ML13128A056
| ML13128A056 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 05/07/2013 |
| From: | Reynolds S Division Reactor Projects III |
| To: | Pacilio M Exelon Generation Co, Exelon Nuclear |
| References | |
| EA-13-079 IR-13-002 | |
| Download: ML13128A056 (56) | |
See also: IR 05000237/2013002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
May 7, 2013
Mr. Michael J. Pacilio
Senior Vice President, Exelon Generation Company, LLC
President and Chief Nuclear Officer (CNO), Exelon Nuclear
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3, INTEGRATED
INSPECTION REPORT 05000237/2013002, 05000249/2013002; PRELIMINARY
WHITE FINDING
Dear Mr. Pacilio:
On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated
inspection at your Dresden Nuclear Power Station, Units 2 and 3. The enclosed report
documents the results of this inspection, which were discussed on April 8, 2013,
with Mr. D. Czufin, and other members of your staff. Additionally on April 19, 2013, the NRC
discussed with Mr. S. Marik, of your staff, the preliminary White determination for the finding
discussed below.
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 one NRC-identified finding, concerning the sites external flooding
strategy, which has preliminarily been determined to be a White finding with low to moderate
safety significance that may require additional NRC inspections. Specifically, Dresden
Abnormal Operating Procedure, DOA 0010-04, Floods, did not contain steps directing
operators to maintain reactor vessel inventory during a probable maximum flood event when
a reasonable simulation of this procedure was executed in August 2012.
The finding is not a current safety concern. A licensee procedure, TSG -3, Attachment T,
establishing a pathway for adding make-up water to the reactor coolant system during external
flooding events up to and including the probable maximum flood, was implemented in
November 2012.
This finding with the supporting circumstances and details is documented in the enclosed
inspection report. This finding was assessed based on the best available information, using the
applicable Significance Determination Process. The basis for the NRCs preliminary significance
determination is also described in the enclosed report. This finding is also an apparent violation
of NRC requirements and is being considered for escalated enforcement action in accordance
with the Enforcement Policy, which can be found on the NRCs Web site at
http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html.
M. Pacilio -2-
In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation
using the best available information and issue our final determination of safety significance
within 90 days of the date of this letter. The significance determination process encourages an
open dialogue between the NRC staff and the licensee; however, the dialogue should not
impact the timeliness of the staffs final determination. Before we make a final decision on this
matter, we are providing you with an opportunity (1) to attend a Regulatory Conference where
you can present to the NRC your perspective on the facts and assumptions the NRC used to
arrive at the finding and assess its significance, or (2) submit your position on the finding to the
NRC in writing. If you 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 your receipt
of this letter. If you decline to request a Regulatory Conference or submit a written response,
you relinquish your right to appeal the final Significance Determination Process determination, in
that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and
Limitation sections of Attachment 2 of Inspection Manual Chapter 0609.
Please contact Mr. Jamnes Cameron at 630-829-9833 and in writing within 10 days from the
issue date of this letter to notify the NRC of your intentions. If we have not heard from you
within 10 days, we will continue with our significance determination and enforcement decision.
The final resolution of this matter will be conveyed in separate correspondence.
Because the NRC has not made a final determination in this matter, no Notice of Violation is
being issued for the inspection finding at this time. In addition, please be advised that the
number and characterization of the apparent violation described in the enclosed inspection
report may change as a result of further NRC review.
This report also documents one additional NRC-identified finding of very low safety significance
(Green). This additional finding was determined not to involve a violation of NRC requirements.
If you contest the subject or severity of this Green finding, 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,
2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector
Office at the Dresden Nuclear Power Station. In addition, if you disagree with the cross-cutting
aspect assigned to any finding in this report, you should provide a response within 30 days of
the date of this inspection report, with the basis for your disagreement, to the Regional
Administrator, Region III, and the NRC Resident Inspector at the Dresden Nuclear Power
Station.
M. Pacilio -3-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in
the NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's Agencywide Document Access and Management 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 Kenneth G. OBrien for/
Steven A. Reynolds, Director
Division of Reactor Projects
Docket Nos. 50-237, 50-249
License Nos. DPR-19 and DPR-25
Enclosure: Inspection Report 05000237/2013002, 05000249/2013002
w/Attachment: Supplemental Information
cc w/encl: Distribution via ListServ
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 05000237; 05000249
License Nos: DPR-19 and DPR-25
Report No: 05000237/2013002; 05000249/2013002
Licensee: Exelon Generation Company, LLC
Facility: Dresden Nuclear Power Station, Units 2 and 3
Location: Morris, IL
Dates: January 1 through March 31, 2013
Inspectors: G. Roach, Senior Resident Inspector
D. Meléndez-Colón, Resident Inspector
D. Jones, Reactor Inspector
J. Corujo-Sandín, Reactor Engineer
T. Go, Health Physicist
Approved by: J. Cameron, Chief
Branch 6
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ......................................................................................................... 1
REPORT DETAILS .................................................................................................................... 3
Summary of Plant Status ........................................................................................................ 3
1. REACTOR SAFETY .................................................................................. 3
1R01 Adverse Weather Protection (71111.01).................................................... 3
1R04 Equipment Alignment (71111.04Q and S) ................................................. 7
1R05 Fire Protection (71111.05) ......................................................................... 8
1R06 Flooding (71111.06) .................................................................................. 9
1R11 Licensed Operator Requalification Program (71111.11) ...........................10
1R12 Maintenance Effectiveness (71111.12) ....................................................11
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) 12
1R15 Operability Determinations and Functional Assessments (71111.15) .......13
1R18 Plant Modifications (71111.18) .................................................................13
1R19 Post-Maintenance Testing (71111.19) ......................................................14
1R22 Surveillance Testing (71111.22) ...............................................................15
1EP6 Drill Evaluation (71114.06) .......................................................................16
2. RADIATION SAFETY ...............................................................................17
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01) ......17
2RS6 Radioactive Gaseous and Liquid Effluent Treatment (71124.06) ..............19
4. OTHER ACTIVITIES ................................................................................25
4OA1 Performance Indicator Verification (71151) ..............................................25
4OA2 Identification and Resolution of Problems (71152) ...................................26
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153) .......36
4OA5 Other Activities .........................................................................................37
4OA6 Management Meetings .............................................................................38
SUPPLEMENTAL INFORMATION............................................................................................. 1
Key Points of Contact ............................................................................................................. 1
Items Opened, Closed, and Discussed ................................................................................... 2
List of Documents Reviewed .................................................................................................. 3
List of Acronyms Used ...........................................................................................................10
Enclosure
SUMMARY OF FINDINGS
Inspection Report (IR) 05000237/2013002, 05000249/2013002; 01/01/2013 - 03/31/2013;
Dresden Nuclear Power Station, Units 2 & 3; Adverse Weather Protection and Identification and
Resolution of Problems.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Two findings were identified by the inspectors.
One of these findings was considered an apparent violation of NRC regulations. The
significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using
Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated
June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the
Cross Cutting Areas, dated October 28, 2011. Findings for which the SDP does not apply may
be Green or be assigned a severity level after NRC management review. All violations of NRC
requirements are dispositioned in accordance with the NRCs Enforcement Policy dated
January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear
power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated
December 2006.
A. NRC-Identified and Self-Revealed Findings
Cornerstone: Mitigating Systems
Green. The inspectors identified a Finding having very low safety significance for the
failure to include acceptance criteria in a surveillance test for equipment that is the sole
source of make-up water to the isolation condenser and spent fuel pool for both units
during a probable maximum flood (PMF) scenario postulated in the Updated Final Safety
Analysis Report (UFSAR). As described in the Exelon Quality Assurance Manual, the
licensee is committed to the requirements of ANSI/ANS 3.2-1988, which states that
surveillance tests contain or reference acceptance criteria in appropriate design or other
source documents.
The inspectors determined that the failure to include adequate acceptance criteria in a
surveillance test was a performance deficiency warranting a significance evaluation.
The inspectors determined that the finding was more than minor because if left
uncorrected, it could lead to a more significant safety concern. Specifically, without any
acceptance criteria in the surveillance test, the licensee cannot determine whether the
flood pump was able to perform its function as described in the UFSAR and calculation
DRE99-0035. The inspectors completed a Phase 1 significance determination of this
finding and determined that the finding impacted the Mitigating Systems Cornerstone.
The inspectors concluded that the diesel-driven make-up pump would be a mitigating
system in the case of the probable maximum flood. The inspectors answered No to
the question on Exhibit 2 - Mitigating Systems Screening Questions of Appendix A, The
Significance Determination Process for Findings At-Power, of IMC 0609. As a result, the
issue screened as of very low safety significance. Similar issues were identified
previously by the inspectors involving inadequate surveillance test and operating
procedures for the flood pump. Therefore, the inspectors determined that this finding
has a cross-cutting aspect in the area of Problem Identification and Resolution,
Corrective Action Program. (P.1(d)) (Section 1R01.3)
1 Enclosure
Preliminary White: The inspectors identified a finding and an associated Apparent
Violation (AV) of Technical Specification (TS) Section 5.4.1. Technical
Specification 5.4.1 requires, in part, that written procedures be established,
implemented, and maintained covering the following activities: the applicable
procedures recommended in Regulatory Guide (RG) 1.33. Revision 2, Appendix A,
February 1978. RG 1.33. Revision 2, Appendix A, Paragraph 6 addresses Procedures
for Combating Emergencies and Other Significant Events and Item w addresses Acts
of Nature (e.g ., tornado, flood, dam failure, earthquakes). From February 20, 1991, to
November 21, 2012, the licensee failed to establish a procedure addressing all of the
effects of an external flooding scenario on the plant. Specifically, DOA 0010-04,
Floods, did not account for reactor vessel inventory make up during an external
flooding scenario up to and including the probable maximum flood event which could
result in reactor vessel water level lowering below the top of active fuel. This finding
does not represent an immediate safety concern in that the licensee now has
procedures for providing reactor vessel make up water during an external flood scenario
up to and including a PMF event.
The inspectors determined that the licensees failure to consider reactor vessel inventory
make up during an external flooding scenario up to and including the PMF was a
performance deficiency warranting a significance evaluation. The finding was
determined to be more than minor in accordance with Inspection Manual
Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, dated September 7, 2012, because it was associated with the Mitigating
Systems Cornerstone attribute of procedure quality and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences. A Significance and
Enforcement Review Panel (SERP), using IMC 0609, Appendix M, Significance
Determination Process Using Qualitative Criteria, dated April 12, 2012, preliminarily
determined the finding to be of low to moderate safety significance (White). The
inspectors determined that this finding has a cross-cutting aspect in the area of Problem
Identification and Resolution, Corrective Action Program, Self and Independent
Assessments, since it involves the failure to identify the lack of procedural steps to
address a critical function during a comprehensive self assessment of the flooding
strategy. (P.3(a)) (Section 4OA2)
B. Licensee-Identified Violations
None.
2 Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 2
With the exception of planned short duration reduction in power to support control rod pattern
adjustments, Unit 2 remained at or near full power for the entirety of the inspection period.
Unit 3
On January 28, operators reduced power to approximately 77 percent in an effort to control
rising exciter bearing no.11 trends, which was due to improperly tensioned turbine shaft
grounding brushes. Operators restored power to 100 percent on January 29, 2013.
On February 17, operators reduced power to approximately 96 percent for a planned insertion
of control rod drive G-8 for scram solenoid pilot valve repairs. Operators restored power to
100 percent on February 17, 2013.
With the exception of planned short duration reduction in power to support control rod pattern
adjustments, Unit 3 was maintained at or near full power for the remainder of the inspection
period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather Protection (71111.01)
.1 Readiness for Impending Adverse Weather Condition - Extreme Cold Conditions
a. Inspection Scope
Since extreme cold conditions were forecast in the vicinity of the facility for
January 22, 2013, the inspectors reviewed the licensees overall preparations/protection
for the expected weather conditions. The inspectors walked down the cribhouse and the
125 volts-direct current (Vdc) and 250 Vdc battery systems because their safety related
functions could be affected or required as a result of the extreme cold conditions
forecast for the facility. The inspectors observed insulation, heat trace circuits, space
heater operation, and weatherized enclosures to ensure operability of affected systems.
