Approval for OP-2A, September 23, 2003
American Transmission Co. Procedure TOP-20GN-000004, Voltage/Reactive Control,
August 31, 2001
Single Line Diagram, EAPK 000003, Station Connections, Revision 17
Routine Maintenance Procedure (RMP) 9200-1, Station Battery D-05 Discharge Tests and
Equalizing Charge, Revision 8
RMP 9201, Control and Documentation for Troubleshooting and Repairs, Revision 0
RMP 9369-1, Amptector Overload Setpoint Check on Low Voltage Breakers, Revision 5
RMP 9303, DB-50 Breaker Routine Maintenance, Revision 15
RMP 9374-1, Molded Case Circuit Breaker and Drawout Unit Maintenance, Revision 7
RMP 9374-2, Molded Case Circuit Breaker (MOB/Panel) Maintenance, Revision 0
RMP 9374-3, Molded Case Circuit Breaker Functional Testing Procedure, Revision 0, Draft B
Correspondence
23 Attachment
E-mail from M. Marz, American Transmission Company, to H. Soulia, NMC, Regarding
Kewaunee and Pt. Beach Voltages Following Loss of Generation, November 14, 2001
E-mail from M. Zahorik, American Transmission Company, to W. Hennig, NMC, Regarding
Point Beach Lower Initial Bus Voltage, September 26, 2003
E-mail from M. Zahorik, American Transmission Co., to T. Lensmire, NMC, Regarding Point
Beach Lower Voltages, September 25, 2003
Letter from L.G. Lutz, Power Conversion Products, to P. Katers, Wisconsin Electric Company.,
Regarding Battery Charge Design and Production Test Data, August 4, 1981
Letter from D. Livermore, Cutler Hammer, to W. Sprang, NMC, Technical Data for PO04777,
August 23, 2002
Miscellaneous
EOM-0119, 95003 Question Response - Grid Voltage Data for Last 4 years,
September 24, 2003
EOM-0159, 95003 Question Response - Plant Operating History, September 23, 2003
EOM-0169, 95003 Question Response - Point Beach Degraded Grid Historical Issue,
September 26, 2003
Feedback Request for OI-35B, Electrical Equipment General Information, Revision 6
Engineering Evaluation 2003-0039, Minimum Required 345 kV System Voltage,
September 24, 2003
White Paper, Licensing Basis Summary for 345kVAC Offsite Power System (GDC-17),
September 2003
2001 Analysis of Circuit Breaker Trending Database, November 2, 2001
WO 9948833, 2002 Analysis of Circuit Breaker Trending Database
WO 0300088, 2003 Analysis of Circuit Breaker Trending Database
Design Guide DGI01, Instrument Setpoint Methodology, Revision 3
PRA Notebook 5.6, 125 VDC Electric Power, Revision 0, Draft A
Design Basis Document DBD-22, 4160 VAC System, Revision 2
Appendix R SER for Appendix R Exemptions, July 3, 1985
SER of the Point Beach Response to the Station Blackout Rule, October 3, 1990
24 Attachment
Technical Specifications
TS LCO 3.8.1, AC Sources - Operating, Unit 1 - Amendment No. 201, Unit 2 - Amendment
No. 206
TS LCO Bases B 3.8.1, AC Sources - Operating, Unit 1 - Amendment No. 201, Unit 2 -
Amendment No. 206
TS LCO 3.8.4, DC Sources - Operating, Unit 1 - Amendment No. 201, Unit 2 - Amendment
No. 206
TS LCO Bases B 3.8.4, DC Sources - Operating, Unit 1 - Amendment No. 201, Unit 2 -
Amendment No. 206
Operability Determination/Recommendation
Operability Determination CR 98-0164, High Energy Line Break in PAB - Electrical Equipment
Important to Safety, Not Previously Evaluated in the Environmental Qualification Program,
Revision 12, April 7, 2003
Operability Recommendation OPR000080, Calculation N-93-002 Does Not Reflect Current
Plant Configuration, September 16, 2003
CAPs and Other Corrective Action Program Documents
ACE001369, DC Voltages Specified in AOP 0.0 Are Inconsistent with 125 VDC Calculations,
July 25, 2003
ACE001379, Available Battery Margin May Be Less Than Calculated, July 31, 2003
ACE001381, Multiple Calculation Related Issues Identified During Assessment, August 1, 2003
CA032290, Implement Recs DC Voltages Specified in AOP 0.0 Are Inconsistent With 125 VDC
Calcs, July 25, 2003
CA033052, Calculations Do Not Adequately Support the DC System - Create Master Calcs,
August 24, 2003
CA033053, Calculations Do Not Adequately Support the DC System - Address Affected Calcs,
August 24, 2003
CA033054, Calculations Do Not Adequately Support the DC System - Affected Procedures,
August 24, 2003
CA033055, Calculations Do Not Adequately Support the DC System - Other Affected
Documents, August 24, 2003
CAP000729, QA Switches - No Periodicity for Calibration, May 30, 2001
25 Attachment
CAP001532, Plant Electrical Equipment May Be Used In Applications Beyond Fault Current
Rating, March 30, 1993
CAP001559, High Energy Line Break in PAB, January 18, 1998
CAP002410, DC Master Calculations Require Updates For Recently Completed Modifications,
March 5, 2002
CAP003038, Calculation N-94-081 Revision 0 Is No Longer Applicable, April 25, 2002
CAP031069, Initial Breaker Close on 2P-10A RHR Pump Failed After MCE/RIC Testing,
February 10, 2003
CAP031241, Insufficient Documentation to Support 1P-11B Motor Replacement and Document
Update, February 20, 2003
CAP033324, Concerns Regarding a High Energy Line Break in the PAB, June 5, 2003
CAP033447, Issues Associated With Battery Charger Current Limit Setpoint, June 9, 2003
CAP034219, DC Voltages Specified in AOP 0.0 Are Inconsistent with 125 VDC Calculations,
July 22, 2003
CAP034379, Available Battery Margin May Be Less Than Calculated, July 29, 2003
CAP034396, Vendor Calculations Were Not Entered Into the Document Control System,
August 29, 2003
CAP034424, Calculations Do Not Adequately Support the 125 VDC System, July 30, 2003
CAP034427, Multiple Calculation Related Issues Identified During Assessment, July 30, 2003
CAP035109, Active Calculation Does Not Reflect Current Plant Configuration, August 25, 2003
