ML033040217
| ML033040217 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 10/30/2003 |
| From: | Reynolds S Division Reactor Projects II |
| To: | Kanda W FirstEnergy Nuclear Operating Co |
| References | |
| EA-03-194, EA-03-197 IR-03-006 | |
| Download: ML033040217 (49) | |
See also: IR 05000440/2003006
Text
October 30, 2003
EA 03-194
EA 03-197
Mr. William R. Kanda
Vice President - Nuclear, Perry
FirstEnergy Nuclear Operating Company
P. O. Box 97, A210
10 Center Road
Perry, OH 44081
SUBJECT:
PERRY NUCLEAR POWER PLANT
NRC INTEGRATED INSPECTION REPORT 05000440/2003006
Dear Mr. Kanda:
On September 30, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection
findings which were discussed on October 2, 2003, with you and other members of your staff.
We also discussed the two issues that appear to have low to moderate safety significance with
you and your staff in separate additional conference calls on October 20, 2003, for the
Emergency Preparedness issue, and October 27, 2003, for the emergency service water issue.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
This report discusses two findings that appear to have a low to moderate safety significance.
The first finding, as described in Section 4OA5.1 of this report, relates to the failure of your
Division 1 emergency service water (ESW) pump on September 1, 2003. This finding did
present an immediate safety concern. However, the preliminary cause of the failure was
promptly identified and the pump was repaired and returned to service on September 5, 2003.
This finding was assessed using the NRC Phase 3 Significance Determination Process and
was preliminarily determined to be White, i.e., a finding with some increased importance to
safety, which may require additional NRC inspection. This finding was also determined to be
an apparent violation of NRC requirements. Specifically, the apparent violation involved the
failure to implement adequate procedures for ESW pump reassembly in that licensee
procedure GMI-0039, Disassembly of the Emergency Service Water Pumps, failed to
completely incorporate the manufacturers instructions for reassembly of the pump shaft
couplings. As a result, at least two of the couplings for the Division 1 ESW pump had
insufficient engagement between the key and coupling sleeve. Your staffs investigation
concluded that the pump shaft coupling failed due to insufficient engagement of the key
between the coupling and the shaft.
W. Kanda
-2-
The second finding, as described in Section 4OA5.2 of this report, relates to an ALERT level
event on April 24, 2003, in which undue delay in declaring the actual emergency condition was
incurred when a shift manager did not follow the emergency classification and action level
scheme as required by your emergency plan. This finding was assessed using the Emergency
Preparedness Significance Determination Process and was preliminarily determined to be
White, i.e., a finding with some increased importance to safety, which may require additional
NRC inspection. This finding was also determined to be an apparent violation of NRC
requirements. Specifically, the apparent violation involved the failure to follow Emergency Plan
Instruction EPI-A1, Emergency Action Levels, which delineates licensee emergency response
responsibilities in accordance with 10 CFR 50.47(b)(2), as well as the emergency action level
scheme in accordance with 10 CFR 50.47(b)(4). These requirements were not met during the
April 24, 2003, ALERT in that, the shift manager did not perform his responsibility to assume
the duties of Emergency Coordinator and assess, identify, and classify the event in a timely
manner.
The apparent violations of NRC requirements are being considered for escalated enforcement
action in accordance with the "General Statement of Policy and Procedures for NRC
Enforcement Actions" (Enforcement Policy), NUREG-1600. The current Enforcement Policy is
included on the NRCs website at www.nrc.gov.
We believe that sufficient information was considered to make the preliminary significance
determinations. However, before we make a final decision on these issues, we are providing
you an opportunity to present to the NRC your perspectives on the facts and assumptions used
by the NRC to arrive at the findings and their significance at a Regulatory Conference or by a
written submittal. If you choose to request a Regulatory Conference, it should be held within
30 days of the receipt of this letter and we encourage you to submit supporting documentation
at least one week prior to the conference in an effort to make the conference more efficient and
effective. If a Regulatory Conference is held, it will be open for public observation. If you
decide to submit only a written response, such submittal should be sent to the NRC within
30 days of the receipt of this letter.
Please contact Mark A. Ring at 630-829-9703 within 10 business days of your receipt of this
letter to notify the NRC of your intentions with respect to the Division 1 ESW pump issue.
Please contact Kenneth Riemer of the Division of Reactor Safety, Plant Support Branch, at
630-829-9757 within 10 business days of your receipt of this letter to notify the NRC of your
intentions with respect to the emergency preparedness issue. If we have not heard from you
within 10 days, we will continue with our significance determinations and enforcement decisions
and you will be advised by separate correspondence of the results of our deliberations on these
matters.
Since the NRC has not made final determinations in these matters, no Notices of Violation are
being issued for these inspection findings at this time. In addition, please be advised that the
number and characterization of apparent violations described in the enclosed inspection report
may change as a result of further NRC review.
W. Kanda
-3-
This report also documents two NRC-identified findings of very low safety significance (Green).
One of the findings was determined to involve a violation of NRC requirements. However,
because of its very low safety significance and because it has been entered into your corrective
action program, the NRC is treating this finding as a Non-Cited Violation in accordance with
Section VI.A.1 of the NRCs Enforcement Policy.
If you contest the subject or severity of a Non-Cited Violation, 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 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 Resident
Inspector Office at the Perry Nuclear Power Plant.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter
and its enclosure will be available electronically for public inspection in the NRC Public
Document Room or from the Publicly Available Records (PARS) component of NRC's
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 by Patrick L. Hiland Acting for/
Steven A. Reynolds, Acting Division Director
Division of Reactor Projects
Docket No. 50-440
License No. NPF-58
Enclosure:
Inspection Report 05000440/2003006
w/Attachment: Supplemental Information
See Attached Distribution
DOCUMENT NAME: G:\\ML033040217.wpd
To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy
OFFICE
RIII
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NAME
MRing for
RLerch/trn
MRing
KRiemer
KLambert for
BClayton
PHiland
SReynolds
DATE
10/29/03
10/29/03
10/30/03
10/30/03
10/30/03
OFFICIAL RECORD COPY
W. Kanda
-4-
cc w/encl:
G. Leidich, President - FENOC
K. Cimorelli, Acting Director,
Maintenance Department
V. Higaki, Manager, Regulatory Affairs
J. Messina, Director, Nuclear
Services Department
T. Lentz, Director, Nuclear
Engineering Department
T. Rausch, Plant Manager,
Nuclear Power Plant Department
Public Utilities Commission of Ohio
Ohio State Liaison Officer
R. Owen, Ohio Department of Health
W. Kanda
-5-
ADAMS Distribution:
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C. Ariano (hard copy)
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No:
50-440
License No:
Report No:
Licensee:
FirstEnergy Nuclear Operating Company (FENOC)
Facility:
Perry Nuclear Power Plant, Unit 1
Location:
P.O. Box 97 A200
Perry, OH 44081
Dates:
July 1 through September 30, 2003
Inspectors:
R. Powell, Senior Resident Inspector
J. Ellegood, Resident Inspector
S. Campbell, Senior Resident Inspector, Fermi
J. House, Senior Radiation Specialist
R. Jickling, Emergency Preparedness Analyst
B. Winter, Regional Inspector
Approved by:
Mark A. Ring, Chief
Branch 1
Division of Reactor Projects
TABLE OF CONTENTS
SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.
REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R04
Equipment Alignment (71111.04) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1R05
Fire Protection (71111.05) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
1R06
Flood Protection Measures (71111.06) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R11
Licensed Operator Requalification (71111.11) . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R12
Maintenance Effectiveness (71111.12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13) . . . . . 8
1R14
Operator Performance During Non-Routine Evolutions and Events (71111.14)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
1R15
Operability Evaluations (71111.15) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R16
Operator Workarounds (71111.16) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
1R19
Post-Maintenance Testing (71111.19) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R20
Refueling and Outage Activities (71111.20) . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
1R22
Surveillance Testing (71111.22) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
1R23
Temporary Plant Modifications (71111.23) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.
RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2OS1 Access Control to Radiologically Significant Areas (71121.01) . . . . . . . . . . . . 13
2OS2 As Low As Is Reasonably Achievable Planning And Controls (71121.02) . . . . 13
2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03) . . 14
2PS2
Radioactive Material Processing and Transportation (71122.02) . . . . . . . . . . . 15
4.
OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
4OA1 Performance Indicator Verification (71151) . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
4OA2 Identification and Resolution of Problems (71152) . . . . . . . . . . . . . . . . . . . . . . 18
4OA3 Event Followup (71153) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
4OA6 Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
KEY POINTS OF CONTACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
LIST OF DOCUMENTS REVIEWED
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
LIST OF ACRONYMS USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1
SUMMARY OF FINDINGS
IR 05000440/2003006; 07/01/2003 - 09/30/2003; Perry Nuclear Power Plant; Fire Protection;
Maintenance Effectiveness; Other Activities.
The report covered a 3-month period of baseline resident inspection, an announced baseline
inspection on radiation protection, and followup inspection activities on emergency
preparedness. The inspection was conducted by Region III inspectors and the resident
inspectors. This inspection identified two preliminary White findings and associated apparent
violations (AVs), one Green Non-Cited Violation (NCV), and one Green finding (FIN). 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-Revealed Findings
Cornerstone: Mitigating Systems
To Be Determined. A self-revealed apparent violation of Technical Specification (TS) 5.4 occurred when the Division 1 emergency service water (ESW) pump failed
during routine pump operation. The licensee rebuilt the pump in 1997 and during
this reassembly, failed to properly reassemble the pump shaft connections. The
improper reassembly led to pump failure on September 1, 2003.
The NRC assessed this finding through Phase 3 of the Significance Determination
Process and made a preliminary determination that it is an issue with low to
moderate safety significance. (Section 4OA5.1)
Green. The inspectors identified a Non-Cited Violation of 10 CFR 50.65(a)(1) for the
failure of the licensee to monitor the performance of the rod control and information
system (RCIS) against licensee established goals. The licensee Maintenance Rule
expert panel approved re-categorization of the system function of manual rod
insertion to (a)(1) on November 6, 2002. As of September 25, 2003, the licensee
had failed to establish goals for system monitoring. The inspectors identified a
similar deficiency with five additional systems or system functions currently classified
as (a)(1) by the licensee.