The inspectors reviewed licensee procedures and discussed potential compensatory
measures with control room personnel. The inspectors focused on plant managements
actions for implementing the stations procedures for ensuring adequate personnel for
safe plant operation and emergency response would be available. Specific documents
reviewed during this inspection are listed in the Attachment to this report.
This inspection constituted one readiness for impending adverse weather condition
sample as defined in Inspection Procedure (IP) 71111.01-05.
3 Enclosure
b. Findings
No findings were identified.
.2 Readiness for Impending Adverse Weather Condition - High Wind Conditions
a. Inspection Scope
Since a strong winter storm with the potential for high winds was forecast in the vicinity
of the facility for January 29, 2013, the inspectors reviewed the licensees overall
preparations/protection for the expected weather conditions. The inspectors walked
down the high pressure coolant injection and isolation condenser systems, in addition to
the licensees emergency alternating current (AC) power systems, because their safety
related functions could be required as a result of high-winds-generated missiles or the
loss of offsite power. The inspectors evaluated the licensee staffs preparations against
the sites procedures and determined that the staffs actions were adequate. During the
inspection, the inspectors focused on plant-specific design features and the licensees
procedures used to respond to specified adverse weather conditions. The inspectors
also toured the plant grounds to look for any loose debris that could become missiles
from strong wind gusts. The inspectors evaluated operator staffing and accessibility of
controls and indications for those systems required to control the plant. Additionally, the
inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and
performance requirements for systems selected for inspection, and verified that operator
actions were appropriate as specified by plant specific procedures. The inspectors also
reviewed a sample of corrective action program (CAP) items to verify that the licensee
identified adverse weather issues at an appropriate threshold and dispositioned them
through the CAP in accordance with station corrective action procedures. Specific
documents reviewed during this inspection are listed in the Attachment to this report.
This inspection constituted one readiness for impending adverse weather condition
sample as defined in IP 71111.01-05.
b. Findings
No findings were identified.
.3 (Closed) Unresolved Item 05000237/2011003-01; 05000249/2011003-01, Failure to
Include Adequate Acceptance Criteria in a Surveillance Test
a. Inspection Scope
The inspectors reviewed the unresolved item and reviewed the resolution of Unresolved
Item (URI)05000237/2011004-01; 05000249/2011004-01, Classification of Emergency
Diesel-Driven Flood Pump to Required Quality Standards, in Section 4OA5.1 of this
report to determine whether a violation of any regulatory requirements existed.
b. Findings
Introduction: The inspectors identified a Finding having very low safety significance
(Green) for the failure to include adequate acceptance criteria in a surveillance test for
equipment that is the sole source of make-up water to the isolation condenser and spent
4 Enclosure
fuel pool for both units during a probable maximum flood (PMF) scenario as postulated
in the UFSAR.
Description: On April 8, 2011, the inspectors observed the performance of Work Order
(WO) 872864, D2/3 6Y PM Emergency Diesel Pump (Flood Pump) Operation. After
the surveillance was completed, the inspectors reviewed the completed work package
and identified that the work instructions did not include acceptance criteria for the
surveillance.
Work Order 872864 instructed the licensee, in part, to:
- Throttle 2-inch brass valve until a discharge pressure of 50 psig (-0%, +2%) was
reached;
- Record pump discharge pressure;
- Record engine speed;
- Record the number of gallons in the tank;
- Record the time required to fill the tank.
Revision 2 of the WO instructions stated: Clarified work step no.19 to perform test or
tests at the discretion of the test engineer. Test discharge pressure to be determined by
test engineer. The test engineer determined that the 2-inch brass valve was to be
throttled until discharge pressures of 50, 75 and 100 pounds-force per square inch
gauge (psig) were reached.
Calculation DRE99-0035, Capacity and Discharge Head for Portable Isolation
Condenser Make-Up Pumps to be used during Flood Conditions, Revision 4,
determined that the most demanding hydraulic requirement for the flood pump is
350 gallons per minute (gpm) at 47 psig.
Dresden USFAR, Section 3.4.1.1, External Flood Protection Measures, states, in part,
that in the highly unlikely event that a PMF is predicted (528 feet (ft)) above mean sea
level (MSL)), the plant will shutdown in advance of the time predicted for flood stage
occurrence, i.e., grade level (517.5 ft). When the water level reaches 509 ft all reactors
will be shut down, the drywells will be deinerted, and the vessels will be flooded.
If the water level reaches 513 ft MSL at the plant site, cooling of the reactors will be
transferred to the isolation condensers, which will thereafter maintain the primary
system in a safe shutdown condition.
If forecast flood levels exceed 517 ft MSL, a diesel-driven emergency flood pump will be
connected by hoses to a fire system header in each unit. Through these fire system
headers, the emergency flood pump will be capable of providing at least 175 gpm of flow
to each unit. This flow will be used for make-up to the shell of the isolation condensers
and the spent fuel pools.
None of these requirements were referenced in the work order. Task 1 of WO 872864,
MM D2/3 6Y PM Emergency Diesel Pump (Flood Pump) Operation, stated that the
surveillance was found and left within acceptance criteria. The comments section of
Task 2 of WO 872864, Ops Support Flood Emergency Makeup Pump Maintenance,
stated there is no specific Acceptance Criteria in task-01.
5 Enclosure
As described in the Exelon Quality Assurance Manual, the licensee is committed to
follow the requirements of American National Standard Administrative Control and
Quality Assurance for the Operational Phase of Nuclear Power Plants
(ANSI/AN 3.2-1988). This standard states, in part, under Section 5.3.14, Test and
Inspection Procedures, that tests, including surveillance tests, and inspection
procedures contain or reference, as appropriate, acceptance criteria or limits contained
in applicable design or other source documents, such as vendors literature, engineering
drawings or plant specification that will be used to evaluate the results.
Similar issues were identified previously by the inspectors, involving surveillance
tests and operating procedures for the flood pump. Refer to non-cited violation
(NCV)05000237/2004010-02; 05000249/2004010-02, Source of Make-up Water,
URI 05000237/2006010-04; 05000249/2006010-04, Full Flow Testing of the Diesel
Driven Flood Pump at Design Conditions, and NCV 05000237/2007003-
04;05000249/2007003-04, Failure to Identify and Correct Issues with the Operation
and Testing of the Diesel Driven Pump Used to Respond to External Flooding.
Analysis: The inspectors determined that the failure to include acceptance criteria in a
surveillance test for equipment that is the sole source of make-up water to the isolation
condenser for both units during a PMF scenario did not meet ANSI/ANS 3.2-1988, a
performance deficiency warranting a significance evaluation in accordance with
Inspection Manual Chapter (IMC) 0612, Power Reactors Inspection Reports,
Appendix B, Issue Screening, issued on September 7, 2012. The inspectors
determined that the finding was more than minor because if left uncorrected, it could
lead to a more significant safety concern. Specifically, without any acceptance criteria in
the surveillance test, the licensee cannot determine whether the flood pump was able to
perform its function as described in the UFSAR and calculation DRE 99-0035.
The inspectors completed a Phase 1 significance determination of this finding using
IMC 0609, Significance Determination Process, Attachment 609.04, issued on
June 19, 2012. The inspectors determined that the finding impacted the Mitigating
Systems Cornerstone. The inspectors concluded that the diesel-driven make-up pump
would be a mitigating system in the case of the probable maximum flood. The
inspectors answered No to the questions on Exhibit 2 - Mitigating Systems Screening
Questions of Appendix A, The Significance Determination Process (SDP) For Findings
At-Power, of IMC 0609. As a result, the issue screened as of very low safety
significance (Green).
The inspectors determined that this finding has a cross-cutting aspect in the area of
Problem Identification and Resolution, Corrective Action Program, since it involves the
failure to ensure that issues potentially impacting nuclear safety are promptly identified,
fully evaluated, and that actions are taken to address safety issues in a timely manner,
commensurate with their significance. Specifically, the licensee failed to take
appropriate corrective actions to include acceptance criteria in a surveillance test for
equipment that is the sole source of make-up water to the isolation condenser and spent
fuel pool for both units during a PMF scenario as postulated in the UFSAR. As
discussed in the description section, similar issues were identified previously by the
inspectors, involving surveillance test and operating procedures for the flood pump.
6 Enclosure
Enforcement: This finding does not involve enforcement action because, while a
performance deficiency existed, no violation of a regulatory requirement was identified.
The licensee generated issue reports (IR) 1209642, NRC Identified URI with Flood
Pump Acceptance Criteria, and 1487554, Follow-Up to IR to NRC Question on Diesel
Driven Flood Pump, to document the inspectors concerns. Corrective action includes
the development of acceptance criteria which ensure the pump meets licensing basis
requirements for a PMF event.
Because this finding does not involve a violation and is of very low safety or security
significance, it is identified as a FIN. (05000237/2013002-01; 05000249/2013002-01,
Failure to Include Acceptance Criteria in a Surveillance Test)
This URI is closed. This activity does not represent a completed inspection sample.
1R04 Equipment Alignment (71111.04Q and S)
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- Unit 2/3 emergency diesel generator (EDG) during Unit 3 EDG maintenance;
- Unit 2 A standby liquid control (SBLC) train during B SBLC train inoperable for
relay repair;
- Unit 2 isolation condenser (IC) during Unit 2 high pressure coolant injection
(HPCI) maintenance outage; and
The inspectors selected these systems based on their risk significance relative to the
Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, UFSAR, TS requirements, outstanding work orders (WOs), condition
reports, and the impact of ongoing work activities on redundant trains of equipment in
order to identify conditions that could have rendered the systems incapable of
performing their intended functions. The inspectors also walked down accessible
portions of the systems to verify system components and support equipment were
aligned correctly and operable. The inspectors examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
or impact the capability of mitigating systems or barriers and entered them into the CAP
with the appropriate significance characterization. Documents reviewed are listed in the
Attachment to this report.
These activities constituted four partial system walkdown samples as defined in
IP 71111.04-05.
7 Enclosure
b. Findings
No findings were identified.
.2 Semi Annual Complete System Walkdown
a. Inspection Scope
On March 12, 2013, the inspectors performed a complete system alignment inspection
of the Unit 2 HPCI system to verify the functional capability of the system. This system
was selected because it was considered both safety significant and risk significant in the
licensees probabilistic risk assessment. The inspectors walked down the system to
review mechanical and electrical equipment lineups; electrical power availability; system
pressure and temperature indications, as appropriate; component labeling; component
lubrication; component and equipment cooling; hangers and supports; operability of
support systems; and to ensure that ancillary equipment or debris did not interfere with
equipment operation. A review of a sample of past and outstanding WOs was
performed to determine whether any deficiencies significantly affected the system
function. In addition, the inspectors reviewed the CAP database to ensure that system
equipment alignment problems were being identified and appropriately resolved.
Documents reviewed are listed in the Attachment to this report.
These activities constituted one complete system walkdown sample as defined in
IP 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1 Routine Resident Inspector Tours (71111.05Q)
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- Fire Zone 8.2.5C, Unit 2 Lube Oil Room and Unit 2/3 Electro-hydraulic Control
Reservoir Area, Elevation 517;
- Fire Zone 11.2.1, Unit 2 Southwest Corner Room, Elevation 476;
- Fire Zone 11.2.3, Unit 2 HPCI Pump Room, Elevation 476; and
- Fire Zone 9.0C, Unit 2/3 Swing Diesel Generator Room, Elevation 517.
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained
passive fire protection features in good material condition, and implemented adequate
compensatory measures for out-of-service, degraded or inoperable fire protection
equipment, systems, or features in accordance with the licensees fire plan. The
inspectors selected fire areas based on their overall contribution to internal fire risk as
8 Enclosure
documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the Attachment to this report, the inspectors verified that fire
hoses and extinguishers were in their designated locations and available for immediate
use; that fire detectors and sprinklers were unobstructed; that transient material loading
was within the analyzed limits; and fire doors, dampers, and penetration seals appeared
to be in satisfactory condition. The inspectors also verified that minor issues identified
during the inspection were entered into the licensees CAP. Documents reviewed are
listed in the Attachment to this report.