CAP049793, Enhancements and Clarifications for Modification MR 03-005, September 2, 2003
CAP049868, DG Loading Calculation Weakness, September 4, 2003
CAP050013, FSAR Appendix A.1 (Station Blackout) Inaccuracies, September 9, 2003
CAP050022, Design Basis Document DBD-T-46 (Station Blackout) Error, September 9, 2003
CAP050027, FSAR Appendix A.1 Not Updated to Reflect More Recent SBO Information,
September 9, 2003
CAP050028, Old Calculations on Inverter Room Heatup Should Be Superseded,
September 9, 2003
CAP050090, Questions on New DC Calculations, September 11, 2003
26 Attachment
CAP050096, Need to Update Drawings to Reflect As-Built Condition; PAB Battery Room Vent,
September 11, 2003
CAP050127, Missing Documentation on DB Breaker Testing Methodology, September 12, 2003
CAP050151, NRC Question On Temperature Effects On 125VDC Cables, September 14, 2003
CAP050164, Instrument Bus Static Transfer Switch Issues, September 15, 2003
CAP050171, Calculation N-93-058 Contains an Inappropriate Assumption, September 15, 2003
CAP050174, Consideration Should Be Given to Add MOV Loads in Calculation N-93-002,
September 15, 2003
CAP050179, Industry OE - Callaway - Inoperability of Both Offsite Power Sources,
September 15, 2003
CAP050203, Calculation N-93-002 Does Not Reflect Current Plant Configuration,
September 16, 2003
CAP050211, Calc N-93-002 Does Not Adequately Address the Voltage Available at Battery
Charger, September 16, 2003
CAP050225, 345 kV & 4160 V Low Voltage Alarms Not Available in the Control Room,
September 17, 2003
CAP050227, OP 2A Attachment H Enhancement May Be Needed, September 17, 2003
CAP050258, Multiple Drawing Errors Discovered During Creation of Calculation 2003-0006,
September 17, 2003
CAP050270, WO 9510436 Testing Inadequate for Bucket Starter 1B52-427M,
September 18, 2003
CAP050325, Errors and Inconsistencies in Calculation N-93-003-03-A, September 22, 2003
CAP050343, Evaluate Combinations of Offsite Power Conditions That Could Challenge Plant
Ops, September 23, 2003
CAP050348, CAP049868 Screened by Non-SRO, Prescreened by SRO, September 23, 2003
CAP050356, Assumption in Calc 2003-0046 Needs Clarification, September 23, 2003
CAP050359, FSAR Section 8.1 May Not Accurately Reflect Degraded Grid Licensing Basis,
September 23, 2003
CAP050366, Tech Spec SR 3.8.4.6 Is Non-Conservative With Respect to the Calc of Record,
September 23, 2003
27 Attachment
CAP050369, Calculation 95-0040, Rev. 0 Input Is Not Conservative, September 24, 2003
CAP050390, OI-35 Series Procedure Improvement Recommendation, September 24, 2003
CAP050396, NRC Questions - Basis of TS 3.8.1, Offsite Power Sources and Related
Assumptions, September 24, 2003
CAP050403, Modifications Not Adhering to Requirements of Calculation Procedure
Requirements, September 24, 2003
CAP050407, Calculation E-09334-369-DG.1 Enhancement, September 25, 2003
CAP050414, Potential to Separate From Grid When Both X02 Are OOS And a X03 Failure
Occurs, September 25, 2003
CAP050415, Question On the Set Point Drift Value Provided in Calculation N-93-098,
September 25, 2003
CAP050430, D-07, D-08, and D-09 Transformer Tap Setting Documentation Discrepancies,
September 25, 2003
CAP050456, Establishment of App. R Backup Air for Charging Pumps May Be Hot Shutdown
Repair, September 26, 2003
CE011998, Calculations Do Not Adequately Support the 125 VDC System, August 1, 2003
CE012276, DG Loading Calculation Weakness, September 8, 2003
CE012342, NRC Question On Temperature Effects On 125VDC Cables, September 16, 2003
QCR95032, Breaker Testing Equipment Being Used While Past Due Calibration,
October 20, 1995
QCR94004, Reset Characteristics of the Degraded Voltage Relays Have Not Been Analyzed,
February 4, 1994
Vendor
Power Conversion Products Inc. Instruction Manual, Three-Phase Thyristor Controlled,
May 28, 1981
Westinghouse Instruction Leaflet I.L. 33-791-G, Amptector Tester Instructions, April 1986
Westinghouse Descriptive Bulletin 49-380, Static Trip Modernization Low Voltage Air Circuit
Breakers, November 1973
Work Orders (WOs)
WO 0200812, Analyze the Condition with MCE Tester - MCE Test W/RIC: Perform Standard,
28 Attachment
PI, RIC, and DA Tests, March 6, 2003
WO and Associated Work Plan 0200976, Perform Breaker Maintenance per RMP 9303
Perform Amptector Settings Maintenance per RMP 9369-1, March 6, 2003
WO 0200976 and Associated Work Plan, Perform Breaker Maintenance per RMP 9303
Perform Amptector Settings Maintenance per RMP 9369-1, March 6, 2003
WO 9933756 and Associated Work Plan, Perform Breaker Maintenance per RMP 9303
Perform Amptector Settings Maintenance per RMP 9369-1, March 6, 2003
WO 9510436 and Associated Work Plan, Removal of the 1B52-427M Breaker Bucket,
Performance of Breaker Starter Testing and Breaker Bucket Replacement, December 7, 1999
WO 9510437 and Associated Work Plan, Perform a Bench Test to Determine if the P-12A
Motor Starter Contactor Will Pick Up, December 13, 1999
Calculations
Calculation 96-0103, Cooling of Recirculation Flow by the RHR HX Post-LOCA, Revision 0,
September 3, 1996
Calculation 96-0284, Uncertainty Associated with Instrumentation Used in IT-12 & IT-13,
Revision 1, April 20, 1998
Calculation 98-0034, CCW Surge Tank Minimum Water Volume at the Low Level Alarm
Setpoint, Revision 0
Calculation 98-0036, CCW Heat Exchanger Service Water Differential Pressure Indicator
Uncertainty Calculation, Revision 0, April 6, 1998
Calculation 2001-0055, MOV Stem Thrust Margin for Gate and Globe Valves, Revision 1,
September 30, 2002
Calculation 2002-0003, Service Water System Design Basis, Revision 0, June 13, 2002