This finding is greater than minor because it was associated with the mitigating
system cornerstone attribute of equipment reliability and affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. Although not
suited for Significance Determination Process review, the finding was determined to
be of very low safety significance in that the failure to establish goals and monitor
system performance in accordance with 10 CFR 50.65(a)(1) did not directly result in
additional system or function failures. (Section 1R12)
2
Green. The inspectors identified a finding of very low safety significance for the
failure of the licensee to promptly identify a degraded fire barrier between the
Division 3 and Division 2 Emergency Diesel Generator (EDG) rooms. The
inspectors observed that with the ventilation system operating as required for EDG
operations, the fire door separating the two rooms would not close without
assistance and thus, was an impairment or degradation of a fire protection feature.
This finding is greater than minor because it is associated with fire protection
equipment performance and degraded the ability to meet the cornerstone objective.
This issue had very low safety significance because the separation of redundant
trains of safe shutdown equipment was not compromised. (Section 1R05)
Cornerstone: Emergency Preparedness
To Be Determined. The inspectors identified an apparent violation having
preliminarily low to moderate safety significance when the licensee failed to follow
the requirements of the Perry Emergency Plan during an ALERT level event on
April 24, 2003. During this event, damage to irradiated fuel caused a high alarm on
the fuel handling building ventilation exhaust gaseous radiation monitor.
The finding was determined to be greater than minor because it affected the
Emergency Preparedness Cornerstone objective of implementing adequate
measures to protect the health and safety of the public in the event of a radiological
emergency. The finding was preliminarily determined to be of low to moderate
safety significance because the licensee failed to implement a risk significant
planning standard (10 CFR 50.47(b)(4)) during an actual Alert emergency.
(Section 4OA5.2)
B.
Licensee-Identified Violations
No findings of significance were identified.
3
REPORT DETAILS
Summary of Plant Status
The plant began the inspection period at 100 percent power and remained there except for
minor downpowers for rod line adjustments until August 14. At 4:10 p.m. on August 14, the
plant scrammed due to a loss of all offsite power. The plant declared an Unusual Event at
4:20 p.m. due to the loss of all offsite power. The plant subsequently exited the Unusual Event
after restoration of offsite power and initiation of shutdown cooling at 7:52 p.m. on August 15.
The plant entered Mode 4 at 1:20 a.m. on August 16. After completing restart readiness
activities, the plant entered Mode 2 at 1:50 a.m. on August 20, and reached criticality at
8:36 a.m. that same day. The plant synchronized to the grid at 1:23 a.m. on August 21, and
reached 100 percent power on August 23. On September 14, the plant reduced power to
20 percent to repair a hydraulic leak on a bypass valve and began a power ascension later that
day. During the downpower, the plant detected a leaking fuel pin which limited power to
90 percent until a rod line change could be performed. On September 18, the plant reduced
power to 58 percent to adjust the rod line. On September 19, the plant returned to 100 percent
power. On September 26, the plant reduced power to 67 percent to perform power suppression
testing in order to identify the leaking fuel pin. On September 29, the plant returned to
100 percent power.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04
Equipment Alignment (71111.04)
.1
Complete System Walkdown
a.
Inspection Scope
The inspectors performed a complete walkdown of accessible portions of the ESW
system to verify system operability during the week ending July 12. The ESW system
was selected due to its risk significance. The inspectors used ESW system valve lineup
instructions (VLIs) and system drawings to accomplish the inspection.
The inspectors observed selected switch and valve positions, electrical power
availability, component labeling, and general material condition. The inspectors also
reviewed open system engineering issues as identified in the licensees quarterly
system health reports, outstanding maintenance work requests, and a sampling of
licensee condition reports (CRs) to verify that problems and issues were identified, and
corrected, at an appropriate threshold. The documents used for the walkdown and
issue review are listed in the attached List of Documents Reviewed.
b.
Findings
No findings of significance were identified.
4
.2
Partial System Walkdowns
a.
Inspection Scope
The inspectors conducted partial walkdowns of the system trains listed below to verify
that the systems were correctly aligned to perform their designed safety function. The
inspectors used licensee VLIs and system drawings during the walkdowns. The
walkdowns included selected switch and valve position checks, and verification of
electrical power to critical components. Finally, the inspectors evaluated other
elements, such as material condition, housekeeping, and component labeling. The
documents used for the walkdowns are listed in the attached List of Documents
Reviewed. The inspectors reviewed the following three systems:
the high pressure core spray (HPCS) system, including the Division 3 EDG, on
August 11, during a planned reactor core isolation cooling (RCIC) system
maintenance outage;
the EDG support systems, on August 20, during a period of heightened attention to
electrical grid stability; and
the Division 2 and Division 3 switchgear, on September 5, during a Notice of
Enforcement Discretion (NOED) for an inoperable Division 1 ESW system.
b.
Findings
No findings of significance were identified.
1R05
Fire Protection (71111.05)
a.
Inspection Scope
The inspectors walked down the following 11 areas to assess the overall readiness of
fire protection equipment and barriers:
Fire Area 1AB-1f, HPCS Pump Room;
Fire Zone 1AB-2, Unit 1 Auxiliary Building, 599'-0";
Fire Zones 1AB-3a and 1AB-3b, Unit 1 Auxiliary Building - EL. 620'-6";
Fire Area 2CC-3, Units 1 and 2 Control Complex and Diesel Generator (DG)
Buildings Elev. 620'-6";
Fire Zone IB-1, Intermediate Building Elevation 574'-10";
Fire Zone IB-2, Intermediate Building Elevation 599'-0";
Fire Area 1DG-1a, Division 2 DG Room;
Fire Area 1CC-4, Control Complex Elevation 638'-6";
ESW pumphouse;
Fire Area 1CC-5, Control Complex Elevation 654'-6"; and
Fire Area CC-2, Control Complex Elevation 599'-0".
Emphasis was placed on the control of transient combustibles and ignition sources, the
material condition of fire protection equipment, and the material condition and
operational status of fire barriers used to prevent fire damage or propagation.
5
The inspectors looked at fire hoses, sprinklers, and portable fire extinguishers to verify
that they were installed at their designated locations, were in satisfactory physical
condition, and were unobstructed. The inspectors also evaluated the physical location
and condition of fire detection devices. Additionally, passive features such as fire doors,
fire dampers, and mechanical and electrical penetration seals were inspected to verify
that they were in good physical condition. The documents listed in the Supplemental
Information (attachment to this report) were used by the inspectors during the
assessment of this area.
b.
Findings
Introduction: The inspectors identified a finding of very low safety significance (Green)
for the failure of the licensee to promptly identify a degraded fire barrier between the
Division 3 and Division 2 EDG rooms. The finding was not considered a violation of
regulatory requirements. The inspectors observed that with the ventilation system
operating as required for EDG operations, the fire door separating the two rooms would
not close without assistance and thus, was an impairment or degradation of a fire
protection feature.
Description: On July 25, during operation of the Division 2 EDG, the inspectors noted
that the fire door separating the Division 2 and Division 3 EDGs required assistance to
close and latch. If assistance was not provided, the door remained open approximately
1 inch and air flow could be felt from the Division 2 EDG room. Although several
members of the licensee staff were present in the room, none of them identified the
failure to latch as a degradation of a fire barrier. After the inspectors notified the
licensee of the condition, the licensee declared the door impaired and initiated a
notification to repair the door. This door provided part of the fire barrier between the
Division 2 EDG, which was safe shutdown equipment, and the Division 3 EDG.
Subsequent to the inspectors identification of this issue, the licensee identified a similar
condition with respect to the Division 3 EDG hallway door. On August 27, the licensee
identified that the door would not close without assistance while the EDG was running.
The licensee tested the door from 90 degrees, 45 degrees, and 15 degrees and the
door failed each test.
Analysis: The inspectors noted several deficiencies with respect to licensee
performance. First, numerous members of the licensee staff were in the area, yet none
identified that the fire door did not operate as required. In addition, the door inspection
procedure did not require that door closure be verified with the most challenging
ventilation lineup. In this instance, the door would not perform its required function
during EDG operation even though the door functioned with the ventilation system in its
normal lineup.
The inspectors determined that the finding was more than minor using guidance in
Appendix B, of IMC 0612. Specifically, the inspectors concluded that the finding was
associated with fire protection equipment performance and degraded the ability to meet
the cornerstone objective since it was associated with the impairment or degradation of
a fire protection feature. This issue had very low safety significance (Green) because
the separation of redundant trains of safe shutdown equipment was not compromised.
6
Enforcement: Because fire barriers are not subject to the requirements of 10 CFR Part 50, Appendix B, no violation of regulatory requirements occurred. This finding
(FIN 05000440/2003006-01) was entered in the licensees corrective action system as
CR 03-04401.
1R06
Flood Protection Measures (71111.06)
a.
Inspection Scope
During the week ending August 9, the inspectors reviewed design basis and licensee
documentation concerning common mode flooding of the emergency core cooling
system (ECCS) equipment rooms. In selected pump rooms, the inspectors verified that
watertight doors and selected room penetrations were intact. Additionally, the
inspectors reviewed licensee maintenance procedures for door inspection and
maintenance against established vendor guidance. Finally, the inspectors reviewed
ECCS pump room sump level high alarm response instructions and verified that actions
prescribed in the procedure could reasonably be used to achieve the desired effects.
b.
Findings
No findings of significance were identified.
1R11
Licensed Operator Requalification (71111.11)
a.
Inspection Scope
The resident inspectors observed licensed operator performance in the plant simulator.
The inspectors evaluated crew performance in the areas of: clarity and formality of
communication; ability to take timely action in the safe direction; prioritizing, interpreting,
and verifying alarms; correct use and implementation of procedures, including alarm
response procedures; timely control board operation and manipulation, including
high-risk operator actions; and group dynamics. The inspectors also observed the
licensees evaluation of crew performance to verify that the training staff had observed
important performance deficiencies and specified appropriate remedial actions. The
inspectors observed the following two evaluated simulator scenarios:
operating crew #2 on September 10; and
operating crew #4 on September 24.
b.
Findings
No findings of significance were identified.
1R12
Maintenance Effectiveness (71111.12)
a.
Inspection Scope
The inspectors reviewed the licensee's implementation of the Maintenance Rule
requirements to verify that component and equipment failures were identified and
7
scoped within the Maintenance Rule and that select structures, systems, and
components (SSCs) were properly categorized and classified as (a)(1) or (a)(2) in
accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance
work orders, selected surveillance test procedures, and a sample of CRs to verify that
the licensee was identifying issues related to the Maintenance Rule at an appropriate
threshold and that corrective actions were appropriate. Additionally, the inspectors
reviewed the licensees performance criteria to verify that the criteria adequately
monitored equipment performance and to verify that licensee changes to performance
criteria were reflected in the licensees probabilistic risk assessment. During this
inspection period, the inspectors reviewed the following four areas:
safety-related instrument air, instrument air, and service air systems;
control room, battery room, and emergency closed cooling (ECC) pump area
ventilation systems;
direct current electrical systems; and
RCIS.