These activities constituted four quarterly fire protection inspection samples as defined in
IP 71111.05-05.
b. Findings
No findings were identified.
1R06 Flooding (71111.06)
a. Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
flooding events. The inspectors reviewed flood analyses and design documents,
including the UFSAR, engineering calculations, and abnormal operating procedures to
identify licensee commitments. The specific documents reviewed are listed in the
Attachment to this report. In addition, the inspectors reviewed licensee drawings to
identify areas and equipment that may be affected by internal flooding caused by the
failure or misalignment of nearby sources of water, such as the fire suppression or the
circulating water systems. The inspectors also reviewed the licensees corrective action
documents with respect to past flood related items identified in the corrective action
program to verify the adequacy of the corrective actions. The inspectors performed a
walkdown of the following plant area to assess the adequacy of watertight doors and
verify drains and sumps were clear of debris and were operable, and that the licensee
complied with its commitments:
- Unit 3 containment cooling service water (CCSW) pump vault with a focus on the
floor drain system check valve.
Specific documents reviewed during this inspection are listed in the Attachment to this
report. This inspection constituted one internal flooding sample as defined in
IP 71111.06-05.
b. Findings
No findings were identified.
9 Enclosure
1R11 Licensed Operator Requalification Program (71111.11)
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification (71111.11Q)
a. Inspection Scope
On February 8, 2013, the inspectors observed a crew of licensed operators in the plants
simulator during licensed operator requalification training to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems and training was being conducted in accordance with licensee
procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations and successful critical task completion requirements. Documents reviewed
are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator requalification program
simulator sample as defined in IP 71111.11.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk (71111.11Q)
a. Inspection Scope
On January 29, 2013, the inspectors observed power ascension to 100 percent rated
thermal power (RTP) on Unit 3 and adverse condition monitoring of the main turbine
bearing no. 11 which had previously exhibited high temperatures and erratic vibrations.
The licensee previously lowered generator power output until temperature and vibrations
stabilized. The licensee determined the bearing was being adversely affected by static
voltages developing between the main turbine and the bearing metal which were the
resultant of the main turbine shaft ground brushes not being properly fastened to the
shaft at the conclusion of the previous refueling outage, D3R22, in December 2012.
Once the licensee restored adequate brush tension on the shaft the stray voltages were
alleviated and bearing conditions normalized. Prior to restoring plant conditions to full
power, the licensee consulted with the vendor to ensure bearing no. 11 was capable of
operating at rated conditions. This was an activity that required heightened awareness
or was related to increased risk. The inspectors evaluated the following areas:
10 Enclosure
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms (if applicable);
- correct use and implementation of procedures;
- control board (or equipment) manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications (if applicable).
The performance in these areas was compared to pre established operator action
expectations, procedural compliance and task completion requirements. Documents
reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator heightened activity/risk
sample as defined in IP 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations (71111.12Q)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following
risk-significant system and evaluated the periodic assessment of the maintenance rule:
- Maintenance Rule Periodic Assessment no. 9 (10CFR50.65(a)(3) Assessment)
Assessment Period 10/1/2010 - 9/30/2012; and
- 4 kv switchgear and circuit breakers.
The inspectors reviewed events such as where ineffective equipment maintenance had
or could have resulted in valid or invalid automatic actuations of engineered safeguards
systems and independently verified the licensee's actions to address system
performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for structures, systems, and
components (SSCs)/functions classified as (a)(2), or appropriate and adequate
goals and corrective actions for systems classified as (a)(1).
11 Enclosure
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the CAP with the appropriate significance
characterization. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two quarterly maintenance effectiveness samples as defined
in IP 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
- Unit 2 Yellow Risk during the performance of DIS 1500-05 (24 month low
pressure coolant injection (LPCI) initiation circuitry testing);
- Unit 2 Yellow Risk during 2B SBLC train inoperable for relay repair;
- Unit 2 Yellow Risk during Division I CCSW work window;
- Unit 2 Yellow Risk for U2 HPCI maintenance outage; and
- Unit 3 Yellow Risk for U3 HPCI maintenance outage.
These activities were selected based on their potential risk significance relative to the
Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that
risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate
and complete. When emergent work was performed, the inspectors verified that the
plant risk was promptly reassessed and managed. The inspectors reviewed the scope
of maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical advisor, and verified plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Specific
documents reviewed during this inspection are listed in the Attachment to this report.
These maintenance risk assessments and emergent work control activities constituted
five samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
12 Enclosure
1R15 Operability Determinations and Functional Assessments (71111.15)
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- IR 1453700, Key Calculation Review Identifies Issues in DRE 98-0030;
- IR 1455933, U3 HPCI Valve Found in Alert Range During Valve Timing;
- Engineering Change Evaluation 39168, Unit 3 Drywell Equipment Drains Sump
Cover Plate Bent, Revision 0;
- IR 1487125, U2 Isolation Condenser Support Nut Engagement Deficiency; and
- IR 1453610, Installed Contactors Do Not Meet All Acceptance Criteria.
The inspectors selected these potential operability issues based on the risk significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors reviewed a sampling of corrective action
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations. Documents reviewed are listed in the
Attachment to this report.
This operability inspection constituted five samples as defined in IP 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications (71111.18)
.1 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following modification:
- IR 1481716, 3-0590-102D Relay Did Not Pick Up During Main Steam Line
Isolation Valve Closure SCRAM Circuit Functional Test, DOS 0500-08
The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety
evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to
verify that the modification did not affect the operability or availability of the affected
system. The inspectors, as applicable, observed ongoing and completed work activities
13 Enclosure
to ensure that the modifications were installed as directed and consistent with the design
control documents; the modifications operated as expected; post-modification testing
adequately demonstrated continued system operability, availability, and reliability; and
that operation of the modifications did not impact the operability of any interfacing
systems. As applicable, the inspectors verified that relevant procedure, design, and
licensing documents were properly updated. Lastly, the inspectors discussed the plant
modification with operations, engineering, and training personnel to ensure that the
individuals were aware of how the operation with the plant modification in place could
impact overall plant performance. Documents reviewed in the course of this inspection
are listed in the Attachment to this report.
This inspection constituted one temporary plant modification samples as defined in
IP 71111.18-05.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance (PM) activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- WO 1379083-03, OP PMT EDG3 Fuel Oil Transfer Pump Motor 3-5203;
- WO 1418376, Dresden Unit 2 Two Year PM Standby Diesel Generator
Inspection;
- WO 1605861, D2 Quarterly TS HPCI [high pressure coolant injection] Pump
Operability Test and IST [in-service testing] Surveillance;
- WO 1423633, D3 2 Year TS HPCI Pump Comprehensive Operability Test and
In-Service Test (IST) Surveillance; and
- WO 1546493-02, PM Air Start Regulator Valve on 2/3 EDG.
These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for 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 in accordance with properly reviewed and approved procedures; equipment was
returned to its operational status following testing (temporary modifications or jumpers
required for test performance were properly removed after test completion); and test
documentation was properly evaluated. The inspectors evaluated the activities against
TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various
NRC generic communications to ensure that the test results adequately ensured that the
equipment met the licensing basis and design requirements. In addition, the inspectors
reviewed corrective action documents associated with post-maintenance tests to
determine whether the licensee was identifying problems and entering them in the CAP
14 Enclosure
and that the problems were being corrected commensurate with their importance to
safety. Documents reviewed are listed in the Attachment to this report.
This inspection constituted five post-maintenance testing samples as defined in
IP 71111.19-05.
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
.1 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
- WO 01579759, D2 Quarterly TS LPCI Pump Run and IST Surveillance,
- WO 01407992, Recirculation Pump Running Differential Pressure Switch
Calibration (routine);
- WO 01234966, Electrical Maintenance D3 4Y EQ Butyl Rubber Cable
Surveillance MO3-1301-4 (routine);
- WO 01616773, D2/3 1M TSTR/COM Diesel Fire Pump Operability Surveillance
(routine); and
- WO 01396238, D2 Recirculation Flow Dual Limiter 262-26B (routine).
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine the following:
- did preconditioning occur;
- the effects of the testing were adequately addressed by control room personnel
or engineers prior to the commencement of the testing;
- acceptance criteria were clearly stated, demonstrated operational readiness, and
consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges; and the calibration frequency was
in accordance with TSs, the UFSAR, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy; applicable
prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability;
tests were performed in accordance with the test procedures and other
applicable procedures; jumpers and lifted leads were controlled and restored
where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
15 Enclosure
- where applicable for inservice testing activities, testing was performed in
accordance with the applicable version of Section XI, ASMEs code, and
reference values were consistent with the system design basis;
- where applicable, test results not meeting acceptance criteria were addressed
with an adequate operability evaluation or the system or component was
declared inoperable;
- where applicable, actual conditions encountering high resistance electrical
contacts were such that the intended safety function could still be accomplished;
- prior procedure changes had not provided an opportunity to identify problems
encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the
performance of its safety functions; and
- all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted four routine surveillance testing samples, one in-service
testing sample, and one reactor coolant system leak detection sample as defined in
IP 71111.22, Sections -02 and -05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on
February 7, 2013, to identify any weaknesses and deficiencies in classification,
notification, and protective action recommendation development activities. The
inspectors observed emergency response operations in the Technical Support Center
to determine whether the event classification, notifications, and protective action
recommendations were performed in accordance with procedures. The inspectors also
attended the licensee drill critique to compare any inspector observed weakness with
those identified by the licensee staff in order to evaluate the critique and to verify
whether the licensee staff was properly identifying weaknesses and entering them into
the corrective action program. As part of the inspection, the inspectors reviewed the drill
package and other documents listed in the Attachment to this report.
This emergency preparedness drill inspection constituted one sample as defined in
IP 71114.06-05.
b. Findings
No findings were identified.
16 Enclosure
2. RADIATION SAFETY
CORNERSTONE: OCCUPATIONAL RADIATION SAFETY
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
This inspection constituted a partial sample as defined in IP 71124.01-05.
.1 Radiological Hazard Assessment (02.02)
a. Inspection Scope
The inspectors conducted walkdowns of the facility, including radioactive waste
processing, storage, and handling areas to evaluate material conditions and performed
independent radiation measurements to verify conditions.
b. Findings
No findings were identified.
.2 Instructions to Workers (02.03)
a. Inspection Scope
The inspectors selected various containers holding non-exempt licensed radioactive
materials that may cause unplanned or inadvertent exposure of workers, and assessed
whether the containers were labeled and controlled in accordance with 10 CFR 20.1904,
Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions To
Labeling Requirements.
For work activities that could suddenly and severely increase radiological conditions,
the inspectors assessed the licensees means to inform workers of changes that could
significantly impact their occupational dose.
b. Findings
No findings were identified.
.3 Contamination and Radioactive Material Control (02.04)
a. Inspection Scope
The inspectors reviewed the licensees criteria for the survey and release of potentially
contaminated material. The inspectors evaluated whether there was guidance on how to
respond to an alarm that indicates the presence of licensed radioactive material.
The inspectors reviewed the licensees procedures and records to verify that the
radiation detection instrumentation was used at its typical sensitivity level based on
appropriate counting parameters. The inspectors assessed whether or not the licensee
has established a de facto release limit by altering the instruments typical sensitivity
through such methods as raising the energy discriminator level or locating the instrument
in a high-radiation background area.
17 Enclosure
b. Findings
No findings were identified.
.4 Radiological Hazards Control and Work Coverage (02.05)
a. Inspection Scope
The inspectors evaluated ambient radiological conditions (e.g., radiation levels or
potential radiation levels) during tours of the facility. The inspectors assessed whether
the conditions were consistent with applicable posted surveys, radiation work permits,
and worker briefings.
The inspectors evaluated the adequacy of radiological controls, such as required
surveys, radiation protection job coverage (including audio and visual surveillance for
remote job coverage), and contamination controls. The inspectors evaluated the
licensees use of electronic personal dosimeters in high noise areas as high radiation
area monitoring devices.