Calculation ATD-0296, Evaluation of Closing the Vent on the Component Cooling Water Surge
Tank, Revision 0, July 23, 1993
Calculation EVAL-WE0005-01, Determination of Initial Setting for Component Cooling Water
Throttle Valves 1CC-842B and 2CC-842B, Revision 0, November 3, 1998
Calculation M-09334-353-CC.1, Closed Loop Inside Containment Reclassification of the Unit 1
and 2 CCW System Field Walkdown Report, Revision 0, July 2, 1999
Calculation M-09334-353-CC.3, Evaluation of HELB Affect on CCW Piping, Revision 0,
29 Attachment
July 2, 1999
Calculation M-09334-353-CC.4, Evaluation of HELB Affect on CCW Piping, Revision 0,
July 2, 1999
Calculation M-09334-353-CC.5, CC System External Pressure Capability, Revision 0,
July 2, 1999
Calculation M-09334-353-CC.6, Evaluation of CC for Closed System Inside Containment,
Revision 0, July 26, 1999
Calculation N-89-009, Decay Heat Rate Curve, Revision 0, March 2, 1989
Calculation N-93-71, 1(2) CC-754A, 754B, 1(2) CC-759A, 759B (Group 11) MOV Differential
Pressure Calculation, Revision 0, February 1, 1994
Calculation N-94-059, CCW HX-12A-D Service Water Flow Versus Temperature Requirement,
Revision 1, July 17, 2003
Calculation PGT-2000-1382, Point Beach Nuclear Plant Component Cooling Water Heat
Exchangers HX-12C and HX-12D Thermal Performance Test Data Evaluation and Uncertainty
Analysis, Revision 0, January 22, 2001
Calculation PGT-2001-1180, Point Beach Nuclear Plant Component Cooling Water Heat
Exchangers HX-12A and HX-12B Thermal Performance Test Data Evaluation and Uncertainty
Analysis, Revision 0, May 7, 2001
Calculation PGT-2003-1189, PBNP Component Cooling Water Heat Exchangers HX-012A and
HX-012B Thermal Performance Test Data Evaluation and Uncertainty Analysis, Revision 0
Calculation RFS-W-440, Size the ACS Relief Valves, February 23, 1968
Calculation WEP-SPT-34a, RHR Flow Indication Uncertainty (F-928), Revision 0, April 30, 2000
RFS-W-107, WEP Plant ACS Design Parameters, December 23, 1966
Corrective Action Program Documents
ACE000442, Radwaste CC Isolation Valves CC-LW-63/64 Quick Closure On Break in
Radwaste System, August 26, 1999
ACE001407, CC System Licensing Basis Not Well Documented and/or Ambiguous,
August 18, 2003
CA003024, Radwaste CC Isolation Valves CC-LW-63/64 Quick Closure On Break in Radwaste
System, September 14, 1999
CA009715, Non-Essential Loads Not Isolated in EOP During DBA, November 13, 1997
30 Attachment
CA003025, Radwaste CC Isolation Valves CC-LW-63/64 Quick Closure On Break in Radwaste
System, May 10, 2000
CA013529, Safety Injection IST Program Acceptance Criteria Non-Conservative, June 27, 1996
CA013530, Safety Injection IST Program Acceptance Criteria Non-Conservative,
December 3, 1996
CA013790, Accident Analysis Assumptions Questioned, March 3, 1997
CA013791, Accident Analysis Assumptions Questioned, June 24, 1997
CA017975, Potential Overstress Piping and Supports During Post-LOCA Recirculation,
July 2, 1999
CA017976, Potential Overstress Piping and Supports During Post-LOCA Recirculation,
July 2, 1999
CA018346, Restricted Use of Appendix R Spare Motor Not Adequately Documented - Review
Calculation, November 22, 2000
CA026038, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 12, 2002
CA026042, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 12, 2002
CA026043, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 12, 2002
CA026044, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 12, 2002
CA026045, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 12, 2002
CA026066, Calc of Cont Spray Duration Does Not Consider No Auto Initiation of Cont Spray,
August 13, 2002
CA026250, EOP Issues Identified During 2002 SSDI [Safety System Design Inspection],
September 6, 2002
CA028253, Adequacy of Comp Measure to Start/Stop AFW Pumps While Running on Service
Water, February 21, 2003
CA028254, Vulnerability of TDAFPs to Restart When Run on SW, February 21, 2003
CA032399, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, July 29, 2003
CA032642, Revise EOP 1.3 Step 24/26 by Revising/Removing CCW HX Outlet Temperature
Limit, August 8, 2003
CA033093, Review EOP 1.4 and Consider Recommended Changes, August 25, 2003
31 Attachment
CA051892, SFP HX Safety Classification Change, August 29, 2003
CAP000195, Action Plan for GL 89-13 (SW) Needed, May 17, 2000
CAP001640, Radwaste CC Isolation Valves CC-LW-63/64 Quick Closure On Break in
Radwaste System, August 12, 1999
CAP001870, 2P-11A CCW Pump Post Maintenance Testing Change, January 15, 2002
CAP002914, PBNP Continues To Lift CC and CCW System Relief Valves During Routine
Maintenance, April 18, 2002
CAP003216, Potential to Dead-Head CC Pumps Not Evaluated, May 7, 2002
CAP003224, Q-List Discrepancies on Auxiliary Feedwater Minimum Flow Recirculation Line,
May 8, 2003
CAP005473, Component Cooling Heat Exchanger, August 15, 2001
CAP005667, Component Cooling Water (CCW) Surge Tank Level Transmitter Concerns,
November 11, 2001
CAP012480, Conflicting Information on Required Valve Position (Valve 2CC-748A),
August 11, 2000
CAP012797, Component Cooling (CC) Supply to Containment Failed Stroke Test,
October 16, 2000
CAP018366, Non-Essential Loads Not Isolated in EOP During DBA, November 12, 1997
CAP022794, CCW Heat Exchanger Cleaning Compliance With GL 89-13, May 7, 2001
CAP023473, Safety Injection IST Program Acceptance Criteria Non-Conservative,
June 25, 1996
CAP023644, Accident Analysis Assumptions Questioned, February 28, 1997
CAP024039, IST Program Excluded Thermal Barrier CCW Supply and Return Valves,
November 19, 1997