The problem identification and resolution CRs reviewed are listed in the attached List of
Documents Reviewed.
b.
Findings
Introduction: The inspectors identified an NCV of 10 CFR 50.65(a)(1) for the failure of
the licensee to monitor the performance of the RCIS against licensee established goals.
The licensee Maintenance Rule expert panel approved re-categorization of the system
function of manual rod insertion to (a)(1) on November 6, 2002. As of
September 25, 2003, the licensee had failed to establish goals for system monitoring.
The inspectors identified a similar deficiency with five additional systems or system
functions currently classified as (a)(1) by the licensee.
Description: On September 25, the inspectors attended a licensee maintenance rule
expert panel meeting. The meeting was the first such meeting conducted since
March 2003. Based on information presented at the meeting, subsequent record review,
and discussions with licensee personnel, the inspectors determined that the licensee had
not established performance monitoring goals for six systems which the licensee had
categorized as (a)(1). Specifically, as of September 25, performance monitoring goals
had not been established for:
Maintenance Rule function C11-02, manually insert control rods, despite the function
being categorized as (a)(1) on November 6, 2002;
Maintenance Rule function C11-00-PL, control rod drive forced loss rate due to scram
discharge volume valve rework, despite the function being categorized as (a)(1) on
December 23, 2002;
Maintenance Rule function C11-13, scram discharge vent and drain; despite the
function being categorized as (a)(1) on November 13, 2002;
Maintenance Rule function E22-00, HPCS pump failure to start in October 2002,
despite the function being categorized as (a)(1) on November 13, 2002;
Maintenance Rule function N32-02, reactor/turbine generator trip forced loss rate
criterion, despite the function being categorized as (a)(1) on November 13, 2002; and
8
Maintenance Rule function R51-01, plant party line page, despite the function being
categorized as (a)(1) on January 8, 2003.
Analysis: This finding is greater than minor because it was associated with the mitigating
system cornerstone attribute of equipment reliability and affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Although not suited for SDP
review, the finding was determined to be of very low safety significance in that the failure
to establish goals and monitor system performance in accordance with
10 CFR 50.65(a)(1) did not directly result in additional system or function failures.
Enforcement: 10 CFR 50.65(a)(1) requires in part that licensees shall monitor the
performance or condition of systems, structures, and components (SSCs) against
licensee established goals, in a manner sufficient to provide reasonable assurance that
such SSCs, as defined in 10 CFR 50.65(b), are capable of fulfilling their intended
functions. Further, (a)(1) requires that such goals shall be established commensurate
with safety and, where practical, take into account industry-wide operating experience.
When the performance or condition of a structure, system, or component does not meet
established goals, appropriate corrective action shall be taken.
Contrary to the above, the licensee failed to establish goals for the RCIS system after
categorizing the system as (a)(11) on November 6, 2002. The inspectors also identified
five additional examples of the licensees failure to establish performance monitoring
goals for systems or functions categorized as (a)(1). Because of the very low safety
significance and because the issue has been entered into the licensees corrective action
program, the issue is being treated as a NCV, consistent with Section VI.A.1 of the NRC
Enforcement Policy (NCV 05000440/2003006-02).
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13)
a.
Inspection Scope
The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration
control, and performance of maintenance associated with planned and emergent work
activities, to verify that scheduled and emergent work activities were adequately
managed. In particular, the inspectors reviewed the licensees program for conducting
maintenance risk assessments to verify that the licensees planning, risk management
tools, and the assessment and management of on-line risk and shutdown risk were
adequate. The inspectors also reviewed licensee actions to address increased on-line
risk when equipment was out of service for maintenance, such as establishing
compensatory actions, minimizing the duration of the activity, obtaining appropriate
management approval, and informing appropriate plant staff, to verify that the actions
were accomplished when on-line risk was increased due to maintenance on
risk-significant SSCs. The following seven assessments and/or activities were reviewed:
the maintenance risk assessment for the week of July 21, which was modified due to
an emergent issue with the Division 2 EDG, which resulted in an unplanned entry into
the Yellow risk category;
the risk assessment and work planning associated with the emergent maintenance
9
activities on regulating transformer 1R25-S0027 which powered essential 120 V bus
EB-1-B1 conducted August 2 and 3;
the maintenance risk assessment and work progression associated with a planned
RCIC outage conducted the week of August 11;
the shutdown risk associated with a forced outage resulting from loss of offsite power
(LOOP) on August 14;
the maintenance risk assessment for the week of August 25, which included entry
into an elevated risk profile due to planned testing of the Division 2 remote shutdown
functions;
the risk assessment and work planning associated with the failure of the Division 1
ESW pump; and
the maintenance risk assessment for the week of September 8, which included
planned motor driven feedpump maintenance, retesting of the Division 2 remote
shutdown functions, and Division 1 and 2 ECCS waterleg pump testing.
b.
Findings
No findings of significance were identified.
1R14
Operator Performance During Non-Routine Evolutions and Events (71111.14)
.1
Response to Alarms Received While Shifting Motor Control Center Power Supply
a.
Inspection Scope
On August 5, the licensee received unexpected fuel handling building radiation and
evacuation alarms and manhole 20 effluent monitor alarms coincident with shifting the
power supply for 480 V motor control center F1C08 from normal to emergency for
planned maintenance activities. The inspectors reviewed licensee immediate and
supplemental actions. Specifically, the inspectors verified the licensees actions were
consistent with operating instructions, alarm response instructions, and off-normal
instructions (ONIs).
b.
Findings
No findings of significance were identified.
.2
Waterleg Pump and Piping Venting Evolutions
a.
Inspection Scope
On the afternoon of September 11, and morning of September 12, the inspectors
observed performance of operations evolution orders designed to vent the low pressure
core spray (LPCS)/residual heat removal (RHR) A and RHR B/RHR C waterleg pumps
and associated system piping. The evolutions were conducted as part of a root cause
team investigation of the August 14 air binding of the LPCS/RHR A waterleg pump. The
inspectors reviewed the licensees work planning, observed the pre-job briefings, and
verified the actual work met licensee standards and expectations with respect to
procedure usage, crew communications, and work control.
10
b.
Findings
No findings of significance were identified.
1R15
Operability Evaluations (71111.15)
a.
Inspection Scope
The inspectors selected CRs related to potential operability issues for risk significant
components and systems. These CRs were evaluated to determine whether the
operability of the components and systems was justified. The inspectors compared the
operability and design criteria in the appropriate sections of the Technical Specifications
(TSs) and Updated Safety Analysis Report (USAR) to the licensees evaluations, to verify
that the components or systems were operable. Where compensatory measures were
required to maintain operability, the inspectors verified that the measures were in place,
would work as intended, and were properly controlled. Additionally, the inspectors
verified, where appropriate, compliance with bounding limitations associated with the
evaluations. The inspectors reviewed:
an operability determination of steam tunnel thermocouples due to ambiguities in
TS basis;
an operability determination on primary containment isolation valves outside their
qualified life;
an immediate investigation on non-conservatism in power to flow map stability
regions;
an operability determination on improper voltage to ground on a TOPAZ inverter;
an operability determination on water hammer in the LPCS water leg; and
an operability determination concerning common cause failure susceptibility of the
Division 3 ESW pump relative to the failure of the Division 1 ESW pump on
September 1.
b.
Findings
No findings of significance were identified.
1R16
Operator Workarounds (71111.16)
a.
Inspection Scope
The inspectors reviewed selected operator workarounds (OWAs) to determine whether
there was any impact on the operators ability to properly respond to plant transients and
accidents and to implement ONIs and plant emergency instructions in response to an
initiating event. The two OWAs reviewed were:
adjustments to maximum fraction limiting power density to account for errors in single
loop thermal limiting calculations performed by 3D Monicore; and
operator actions to reset the RCIC overspeed trip due to sympathetic tripping
following manual trips of the turbine.
11
b.
Findings
No findings of significance were identified.
1R19
Post-Maintenance Testing (71111.19)
a.
Inspection Scope
The inspectors evaluated the following post-maintenance testing (PMT) activities for risk
significant systems to assess the following (as applicable): the effect of testing on the
plant had been adequately addressed; testing was adequate for the maintenance
performed; acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate; tests were performed as written; and equipment was
returned to its operational status following testing. The inspectors evaluated the activities
against TSs, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various
NRC generic communications. In addition, the inspectors reviewed CRs associated with
PMT to determine if the licensee was identifying problems and entering them in the
corrective action program. The specific procedures reviewed are listed in the attached
List of Documents Reviewed. The following seven post-maintenance activities were
reviewed:
LPCS operation following breaker reinsertion on July 18;
Division 2 EDG testing following repairs to the motor operated controller on July 25;
breaker EH2104 testing after a cell switch adjustment completed on July 28;
regulating transformer 1R25-S0027 testing after a capacitor replacement completed
on August 3;
RCIC testing performed August 20 and 21 following planned system maintenance
activities and emergent work associated with the gland seal compressor;
Division 1 ESW pump testing following pump repairs conducted September 5; and
scram time testing following replacement of hydraulic control unit accumulators
conducted on September 15.
b.
Findings
No findings of significance were identified.
1R20
Refueling and Outage Activities (71111.20)
a.
Inspection Scope
The inspectors observed activities associated with a forced outage initiated on
August 14, when the plant scrammed due to a loss of all offsite power, and continued
through August 21 when the plant synchronized to the grid. The inspectors assessed the
adequacy of forced outage-related activities, including implementation of risk
management, conformance to approved site procedures, and compliance with TS
requirements. The following major activities were observed or performed:
On August 15 and 16, the inspectors observed the licensees shutdown and
cooldown of the reactor. The inspectors observed shift briefings, operator
12
performance, shift management coordination of plant activities, and conformance
with TS requirements including cooldown limitations.
From August 16 through August 20, the inspectors reviewed licensee restart
readiness activities to verify emergent issues were appropriately identified as restart
restraints and that restart restraint issues were appropriately resolved prior to mode
changes.
On August 20, the inspectors observed the licensees reactor startup. The inspectors
observed shift briefings, operator performance, shift management coordination of
plant activities, and conformance with TS requirements including heatup limitations
and mode change requirements.
b.