The inspectors examined the licensees physical and programmatic controls for highly
activated or contaminated materials, (nonfuel) stored within spent fuel and other storage
pools. The inspectors assessed whether appropriate controls, (i.e., administrative and
physical controls) were in place to preclude inadvertent removal of these materials from
the pool.
The inspectors examined the posting and physical controls for selected high radiation
areas and very high radiation areas to verify conformance with the occupational
performance indicator.
b. Findings
No findings were identified.
.5 Risk-Significant High Radiation Area and Very High Radiation Area Controls (02.06)
a. Inspection Scope
The inspectors discussed with the radiation protection manager the controls and
procedures for high-risk high radiation areas and very high radiation areas. The
inspectors discussed methods employed by the licensee to provide stricter control of
very high radiation area access as specified in 10 CFR 20.1602, Control of Access to
Very High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and
Very High Radiation Areas of Nuclear Plants. The inspectors assessed whether any
changes to licensee procedures substantially reduce the effectiveness and level of
worker protection.
The inspectors discussed the controls in place for special areas that have the potential
to become very high radiation areas during certain plant operations with first-line health
physics supervisors (or equivalent positions having backshift health physics oversight
authority). The inspectors assessed whether these plant operations require
communication beforehand with the health physics group, so as to allow corresponding
18 Enclosure
timely actions to properly post, control, and monitor the radiation hazards including re-
access authorization.
b. Findings
No findings were identified.
.6 Radiation Worker Performance (02.07)
a. Inspection Scope
The inspectors observed radiation worker performance with respect to stated radiation
protection work requirements. The inspectors assessed whether workers were aware of
the radiological conditions in their workplace and the radiation work permit controls/limits
in place, and whether their performance reflected the level of radiological hazards
present.
b. Findings
No findings were identified.
2RS6 Radioactive Gaseous and Liquid Effluent Treatment (71124.06)
This inspection constituted one complete sample as defined in IP 71124.06-05.
.1 Inspection Planning and Program Reviews (02.01)
Event Report and Effluent Report Reviews
a. Inspection Scope
The inspectors reviewed the radiological effluent release reports issued since the last
inspection to determine if the reports were submitted as required by the Offsite Dose
Calculation Manual/TSs. The inspectors reviewed anomalous results, unexpected
trends, or abnormal releases identified by the licensee for further inspection to determine
if they were evaluated, were entered in the corrective action program, and were
adequately resolved.
The inspectors identified radioactive effluent monitor operability issues reported by the
licensee as provided in effluent release reports, to review these issues during the onsite
inspection, as warranted, given their relative significance and determine if the issues
were entered into the CAP and adequately resolved.
b. Findings
No findings were identified.
19 Enclosure
Offsite Dose Calculation Manual and Final Safety Analysis Report Review
a. Inspection Scope
The inspectors reviewed UFSAR descriptions of the radioactive effluent monitoring
systems, treatment systems, and effluent flow paths so they could be evaluated during
inspection walkdowns.
The inspectors reviewed changes to the Offsite Dose Calculation Manual made by the
licensee since the last inspection against the guidance in NUREG-1301, 1302 and 0133,
and Regulatory Guides 1.109, 1.21 and 4.1. When differences were identified, the
inspectors reviewed the technical basis or evaluations of the change during the onsite
inspection to determine whether they were technically justified and maintain effluent
releases as-low-as-is-reasonably-achievable (ALARA).
The inspectors reviewed licensee documentation to determine if the licensee has
identified any non-radioactive systems that have become contaminated as disclosed
either through an event report or the Offsite Dose Calculation Manual since the last
inspection. This review provided an intelligent sample list for the onsite inspection of any
10 CFR 50.59 evaluations and allowed a determination if any newly contaminated
systems have an unmonitored effluent discharge path to the environment, whether any
required Offsite Dose Calculation Manual revisions were made to incorporate these new
pathways and whether the associated effluents were reported in accordance with
b. Findings
No findings were identified.
Groundwater Protection Initiative Program
a. Inspection Scope
The inspectors reviewed reported groundwater monitoring results and changes to the
licensees written program for identifying and controlling contaminated spills/leaks to
groundwater.
b. Findings
No findings were identified.
Procedures, Special Reports, and Other Documents
a. Inspection Scope
The inspectors reviewed Licensee Event Reports, event reports and/or special reports
related to the effluent program issued since the previous inspection to identify any
additional focus areas for the inspection based on the scope/breadth of problems
described in these reports.
The inspectors reviewed Effluent Program implementing procedures, particularly those
associated with effluent sampling, effluent monitor set-point determinations, and dose
calculations.
20 Enclosure
The inspectors reviewed copies of licensee and third party (independent) evaluation
reports of the Effluent Monitoring Program since the last inspection to gather insights
into the licensees program and aid in selecting areas for inspection review (smart
sampling).
b. Findings
No findings were identified.
.2 Walkdowns and Observations (02.02)
a. Inspection Scope
The inspectors walked down selected components of the gaseous and liquid discharge
systems to evaluate whether equipment configuration and flow paths aligned with the
documents reviewed in Section 2RS6.1 02.01 above and to assess equipment material
condition. Special attention was made to identify potential unmonitored release points
(such as open roof vents in boiling water reactor turbine decks, temporary structures
butted against turbine, auxiliary or containment buildings), building alterations which
could impact airborne, or liquid effluent controls, and ventilation system leakage that
communicates directly with the environment.
For equipment or areas associated with the systems selected for review that were not
readily accessible due to radiological conditions, the inspectors reviewed the licensee's
material condition surveillance records, as applicable.
The inspectors walked down filtered ventilation systems to assess for conditions such as
degraded high-efficiency particulate air/charcoal banks, improper alignment, or system
installation issues that would impact the performance or the effluent monitoring capability
of the effluent system.
As available, the inspectors observed selected portions of the routine processing and
discharge of radioactive gaseous effluent (including sample collection and analysis) to
evaluate whether appropriate treatment equipment was used and the processing
activities align with discharge permits.
The inspectors determined if the licensee has made significant changes to their effluent
release points, (e.g., changes subject to a 10 CFR 50.59 review) or require NRC
approval of alternate discharge points.
As available, the inspectors observed selected portions of the routine processing and
discharge liquid waste (including sample collection and analysis) to determine if
appropriate effluent treatment equipment is being used and that radioactive liquid waste
is being processed and discharged in accordance with procedure requirements and
aligns with discharge permits.
b. Findings
No findings were identified.
21 Enclosure
.3 Sampling and Analyses (02.03)
a. Inspection Scope
The inspectors selected effluent sampling activities, consistent with smart sampling, and
assessed whether adequate controls have been implemented to ensure representative
samples were obtained (e.g., provisions for sample line flushing, vessel recirculation,
composite samplers, etc.)
The inspectors selected effluent discharges made with inoperable (declared out-of-
service) effluent radiation monitors to assess whether controls were in place to ensure
compensatory sampling was performed consistent with the radiological effluent
TSs/Offsite Dose Calculation Manual and that those controls were adequate to prevent
the release of unmonitored liquid and gaseous effluents.
The inspectors determined whether the facility was routinely relying on the use of
compensatory sampling in lieu of adequate system maintenance, based on the
frequency of compensatory sampling since the last inspection.
The inspectors reviewed the results of the Inter-Laboratory Comparison Program to
evaluate the quality of the radioactive effluent sample analyses and assessed whether
the Inter-Laboratory Comparison Program includes had-to-detect isotopes as
appropriate.
b. Findings
No findings were identified.
.4 Instrumentation and Equipment (02.04)
Effluent Flow Measuring Instruments
a. Inspection Scope
The inspectors reviewed the methodology the licensee uses to determine the effluent
stack and vent flow rates to determine if the flow rates were consistent with Radiological
Effluent Technical Specifications/Offsite Dose Calculation Manual or UFSAR values, and
that differences between assumed and actual stack and vent flow rates did not affect the
results of the projected public doses.
b. Findings
No findings were identified.
Air Cleaning Systems
a. Inspection Scope
The inspectors assessed whether surveillance test results since the previous inspection
for TSs required ventilation effluent discharge systems (high-efficiency particulate air
and charcoal filtration), such as the Standby Gas Treatment System and the
Containment/Auxiliary Building Ventilation System, met Technical Specifications
acceptance criteria.
22 Enclosure
b. Findings
No findings were identified.
.5 Dose Calculations (02.05)
a. Inspection Scope
The inspectors reviewed all significant changes in reported dose values compared to the
previous radiological effluent release report (e.g., a factor of 5, or increases that
approach Appendix I criteria) to evaluate the factors which may have resulted in the
change.
The inspectors reviewed radioactive liquid and gaseous waste discharge permits to
assess whether the projected doses to members of the public were accurate and based
on representative samples of the discharge path.
Inspectors evaluated the methods used to determine the isotopes that are included in
the source term to ensure all applicable radionuclides are included within detectability
standards. The review included the current Part 61 analyses to ensure hard-to-detect
radionuclides are included in the source term.
The inspectors reviewed changes in the licensees offsite dose calculations since the
last inspection to evaluate whether changes were consistent with the Offsite Dose
Calculation Manual and Regulatory Guide 1.109. Inspectors reviewed meteorological
dispersion and deposition factors used in the Offsite Dose Calculation Manual and
effluent dose calculations to evaluate whether appropriate factors were being used for
public dose calculations.
The inspectors reviewed the latest Land Use Census to assess whether changes (e.g.,
significant increases or decreases to population in the plant environs, changes in critical
exposure pathways, the location of nearest member of the public, or critical receptor, etc.)
have been factored into the dose calculations.
For the releases reviewed above, the inspectors evaluated whether the calculated doses
(monthly, quarterly, and annual dose) are within the 10 CFR Part 50, Appendix I and
TSs dose criteria.
The inspectors reviewed, as available, records of any abnormal gaseous or liquid tank
discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc) to
ensure the abnormal discharge was monitored by the discharge point effluent monitor.
Discharges made with inoperable effluent radiation monitors, or unmonitored leakages
were reviewed to ensure that an evaluation was made of the discharge to satisfy
10 CFR 20.1501 so as to account for the source term and projected doses to the public.
b. Findings
No findings were identified.
23 Enclosure
.6 Groundwater Protection Initiative Implementation (02.06)
a. Inspection Scope
The inspectors reviewed monitoring results of the Groundwater Protection Initiative to
determine if the licensee had implemented its program as intended and to identify any
anomalous results. For anomalous results or missed samples, the inspectors assessed
whether the licensee had identified and addressed deficiencies through its CAP.
The inspectors reviewed identified leakage or spill events and entries made into
10 CFR 50.75 (g) records. The inspectors reviewed evaluations of leaks or spills and
reviewed any remediation actions taken for effectiveness. The inspectors reviewed
onsite contamination events involving contamination of ground water and assessed
whether the source of the leak or spill was identified and mitigated.
For unmonitored spills, leaks, or unexpected liquid or gaseous discharges, the
inspectors assessed whether an evaluation was performed to determine the type
and amount of radioactive material that was discharged by:
Assessing whether sufficient radiological surveys were performed to evaluate the
extent of the contamination and the radiological source term and assessing
whether a survey/evaluation had been performed to include consideration of
hard-to-detect radionuclides.
Determining whether the licensee completed offsite notifications, as provided in
its Groundwater Protection Initiative implementing procedures.
The inspectors reviewed the evaluation of discharges from onsite surface water bodies
that contain or potentially contain radioactivity, and the potential for ground water
leakage from these onsite surface water bodies. The inspectors assessed whether the
licensee was properly accounting for discharges from these surface water bodies as part
of their effluent release reports.
The inspectors assessed whether on-site ground water sample results and a description
of any significant on-site leaks/spills into ground water for each calendar year were
documented in the Annual Radiological Environmental Operating Report for the
Radiological Environmental Monitoring Program or the Annual Radiological Effluent
Release Report for the Radiological Effluent TSs.