CAP026451, Potential Overstress Piping and Supports During Post-LOCA Recirculation,
June 25, 1998
CAP026926, CCW Pump Vibration, February 15, 2001
CAP028467, Inappropriate Value for CCW Flow to CCW HX Used in Calculation,
June 13, 2002
CAP028472, Auxiliary Feedwater Testing Concerns, June 14, 2002
32 Attachment
CAP028893, Two Cases in EOPs Omitted When Revising ECCS NPSH [Emergency Core
Cooling System Net Positive Suction Head] Calculation, July 30, 2002
CAP028894, Observations in EOP 1.3, July 30, 2002
CAP028910, SI Alignments in EOP 1.3 Could Result in Excessive Flow Rates, July 31, 2002
CAP028911, Potential for Draining the RWST to Containment During a DBA LOCA,
July 31, 2002
CAP028946, SSDI Question #43, EOP 1.3 Manual CC Valves, August 5, 2002
CAP028992, EOP 1.4 Step 19d - Inadequate Basis for the 130 psig Setpoint, August 8, 2002
CAP028994, Calculation of Containment Spray Duration Does Not Consider No Auto Initiation
of Cont Spray, August 8, 2002
CAP028998, EOP Issues Identified During the 2002 SSDI, August 8, 2002
CAP029261, Appendix R Classification Discrepancies in AFW Common Recirc Line,
September 10, 2002
CAP029510, 1P-11A CC Pump Operated at Above Max Flow for Continuous Operation,
September 24, 2002
CAP030790, Raceway Separation Requirements Are Met for CST Level Indication on Both T-
24A & B, January 21, 2003
CAP030899, AFW Pump Suction Check Valves Function, January 28, 2003
CAP030902, Point Beach AFW Pump Failure in 1974 After Unintentionally Pumping Service
Water, January 28, 2003
CAP031002, Analysis for Aux Feed Pumps dP [differential pressure] Is Non-Conservative for
IST Test Criteria, February 5, 2003
CAP031021, Correction to 1/2MS-2090 IST Valve Data Sheet, February 6, 2003
CAP031040, IST Background Data Sheets for AFWP Suctions Contain Incorrect Information,
February 27, 2003
CAP031157, Adequacy of Comp Measure to Start/Stop AFW Pumps While Running on Service
Water, February 14, 2003
CAP031339, Facade Heat Trace for TDAFW Pumps Steam Lines, February 26, 2003
CAP031726, Unit 2 CC System Temperature Exceeds 105 Degrees F for Two Minutes,
March 20, 2003
33 Attachment
CAP031730, Requirements for Seismic Induced Blockage of Pipe Not Clear, March 20, 2003
CAP032409, Engineering Evaluation for CC HX Tube Plugging Limit Did Not Address Increase
in Velocity, April 23, 2003
CAP033104, GL 89-13 Action Plan Item in OPS Procedure Feedback Backlog for 2 Years,
May 27, 2003
CAP033467, Unexpected U-2 CCW Surge Tank Level Hi Alarm, June 10, 2003
CAP033580, Determine Current LBB Analysis of Record for PBNP, June 16, 2003
CAP034321, Temperature Inconsistency for Non-Regen CC Temperature Between Units,
July 25, 2003
CAP034408, Component Cooling Pump Hydraulic Concerns, July 29, 2003
CAP034416, Seismic Concerns Identified During CC System Assessment Walkdown,
July 30, 2003
CAP034446, Compilation of CC System Inadvertent Relief Valve Lifting Evaluations,
July 30, 2003
CAP034504, Manual Operation of Main Zurn After Loss of Power Not Described in Procedures,
August 1, 2003
CAP034513, Basis for Prompt Operability Screening on CAP 33580 Incorrect, August 1, 2003
CAP034526, Documentation for Upgrade of CC System to Safety-Related Could Not be Found,
August 2, 2003
CAP034548, Calculation Weaknesses in Calculation N-94-064, Revision 3, August 4, 2003
CAP034555, Calculation N-94-059, Revision 1 Weakness, August 4, 2003
CAP034560, Completed Procedure Does Not Have Vibration Data Entered, August 4, 2003
CAP034575, Tracking Method for IST Procedure Updates Seen as Informal, August 5, 2003
CAP034608, Conflicting Drawings, Procedures, and Operability Status of 1(2)RC-508,
August 6, 2003
CAP034628, Enhance EOP 1.3 Step 24/26 By Revising/Removing CCW HX Outlet
Temperature Limit, August 6, 2003
CAP034636, Interface Between Lever and Shaft Damaged on 2CC-130, August 7, 2003
CAP034703, Temporary Modification Procedure Questions, August 8, 2003
34 Attachment
CAP034710, Install Larger Motors on 1-CC-738A&B to Increase Close Margin, August 8, 2003
CAP034716, CC Header Temperature Design Basis Clarification, August 8, 2003
CAP034717, CC System - Electrical Evaluation, Revision 0, Nomenclature Deficiency,
August 8, 2003
CAP034718, Abandoned in Place Configuration Deficiencies, August 8, 2003
CAP034719, NP 7.1.5 Definition and Section Title Inconsistency, August 8, 2003
CAP034720, OI-151 Acceptance Criteria Deficiency, August 8, 2003
CAP034721, Temporary Modification Procedure Concerns, August 8, 2003
CAP034782, SW Main Zurn Strainers Auto-Backwash & Alarm Setpoint Deficiencies,
August 12, 2003
CAP034800, Potential Need for Equipment Root Cause on Closed CAPs, August 13, 2003
CAP034803, Potential of Closed CAP Without Sufficient Investigation, August 13, 2003
CAP034809, Main SW Zurn Strainer Documentation of Current Method of Operation Concern,
August 13, 2003
CAP034829, PRA Model Has Non-Conservative Value for SW Strainer Plugging,
August 13, 2003
CAP034830, CC System Licensing Basis Not Well Documented and/or Ambiguous,
August 13, 2003
CAP034865, FSAR (06/03) Table 9.1-1 Was Not Updated to Reflect Current Design
Information, August 14, 2003
CAP034916, 2Z104b Is Obsolete, August 15, 2003
CAP034923, Zurn Strainer Failures, August 16, 2003
CAP034962, Shear Pin Material Concerns With the 3 and 6 Zurn Strainers, August 19, 2003
CAP034982, Parts No Longer Available for Zurn Strainers, August 19, 2003
CAP035026, SFP [Spent Fuel Pool] HX Safety Classification Change, August 20, 2003
CAP035030, CCW HX Cleaning Delays & Issues Related to HX Cleaning, August 20, 2003
CAP035031, SW Zurn Strainer Blowdown Drainline Backflow, August 20, 2003