Findings
No findings of significance were identified. Inspection activities associated with the
equipment anomalies involving the Division 1 EDG and LPCS/RHR A waterleg pump
were completed as part of NRC Special Inspection, 05000440/2003009, which was
chartered on August 27.
1R22
Surveillance Testing (71111.22)
a.
Inspection Scope
The inspectors observed surveillance testing or reviewed test data for risk-significant
systems or components to assess compliance with TSs, 10 CFR Part 50, Appendix B,
and licensee procedure requirements. The testing was also evaluated for consistency
with the USAR. The inspectors verified that the testing demonstrated that the systems
were ready to perform their intended safety functions. The inspectors reviewed whether
test control was properly coordinated with the control room and performed in the
sequence specified in the surveillance instruction (SVI), and if test equipment was
properly calibrated and installed to support the surveillance tests. The procedures
reviewed are listed in the attached List of Documents Reviewed. The five specific
surveillance activities assessed were:
electromagnetic interference testing of various electrical equipment conducted July 9;
RHR A pump and valve operability test conducted July 15;
RCIC turbine overspeed trip testing conducted August 13;
Division 1 EDG testing conducted August 21; and
average power range monitor B weekly calibration conducted on September 30.
b.
Findings
The inspection activity associated with the Division 1 EDG surveillance test failure was
completed as part of NRC Special Inspection, 05000440/2003009, which was chartered
on August 27.
13
1R23
Temporary Plant Modifications (71111.23)
a.
Inspection Scope
The inspectors reviewed the licensees temporary installation of blowers to improve air
mixing in the turbine building to verify that the temporary modifications did not affect
system operability or availability. The inspectors reviewed screening and evaluation in
accordance with 10 CFR 50.59. The inspectors reviewed post-installation temperature
data to verify that the temporary modification performed as expected.
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1
Plant Walkdowns and Radiological Boundary Verifications
a.
Inspection Scope
The inspectors conducted walkdowns of the radiologically protected area to verify the
adequacy of radiological area boundaries and postings. Specifically, the inspectors
walked down radiologically significant work area boundaries (high and locked high
radiation areas) in the Radwaste and Fuel Handling Buildings, and performed
confirmatory radiation measurements to determine if these areas were properly posted
and controlled in accordance with 10 CFR Part 20, licensee procedures, and TSs. The
inspectors also evaluated the radiological condition of those areas walked down to
assess radiological housekeeping and contamination controls.
The inspectors also reviewed the licensees physical and programmatic controls for
highly activated and/or contaminated materials (non-fuel) stored within spent fuel or other
storage pools.
b.
Findings
No findings of significance were identified.
2OS2 As Low As Is Reasonably Achievable Planning And Controls (71121.02)
.1
Source-Term Reduction and Control
a.
Inspection Scope
The inspectors reviewed licensee records to determine the historical trends and current
status of tracked plant source terms (STs) and determined that the licensee was making
14
allowances and had developing contingency plans for expected changes in the ST due to
changes in plant fuel performance issues or changes in plant primary chemistry.
The inspectors verified that the licensee had developed an understanding of the plant
ST, that this included knowledge of input mechanisms to reduce the ST and that the
licensee had an ST control strategy in place that included a cobalt reduction strategy and
shutdown ramping and operating chemistry plan which was designed to minimize the ST
external to the core. Other methods used by the licensee to control the ST including
component and system decontamination, and use of shielding were evaluated.
The licensees identification of specific sources was reviewed along with exposure
reduction actions and the priorities the licensee had established for implementation of
those actions. The results that had been achieved against these priorities since the last
refueling cycle were reviewed. For the current assessment period, source reduction
evaluations were verified along with actions taken to reduce the overall ST compared to
the previous year.
b.
Findings
No findings of significance were identified.
.2
Declared Pregnant Workers
a.
Inspection Scope
The inspectors reviewed dose records of declared pregnant workers for the current
assessment period to verify that the exposure results and monitoring controls employed
by the licensee complied with the requirements of 10 CFR Part 20.
b.
Findings
No findings of significance were identified.
2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)
.1
Rescue Capabilities During Use of One-Piece Atmosphere Supplying Respiratory
Protection Devices
a.
Inspection Scope
The inspectors reviewed the licensee's respiratory protection and confined space entry
procedures and discussed their implementation relative to the requirements of
10 CFR 20.1703(f) for standby rescue persons whenever one-piece atmosphere
supplying suits, or any combination of respiratory protection and personnel protective
equipment were used from which the wearer may have difficulty extricating himself.
The inspectors discussed with radiation protection (RP) management, proposals for
enhancing the radiation work permit and the as-low-as-is-reasonably-achievable
15
(ALARA) planning process and for developing safety plans for those jobs not performed
in confined space atmospheres to formally address work provisions for standby rescuers.
b.
Findings
No findings of significance were identified.
Cornerstone: Public Radiation Safety
2PS2
Radioactive Material Processing and Transportation (71122.02)
.1
Radioactive Waste System
a.
Inspection Scope
The inspectors reviewed the liquid and solid radioactive waste system description in the
USAR for information on the types and amounts of radioactive waste (radwaste)
generated and disposed. The inspectors reviewed the scope of the licensees audit
program with regard to radioactive material processing and transportation programs to
verify that it met the requirements of 10 CFR 20.1101(c).
b.
Findings
No findings of significance were identified.
.2
Radioactive Waste System Walkdowns
a.
Inspection Scope
The inspectors performed walkdowns of the liquid and solid radwaste processing
systems to verify that the systems agreed with the descriptions in the USAR and the
Process Control Program, and to assess the material condition and operability of the
systems. The inspectors reviewed the status of radwaste process equipment that was
not operational and/or was abandoned in place. The inspectors reviewed the licensees
administrative and physical controls to ensure that the equipment would not contribute to
an unmonitored release path or be a source of unnecessary personnel exposure.
The inspectors reviewed the current processes for transferring waste resin into shipping
containers to determine if appropriate waste stream mixing and/or sampling procedures
were utilized. The inspectors also reviewed the methodologies for waste concentration
averaging to determine if representative samples of the waste product were provided for
the purposes of waste classification in 10 CFR 61.55. During this inspection, the
inspectors were unable to observe waste processing; see Section 2OS1(.1) of
IR 50-440/02-05(DRP) for observations.
b.
Findings
No findings of significance were identified.
16
.3
Waste Characterization and Classification
a.
Inspection Scope
The inspectors reviewed the licensees radiochemical sample analysis results for each of
the licensees waste streams, including dry active waste (DAW), spent resins and filters.
The inspectors also reviewed the licensees use of scaling factors to quantify
difficult-to-measure radionuclides (e.g., pure alpha or beta emitting radionuclides). The
reviews were conducted to verify that the licensees program assured compliance with
10 CFR 61.55 and 10 CFR 61.56, as required by Appendix G of 10 CFR Part 20. The
inspectors also reviewed the licensees waste characterization and classification program
to ensure that the waste stream composition data accounted for changing operational
parameters and thus remained valid between the annual sample analysis updates.
b.
Findings
No findings of significance were identified.
.4
Shipment Preparation
a.
Inspection Scope
The inspectors observed selected aspects of the preparation of a Sealand container and
the survey of an empty incoming trailer. This included observations of radiation worker
practices to verify that the workers had adequate skills to accomplish each task. The
inspectors reviewed the records of training provided to personnel responsible for the
conduct of radwaste processing and radioactive shipment preparation activities. The
review was conducted to verify that the licensees training program provided training
consistent with NRC and Department of Transportation (DOT) requirements.
b.
Findings
No findings of significance were identified.
.5
Shipping Records
a.
Inspection Scope
The inspectors reviewed five non-excepted package shipment manifests/documents
completed in 2002/2003 to verify compliance with NRC and DOT requirements
(i.e., 10 CFR Parts 20 and 71 and 49 CFR Parts 172 and 173).
b.
Findings
No findings of significance were identified.
17
.6
Identification and Resolution of Problems
a.
Inspection Scope
The inspectors selectively reviewed 2002 and 2003 CRs, audits and self-assessments
that addressed radwaste and radioactive materials shipping program deficiencies, to
verify that the licensee had effectively implemented the corrective action program and
that problems were identified, characterized, prioritized and corrected. The inspectors
also verified that the licensees self-assessment program was capable of identifying
repetitive deficiencies or significant individual deficiencies in problem identification and
resolution.
The inspectors also reviewed selected corrective action reports from the radioactive
material and shipping programs since the previous inspection, interviewed staff and
reviewed documents to determine if the following activities were being conducted in an
effective and timely manner commensurate with their importance to safety and risk:
initial problem identification, characterization, and tracking;
disposition of operability/reportability issues;
evaluation of safety significance/risk and priority for resolution;
identification of repetitive problems;
identification of contributing causes;
identification and implementation of effective corrective actions;
resolution of NCVs tracked in corrective action system(s); and
implementation/consideration of risk significant operational experience feedback.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
Cornerstones: Mitigating Systems
4OA1 Performance Indicator Verification (71151)
a.
Inspection Scope
The inspectors reviewed reported second quarter 2003 data for high pressure injection
system unavailability and RHR system unavailability performance indicators using the
definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory
Assessment Indicator Guideline, Revision 2. The inspectors reviewed station logs,
surveillance procedures, maintenance records, and TS logs to verify the accuracy of the
licensees data submission.
b.
Findings
No findings of significance were identified.
18
4OA2 Identification and Resolution of Problems (71152)
.1
Routine Review of Identification and Resolution of Problems
a.
Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues
during baseline inspection activities and plant status reviews to verify that they were
being entered into the licensees corrective action program at an appropriate threshold,
that adequate attention was being given to timely corrective actions, and that adverse
trends were identified and addressed.
b.
Findings
No findings of significance were identified.
.2
Annual Sample Review
a.
Inspection Scope
The inspectors reviewed the implementation of licensee corrective actions in the area of
inappropriate use of operability determinations pertaining to steam stop valve
1N11F0020B. Specifically, the inspectors reviewed the corrective actions documented in
CR 02-03939, Operability Determination Decision Questioned by NRC Resident.
b.