For significant, new effluent discharge points (such as significant or continuing leakage
to ground water that continues to impact the environment if not remediated), the
inspectors evaluated whether the offsite dose calculation manual was updated to include
the new release point.
b. Findings
No findings were identified.
24 Enclosure
.7 Problem Identification and Resolution (02.07)
a. Inspection Scope
Inspectors assessed whether problems associated with the Effluent Monitoring and
Control Program were being identified by the licensee at an appropriate threshold and
were properly addressed for resolution in the licensee CAP. In addition, they evaluated
the appropriateness of the Corrective Actions for a selected sample of problems
documented by the licensee involving radiation monitoring and exposure controls.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Occupational Radiation Safety, Public Radiation Safety, and
Security
4OA1 Performance Indicator Verification (71151)
.1 Unplanned Scrams per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical
Hours (IE01) performance indicator (PI) for Dresden Nuclear Power Station Units 2
and 3 covering the period from the first through fourth quarter 2012. To determine the
accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were
used. The inspectors reviewed the licensees operator narrative logs, issue reports,
event reports and NRC Integrated Inspection Reports for the period of first through the
fourth quarter 2012 to validate the accuracy of the submittals. The inspectors also
reviewed the licensees issue report database to determine if any problems had been
identified with the PI data collected or transmitted for this indicator and none were
identified. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two unplanned scrams per 7000 critical hours samples as
defined in IP 71151-05.
b. Findings
No findings were identified.
.2 Unplanned Scrams with Complications
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams with
Complications (IE02) performance indicator for Dresden Nuclear Power Station Units 2
and 3 covering the period from the first through the fourth quarter 2012. To determine
25 Enclosure
the accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the
licensees operator narrative logs, issue reports, event reports and NRC Integrated
Inspection Reports for the period of first through the fourth quarter 2012 to validate the
accuracy of the submittals. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified. Documents reviewed are listed in
the Attachment to this report.
This inspection constituted two unplanned scrams with complications samples as
defined in IP 71151-05.
b. Findings
No findings were identified.
.3 Unplanned Transients per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Transients per 7000
Critical Hours (IE03) performance indicator Dresden Nuclear Power Station Units 2
and 3 covering the period from the first through the fourth quarter 2012. To determine
the accuracy of the PI data reported during those periods, PI definitions and guidance
contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the
licensees operator narrative logs, issue reports, maintenance rule records, event
reports, and NRC Integrated Inspection Reports for the period of first through the fourth
quarter 2012 to validate the accuracy of the submittals. The inspectors also reviewed
the licensees issue report database to determine if any problems had been identified
with the PI data collected or transmitted for this indicator and none were identified.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted two unplanned transients per 7000 critical hours samples as
defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems (71152)
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify they were being entered into the licensees CAP at an
appropriate threshold, that adequate attention was being given to timely corrective
actions, and that adverse trends were identified and addressed. Attributes reviewed
26 Enclosure
included: identification of the problem was complete and accurate; timeliness was
commensurate with the safety significance; evaluation and disposition of performance
issues, generic implications, common causes, contributing factors, root causes,
extent-of-condition reviews, and previous occurrences reviews were proper and
adequate; and that the classification, prioritization, focus, and timeliness of corrective
actions were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations
are included in the Attachment to this report.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees CAP. This review was accomplished through
inspection of the stations daily condition report packages.
These daily reviews were performed by procedure as part of the inspectors daily plant
status monitoring activities and, as such, did not constitute any separate inspection
samples.
b. Findings
No findings were identified.
.3 Selected Issue Follow-Up Inspection: Review of the Sites Procedural and Physical
Modifications for the Response to a Probable Maximum Flood Event
a. Inspection Scope
In August 2012, as required by a letter from the NRC to licensees entitled, Request for
Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding
Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights
from the Fukushima Dai-Ichi Accident, dated March 12, 2012 (ADAMS Accession
No. ML12053A340), the licensee performed external flooding vulnerability walk downs of
the site and a reasonable simulation of the flood response Abnormal Operating
Procedure DOA 0010-04, Floods, under the observation of the sites NRC resident
inspectors and NRC staff from the Japan Lessons Learned Directorate (JLD). The
results of the simulation and walk downs indicated that the licensee could perform the
procedure as written, except potentially for several non-critical steps, within the
appropriate timeline and that the procedure could achieve its goal of placing both Units 2
and 3 in a Hot Shutdown condition (Mode 3) and maintaining each units respective
27 Enclosure
spent fuel pool filled with make-up water. Many areas for improvement with the
procedure were identified, but no specific issue was identified that by itself could be
shown as preventing the licensee from achieving the desired end state within the time
line identified by the 1982, Hydrological Considerations Technical Evaluation Report
which defines the PMF scenario at the Dresden Nuclear Power Station. The PMF for
Dresden assumes a severe precipitation event covering northern Illinois and Indiana
which results in flood still water levels reaching 525 ft above mean sea level (MSL) with
wave run up reaching 528 ft MSL. Ground elevation at Dresden is 517.5 ft MSL with
Illinois River level maintained at approximately 505 ft MSL by the downstream U. S.
Army Corps of Engineers controlled Dresden Island Lock and Dam.
The sites flooding response requires opening safety related structures including the
reactor building to the environment once flood levels reach site grade (517.5 ft MSL)
allowing flood waters to enter, as the structures are not designed to resist the static force
of the flood water on their outer walls. This results in a station blackout as offsite and
onsite AC electrical power would be unavailable and emergency core cooling systems
(ECCS) and other sources of cooling and injection would not be available as they are
submerged by the flood waters or are without electrical power to operate. To cope with
this condition, the licensee would operate a diesel-powered pump which will be
connected to the fire protection system and provide water from the flooded reactor
building to the shell side of each units isolation condenser to remove decay heat from
the reactors and provide make-up water to both spent fuel pools. The flood pump was
originally to be supported above the flood waters by a chain fall mounted to a jib crane in
the reactor building track way, but can now be mounted on a floating dock which would
be staged in the reactor building trackway in the lead up to the flood waters reaching site
grade.
The inspectors performed a historical review of DOA 0010-04, Floods, from its origin
until the current revision (Revision 38); observed the licensees performance during
numerous simulations and actual demonstrations of portions of the flood strategy;
ensured the availability of various instruments, gauges and indications relied upon by the
licensee to implement the flood strategy; reviewed the licensees implementation plans
for the Aqua-Dam; assisted Headquarters and Regional management in developing and
reviewing follow-up questions for the licensee; and reviewed the licensees future plans
for structurally modifying the reactor building in order to ensure adequate strength to
resist the static forces of the flood waters and to ensure its water-tight integrity. This
structural modification is intended to maintain the reactor building free from flooding and
as such ensure the availability of onsite emergency AC power and numerous safety
related systems installed in the plant to keep the reactors safely shut down.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Findings and Observations
Following the walk downs and simulation, the licensee along with a contracted
engineering firm who observed these activities, developed a number of mitigating
strategies for external flood events impacting the site up to and including the PMF. As
previously noted, the site becomes vulnerable to flooding as soon as flood waters reach
site grade. As a result, the licensee has purchased equipment and revised procedures
to mitigate the impact on the site from an external flood. In addition, the NRC has raised
28 Enclosure
a number of questions and concerns regarding the outcome of the walk downs and
reasonable simulation. These questions were submitted in a 30 day response letter to
the licensee on November 1, 2012, (ML12306A393) with the licensee response to these
questions received on December 1, 2012 (ML12348A012). The initial round of NRC
questions along with licensee identified weaknesses in the sites response strategy
resulted in the following enhancements and mitigating strategies being developed:
1) Enhancements
- Attachments were added to DOA 0010-04 which specifically list electrical buses
to be de-energized and underground fuel tanks to be filled prior to flood waters
reaching site grade.
- The purchase of four motor boats maintained in the owner controlled area (OCA)
for use of moving personnel around the site instead of having to rely on offsite
assets.
- The addition of the floating dock to mount the diesel-driven flood pump and six
diesel fuel barrels provides a more stable platform that will naturally adjust to
changing flood height levels as compared to suspending the pump from a chain
fall strung from the reactor building jib crane.
- Purchasing back up floating gas powered drafting pumps which can be used in
the event the diesel-driven flood pump needs to be taken out of service.
- Flood height markers added in the reactor building trackway and the cribhouse
will assist the site in trending flood waters.
- Licensee follow up to the reasonable simulation identified that during the early
stages of the flooding event, when level in the reactor building was still relatively
shallow, it is possible for air in addition to water to be drawn into the suction of
the flood pump. The licensee enhanced the flood procedure to direct operators
to put the flood pump suction line into the CRD pull-put channel to increase its
submergence and minimize the possibility of air binding the pump.
2) Mitigating Strategies
- The acquisition of 4000 feet of Aqua-Dam to provide protection for the power
block for floods up to 5.5 feet above ground elevation. The berm is stored on two
53 foot long flatbeds parked in the OCA for deployment. The licensee also had a
custom bridge/dock made to be able to transport personnel over the Aqua-Dam
to boats/land on either side.
- Installation of flood barriers at the isolation condenser make-up pump house to
reduce the amount of time and personnel required to provide flood protection to
this structure early in the event. At the time of the reasonable simulation, the
licensee provided two feet of flood protection by building a sand bag berm which
required approximately 8.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> to construct. The addition of the barriers
provides four feet of flood mitigation and only requires maintenance technicians
two hours to deploy. Providing this protection allows the site to rely on plant
installed equipment to provide make up to the isolation condensers removing
reactor decay heat for lesser flooding events and delaying the transition to the
dock mounted diesel flood pump which would still be providing make-up to the
reactors and spent fuel pools.
- The licensee developed Technical Support Guideline (TSG) - 3, Attachment T,
which created a proceduralized pathway to add make-up water to the reactors
utilizing the pressurized fire header, through test connections in the SBLC,
29 Enclosure
directly to the reactor for both units if make-up via a traditional means is not able
to be restored. The licensee also modified the flooding procedure to instruct
operators to close the reactor recirculation loop isolation valves isolating
recirculation pump seals from the reactor and removing a potential source of
reactor coolant inventory loss.
The NRC submitted a second round of questions to the licensee on January 3, 2013,
with a focus on several of the enhancements and mitigating strategies recently
implemented and follow-up on the licensees original responses (ML13003A226). The
licensee responded on January 31, 2013, to the NRCs inquiries (ML13037A045).
Through review of the licensees responses to the staffs concerns in addition to
observing the reasonable simulation, the inspectors noted that the licensees procedure
for monitoring canal level as the flood waters rose above 509 ft. MSL required the use of
canal level instrumentation. In particular, a level transmitter that could be read remotely
from the control room as Plant Process Computer point E354 was called out as the
primary means of determining flood level until flood waters reached site grade at 517.5 ft
MSL. The flood procedure also allowed operators to manually identify flood level in the
cribhouse with a tape measure or other level indicator if the canal level indicator was not
available. During the reasonable simulation and prior, the E354 computer point was not
functioning and Dresden operators would have always had to rely on local, manual
actions to identify flood levels between 509 ft MSL and 517.5 ft MSL. It should be noted
that following the NRCs Systematic Evaluation Program review of Unit 2 in 1982, the
licensee committed in a letter from Thomas J. Rausch to Paul OConnor titled,
Dresden 2 SEP Topic: II-3.B, Flooding Potential and Protective Requirements; II-3.B.1,
Capability of Operating Plants to Cope with Design Basis Flood Conditions; and II-3.C,
Safety Related Water Supply (Ultimate Heat Sink), dated November 17, 1982, to install
a level gauge in the intake canal. The inspectors noted that this level gauge was not
operational for several years or may have never been operational requiring the operators
to perform manual actions to identify flood height. In addition to performing several
actions directed by DOA 0010-04 based on the flood water height prior to reaching site
grade as measured by operators, the Dresden Emergency Plan requires the site to
declare an ALERT under Emergency Action Level (EAL) HA4 when intake canal level
reaches 513 ft MSL. The inspectors determined that not meeting a NRC commitment in
that an operational canal level indicator was not installed following the Systematic
Evaluation Program review of Unit 2 in 1982 was a performance deficiency. This
performance deficiency was not more than minor in that the licensee had procedurally
driven compensatory measures in place and possessed the equipment necessary to
accurately measure flood water height between 509 ft MSL and 517.5 ft MSL and as a
result would have been capable of performing the flooding response strategy and carry
out the sites Emergency Plan.