CAP035046, Discrepancies Noted During Component Cooling Water Walkdown,
35 Attachment
August 21, 2003
CAP035073, Cause of CCW Pipe Crack Not Evaluated Under CAP030312, August 22, 2003
CAP035087, Calculation 0087-00027-005 Weakness, August 22, 2003
CAP035093, Procedure Enhancements to CC Operating Procedures, August 23, 2003
CAP049694, Engineering System Assessment Open Questions - Zurn SW Strainers,
August 27, 2003
CAP049695, Engineering System Assessment Open Questions, August 27, 2003
CAP049735, PBNP May Not Have Notified NRC Re: Completion of CCW Safety-related
Upgrade, August 29, 2003
CAP049751, Items to Consider Prior to Upgrading Main SW Zurn Strainers to Safety Related,
August 29, 2003
CAP049752, Ensure Service Water Operating Procedures are Complete and Consistent,
August 29, 2003
CAP049812, Potential Improvements for AOP-9A, September 3, 2003
CAP049829, OI-70 Procedure Adequacy, September 3, 2003
CAP049832, Supporting Design Basis Documents for CWPH HVAC System Marginally
Acceptable, September 4, 2003
CAP049860, Q-List Classification of Identified RHR Components Need to be Re-evaluated,
September 4, 2003
CAP049867, Apparent Mismatch in CCW Appendix R Commitment, September 4, 2003
CAP049873, Items to Consider Prior to Upgrading Main SW Zurn Strainers to Safety Related,
September 4, 2003
CAP050070, CCW Test Protocol Update Needed, September 10, 2003
CAP050116, GL 89-13 Related Callups Are Not Identified as NRC Commitments in CHAMPS,
September 11, 2003
CAP050133, Procedural Clarifications Recommended for Spare CC Pump Motor,
September 12, 2003
CAP050168, PM Item 2CC-00721D, Replace Relief Valve Not Completed By Its 125 percent of
Due Date, September 15, 2003
CAP050171, Calculation N-93-058 Contains an Inappropriate Assumption, September 15, 2003
36 Attachment
CAP050173, NRC Required Programs May Not Fully Implement Commitments,
September 15, 2003
CAP050192, EOP Setpoint Basis Document for V.14 and V.35 Is Not Accurate,
September 15, 2003
CAP050229, Relief Set Point Changed on 1&2CC-736A&B Without Considering MOV Design
Basis, September 17, 2003
CAP050258, Multiple Drawing Errors Discovered During Creation of Calculation 2003-0006,
September 17, 2003
CAP050276, Lot Number for Spare CCW Motor in Procedure RMP 9006-4 Incorrect,
September 18, 2003
CAP050284, Appendix R Discussion in Section 2.2.3 of DBD-02 Is Not Accurate,
September 18, 2003
CAP050340, Determine Safety Function of Component Cooling Water System Manual Valves,
September 22, 2003
CAP050350, Perform New Review of AFW System to Support Recirc AOV Safety Function
Upgrade, September 23, 2003
CAP050367, 50.59 Screening for CC Relief Valve Setpoint Change Inadequately Documented,
September 23, 2003
CAP050388, EOPSTPT L.3 and L.13 Existing Values Are Non-Conservative,
September 24, 2003
CAP050398, Remove Reference to Second Spare CCW Pump Motor for Appendix R Use,
September 24, 2003
CAP050405, CCW Licensing Basis, September 24, 2003
CAP050420, Procedure Feedback Request Concern, September 25, 2003
CAP050429, EOP Setpoint Calculations Recommendation, September 25, 2003
CAP050456, Establishment of Appendix R Backup Air For Charging Pumps May Be Hot
Shutdown Repair, September 26, 2003
CAP050499, Emergency Procedure Conflicts Not Yet Corrected, September 29, 2003
CAP050502, Local Manual Operation of MOVs and Manual Valves Not in IST Program,
September 29, 2003
CAP050509, Incorrect Closure of CAP032355, September 29, 2003
37 Attachment
CAP050511, Fire Operating Procedure FOP 1.2 Not Updated in a Timely Fashion,
September 29, 2003
CAP050515, OPR 49, Part II Deficiency, September 29, 2003
CAP050538, Corrective Action Not Fully Completed, September 30, 2003
CAP051530, Non QA Worm and Worm Gear Used in QA Application for Limitorque Operator
SMB-00, October 29, 2003
CE005825, Potential Overstress Piping and Supports During Post-LOCA Recirculation,
June 30, 1998
CE010497, SSDI Question #43, EOP 1.3 Manual CC Valves, August 6, 2002
CE010524, EOP Issues Identified During 2002 SSDI, August 12, 2002
CE011207, Adequacy of Comp Measure to Start/Stop AFW Pumps While Running on Service
Water, February 18, 2003
CE011789, Determine Current LBB Analysis of Record For PBNP, June 18, 2003
EWR026103, Calc of Cont Spray Duration Does Not Consider No Auto Initiation of Cont Spray,
August 16, 2002
OTH029041, SSDI Question #43, EOP 1.3 Manual CC Valves, April 8, 2003
OTH032467, Compilation of CC System Inadvertent Relief Valve Lifting Evaluations,
August 1, 2003
OTH033040, Take to ORC - SFP HX Safety Classification Change, August 22, 2003
Drawings
110E018, P&ID Auxiliary Coolant System, Sheet 1, Revision 57
PB-01-M-CCK-000-001, P&ID Auxiliary Coolant System, Revision 40
PB-01-M-CCK-000-004, P&ID Auxiliary Coolant System, Revision 21
PB-01-M-SFK-000-002, P&ID Auxiliary Coolant System, Revision 59
PB-02-M-SFK-000-001, P&ID Auxiliary Coolant System, Revision 50
PB-02-M-SFK-000-003, P&ID Auxiliary Coolant System, Revision 43
PB-02-M-SFK-000-004, P&ID Auxiliary Coolant System, Revision 17
PB-31-M-WHK-000-001, P&ID Radwaste Component Cooling Water, Revision 13
38 Attachment
Operability Determination CR 99-1972, Radwaste CC Isolation Valves CC-LW-63/64 Quick
Closure On Break in Radwaste System, August 17, 1999
Operability Recommendation OPR 000024, Potential for Draining the RWST to Containment
During a DBA LOCA, August 2, 2002
OPR 000025, Calc of Cont Spray Duration Does Not Consider No Auto Initiation of Cont Spray,
August 9, 2002
OPR 000040, Point Beach AFW Pump Failure in 1974 After Unintentionally Pumping Service
Water, January 28, 2003