Findings
Although PYBP-SITE-0014, Operability Determination Reference Guide, Revision 0,
had been updated to include direction to not write operability determinations when a SSC
failed an American Society of Mechanical Engineers (ASME) or TS required test, as
specified in Corrective Action 3, the guide remained weak. For example, a previous NRC
finding (NCV 05000440/2003002-03) identified that an evaluation was not done to
characterize pipe elbow flaws in Train B of the ESW system and Perry personnel wrote
an operability determination to address the issue. This use of an operability
determination was contrary to Generic Letter 91-18 guidance. Despite this example, the
subject of flaw evaluations had not been addressed in the reference guide. Also, the
guide did not cover, in detail, all topics listed in Generic Letter 91-18. For example,
issues involving treatment of single failure operability determinations and environmental
qualifications were not included. The inspectors concluded that a potential vulnerability
still existed with respect to the licensees use of operability evaluations. The inspectors
noted that a more comprehensive extent of condition review could have identified these
potential vulnerabilities.
The inspectors noted that the experience review and extent of condition reviews were
essential in measuring the effectiveness of a corrective action program. The inspectors
determined that the experience review section documented in the root cause report for
CR 02-03939 was weak in that the extent of review was not documented, such as a
review of currently open operability determinations and an historical review of previously
written operability determinations. The experience review stated that no other instance of
inappropriate use of an operability determination had occurred in recent Perry plant
performance. The inspectors considered recent performance as within 3 years and
19
reviewed all operability determinations generated since year 2001. Operability
determinations had been requested and accepted for failure of the RCIC First Test Valve
to CST 1E51F0022 to operate from the control room (CR 01-01993) and failure of HPCS
CST Test Thermal Expansion Check E21F0039 (CR 02-00773) to satisfy an exercise
test. Both of these issues involved failures during ASME testing. These issues were not
identified in the experience review as unacceptable use of operability determinations and
should have been so identified. The inspectors determined that had a comprehensive
experience review been done, the licensee could have obtained additional information
with which to assess the effectiveness of the corrective action program and correct
potential inadequacies in the program, as necessary.
4OA3 Event Followup (71153)
.1
Seismic Event
a.
Inspection Scope
The inspectors observed control room personnel responding to a seismic event which
occurred June 27. The inspectors arrived in the control room within minutes of the event
and observed the followup actions by the licensee including operator briefings,
monitoring of plant conditions, completion of required ONI actions, and emergency plan
review. The inspectors reviewed the licensees emergency plan to verify the event was
appropriately characterized as an Unusual Event and that notification of county, state,
and federal agencies occurred in a timely manner.
Although the activation of the licensees Technical Support Center (TSC) was not
procedurally required at the Unusual Event threshold, the licensee chose to staff the
facility to coordinate plant walkdowns and system operability evaluations. The inspectors
observed TSC personnel performance to verify adequacy of communications and assess
effectiveness of recovery plan actions.
b.
Findings
No findings of significance were identified.
.2
On August 14, the plant scrammed due to a LOOP. When the scram occurred, the
inspectors were in the control room and observed the licensees immediate response to
the scram and LOOP. The inspectors observed the licensees declaration of an Unusual
Event and their actions to restore offsite power and recovery of offsite power.
The licensee activated their TSC and the inspectors observed TSC personnel
performance and coordination between the TSC and the control room. The inspectors
observed the licensees processes to prioritize restoration of power to plant loads and the
recovery of ECCSs.
20
b.
Findings
No findings of significance were identified. Inspection activities associated with the
equipment anomalies involving the Division 1 EDG and LPCS/RHR A waterleg pump
were completed as part of NRC Special Inspection, 05000440/2003009, which was
chartered on August 27.
.3
(Closed) Licensee Event Report (LER) 05000440/2003-001-00: Manual Actuation of
the Reactor Protection System With All Control Rods Inserted During Testing. On
May 10, while conducting LOOP/loss-of-coolant accident (LOCA) testing, the licensee
inserted a manual scram due to failure of the instrument air system containment isolation
valve to reopen. At the time of the test, the plant was in Mode 5 with all rods inserted.
The licensee entered the ONI for loss of instrument air and inserted a scram when
unable to restore instrument air. The licensees review determined that a failed relay
prevented the valve from reopening when operators manually repositioned the LOCA
override control switch. The inspectors reviewed the LER and this LER is closed.
b.
Findings
No findings of significance were identified.
4OA5 Other Activities
.1
Review of Events Leading to a Notice of Enforcement Discretion
a.
Inspection Scope
The inspectors reviewed the licensees activities in response to a failure of the Division 1
ESW pump and the licensees submission of a request for a NOED. The inspectors
observed maintenance activities and inspected pump components.
b.
Findings
Introduction: A self-revealed apparent violation (AV) of TS 5.4 occurred when the
Division 1 ESW pump failed during routine pump operation. The licensee rebuilt the
pump in 1997 and during this reassembly, failed to properly reassemble the pump shaft
connections. The improper reassembly led to pump failure on September 1. The NRC
assessed this finding in accordance with IMC 0609 and made a preliminary determination
that it is an issue with some increased importance to safety.
Description: On September 1, 2003, the licensee started the Division 1 ESW pump to
provide dilution for draining a leaking sodium hypochlorite line. At 5:17 p.m., the control
room received several alarms associated with the Division 1 ESW pump. Subsequent
investigation revealed that the pump shaft had failed. The licensee investigated the shaft
failure and concluded that a coupling had failed due to insufficient engagement of a key
between the coupling and the shaft. The pump shaft consisted of four sections with five
couplings to connect the sections and transfer power from the motor to the pump. Each
of the couplings consisted of a two-piece split ring, a coupling sleeve, two keys and two
setscrews. To achieve proper engagement between the coupling sleeve, keys, and
shaft, the mechanic must locate the sleeve vertically on the shaft such that the setscrews
21
align with a groove machined into the split ring. During the last pump reassembly, the
licensee failed to align the coupling sleeve with the groove in the split ring causing
insufficient engagement between the key and the coupling sleeve. The reduced
engagement caused the stresses in the coupling sleeve to exceed the allowable stresses
and the resulting high stresses led to stress corrosion cracking of the sleeve and
eventual failure of the sleeve. The licensee restored the pump to operability at 6:55 p.m.
on September 5.
During the licensees initial evaluation of the condition, the licensee identified that the
procedure used to reassemble the pump failed to completely incorporate the
manufacturers instruction for reassembly of the coupling. Specifically, the licensees
procedure did not require alignment of the setscrew holes with the groove in the split
ring. As a result, at least two of the couplings for the Division 1 ESW pump had
insufficient engagement between the key and coupling sleeve. Even though the
procedure was not adequate, the licensees extent of condition concluded that failure of
either the Division 2 or 3 pump was not imminent. The licensee rebuilt the Division 2
pump in April of this year and the mechanics reported that upon completion, the
setscrews were flush with the coupling sleeve, indicating proper alignment. The licensee
also reported that the Division 3 pump had not been rebuilt by the licensee since its
installation in 1985 and therefore, the licensees deficient procedure had not been used
on this pump.
Analysis: The inspectors evaluated this finding under the SDP. The inspectors
concluded that this finding directly effected the mitigating system cornerstone objective of
safety system availability. The inspectors evaluated the finding under Phase 1 of the
SDP process and determined a Phase 2 evaluation was needed. The inspectors based
this conclusion on the loss of the Division 1 ESW safety function. With the shaft broken,
the Division 1 ESW system could not perform its safety function. In addition, the loss of
ESW resulted in inoperability of numerous supported systems including the Division 1
EDG, RHR A, and LPCS systems. The Division 1 ESW pump was considered to be
unavailable for a duration of 14 days. This was based on the assumption that the
Division 1 ESW pump was considered unavailable from August 22 to September 5,
following restoration to service. The pump was secured from service on August 23,
following an extended period of operation to support the LOOP caused by grid instability.
Following August 23, the pump was operated twice for a short period of time. As the
typical probabilistic risk assessment mission time is a 24-hour duration, the regional
senior risk analyst concluded that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to securing the pump following extended
service was the last time there was any confidence that the pump could perform its
function for the full mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The initial Phase 2 risk assessment characterized this finding as Yellow using the site
specific Risk-Informed Inspection Notebook. However, a Phase 3 analysis performed by
the senior risk analyst determined the issue was a White finding, after providing
additional consideration for duration and cross-tying capability of the EDGs.
Enforcement: Technical Specification 5.4 states, in part, that procedures shall be
established, implemented and maintained as recommended in Regulatory Guide 1.33.
Regulatory Guide 1.33 recommended the establishment of written procedures,
appropriate to the circumstances, for performing maintenance that can affect
performance of safety related equipment. The licensee failed to establish a written
22
procedure appropriate to the circumstances for pump reassembly. Specifically, the
vendor procedure specified that the setscrew holes would align with the groove in the slip
ring such that the setscrews should be flush with the coupling sleeve. The licensee failed
to transfer this requirement to the procedure for pump reassembly resulting in improper
alignment of the coupling components. Pending completion of a final safety significance
review, this issue is identified as AV 05000440/2003006-03. The licensee has entered
this apparent violation into its corrective action program as CR 03-05065.
.2
(Closed) URI 05000440/2003004-04 (formerly URI 50-440/2003004-04): Failure to
Classify an Alert Within 15 Minutes.
Introduction: A preliminary White finding and an associated apparent violation were
identified for failure to follow the requirements of the Perry Emergency Plan during an
ALERT event on April 24, 2003, when damage to irradiated fuel caused a high alarm on
the fuel handling building ventilation exhaust gaseous radiation monitor.
Description: On April 24, 2003, the inspectors observed control room personnel respond
to fuel handling building and evacuation alarms received after an irradiated fuel rod was
damaged during licensee inspection activities. Following the declaration of an ALERT
emergency due to the event, the inspectors identified that the emergency classification
was not made in a timely manner. Specifically, during the first 50 minutes of the event
with conditions warranting an Alert classification, the shift manager (SM), for a period in
this time interval, did not use the emergency classification scheme required by the Perry
Emergency Plan in accordance with 10 CFR 50.47(b)(4). More specifically, Section 4.1
of the plan required that the SM declare an appropriate emergency classification
whenever plant status (as determined by the classification scheme values in emergency
plan implementing procedure EPI-A1, Attachment 1, Category GA2) warrants a
declaration. Emergency plan instruction EPI-A1, Emergency Action Levels, required, in
part, that the SM classify an emergency event when actual or potential plant conditions
dictate and ensure required actions are implemented. An Alert classification was met
when damage to irradiated fuel caused a high alarm on the fuel handling building
ventilation gas radiation monitor.