The inspectors identified a second performance deficiency associated with no licensee
procedure for providing make-up water to the reactor coolant system while flood waters
are above site grade level.
Introduction: A finding preliminarily determined to be of low to moderate safety
significance (White) and an associated Apparent Violation (AV) of TS Section 5.4.1 was
identified by the inspectors, in that, prior to November 2012, the licensees procedures
and specifically Abnormal Operating Procedure (AOP) DOA 0010-04, Floods, did not
account for reactor inventory make up during an external flooding scenario up to and
30 Enclosure
including the PMF event which could result in reactor vessel water level lowering below
top of active fuel (TAF) leading to core damage.
Description: In August 2012, the licensee performed a reasonable simulation of its
external flooding strategy for coping with a PMF event. The inspectors subsequently
noted that the flood strategy did not contain steps accounting for losses in reactor vessel
inventory. Under normal plant conditions there are both unidentified and identified
leakage paths from the reactor coolant system. During the PMF event, systems which
would provide normal and emergency make up capacity to the reactors would be
inundated by the flood waters and would not be available.
The NRC questioned the licensee regarding this concern in a 30 day response letter to
the licensee on November 1, 2012 (ML12306A393). In response to this concern, the
licensee developed TSG-3, Attachment T, effective November 21, 2012, proceduralizing
the use of the fire protection header which would be pressurized and supplied by the
diesel flood pump to supply through mechanical adapters, which are labeled and stored
above projected PMF flood levels, the reactor by connecting to test connections in the
SBLC system. The licensee also revised DOA 0010-04, Floods, directing operators to
shut reactor recirculation loop isolation valves to reduce potential reactor leakage
sources to those governed by the unidentified leakage Technical Specification.
The licensee determined that with reactor unidentified leakage at 5 gpm, the maximum
permitted by TS, it would take approximately 130 hours0.0015 days <br />0.0361 hours <br />2.149471e-4 weeks <br />4.9465e-5 months <br /> to reach a reactor water level at
the TAF. The Dresden PMF hydrograph indicates that flood waters would exist at site
grade for approximately 57 hours6.597222e-4 days <br />0.0158 hours <br />9.424603e-5 weeks <br />2.16885e-5 months <br />. After the flood waters recede, the licensee identified
that TSG-3 Attachment H, Reactor Pressure Vessel Injection Using Portable Diesel
Driven Pump, could be used to provide injection by tying a dedicated diesel driven
FLEX pump (three are maintained onsite) into the fire protection ring header and
injecting to each units reactor vessel through the low pressure coolant injection system.
In addition, after the flood waters recede, mechanical level instruments for the entire fuel
zone would once again be available to the operators.
The inspectors challenged the licensees leakage assertion in that TS permit a total
leakage rate of up to 25 gpm which would significantly reduce the amount of time until
TAF is reached under the worst case permitted leakage conditions in the reactor coolant
system. The inspectors based this concern on the fact that the licensee did not originally
employ the strategy for isolating reactor recirculation loops which would make them
susceptible to losses due to both unidentified and identified pathways. During the site
flood event operators would be limited in their ability to monitor reactor water level as the
mechanical level indicator called out by licensee procedures has an indication band
between +60 inches and - 60 inches of water. Top of active fuel for Dresden is
considered at -143 inches of water. As a result, operators would have to provide make
up to the reactor vessel much sooner than 130 hours0.0015 days <br />0.0361 hours <br />2.149471e-4 weeks <br />4.9465e-5 months <br /> in order for level in the reactor to
not become indeterminate or possibly reach TAF during the 57 hours6.597222e-4 days <br />0.0158 hours <br />9.424603e-5 weeks <br />2.16885e-5 months <br /> the flood waters
inundate the site.
The licensee reviewed its inventory of procedures prior to November 2012 up to and
including the Severe Accident Mitigation Guidelines and was not able to identify written
instructions for operators attempting to control reactor vessel level under station blackout
conditions with high pressure coolant injection and all installed diesel driven systems
31 Enclosure
(fire protection) unavailable to provide injection capacity, which would be the situation on
site while flood waters were present.
Analysis: The inspectors determined that the licensees failure to consider reactor
vessel inventory make up during an external flooding scenario up to and including the
PMF was a performance deficiency warranting a significance evaluation. The finding
was determined to be more than minor in accordance with Inspection Manual
Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, dated September 7, 2012, because it was associated with the Mitigating
Systems Cornerstone attribute of procedure quality and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences.
The inspectors determined the finding could be evaluated using the SDP in accordance
with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial
Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance
Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems
Screening Questions, dated June 19, 2012. The inspectors answered YES to the
External Event Mitigation question which directed them to Exhibit 4, External Events
Screening Questions. The inspectors determined the statement that the finding would
degrade one or more trains of a system that supports a risk significant system or
function was TRUE and as a result a detailed risk evaluation was required.
A Significance and Enforcement Review Panel (SERP) determined that IMC 0609,
Appendix M, Significance Determination Process Using Qualitative Criteria, dated
April 12, 2012, was appropriate to use due to the lack of existing quantitative SDP tools
for evaluating external flooding risk. As part of that process, the Region III Senior
Reactor Analyst (SRA) developed a simple event tree model to perform a bounding
quantitative evaluation. The model represents an external flood event that exceeds
grade level elevation (517.5) and requires implementation of the flood procedure,
DOA 0010-04, Floods, Revision 32.
The input assumptions were highly uncertain and were varied to calculate a range of risk
estimates. The values for flood frequency, the probability of reactor pressure vessel
leakage requiring makeup, and the likelihood of successful makeup to the vessel during
and after the flood recedes were key inputs to the evaluation. The change in core
damage frequency (CDF) estimates ranged from Green, a finding of very low safety
significance, to Yellow, a finding of substantial safety significance. For the quantitative
evaluation, the flood frequency was varied from 1E-4/yr to 1E-6/yr. The probability of
reactor pressure vessel leakage requiring inventory makeup was varied from 1.0,
makeup would always be required, to .02, makeup would be required 2 percent of the
time. To represent the change in risk due to the performance deficiency, the SRA
assumed that reactor pressure vessel (RPV) makeup during the flood would not be
successful and that makeup after the flood would have a failure probability ranging from
0.1 to 0.5. For the base case, absent the performance deficiency, the SRA assumed
that a makeup strategy would be available both during and after the flood and that the
nominal failure probability would be much lower than in the performance deficiency case.
For the evaluation of the qualitative decision-making attributes, the NRC determined that
defense-in-depth, safety margin, and the period of time the performance deficiency
existed were the most important factors.
32 Enclosure
The flood procedure did not provide for defense-in-depth for reactor inventory control
during a flood event. A flood greater than elevation 517.5 ft will fail sources of reactor
inventory makeup including feedwater, condensate, control rod drive injection, fire
pumps, service water and all ECCS. Recovery of plant systems after the flood is not
likely to be successful and the use of alternate temporary systems after the flood
recedes was not specified in the flood procedure. Plant shutdown under flooding
conditions would require the implementation of many diverse plant procedures which are
not well integrated into the flood procedure. The lack of integrated procedures combined
with the lack of flood level predictive capabilities could result in variable plant conditions
at the onset of significant flood impacts. As a result, the need for inventory makeup
during the flood is possible. Also, the defense-in-depth barriers of secondary
containment and primary containment are degraded during the implementation of the
flood procedure.
The licensee did not have an administrative limit for reactor operation with reactor vessel
leakage, only TS limits. The lack of a conservative limit allowed no safety margin
between operational practices and TS limits.
The performance deficiency represents a longstanding issue. In 1982 the PMF scenario
was initially identified. The licensee had the potential to identify that, during an extended
site inundation flooding event, there would be a need to have planned actions to
maintain RPV inventory but did not identify that need until the lack of a proceduralized
method was questioned by the NRC.
A SERP held on April 18, 2013, made a preliminary determination that the finding was of
low to moderate safety significance (White) based on the quantitative and qualitative
evaluations. Considerations involved in that determination included the minimal defense
in depth for addressing reactor vessel makeup, lack of administrative limits for reactor
vessel leakage, that during a flooding event the operators would be required to
implement numerous procedures which did not appear to be well integrated into the
flooding response procedure, that the licensee had numerous opportunities recently and
in the past to identify and then address the deficiency of not addressing a reactor
makeup method, and the length of time the performance deficiency existed.
The inspectors determined that this finding has a cross-cutting aspect in the area of
Problem Identification and Resolution, CAP, Self and Independent Assessments, since it
involves the failure to identify the lack of procedural steps to address a critical function
during a comprehensive self assessment of the flooding strategy. Specifically, the
licensee failed to conduct a self assessment with sufficient depth when reviewing the
sites flooding strategy during a reasonable simulation and comprehensive flooding
strategy site walk down in August 2012. (P.3(a))
Enforcement: Technical Specification 5.4.1 requires in part, that written procedures be
established, implemented, and maintained covering the following activities: the
applicable procedures recommended in Regulatory Guide (RG) 1.33. Revision 2,
Appendix A, February 1978. RG 1.33. Revision 2, Appendix A, Paragraph 6, addresses
Procedures for Combating Emergencies and Other Significant Events and Item w
addresses Acts of Nature (e.g ., tornado, flood, dam failure, earthquakes). An AV of
TS 5.4.1 has been identified in that, from February 20, 1991, to November 21, 2012, the
licensee failed to ensure procedures existed which ensured reactor vessel inventory
could be maintained during external floods. Specifically, DOA 0010-04, Floods, did not
33 Enclosure
account for reactor vessel inventory make up during an external flooding scenario up to
and including the probable maximum flood event which could result in reactor vessel
water level lowering below the top of active fuel. (AV 05000237/2013002-02;
05000249/2013002-02, Deficiency In Abnormal Operating Procedures for Site
Response to External Flooding Events)
This finding does not represent an immediate safety concern. The licensee entered this
issue into the corrective action program as IR 1485203, NRC Question Regarding
External Flooding. Corrective actions completed include, implementation of a TSG-3,
Attachment T, as of November 21, 2012, for reactor vessel inventory make up with the
diesel flood pump and revising DOA 0010-04 requiring operators to isolate the reactor
recirculation loops in order to minimize reactor coolant system leakage.
The inspectors intend on observing the licensees additional modifications and
simulations of the flood strategy and the maintenance and control of flood strategy
equipment through the annual external flooding inspection sample as governed by
Inspection Procedure 711111.01, Adverse Weather Protection.
.4 Selected Issue Follow-Up Inspection: Corrective Actions Following Identification of a
Potential Non-conservative Technical Specification
a. Inspection Scope
The inspectors reviewed plant design analysis and licensee actions to correct a potential
non-conservative technical specification. Technical Specification 3.6.2.5, Drywell to
Suppression Chamber Differential Pressure, potentially did not address design basis
accident impacts on the containment. Following a Safety Communication from General
Electric in July 2002, the licensee determined that TS 3.6.2.5 was potentially non-
conservative in that the limiting condition for operations (LCO) action did not establish
plant conditions which addressed the effects on containment of a design basis loss of
coolant accident (LOCA). Specifically, in August 2002, the licensee implemented the
administrative controls of NRC Administrative Letter 98-10, Dispositioning of TSs that
are Insufficient to Ensure Plant Safety, for maintaining adequate differential pressure
between the drywell and the suppression pool (torus). Subsequent to establishing
administrative controls, the licensee has not submitted a license amendment to address
the technical specification.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Observations
On July 26, 2002, General Electric published Safety Information Communication
SC02-10, Drywell-to-Wetwell Differential Pressure Control TS for Some Mark I
Containments, in which it was discussed that BWR with Mark I containments requiring a
differential pressure of at least 1 psid between the drywell and the torus could be at risk
due to the effects of pool swell loads during a design basis LOCA. Specifically, if the
1 psid differential pressure was not maintained, excessive water columns would form in
the downcomer lines in the torus increasing the severity of pool swell loading on the
containment during a design basis LOCA event. The Safety Communication also noted
that the governing TS, TS 3.6.2.5, for plants with Improved Standard TSs allowed for
continued operation for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with differential pressure conditions less than 1 psid
34 Enclosure
and then required the licensee to lower reactor power below 15 percent rated thermal
power (RTP) within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This subsequent step of reducing power below 15 percent
RTP does not address the concern of a pressure surge in the drywell, resulting from a
LOCA, driving water in the downcomer vents into the torus and creating excessive swell
loading. Reactor pressure and temperature would remain constant when power was
reduced below 15 percent RTP and as a result the drywell pressure conditions driving
the water columns would be unaffected by the power change. In order to remove the
driving force of the LOCA event on containment when differential pressure could not be
maintained greater than 1 psid, the reactor coolant system would need to be cooled and
depressurized.