OPR 000072, Determine Current LBB Analysis of Record for PBNP, August 1, 2003
OPR 000073, Interface Between Shaft and Lever Damaged on 2CC-130, August 8, 2003
OPR, Component Cooling Water System Manual Valves Listed in Attachment A of Unit 1 and 2
EOPs 1.3 and 1.4 (Transfer to Containment Sump Recirculation), September 24, 2003
Procedures
AOP-9B, Unit 2, Component Cooling System Malfunction, May 8, 2000
AOP-10B, Unit 1, Safe to Cold Shutdown in Local Control, August 7, 2003
Design & Installation Guidelines Manual DG-101, Instrument Setpoint Methodology,
October 12, 2001
EOP-1.3, Unit 1, Transfer to Containment Sump Recirculation - Low Head Injection,
December 5, 2002
EOP-1.4, Unit 1, Transfer to Containment Sump Recirculation - High Head Injection,
December 5, 2002
ICP 6.15, Auxiliary Coolant System (Non-Outage), Data Sheet 19, Revision 27
Inservice Test IT 12, Component Cooling Water Pumps and Valves (Quarterly) Unit 1,
April 18, 2002
IT 12A, CC Pumps and Valves While Aligned for RHR Operation (Cold Shutdown) Unit 1,
Revisions 5 and 9
IT 13, Component Cooling Water Pumps and Valves (Quarterly) Unit 2, April 22, 2002
IT 13A, CC Pumps and Valves While Aligned for RHR Operation (Cold Shutdown) Unit 2,
39 Attachment
Revisions 2 and 13
Operating Instructions OI 62A, Motor-Driven Auxiliary Feedwater System (P-38A & P-38B),
April 7, 2003
OI 62B, Turbine-Driven Auxiliary Feedwater System (P-29), April 7, 2003
OI 151, HX-012C & D Component Cooling System Heat Exchanger Data Collection Unit 2,
May 5, 2003
OI 152, HX-012A & B Component Cooling System Heat Exchanger Data Collection Unit 1,
May 5, 2003
Operations Refueling Test (ORT) 11, CVCS and CC Systems Check Valve Stroke Test Unit 1
(Refueling), May 15, 2003
ORT 68, Component Cooling Water To and From 2P-1A Refueling Shutdown - Unit 2,
April 30, 2002
ORT 68, Component Cooling Water To and From 2P-1A Refueling Shutdown - Unit 1,
August 26, 2002
ORT 69, Component Cooling Water To and From 2P-1B Refueling Shutdown - Unit 1,
September 5, 2002
Periodic Check PC 43, Part 3, Service Water System Stainers and Flushing, Revision 27
NP 1.4.2, Permanent Drawing System, Revision 4
NP 5.3.7, Operability Determinations (OD), September 10, 2003
NP 8.4.8, Requirements for Scaffold Near Safety Related Equipment, January 29, 2003
RMP 9006-4, Component Cooling Water Pump Motor Emergency Replacement, June 12, 2002
System Operating Procedure 0-SOP-SW-101, South Service Water Supply Header Isolation
and Restoration, September 19, 2002
System Operating Procedure 1-SOP-CC-001, Component Cooling System, June 12, 2003
System Operating Procedure 2-SOP-CC-001, Component Cooling System, June 12, 2003
System Operating Procedure 1-SOP-CC-002, Component Cooling System Drain and Refill,
July 14, 2003
System Operating Procedure 2-SOP-CC-002, Component Cooling System Drain and Refill,
July 14, 2003
Work Orders
40 Attachment
WO 86-114A, Check Valve Will Not Seat Properly, January 1, 1986
WO 860910, Failed ORT Cut Out and Replace, October 4, 1986
WO 871475, Replace Check Valve Perform an ORT Leak Check on New Check Valve Before
Installing, April 17, 1987
WO 881532, Check Valve Leaked by During ORT-68 @ 122 lpm @ 42 psig, April 14, 1988
WO 881954, Valves of this Type Have History of Failing Leak Rate Tests - Replace,
May 10, 1988
WO 911677, During the Performance of ORT-11 Check Valve Stroke Test, the Valve
Demonstrated Gross Leakage, April 11, 1991
WO 9714608, During the Performance of ORT-11 Check Valve Has Gross Leakage as
Identified in IT-255, November 29, 1997
10 CFR 50.59 Evaluations
SER 93-071, Change to CCW System Configuration for Normal Operation, August 31, 1993
SE 2001-0007, Component Cooling Water System Closed Loop Inside Containment,
February 24, 2001
Other Documents
Assessment of Potential Vulnerabilities for License Renewal, Martin/Sigmon Consulting
Services Inc., March 2003
CCW GL 89-13 Performance Testing Results for HX-012A/B/C/D, December 1998 -
September 2002
DBD-02, Component Cooling Water System Design Basis Document, June 20, 2003
DBD Validation Procedure, June 2003
EOP Setpoint Document EOPSTPT L.3, Flows (LHSI B Train), March 25, 1992
EOP Setpoint Document EOPSTPT L.7, Flows (LHSI), March 25, 1992
EOP Setpoint Document EOPSTPT L.8, Flows (RHR Recirculation), July 1, 1985
EOP Setpoint Document EOPSTPT L.13, Flows (LHSI A Train), March 25, 1992
EOP Setpoint Document EOPSTPT V.14, Misc (CC HX D/P), November 29, 1994
EOP Setpoint Document EOPSTPT V.35, Misc (CC HX D/P), November 29, 1994
41 Attachment
FSAR Figure 5.2-15, Component Cooling Water to Reactor Coolant Pump, June 2002
FSAR Figure 5.2-16, Component Cooling Water to Reactor Coolant Pump, June 2002
FSAR Figure 5.2-17, Component Cooling Water from Reactor Coolant Pump, June 2002
FSAR Figure 5.2-18, Component Cooling Water from Reactor Coolant Pump, June 2002
FSAR Figure 5.2-19, Component Cooling Water to Excess Letdown Heat Exchanger,
June 2002
FSAR Figure 5.2-20, Component Cooling Water from Excess Letdown Heat Exchanger,
June 2002
FSAR Section 9.1, Component Cooling Water (CC), June 2003
FSAR Table 5.2-1, Index of Containment Penetration Figures, June 2003
FSAR Table 9.1-1, Component Cooling System Component Data, June 2003
Heat Exchanger Visual Inspection Results for HX-012A/B/C/D, 2002-2003
I&C Calculation Update Program Project Plan, June 6, 2003
Licensing Basis Summary for Component Cooling Water System, September 8, 2003
LER 92-009-01, Component Cooling Water Surge Tank Vent Valves Outside Design Basis,
May 17, 1993
LER 96-009-00, Component Cooling Water System Outside Design Basis for Closed System