Analysis: The inspectors determined the licensees failure to implement its emergency
classification and action level scheme in a timely manner as required by the Perry
Emergency Plan was a performance deficiency. Traditional enforcement does not apply
because the issue did not have any actual safety consequences or potential for
impacting the NRCs regulatory function and was not the result of any willful violation of
NRC requirements or FirstEnergy procedures. The inspectors determined that the issue
was associated with the emergency response organization performance attribute of the
Emergency Preparedness Cornerstone and affected the cornerstone objective of
implementing adequate measures to protect the health and safety of the public in the
event of a radiological emergency. Therefore, the finding was determined to be more
than minor.
The finding was determined to be associated with an actual event implementation
problem, and its significance was assessed using Manual Chapter 0609, Appendix B,
Emergency Preparedness Significance Determination Process (SDP). Using the
Emergency Preparedness SDP Sheet 2, Actual Event Implementation Problem, the
inspectors determined that the actual event was not an Unusual Event, but the event was
23
an Alert. The finding was associated with the improper implementation of a risk
significant planning standard (10 CFR 50.47(b)(4), standard emergency classification
and action level scheme). Therefore, the finding was determined preliminarily to be of
low to moderate safety significance (White).
Enforcement: 10 CFR 50.54(q) requires, in part, that a licensee shall follow and maintain
in effect emergency plans which meet the standards in 10 CFR 50.47(b).
10 CFR 50.47(b)(4) requires, in part, that a standard emergency classification and action
level scheme is used. The Emergency Plan for Perry sets forth, among other things,
on-shift facility licensee responsibilities for emergency response and delineates the
standard emergency classification and action level scheme in use by the licensee
(in accordance with 10 CFR 50.47(b)(4)). Section 4.1 of the Emergency Plan states,
in part, that the classification system provided in Emergency Plan Instruction EPI-A1,
provides for implementation of certain actions applicable to specific indications, and
identifies that the Emergency Coordinator shall declare the emergency classification
and the actions to be taken. Emergency Plan Instruction EPI-A1, Emergency Action
Levels, requires that the Control Room Shift Supervisor be designated the Emergency
Coordinator, place high priority on classifying an emergency plan event when actual or
potential plant conditions dictate, and ensure required actions are implemented. On
April 24, 2003, a shift manager did not follow the emergency classification and action
level scheme as required by the emergency plan when actual plant conditions warranted
an Alert emergency classification. Specifically, the shift manager did not carryout the
duties of the Emergency Coordinator and assess, identify, and classify the event in a
timely manner. This is considered an apparent violation (AV 05000440/2003006-04).
.3
Unusual Crud Buildup on the Reactor Vessel Interior Walls
The inspectors confirmed the status of the NRCs review of the licensees identification of
uneven deposits of a grey or white film on the reactor vessel interior walls during the
cycle 9 refueling outage. The inspectors confirmed that the Office of Nuclear Reactor
Regulation (NRR) and region based specialist inspectors had reviewed reports and
photographs provided by the licensee. The inspectors noted that NRR personnel
concluded that an immediate safety issue did not exist, but that long term effects were
still under investigation. It was also noted that the condition is not unique to Perry in that
it has been observed at other plants that have some combination of hydrogen water
chemistry, noble metals addition, or zinc addition. The inspectors confirmed the issue
was entered into the licensees corrective action program as CR 03-01995.
4OA6 Meetings
.1
Exit Meeting
The inspectors presented the inspection results to Mr. W. Kanda, Site Vice President,
and other members of licensee management at the conclusion of the inspection on
October 2. The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary information was
identified.
24
The inspectors re-exited with Mr. W. Kanda and other members of licensee management
by telephone on October 20, to present the preliminary significance determination of the
emergency preparedness issue.
The inspectors re-exited with Mr. Kanda on October 27, to present the preliminary
significance determination of the Division 1 ESW pump issue.
.2
Interim Exit Meetings
Access Control, ALARA and Radwaste/Transportation with Mr. T. Rausch on
August 8.
ATTACHMENT: SUPPLEMENTAL INFORMATION
Attachment
1
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
W. Kanda, Vice President-Nuclear
D. Bauguess, Emergency Preparedness Unit Supervisor
R. Coad, Radiation Protection Manager
V. Higaki, Manager, Regulatory Affairs
T. Lentz, Director Nuclear Engineering
J. Lausberg, Supervisor, Compliance
M. Medakovich, Radwaste Shipping Supervisor
T. Rausch, General Manager, Nuclear Power Plant Department
A. Schwenk, Radwaste Superintendent
R. Strohl, Superintendent, Plant Operations
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Failure to Maintain Fire Barriers (1R05)05000440/2003006-02
Failure to Establish Performance Criteria for (A)(1) Systems
(1R12)05000440/2003006-03
Improper Maintenance Causes Emergency Service Water
Pump Failure (4OA5.1)05000440/2003006-04
Failure to Classify an Alert Within 15 Minutes (4OA5.2)
Closed
Failure to Maintain Fire Barriers (1R05)05000440/2003006-02
Failure to Establish Performance Criteria for (A)(1) Systems
(1R12)
05000440/2003-001-00
LER
Manual Actuation of the Reactor Protection System With All
Control Rods Inserted During Testing (4OA3)05000440/2003004-04
Failure to Classify an Alert Within 15 Minutes (4OA5.2)
Discussed
Failure to Perform Adequate Design Reviews for Installa-
tion of Half-Couplings on a B Train Emergency Service
Water Elbow (4AO2.2)
Attachment
2
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety but rather that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
1R04
Equipment Alignment
SOI-P45/49; Emergency Service Water and Screen Wash System; Rev. 7
Drawing 302-0791-00000; Emergency Service Water System; Rev. LL
Drawing 302-0792-00000; Emergency Service Water System; Rev. HH
SVI-P45-T1254; Emergency Service Water System Valve Position Verification; Rev. 3
VLI-P45; Emergency Service Water System; Rev. 6
SDM-P45; Emergency Service Water System; Rev. 9
System Health Report; Fourth Quarter 2002
Drawing 302-09701-00000; High Pressure Core Spray System; Rev. DD
VLI-E22A; High Pressure Core Spray (Unit 1); Rev. 5
VLI-R44/E22B; Division 3 DG Starting Air System (Unit 1); Rev. 4
VLI-R44; Division 1 and 2 Diesel Generator Starting Air System (Unit 1); Rev. 4
VLI-R45/E22B; Division 3 DG Fuel Oil System (Unit 1); Rev. 3
VLI-R45; Division 1 and 2 Diesel Generator Fuel Oil System (Unit 1); Rev. 4
VLI-R46/E22B; Division 3 DG Jacket Water System (Unit 1); Rev. 5
VLI-R46; Division 1 and 2 Diesel Generator Jacket Water Systems (Unit 1); Rev. 3
VLI-R47; Division 1 and 2 Diesel Generator Lube Oil; Rev. 5
VLI-P45; Emergency Service Water System; Rev. 6
SOI-P45/49; Emergency Srvice Water and Screen Wash Systems; Rev. 7
SDM R10; Plant Electrical System; Rev. 10
SDM R23/24/25; 480 volt AC Electrical Power; Rev. 4
Attachment
3
1R05
Fire Protection
Drawing E-023-002; Fire Protection Evaluation - Unit 1 Auxiliary and Reactor Buildings
Plan- Elev. 574-10"; Rev. 12
Drawing E-023-003; Fire Protection Evaluation - Unit 1 Intermediate and Fuel Handling
Buildings Plan - Elev. 574-10"; Rev. 12
Drawing E-023-005; Fire Protection Evaluation - Unit 1 Auxiliary and Reactor Buildings
Plan - Elev. 599-0" and 599 - 9"; Rev. 12
Drawing E-023-007; Fire Protection Evaluation Units 1 and 2 Control Complex Plan
Elev. 599-0"; Rev. 12
Drawing E-023-010; Fire Protection Evaluation - Unit 1 Auxiliary and Reactor Buildings
Plan - Elev. 620-6"; Rev. 12
Drawing E-023-011; Fire Protection Evaluation - Units 1 and 2 Control Complex and
Diesel Generator Buildings Elev. 620-6"; Rev. 12
Drawing E-023-015; Fire Protection Evaluation - Units 1 and 2 Control Complex and
Diesel Generator Building Roof Plan - Elevations 638-6" and 646-6"; Rev. 12
Drawing E-023-019; Fire Protection Evaluation Units 1 and 2 Control Complex Plan
Elev. 654-0" and 679-6"; Rev. 12
Drawing E-023-034; Fire Protection Evaluation - Units 1 and 2 Emergency Service Water
Pumphouse - Plans and Sections; Rev. 12
USAR Section 9A.4.2.1.6; Fire Area 1AB-1f
USAR Section 9A.4.2.1.8; Fire Zone 1AB-2
USAR Section 9A.4.2.1.9; Fire Zone 1AB-3a
USAR Section 9A.4.2.1.10; Fire Zone 1AB-3b
USAR Section 9A.4.3.1; Fire Zone IB-1
USAR Section 9A.4.3.2; Fire Zone IB-2
USAR Section 9A.4.4.2; Unit 1 and 2 Fire Areas, Floor 2
USAR Section 9A.4.4.3.2.1; Fire Area 2CC-3
USAR Section 9A.4.4.4; Fire Areas, Floor 4
USAR Section 9A.4.4.5.1.1; Fire Area 1CC-5a