Following this safety communication, the licensee took administrative actions
establishing an Operations Standing Order, Unit 2/3 Standing Order 02-05, on
August 14, 2002, which required placing the affected unit in Mode 3 (hot shutdown)
within 55 hours6.365741e-4 days <br />0.0153 hours <br />9.093915e-5 weeks <br />2.09275e-5 months <br /> and Mode 4 (cold shutdown) within 79 hours9.143519e-4 days <br />0.0219 hours <br />1.306217e-4 weeks <br />3.00595e-5 months <br /> of entering Condition B of
TS 3.6.2.5 which itself required reducing power below 15 percent RTP within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of
entry. In October 2002, the license performed a bounding analysis to determine an
acceptable allowed outage time based on the frequency of a seismically induced LOCA.
This analysis was used in establishing Technical Requirements Manual (TRM) 3.6.c,
Drywell-to-Suppression Chamber Differential Pressure which replaced Operations
Standing Order 02-05 in October 2003. Section 3.6.c of the TRM required in part, that if
drywell to torus differential pressure cannot be restored to greater than 1 psid within
67 hours7.75463e-4 days <br />0.0186 hours <br />1.107804e-4 weeks <br />2.54935e-5 months <br />, the affected unit must placed in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within
36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This procedure remains in effect at the time of writing this report. Based on
the incorrect assumption that the Boiling Water Reactor Owners Group (BWROG) was
going to review this generic issue and recommend industry wide actions, the licensee
failed to submit a license amendment request regarding the potentially non-conservative
TS 3.6.2.5 and has operated with administrative controls in place since August 2002.
The inspectors noted the licensee performed a Plant Unique Analysis Report (PUAR) in
May 1983 in response to NUREG 0661, Mark I Containment Long-Term Program. In
this analysis the licensee calculated stresses on the torus and piping and components
within the torus during a design basis LOCA under differential pressure conditions of
greater than 1 psid and zero psid. In both instances, the stress and pressure values
determined were well within the structural capacity of the torus and the components
within it. This PUAR was reviewed and accepted by the NRC as documented by Safety
Evaluation By the Office of Nuclear Reactor Regulation Related to Mark I Containment
Long-Term Program Pool Dynamic Loads Review Commonwealth Edison Company
Docket Numbers 50-237/249, dated September 18, 1985. With this approved analysis
on record, the inspectors determined that TS 3.6.2.5 was not non-conservative as the
site maintains an approved design analysis showing that even under zero differential
pressure conditions in the containment at the initiation of a design basis accident, the
containment would not be adversely affected. The inspectors determined that the
actions of TS 3.6.2.5 were ineffective in addressing the design basis behind the
existence of the requirement to maintain a differential pressure between the drywell and
the torus and was potentially in conflict with licensees TRM 3.6.c actions. The licensee
has entered this condition into its corrective action program as IR 117545 and is
considering submitting a License Amendment Request to address this specification.
35 Enclosure
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)
.1 Unit 3 Downpower Due to Bearing Number 11 High Temperature
a. Inspection Scope
The inspectors reviewed the licensees response to degrading conditions on Unit 3 main
turbine bearing no. 11 first identified on January 27, 2013. At approximately 0530, main
control room operators noted the start of an increasing trend in bearing no. 11
lubricating oil temperature, metal temperature and vibrations. Bearing no. 11 is located
between the alterex exciter and the main generator supporting the Unit 3 main turbine
shaft.
As conditions worsened in the early morning hours of January 28, 2013, operators
reduced power a total of 220 MWe over the course of several hours in order to maintain
bearing temperatures below upper limits. The potential to develop AC or DC voltages in
the main turbine shaft in the vicinity of the main generator and exciter is not uncommon
and is normally mitigated by grounding brushes which are tensioned in contact with the
main turbine shaft. If the grounding brushes do not direct current flows to ground, then
arcing between the shaft metal and the bearing metal will begin to degrade the bearing.
The Operations personnel initial attempt to determine the status of the grounding
brushes by a visual inspection could not identify the tension with which they were
making contact with the shaft. This attempt to determine the status of the grounding
brushes delayed the licensees eventual recovery from the condition as management
believed initially that the brushes were performing their function. On the evening of
January 28, 2013, licensee electrical maintenance personnel performed troubleshooting
under Work Order 01610877-09 and discovered that the shaft grounding brushes were
not properly tensioned and corrected the condition. Bearing vibrations immediately
returned to a stable, normal value. Bearing metal and oil temperatures stabilized at a
slightly higher than normal value.
The licensee performed bearing analysis measurements with the bearing vendor and
identified that the bearing had sustained minor damage, but would be able to continue
operations at full power conditions for the remainder of the planned operating cycle. The
licensee developed and implemented a detailed adverse condition monitoring plan for
control room and field operators to perform in order to ensure bearing parameters
remain stable during the operating cycle. In addition, a root cause analysis performed
by the licensee identified that a miscommunication between licensee mechanical and
electrical maintenance staff during plant restoration coming out of refueling outage
D3R22 in December 2012 resulted in the shaft grounding brushes being installed on
their brackets without being tensioned in place. Licensee corrective actions include
revising model work orders for turbine shaft grounding equipment to include vendor
manual steps to verify correct adjustment with completion signature required.
On January 29, 2013, the licensee restored Unit 3 to full power conditions. The
inspectors observed main control room operations throughout this event, reviewed
licensee troubleshooting plans, bearing analysis results, adverse condition monitoring,
and the eventual root cause analysis.
Documents reviewed in this inspection are listed in the Attachment to this report.
This event follow-up review constituted one sample as defined in IP 71153-05.
36 Enclosure
b. Findings
No findings were identified.
4OA5 Other Activities
.1 (Closed) Unresolved Item 05000237/2011004-01; 05000249/2011004-01,
Classification of Emergency Diesel-Driven Flood Pump to Required Quality Standards
a. Inspection Scope
The inspectors reviewed the unresolved item and additional documentation provided by
the licensee regarding the safety classification status of the emergency diesel-driven
flood pump to determine the proper safety classification of the pump.
b. Findings
Introduction: The inspectors identified an unresolved item regarding the safety
classification of the emergency diesel-driven flood pump.
Description: On April 8, 2011, the inspectors observed the performance of WO 872864,
D2/3 6Y PM Emergency Diesel Pump (Flood Pump) Operation. After the surveillance
was completed, the inspectors reviewed the completed work package and identified that
the work instructions did not include acceptance criteria.
Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Quality Assurance
Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, establishes quality
assurance requirements for the design, manufacture, construction, and operation of
structures, systems and components that prevent or mitigate the consequences of
postulated accidents that could cause undue risk to the health and safety of the public.
The pertinent requirements of this appendix apply to all activities affecting the safety-
related functions of those structures, systems, and components.
Appendix B, Criterion XI, Test Control, requires that licensees establish a test program
to assure that all testing required to demonstrate that structures, systems, and
components will perform satisfactorily in service is identified and performed in
accordance with written test procedures which incorporate the requirements and
acceptance limits contained in applicable design documents. Hence, the inspectors
questioned whether the test procedure for testing the emergency diesel-driven flood
pump should have had acceptance criteria to demonstrate that the flood pump would
perform satisfactorily in service.
Upon further discussions with the licensee, the inspectors noticed that in early 2007,
the flood pump was reclassified as non-safety-related. Based on the definition of
safety-related systems, structures and components, as described in 10 CFR 50.2,
Definitions, and based on the fact that the flood pump is utilized to mitigate the
consequences of an event described in Section 3.4.1.1, External Flood Protection
Measures, of the Dresden UFSAR, the inspectors were concerned that the flood pump
had been misclassified as non-safety and it should have been classified as a
safety-related piece of equipment. The licensee was unable to produce documentation
that explained the rationale behind the safety downgrade.
37 Enclosure
Upon further evaluation, the inspectors determined that flooding cannot be considered a
Design Basis Event because Dresdens original license was issued describing the plant
as a dry site. Even though the full term license for Unit 2 was issued incorporating the
Systematic Evaluation Program (SEP) requirement for a Flooding Emergency Plan, the
SEP did not require any backfits. The Emergency Flood Plan is a license requirement
because it was incorporated into the Full Term Operating License for Unit 2. Therefore,
since flooding is not a Design Basis Event, the emergency diesel-driven flood pump
would not be required to be safety-related.
This Unresolved Item is closed.
4OA6 Management Meetings
.1 Exit Meeting Summary
On April 8, 2013, the inspectors presented the inspection results to Mr. D. Czufin, and
other members of the licensee staff. The licensee acknowledged the issues presented.
The inspectors verified that no proprietary information was retained by the inspectors or
documented in this report.
.2 Interim Exit Meetings
Interim exits were conducted for:
- The inspection results for the areas of radiological hazard assessment and
exposure controls; and radioactive gaseous and liquid effluent treatment with
Mr. S. Marik, Plant Manager, on February 1, 2013.
- The preliminary White determination for the finding associated with the plants
flooding response procedure with Mr. S. Marik on April 19, 2013.
The inspectors confirmed that none of the potential report inputs discussed were
considered proprietary.
ATTACHMENT: SUPPLEMENTAL INFORMATION
38 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
D. Czufin, Site Vice President
S. Marik, Station Plant Manager
J. Biegelson, Engineering
H. Bush, Radiation Protection Manager
J. Cady, Radiation Protection Manager
P. Chambers, Dresden Licensed Operator Requalification Training Lead
P. DiSalvo, GL 89-13 Program Owner
H. Do, Corporate ISI Manager
D. Doggett, Emergency Preparedness Manager
H. Dodd, Regulatory Assurance Manager
J. Fox, Design Engineer
D. Glick, Radioactive Material Shipping Specialist
G. Graff, Nuclear Oversight Manager
M. Hosain, Site EQ Engineer
R. Johnson, Chemist RETS/ODCM
B. Kapellas, Operations Director
D. Ketchledge, Engineering
J. Knight, Director, Site Engineering
M. Knott, Instrument Maintenance Manager
J. Kish, Site ISI
S. Kvasnicka, NDE Level III
D. Leggett, Chemistry Manager
T. Mohr, Supervisor, Engineering Programs
P. Mankoo, Radiation Protection
G. Morrow, Shift Operations Superintendent
M. McDonald, Maintenance Director
T. Mohr, Programs Engineering Manager
P. OBrien, Regulatory Assurance - NRC Coordinator
D. OFlanagan, Security Manager
M. Otten, Operations Training Manager
R. Ruffin, Licensing Engineer
J. Sipek, Work Control Director
R. Sisk, Buried Pipe Program Owner
L. Torres, Engineering
Nuclear Regulatory Commission
J. Cameron, Chief, Division of Reactor Projects, Branch 6
L. Kozak, Senior Risk Analyst
R. Zuffa, Illinois Emergency Management Agency
1 Attachment
ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000237/2013002-01 FIN Failure to Include Adequate Acceptance Criteria in a
05000249/2013002-01 Surveillance Test (1R01.3)05000237/2013002-02 AV Deficiency In Abnormal Operating Procedures for Site
05000249/2013002-02 Response to External Flooding Events (Section 4OA2.3)
Closed
05000237/2013002-01 FIN Failure to Include Acceptance Criteria in a Surveillance
05000249/2013002-01 Test. (1R01.3)05000237/2011003-01 URI Failure to Include Adequate Acceptance Criteria in a
05000249/2011003-01 Surveillance Test (1R01.3)05000237/2011004-01 URI Classification of Emergency Diesel-Driven Flood Pump to
05000249/2011004-01 Required Quality Standards (4OA5)
Discussed
05000237/2004010-02 NCV Source of Make-up Water (1R01.3)05000249/2004010-02
05000237/2006010-04 URI Full Flow Testing of the Diesel Driven Flood Pump at
05000249/2006010-04 Design Conditions (1R01.3) URI was closed in
IR 05000237/2007003, 05000249/2007003
05000237/2007003-04 NCV Failure to Identify and Correct Issues with the Operation
05000249/2007003-04 and Testing of the Diesel Driven Pump Used to Respond
to External Flooding (1R01.3)
2 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or 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.