Outside Containment, October 14, 1996
Point Beach Letter, NRC-92-144, Classification of Auxiliary Systems Necessary to Assure Safe
Plant Shutdown at Point Beach Units 1 and 2, December 22, 1992
Point Beach Letter, NRC-93-074, Classification of Auxiliary Systems Necessary to Assure Safe
Plant Shutdown at Point Beach Units 1 and 2, June 17, 1993
Point Beach Letter, NPL 97-0401, Component Cooling Water System Issues Update - Point
Beach Units 1 and 2, July 7, 1997
Point Beach Letter, NRC 2003-0065, PBNP Excellence Plan, July 18, 2003
Point Beach Self-Assessment Report, Component Cooling (CC) Water System Self-
Assessment, PBSA-ENG-03-02, September 8, 2003
Point Beach Service Water ISI, Radiography Schedule, Emergency Diesel Generator Coolant
42 Attachment
Heat Exchanger G01 & G02 Cross Tie Supply Lines, 2nd Quarter 2000
Probabilistic Safety Assessment Section 4.11, Component Cooling Water System Notebook,
Revision 0
Program Document, GL 89-13, Revision 2
S-A-ENG-99-007, Component Cooling Water System Safety System Engineering Inspection,
July 26 to September 24, 1999
S-A-ENG-99-007, Engineering Work Request, June 23, 2000
Safety Evaluation Related to Amendment Nos. 174 and 178, July 9, 1997
Safety Evaluation Related to Exemption from Section III.G of 10 CFR Part 50, Appendix R, not
dated
Safety Evaluation Related to Exemption from Appendix R to CFR Part 50, December 31, 1986
Surveillance Test Trending Data - Vibration and Differential Pressure, CCW Pumps 1P11A/B
and 2P11A/B, 2001-2003
System Health Report, Component Cooling Water System (CCW), 2003
System Health Report, Service Water (SW), July 31, 2003
Technical Specification Basis B 3.6.3, Containment Isolation Valves, Unit 1 - Amendment
No. 201, Unit 2 - Amendment No. 206
Technical Specification 3.7.7, Component Cooling Water (CC) System
Training Lesson Plan LP0084, Component Cooling Water, Revision 10
Westinghouse Letter WEP-98-017, Containment Pressure and Temperature Increase During
Recirculation Due to the Loss of RHR Heat Exchanger Cooling, March 5, 1998
Westinghouse Specification Sheet, Auxiliary Relief Valves 1-RV-763A and 1-RV-763B,
May 17, 1968
Maintenance Work Control
ESG 5.1, PRA Maintenance Update Guideline, Revision 2
PRA 4.0, Data Analysis Notebook, Revision 0
Weekly Core Damage Risk Profile (Safety Monitor), August 24, 2003
43 Attachment
Weekly Core Damage Risk Profile (Safety Monitor), July 27, 2003
NP 1.1.7, Managing Work Activity Risk, Revision 2
NP 2.1.4, Operator Workarounds, October 16, 2002
NP 10.2.2, Scheduling, Planning and Implementing On-Line Work, July 30, 2003
NP 10.3.7, On-Line Safety Assessment, October 16, 2002
Safety Monitor Calculation, September 10, 2003, 23:14
PBSA-ENG-03-02, Component Cooling System Self-Assessment, Revision 3, Section 3.03.f.3
Operator Work Around Summary, September 10, 2003
Operable but Degraded Excel Spreadsheet, September 9, 2003
Modification In-Progress (Installing or Testing) Spreadsheet, September 18, 2003
Plan of the Day, PRA Aggregate Impact, September 9, 2003
Plan of the Day, Temporary Modifications Aggregate Impact, September 9, 2003
Plan of the Day, LIT Annunciator Aggregate Impact, September 9, 2003
Plan of the Day, Control Board Deficiencies Aggregate Impact, September 9, 2003
Nuenergy, Inc. AFW SSFA Report, July 23, 2003
CCW Basic Events Ranked by RAW, Point Beach PRA Model, Unit 1, Revision 3.03
CCW Basic Events Ranked by Fussell-Vesely Importance, Point Beach PRA Model,
Unit 1,Revision 3.03
EDG Failure Events, Point Beach PRA Model, Revision 3
PSA Component Cooling Water System Notebook, Revision 0
PRA 5.6, 125Vdc Electric Power Notebook, Revision 0
PRA 5.9, Auxiliary Feedwater System Notebook, Revision 0
Corrective Action Program Documents
CAP000195, Action Plan for GL 89-13 (SW) Needed, May 17, 2000
CAP001870, 2P-11A CCW Pump Post Maintenance Testing Change, January 15, 2002
CAP003216, Potential to Dead-Head CC Pumps Not Evaluated, May 7, 2002
44 Attachment
CAP005473, Component Cooling Heat Exchanger, August 15, 2001
CAP005667, Component Cooling Water (CCW) Surge Tank Level Transmitter Concerns,
November 11, 2001
CAP012480, Conflicting Information on Required Valve Position (Valve 2CC-748A),
August 11, 2000
CAP012797, Component Cooling (CC) Supply to Containment Failed Stroke Test,
October 16, 2000
CAP022794, CCW Heat Exchanger Cleaning Compliance With GL 89-13, May 7, 2001
CAP026926, CCW Pump Vibration, February 15, 2001
CAP028467, Inappropriate Value for CCW Flow to CCW HX Used in Calculation,
June 13, 2002
CAP029510, 1P-11A CC Pump Operated at Above Max Flow for Continuous Operation,
September 24, 2002
CAP031299, IPC Risk Ranking May Overlook Risks Related to Slowly Developing Problems,
February 24, 2003
CAP031726, Unit 2 CC System Temperature Exceeds 105 Degrees F for Two Minutes,
March 20, 2003
CAP032409, Engineering Evaluation for CC HX Tube Plugging Limit Did Not Address Increase
in Velocity, April 23, 2003
CAP033104, GL 89-13 Action Plan Item in OPS Procedure Feedback Backlog for 2 Years,
May 27, 2003
CAP033467, Unexpected U-2 CCW Surge Tank Level Hi Alarm, June 10, 2003
CAP034548, Calculation Weaknesses in Calculation N-94-064 Rev. 3, August 4, 2003
CAP034608, Conflicting Drawings, Procedures, and Operability Status of 1(2)RC-508,
August 6, 2003
CAP034716, CC Header Temperature Design Basis Clarification, August 8, 2003
CAP034720, OI-151 Acceptance Criteria Deficiency, August 8, 2003
CAP034826, Maintenance Rule PRA Calculation Not Completed, August 13, 2003
CAP035026, SFP HX Safety Classification Change, August 20, 2003