USAR Section 9A.4.5.1.1; Fire Area 1DG-1a
Attachment
4
USAR Section 9A.4.6.1; Emergency Service Water Pumphouse
PTI-P54-P0041; Semiannual Fire Door Inspection; rev. 5
I-03-DG-0350; DG-116 Fire Door; dated July 25, 2003
1R06
Flood Protection Measures
ARI-H13-P601-18; Leak Detection; Rev. 5
W.O. 02-2179; Functional Check of Limit Switches and Watertight Door Seal Chalk Test
USAR Section 6.3.2.6; Protection Provisions
USAR Section 9.3.3; Equipment and Floor Drainage System
W.O. 01-15069; Lube-Inspect Watertight Doors LP Core Spray; dated December 7, 2001
Vendor Manual File #663; Watertight Doors; Rev. 3
Drawing D-911-617; Auxiliary Building Dirty Radwaste Drains; Rev. 12
RLI-G61(FDSS); Floor Drain Sump System; Rev. 0
1R12
Maintenance Effectiveness
System Health Report, fourth quarter 2002
USAR Section 6.4; Habitability Systems
USAR Section 6.8; Safety-Related Instrument Air
USAR Section 9.3.1; Compressed Air Systems
Drawing D-302-271; Safety-Related Instrument Air; Rev. 12
VLI-P57; Safety Related Instrument Air System; Rev. 7
SOI-P57; Safety Related Instrument Air System; Rev. 6
PTI-P57-P0001; Loss of Air Test For Safety-Related Instrument Air System; Rev. 4
ONI-P52; Loss of Service and/or Instrument Air; Rev. 5
CR 02-00333; Control Room Emergency Recirc System Operability Not Timely; dated
January 31, 2002
CR 02-00419; Potential For Repeat Maintenance - Part Failure - Safety Relief Valve on
Instrument Air Compressor; dated February 11, 2002
Attachment
5
CR 02-01190; Didnt Receive Expected Alarm When Shutting Down CR Ventilation to
Secured Status; dated April 20, 2002
CR 02-02047; Smoke in the RPS Alternate A Power Supply; dated June 25, 2002
CR 02-02781; M25-0255B Shows Dual Indication After Shifting From ER to Normal;
dated August 16, 2002
CR 02-03032; M25 B006B Heater Controller Power Cable Heat Damage; dated
September 1, 2002
CR 02-03687; Broken 0M25 Damper Springs Found During Inspection; dated
October 7, 2002
CR 03-00029; 1/16" Pin Hole Leak Found on Unit 1 Service Air Compressor Tubing;
dated January 5, 2003
CR 03-00168; Tornado Damper 0M25F0001A Broken Spring; dated January 14, 2003
CR 03-03130; Instrument Air Containment Isolation Valve Failed to Re-Open During
LOOP/LOCA; dated May 10, 2003
CR 03-03138; Leakage Outside of Allowable Value During SVI-P57-T2004; dated
May 10, 2003
CR 03-03908; Control Room Ventilation Train B Damper Lineup; dated June 16, 2003
CR 03-04233; Trip of Unit 2 Service Air Compressor During Startup From High Oil
Temperature; dated July 11, 2003
Root Cause Analysis Report; Failure of Instrument Air Isolation Valve 1P52-F200 to
Reopen During LOOP/LOCA per SVI-R43-T5366; dated June 6, 2003
SAP listing of R42 Notifications, printed September 8, 2003
SDM R42, DC Electrical Systems; Rev. 7
Maintenance Rule Database for R42, printed September 8, 2003
SOI R42; Div 2 DC Distribution, buses ED-1-B and ED-2-B; Batteries, Chargers and
Switchgear; Rev. 3
Selected Operator Logs; September 2001 through August 2003
CR 02-02566; Unit 1 Division 2 Reserve Charger DC Breaker Will not Rack In; dated
August 1, 2002
CR 03-04219; Battery Charger Output Fuses Blown During Functional Testing; dated
July 10, 2003
Attachment
6
1R13
Maintenance Risk Assessments and Emergent Work Control
PAP-1924; On-line Safety and Configuration Risk Management; Rev.3
Week 3, Period 2 Risk Profile
Week 6, Period 2 Risk Profile
RCIC Outage Schedule; dated August 10
Problem Solving Plan associated with the division 2 EDG inoperability
Division 2 Diesel Troubleshooting Plan; dated July 24, 2003
ONI-R25-1; Loss of an Essential 120V Bus; Rev. 4
W.O. 200045423; Troubleshoot/Rework Cause of Div 2 Power Anomaly;
dated August 3, 2003
Drawing D-206-054; Class 1E 120V AC Panels EB-1-B1, EK-1-B1, EK-1-C1; Rev. KK
CR 02-00031; Failed PMT on RCIC Turbine; dated January 3, 2002
CR 03-04717; Repeat Maintenance on RCIC Turbine; dated August 12, 2003
CR 03-04719; Human Red Tag for RCIC Oil Leak; dated August 12, 2002
CR 03-04769; Clarification of Risk Level in Shutdown Safety Needed
NOP-OP-1005; Shutdown Safety; Rev. 3
Daily Shutdown Safety Status Reports; dated August 15 and August 16, 2003
1R14
Operator Performance During Nonroutine Plant Evolutions and Events
Operator Logs; dated August 5, 2003
ELI-R24; 480 Volt MCC; Rev. 8
ELI-R25; 120, 240, and 480V AC Distribution System; Rev. 11
CR 03-04583; Unexpected Alarms When Transferring F1C08 to Emergency;
dated August 5, 2003
ONI-D17; High Radiation Levels Within Plant; Rev. 6
ARI-H13-P902-1; Common Airborne Radiation Monitoring Panel; Rev. 3
Operations Evolution Order; Water Leg Pump Test For CR 03-4764; dated
September 7, 2003
Attachment
7
Operations Evolution Order; RHR B/C Water Leg Pump Test For CR 03-4764; dated
September 10, 2003
1R15
Operability Evaluation
CR 03-04258; M51 System Solenoids Have Exceeded Their Qualified Life;
dated July 14, 2003
CR 03-04195; Leak Detection in the Turbine Building; dated July 9, 2003
Calc. 2.4.6.14; Turbine Building Temperature Response to Steam Leaks; rev. 0
LCO 3.3.6.1; Primary Containment and Drywell Isolation Instrumentation
CR 02-04790; ICAs on Power to Flow Map May not be as Conservative as Previously
Understood; dated December 17, 2002
CR 03-04279; ICAs on Power to Flow Map May not be as Conservative as Previously
Understood; dated July 16, 2003
CR 03-04425; Div 2 Analog Instrumentation Power Perturbation; dated July 28, 2003
Instruction and Operating Manual for Model 86 Temp-Matic Thermocouple Monitor;
Rev 1
DWG D302-0971-00000; Feedwater Leakage Control System; Rev. J
DWG 302-0082-00000; Feedwater System; Rev. JJ
DWG D 302-0705-00000; Low Pressure Core Spray System; Rev. Z
Calc N27-45; Flow Requirement for Feedwater Leakage Control System; Rev. 2
CR 03-05165; Potential for Water Hammer within Feedwater Leakage Control System,
Div. 1; dated September 9, 2003
1R16
Operator Workarounds
CR 03-03764; Single Loop Operation (SLO) LHGR Limits for Perry Cycle 10 Need
Correcting; dated June 6, 2003
1R19
Post-Maintenance Testing
SOI-E21; Low Pressure Core Spray; Rev. 9
PY-SVI-E21-T1196; LPCS Pump Discharge Flow (Bypass) Channel; dated
July 18, 2003
SVI-R43-T1318; Diesel Generator Start and Load Test; dated July 25, 2003
Attachment
8
Operation Manual Static Exciter Regulator; dated August 16, 1977
WO 200044835; Digital Process Tachometer A for 1R4; dated July 25, 2003
WO 200044842; Digital Process Tachometer B for 1R4; dated July 24 2003
WO 200044839; Standby Diesel Generator Control Panel; dated July 25, 2003
WO 200045423; Troubleshoot/Rework Cause of Div 2 Power Anomaly;
dated August 3, 2003
Work in Progress Log; Order 200045423; dated August 3, 2003
Instruction Manual; Single Phase Regulating Transformers Model No. RTF-480/120-15;
Rev. 1
WO 01-0173000-000; Uncouple RCIC Pump From RCIC Turbine; dated August 11, 2003
WO 03-002773-000; Change Oil and Filter, Sample Oil - RCIC Turbine; dated
August 11, 2003
SVI-E51-T2001; RCIC Pump and Valve Operability Test; Rev. 14
Order 200003985; ESW Pump A; dated September 2, 2003
SVI-C11-T1006;Control Rod Maximum Insertion Time ; Rev. 8
1R20
Refueling and Other Outage Activities
IOI-1; Cold Startup; Rev. 11
IOI-3; Power Changes; Rev. 12
IOI-6; Cooldown - Main Condenser Not Available; Rev. 6
CR 03-04763; Observations Made on Isolated Phase Bus Duct Support Structure Just
North of TB; dated August 15, 2003
CR 03-04764; RHR-A/LPCS Water-Leg Pump, Not Supplying Adequate Pressure; dated
August 14, 2003
CR 03-04772; Loss of Off-Site Power and Generator Trip Due to Underfrequency
Condition; dated August 14, 2003
CR 03-04775; Document Div 1 DG Reverse Power Trip During Unloading/Divorcing From
Parallel Op; dated August 15, 2003
CR 03-04778; Unable to Reset RCIC Turbine Trip Remotely; dated August 14, 2003
Attachment
9
CR 03-04798; Control Rod 30-51 Possibly Slow to Settle; dated August 17, 2003
CR 03-04779; Indications Received during C11 Restoration after LOOP; dated
August 15, 2003
CR 03-04793; Control Rod 22-35 Was Slow to Settle; dated August 17, 2003
CR 03-04800; Post Loop Panel Walkdown Found Valve 1M51F090 Open;
dated August 15, 2003
CR 03-04803; RFACR For 1C11N0602C Slow to Reset; dated August 16, 2003
CR 03-04810; Control Rod 22-35 Drifted Out to Position 02 Following Rod Testing; dated
August 17, 2003
CR 03-04838; RC&IS Position Indication Problems; dated August 19, 2003
Post Scram Restart Report; dated August 17, 2003
1R22
Surveillance Testing
PY-SVI-E12T2001; RHR Pump Operability Test; dated July 14, 2003
WO 200005875; Adjust Cell Switch EH2104 per GEI-0135; dated July 28, 2003
GEI-0135; ABB Power Circuit Breakers 5 KV Types 5HK250 and 5HK530 Maintenance;
Rev. 4
PTI-E51-P0003; RCIC Terry Turbine Overspeed Trip Test; Rev. 2
EMI Diagnostics Report; dated August 12, 2003
SVI-C61-T1201; Remote Shutdown Control Test- Division 2 RHR, ECC and ESW;
Rev. 1
DWG 208-0055-00045; Shutdown Cooling Upper Pool MOV F037B (Throttle Valve);
Rev. V
LCO 3.3.3.2; Remote Shutdown System
SVI-C51-T0033-B; APRM B Flow Channel Calibration for 1C51-K605B; Rev. 0
ICI-C-C51-11; APRM Calibration/Adjustment; Rev. 01
1R23
Temporary Plant Modifications
USAR 9.4.4; Turbine Building Area Ventilation System
Attachment
10