CAP050029, Temporary Fire Seal Design Used for Permanent Seal Closure,
45 Attachment
September 9, 2003
CAP050038, Safety Monitor and Maintenance Rule (a)(1) Systems, September 10, 2003
CAP050042, Design Guidance Use for PRA Activities Requires Review, September 10, 2003
CAP050044, Configuration Risk Management Process and Safety Monitor,
September 10, 2003
CAP050048, PRA Review of Proposed Modifications, September 10, 2003
CAP050066, Error in PRA Model for Unit 2 Main Feedwater, September 10, 2003
CAP050093, Appendix R Spare CC Equipment Storage Improvement, September 11, 2003
CAP050094, 2P-11A CCW Pump Is Losing Excessive Amounts of Oil on Its Outboard Pump
Bearing, September 11, 2003
CAP050117, Inadequate Administrative Controls on Appendix R Equipment Temporary
Storage, September 11, 2003
CAP050404, Concerns With Closure of OPR 00040 Rev 1 (AFW Pump Silting Due to SW
Debris), September 24, 2003
CAP050465, Operator Workaround Program Improvement, September 27, 2003
CAP050523, Certain Appendix R Fires May Challenge Operator Response,
September 29, 2003
CAP050641, MOB 406 Labeled as Spare in Master Data Book in WCC [Work Control Center],
October 2, 2003
Log Number 2002-19, PRA Model Review and Change Form, September 11, 2002
Log Number 2003-22, PRA Model Review and Change Form, September 25, 2003
OD Review Team Charter, September 28, 2003
AFW Procedure/Surveillances Charter, September 27, 2003
AFW CAP Evaluation Team Charter
AFW Assessments Area Team Charter, October 1, 2003
AFW Work Order Review Charter
Improved Tech Specifications Team Charter, September 27, 2003
Appendix R Team Charter
46 Attachment
Other Documents
Calculation 2000-0004, Required Seal Thickness of Kaowool Used in Temporary Fire
Penetration Seals, January 25, 2000
47 Attachment
LIST OF ACRONYMS USED
AC Alternating Current
ACE Apparent Cause Evaluation
amp Ampere
ANS Alert and Notification System
AOP Abnormal Operating Procedure
AOV Air-Operated Valve
ATC American Transmission Company
AV Apparent Violation
CA Corrective Action
CAP Corrective Action Program Problem Identification Document
CATPR Corrective Action to Prevent Recurrence
CARB Corrective Action Review Board
CC Component Cooling (Water)
CCW Component Cooling Water
CDF Change in Core Damage Frequency
CE Condition Evaluation
CLB Current Licensing Basis
CR Condition Report (the former Corrective Action Program Problem
Identification Document)
CSP Critical Safety Procedure
CST Condensate Storage Tank
DBD Design Basis Document
DC Direct Current
DEP Drill and Exercise Performance
DRB Design Review Board
DRP Division of Reactor Projects
DRS Division of Reactor Safety
EAL Emergency Action Level
ECA Emergency Contingency Action
ECP Employee Concerns Program
EDG Emergency Diesel Generator
EFR Effectiveness Review
ENS Emergency Notification System
EOF Emergency Operations Facility
EOP Emergency Operating Procedure
EOPSTPT EOP Setpoint Basis Document
EP Emergency Preparedness/Emergency Planning
EPAC Emergency Preparedness Advisory Committee
EPIP Emergency Plan Implementing Procedure
EPMP Emergency Plan Maintenance Procedure
EPZ Emergency Planning Zone
EQ Environmental Qualification
ERO Emergency Response Organization
FEMA Federal Emergency Management Agency
FME Foreign Material Exclusion
48 Attachment
FSAR Final Safety Analysis Report
GE General Emergency
GL NRC Generic Letter
gpm Gallons Per Minute
HELB High-Energy Line Break
HEP Human Error Probability
HVAC Heating, Ventilation, and Air Conditioning
HX Heat Exchanger
IA Instrument Air
I&C Instrument and Control
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Inspection Report
ISI Inservice Inspection
IST Inservice Testing
IT Inservice Test
JPIC Joint Public Information Center
kV Kilovolt(s)
kVA Kilovolt-ampere
LER Licensee Event Report
LCO Limiting Condition for Operation
LOCA Loss-of-Coolant Accident
LLOCA Large-Break Loss-of-Coolant Accident
LOA Letter of Agreement
LOIA Loss of Instrument Air
LOOP Loss of Offsite Power
LOR Licensed Operator Requalification
MC Manual Chapter
MDAFW Motor-Driven Auxiliary Feedwater
MOV Motor-Operated Valve
MR Plant Modification
MRE Maintenance Rule Evaluation
NEI Nuclear Energy Institute
NMC Nuclear Management Company, LLC
NOS Nuclear Oversight (Quality Assurance)
NOUE Notification of Unusual Event
NP Nuclear Plant Business Unit Procedure
NPM Point Beach Memorandum
NRC Nuclear Regulatory Commission
ODI Old Design Issue
OE Operating Experience
OI Operating Instructions
OM Operations Manual
OP Operating Procedure
OPR Operability Request
OTH Other (corrective action program document)
PAB Primary Auxiliary Building
PAR Protective Action Recommendation
49 Attachment
PARS Publicly Available Records System
PBNP Point Beach Nuclear Plant
PCP Power Conversion Products
PI Performance Indicator
P&ID Piping and Instrumentation Diagram
PRA Probabilistic Risk Assessment
psig Pounds Per Square Inch - Gauge
QRT Quality Review Team
RCE Root Cause Evaluation
RSPS Risk Significant Planning Standard
SAE Site Area Emergency
SBCC Site Boundary Control Center
SDP Significance Determination Process
SER Safety Evaluation Report
SEM Scanning Electron Microscopy
SEN Significant Event Notice
SGTR Steam Generator Tube Rupture
SPEED Spare Parts Equivalency Evaluation Document
SR Surveillance Requirement
SS Safety Screening
SSFA Safety System Functional Assessment
TDAFW Turbine-Driven Auxiliary Feedwater
TPCS Transients Without Power Conversion System
TRANS Transients
TS Technical Specification
UAT Unit Auxiliary Transformer
URI Unresolved Item
V Volt(s)
Vac Volt(s) Alternating Current
VDC Volt(s) Direct Current
VIO Violation
50 Attachment