DWG E-001-0030; Final Plant Layout Plan Above El. 620-6" Turbine Room (East End)
and Heater Bay and Auxiliary Boiler Building; Rev. C
DWG D-922-784;Turbine Bldg El. 577-6" East; Rev. C
TM-1-03-011; Operation of Temporary Ventilation Fans in the Turbine Building; dated
July 18, 2003
2OS1 Access Control to Radiologically Significant Areas
FTI-A0017; Non-Special Nuclear Material Pool Inventory Mechanism; Revision 0
Proposal; Perry Nuclear Power Plant Removal Of Candidate Low Level Radioactive
Waste From The Fuel Pool
2OS2 As Low As Is Reasonably Achievable Planning And Controls
HPI-B0003; Processing Of Personnel Dosimetry, Pages 6, 7 and 13; Revision 10
PAP-0114; Radiation Protection Program, Pages 6, and 8-9; Revision 6
Dosimetry Records for Declared Pregnant Workers
CR 03-03880; Root Cause Analysis Report: Investigate Chemistry Causes For The
Elevated Dose Rates In RFO9; dated July 25, 2003
2OS3 Radiation Monitoring Instrumentation and Protective Equipment
NOP-LP-3005; FENOC Confined Space Entry Program; Revision 0
2PS2
Radioactive Material Processing and Transportation
03-3033; Shipment Of Radioactive Material/Waste: Shipping Papers; dated May 12, 2003
03-1012; Shipment Of Radioactive Material/Waste: Shipping Papers; dated July 23, 2003
03-1008; Shipment Of Radioactive Material/Waste: Shipping Papers; dated July 8, 2003
03-3041; Shipment Of Radioactive Material/Waste: Shipping Papers; dated July 18, 2003
03-3024; Shipment Of Radioactive Material/Waste: Shipping Papers; dated April 22, 2003
02-1008; Shipment Of Radioactive Material/Waste: Shipping Papers; dated May 23, 2002
ODCM; Offsite Dose Calculation Manual; Revision 8
PCP; Process Control Program; Revision 7
RWI-G51; Solid Radwaste Solidification System; Revision 5
Attachment
11
NOP-OP-2002; Shipment Of Radioactive Material/Waste; Revision 1
CHI-0022; Reagent, Sample And Source Preparation; Revision 1
RECS-02-00050; Memorandum: Scaling Factors For Waste Streams; dated April 11, 2003
PAP-0305; 10 CFR 50.59 Applicability Check: 01-0036; dated November 20, 2001
PAP-0520; Change Request (USAR); dated October 24, 2001
PAP-0305; 10 CFR 50.59 Safety Evaluation: 01-0034; dated October 17, 2001
PAP-0520; Change Request (USAR); dated October 17, 2001
CR 02-02449; Basic Cause Analysis Report; dated September 4, 2002
PA 02-05; Audit Report: Radwaste Processing; dated June 27, 2002
SA-448-RECS-2002; Self Assessment: Radwaste Shipping; dated December 30, 2002
CR/CA 02-00851; Incoming Radioactive Material Shipment Exceeded DOT Contamination
Limits; dated March 21, 2002
CR/CA 02-01145; OSSC Yard Quarterly Inspection Was Not Completed Per
Instructions; dated April 17, 2002
CR/CA 02-01466; Kindrick Trailer Found To Have Fixed Contamination; dated May 14, 2002
CR/CA 02-04211; Greater Than 1000R/Hr Filter Generated During IFTS Work; dated
November 7, 2002
CR/CA 02-04817; Radwaste Equipment Returned Contaminated From Davis-Besse;
dated December 18, 2002
CR/CA 03-00793; Required Verification Was Missed For Inoperable Component During
Radwaste Discharge; dated February 18, 2003
CR/CA 03-02444; Truck Scheduled For Framatome Rad Shipment Without Approval;
dated April 22, 2003
CR/CA 03-02524; Radioactive Material Shipment Delayed At Canadian Border Due To
Manifest Issues; dated April 27, 2003
CR/CA 03-02970; DAW Sealand Container Packaged In Excess Of DOT Radiation
Limits; dated May 6, 2003
CR/CA 02-01460; Audit PA-0205, Radwaste Shipping And Handling RFA; dated
May 13, 2002
Attachment
12
CR/CA 02-01640; Audit PA-0205, RFA For Shipping Process Improvement; dated
May 16, 2002
CR/CA 02-03953; RFA: Radwaste Shipping Self Assessment Findings; dated October 3, 2002
CR/CA 03-00190; RFA: Request WMG Software Training, Radwaste Shipping; dated
January 16, 2003
CR/CA 02-01175; Laundry Shipment Receipt Radiation Survey Differs From The Vendors
Survey; dated April 18, 2002
CR/CA 02-01598; Unnecessary Dose Was Received During The RWCU HIC Shipment
Survey; dated May 22, 2002
CR/CA 03-00373; Improper Count Of Sample Prior To Shipment; dated January 23, 2003
CR/CA 03-02449; Document Need To Decon Fuel Sipping Skid Prior To Shipment; dated
April 22, 2003
CR/CA 03-04545; Reports Required By 10 CFR Part 110 May Not Have Been Made As
Required; dated August 4, 2003
TMP-2105; Radwaste Operations/Support Unit Training And Certification Programs;
Revision 9
FENOC Integrated Training System Successful Completion Reports (Selected); dated
August 7, 2003
4OA1 Performance Indicator Verification
Plant Narrative Logs; October 1, 2002 through June 30, 2003
Engineering system unavailability tracking logs; second quarter 2003
Engineering system unavailability tracking logs; first quarter 2003
SVI-E22-T1200; HPCS Pump Discharge Pressure - High (Bypass) Channel Functional for
1E22-N651; Rev. 3
SVI-E22-T1202; HPCS System Flow Rate - Low (Bypass) Channel Functional for
1E22-N656; Rev. 4
SVI-E22-T2001; HPCS Pump and Valve Operability Test; Rev. 15
SVI-E12-T2001; RHR A Pump and Valve Operability Test; Rev. 12
SVI-E12-T2002; RHR B Pump and Valve Operability Test; Rev. 12
Attachment
13
4OA2 Identification and Resolution of Problems
CR 02-03939: Operability Determination Decision Questioned by NRC Resident; dated
October 21, 2002
CR 01-1660; Documentation Discrepancies With SRV Nuts; dated March 26, 2001
CR 02-02176; OE14030 Review Identifies Potential Non-Conservative MSIV Testing For
USAR Data; dated July 2, 2002
CR 01-1647; LPCS VT-2 Inspection Not Completed; dated March 26, 2001
CR 01-1939; E51-F019 Exercise Closed Time Unsat for SVI-E51-T2001; dated
April 25, 2001
CR 01-2606; HPCS Pump Suction &&TE Indication During SVI; dated July 12, 2001
CR 01-1682; G41F0280 Operability Determination Due To Not Stroking Open During
SVI-G41-T2001; dated March 29, 2001
CR 01-1993; RCIC Test Return To CST Will Not Stroke Using Control Switch; dated
April 30, 2001
CR 02-00773;During Performance of SVI-E22-T2001, Valve 1E22F039 Failed To Open; dated
March 16, 2002
PAP-0205; Operability of Plant Systems; Rev. 13
Root Cause Analysis Report for Condition Report 02-03939; dated November 27, 2002
PYBP-SITE-0014; Operability Determination Reference Guide, Rev. 0
SVI-E22-T2001; HPCS Pump and Valve Operability Test; Rev. 15
NRC Inspection Manual Part 9900: Technical Guidance, Maintenance - Preconditioning of
Structures, Systems, and Components Before Determining Operability; dated
September 28, 1998
Drawing D-302-701; High Pressure Core Spray System; Rev. BB
4OA3 Event Followup
LER-2003-001; Manual Activation of the Reactor Protection System with All Control Rods
Inserted During Testing; dated July 3, 2003
Operator Logs; dated May 5 -10, 2003
ONI-P52; Loss of Service And/or Instrument Air; Rev 5
Attachment
14
CR 03-03130; 1P52F0200 Fails Closed during Division 1 LOOP/LOCA;
dated May 10, 2003
VLI-R44; Division 1 and 2 Diesel Generator Starting Air System (Unit 1); Rev. 4
ONI-D51; Earthquake; Rev. 5
EPI-A1; Emergency Action Levels; Rev. 6
CR 03-04078; Seismic Event; dated June 30, 2003
ONI-C71-1; Reactor Scram; Rev. 7
ONI-R10; Loss of AC Power; Rev. 7
PEI-B13; Reactor Pressure Vessel Control; Rev. 6
4OA5 Other Activities
GMI-0039; Disassembly of the Emergency Service Water Pump; rev. 5
PY-CEI/NRR-2735L; Request for Enforcement Discretion Regarding Technical Specification (TS) 3.7.1, Emergency Service Water (ESW) System- Division 1 and 2; and TS 3.8.1, AC
Sources-Operating; dated September 8, 2003
CR 03-05065; ESW Pump A Failed; dated September 1, 2003
DWG 22-0125-00000; Large Emergency Service Water Pumps; Rev. 2
Gould Pumps Installation, Operation and Maintenance Instruction Manual; Received
May 1, 1985
Sections 3.0, 4.0 and 5.0; Perry Emergency Plan; Rev. 17
EPI-A1; Emergency Action Levels; Rev. 6
EPI-A2; Emergency Actions Based On Event Classification; Rev. 8
CR 03-02408; Emergency Classification Declaration Not Timely and Cause Analysis; dated
April 24, 2003
CR 03-02415; Drywell/Containment Radiological Recovery Plan From Fuel Handling Building
Fuel Pin Bubble; dated April 24, 2003
CR 03-02422; Lessons Learned During Alert Emergency Classification; dated April 24, 2003
CR 03-02483; Fuel Handling Building Evacuation Alarm; dated April 24, 2003
CR 03-01995; Unusual Crud Buildup on the Reactor Vessel Interior Walls; dated
April 10, 2003
Attachment
15
LIST OF ACRONYMS USED
As-Low-As-Is-Reasonably-Achievable
American Society of Mechanical Engineers
CFR
Code of Federal Regulations
CR
condition report
Dry Active Waste
diesel generator
Department of Transportation
emergency core cooling
EPI
Emergency Plan Instruction
emergency service water
finding
IMC
Inspection Manual Chapter
LER
Licensee Event Report
loss-of-coolant accident
low pressure core spray
non-cited violation
Notice of Enforcement Discretion
NRC
Nuclear Regulatory Commission
ONI
Off-Normal Instruction
operator workaround
post-maintenance testing
reactor core isolation cooling
RCIS
rod control and information system
radiation protection
significance determination process
Shift Manager
structure, system, and component
source-term
SVI
Surveillance Instruction
TS
Technical Specification
unresolved item
Updated Safety Analysis Report
VLI
Valve Lineup Instruction