1R01 Adverse Weather Protection (71111.01)
- OP-AA-108-107-1001, Station Response to Grid Capacity Conditions, Revision 4
- OP-AA-102-102, General Areas Checks and Operator Field Rounds, Revision 12
- IR 1465907, NRC Senior Resident Question
1R04 Equipment Alignment (71111.04)
- DOP 1300-M1/E1, Unit 2 Isolation Condenser System, Revision 17
- Drawing M-28, Diagram of Isolation Condenser Piping
- NRC Inspection Report 05000219/2012005, 10/01/2012 - 12/31/2012; Exelon Energy
Company, LLC, Oyster Creek Generating Station
- Exelon Oyster Creek Procedure 2400-GMM-3900.52
- IR 1487125, U2 Isolation Condenser Support Nut Engagement Deficiency
- DOP 1300-M1/E1, Unit 3 Isolation Condenser, Revision 23
- WO 1571975-13, Weld Map for HPCI Drain Line Replacement of Chrome-Moly Piping with
Stainless Steel Pipe
- DOP 2300-M1/E1, U2 HPCI System Checklist, Revision 38
- Drawing M-51, Diagram of High Pressure Coolant Injection Piping
- SA-AA-141, Management & Control of Hexavalent Chromium During Welding, Cutting, and
Grinding Activities, Revision 1
1R05 Fire Protection (71111.05)
- CALCULATION: DRE97-0105, Determination of Combustible Loading, Revision 8
- Dresden Station Units 2 and 3, Commonwealth Edison Company, Fire Protection Reports,
Volume 4, Interim Measures/Exemption Requests, Section 3.5, Justification for Lack of
Complete Detection and Suppression in Fire Area TB-II.
- Dresden Station Units 2 and 3, Commonwealth Edison Company, Fire Protection Reports,
Volume 1, Updated Fire Hazards Analysis
- Dresden Station Units 2 and 3, Commonwealth Edison Company, Fire Protection Reports,
Volume 4, Interim Measures/Exemption Requests, Section 3.5, Justification for Lack of
Complete Detection and Suppression in Fire Area RB2-II
- IR 1485984, NRC Question on Fire Protection
- IR 1485977, Fire Protection - Pre-Fire Plans
1R06 Flooding (71111.06)
- WO 01505382, Need WR: U3 CCSW VLT Drain CHK VLV Replace with SR Comp.
- WO 01297399-01, D3 8Y PM Perform Check Valve Inspection 3-4999-75
- IR 1477386, Threaded Elbow Degraded and in Need of Replacement
- IR 1477499, Slow Draining During Performance of DOS 4400-01
3 Attachment
1R11 Licensed Operator Requalification Program (71111.11)
- IR 1467190, Apparent Cause Report - Dresden High Exam Failure Rate During LORT Cycle
Exam
1R12 Maintenance Effectiveness (71111.12)
- IR 1448857, Request Design Engineering to Review HELB Barriers for MRule
- IR 1486451, NRC Identified Editorial Error in MRULE A3 Assessment
- Maintenance Rule Periodic Assessment no.9 (10CFR50.65(a)(3) Assessment) Assessment
Period 10/1/2010 - 9/30/2012
- DES 6700-09, Revision 23, Inspection and maintenance of General Electric MC-4.76
Horizontal Draw-out Metal Clad Switchgear
- MA-DR-067-002, Circuit Breaker Control Revision 0
- MA-DR-725-113, Inspection and Maintenance of General Electric 4 KV Magne-Blast Circuit
Breakers Types AMH4.76-250 (Horizontal Drawout), Revision 04
- MA-DR-773-302, Dresden Standby Diesel Generator 2 and 4 KV ACB 2422 Control Circuit
Checks Revision 09
- IR 1374783, Maintenance Rule Function Z67-3 At Risk
- IR 1364609, Result of 4KV BKR Delayed Closing Failure Analysis Report
- IR 1303972, 4KV Breaker Cubicle MOC Switch Parts Issues
- IR 1282685, Breaker Did Not Reclose in Test Position During Surveillance
- IR 1281382, Potentially Deficient Prop Spring Bracket hardware 4KV BKR
- IR 1280299, 4KV Cubicle MOC Switch Rubber Bumper Degrading (New)
- IR 1251072, 1-6712-8, Main Feed to Bus 15 from Bus 12 BRKR Will Not Close
- IR 1216097, HCCT no.3 Pump Motor Breaker Will Not Rack In
- IR 1191551, 4KV Merlin Gerin Circuit Breaker B Phase Bottle Cracked
- IR 1472026, Over Voltage Relay Flag Is Up
- IR 1437824, 4KV Breaker UTC 2861736 Does Not Charge Consistently
- IR 1361972, Results of Troubleshooting, 4KV Breaker Charging Motor
- IR 1399081, NRC Concern - Historical Operability for 2A CCSW PP Breaker
- IR 13339668, Product Advisory Letter Not Incorporated Into Breaker Insp.
- IR 1232355, Streamline 4160V Breaker Trip/Close Fuse Replacements
- IR 1280668, Bus 23 Undervoltage Load Shed
- WO 1064044, 16Y PM Overhaul 4KV Breaker UTC 997129
- IR 1482952, Engineering Requests ACE - 125VDC PCM Template
- IR 1437844, TS Required Paperwork Not Submitted for Record Retetention
- IR 1443849, Feed Breaker Not Operating Properly D3R22SU
- IR 1471251, 2D LPCI Pump Breaker Will Not Charge Springs
- IR 1477941, MRULE: 4KV Breaker Performance Criteria is Non-Conservative
- IR 1443228, MRULE: System 67, MPFF is a RMPFF
- IR 1441171, Bus 33 CUB 10, Bus 33-1 Feed Breaker Wont Close
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
- OP-AA-108-117 Rev.3
- IR 1478889, NRC Inspector Questioned Shift on PPW for SBLC
- Ops Policy 02, Attachment B - Protected Equipment List
4 Attachment
1R15 Operability Determinations and Functional Assessments (71111.15)
- Calculation DRE98-0030, Rev. 0, Determination of Setpoint of CST Low-Low Level Switches
to Prevent Potential Air Entrainment form Vortexing During HPCI Operation.
- IR 1453700, Key Calc Review Identifies Issues in DRES98-0030
- EC 391829, Evaluation of Issues Identified in Calculation DRE98-0030, Revision 0
- EC 360021, Reroute of the Buried HPCI Cross-Tie Piping, Revision 1
- Drawing M-197, Sheet 11 Piping Isometric HPCI Cross-Tie 2/3-3327A-16
- Drawing M-197, Sheet 1 Outdoor Piping
- WO 01575845, Dresden 3 Quarterly Technical Specification HPCI Motor Operated Valve
Operability Surveillance, Revision 1
- IR 1455933, U3 HPCI Valve Found in Alert Range During Valve Timing
- Drawing M-347. Diagram of Reactor Feed Pump
- Drawing M-374, Diagram of High Pressure Coolant Injection Piping
- ER-AA-321, IST Valve Evaluation Form, Revision 12
- Dresden Updated Final Safety Analysis Report (UFSAR), Section 5.2.5, Detection of Leakage
Through Reactor Coolant Pressure Boundary
- IR 128973, NRC Drywell closeout inspection items
- OP-DR-108-111-1003, Drywell Leakage Troubleshooting, Revision 03
- DOS 1600-29, Unit 2 and 3 Drywell Temperature Surveillance, Revision 5
- DAN 902(3)-5 F-3, Rod Drive Temp Hi, Revision 15
- DAN 902(3)-4 C-17,Drywell Equip Sump Temp Hi, Revision 8
- IR 1487125, U2 Isolation Condenser Support Nut Engagement Deficiency
- IR 1487131, U3 Isolation Condenser Support Nut Engagement Deficiency
- MA-MW-736-600, Torquing and Tightening of Bolted Connections, Revision 5
- Drawing ISI-201, Inservice Inspection Class II Isolation Condenser Piping
- Drawing ISI-206, Inservice Inspection Class II Isolation Condenser Piping
- Drawing ISI-307, Inservice Inspection Class III Isolation Condenser and Vent Piping
- Drawing ISI-305, Inservice Inspection Class III Isolation Condenser and Vent Piping
- Drawing Hanger M-1163D-553
- Drawing Hanger M-1199D-1022
- Drawing Hanger M-1199D-1023
- Drawing Hanger M-1199D-1024
- Drawing Hanger M-1163D-554
- Drawing Hanger M-1163D-555
- EC 388891, 2013: Unit 2 SR 480V Bucket Replacement Project, Revisions 0 and 1
1R18 Plant Modifications (71111.18)
- 50.59 Screening No. 2013-0064, Unit 3 Main Steam Line Isolation Valve Closure Scram
Circuit Functional Test
- Drawing 12E-3466, Schematic Diagram Reactor Protection System Channel B Scram &
Auxiliary Trip Relays, Sheet No. 1
- Drawing 12E-3464, Schematic Diagram Reactor Protection System Channel B Trip Aux.
Relays, Sheet No. 2
- IR 1484861, U3 C Main Steam Line Limit Switch Failure
- DOS 0500-27, Unit 3 main Steam Line Isolation Valve Closure Scram Circuit Functional
Test, Revision 1
5 Attachment
1R19 Post-Maintenance Testing (71111.19)
- IR 1465026, Broken Motor Cooling Blades
- WO 1418376, Dresden Unit 2 Two Year PM Standby Diesel Generator Inspection
- IR 1475119, Re-occurring Unexpected Unit 2 EDG Alarm, February 14, 2013
- DOS 6600-01, Diesel Generator Surveillance Tests, Revision 122
- WO 1605861, D2 Quarterly TS HPCI Pump Operability Test and IST Surveillance
- IR 1488336, NRC Identified Housekeeping Issues in the U2 HPCI Room
- WO 1423633, D3 2Y TS HPCI Pump Comprehensive Oper Test and IST Surv
- IR 1490995, Unexpected Alarm HPCI Room Sump Level High
- IR 1492807, Newly Replaced Valve Leaks Past Seat for D2/3 EDG
- WO 1424316-03, D2/3 2 year PM Diesel Generator Engine Temperature Instrument CAL -
Check for Leaks
- WO 681423, D2/3 4year Inspect Cubicle 3 at Bus 40 (Bus Tie to Bus 23-1) - Perform PMT on
Bus 40C
- DOS 6600-01, Diesel Generator Surveillance Tests, Revision 122
1R22 Surveillance Testing (71111.22)
- DOS 1500-10, LPCI System Pump Operability and Quarterly Test with Torus Available and
Inservice Test, Revision 67
- DIS 1500-09, Revision 19, LPCI Reactor Recirculating Pump A and B Differential Pressure
Indicating Switch Calibration and Channel Functional Test
- IR 1462734, Data Transfer Error Discovered During Review of DIS 1500-09
- IR 1461469, Old Word Perfect Symbol Caused < or = to become > or =, January 11, 2013
- Drawing M-357, Sheet 2, Diagram of Nuclear Boiler & Reactor Recirculating Piping
- Drawing 12E-3437A, Schematic Diagram LPCI Containment Cooling System
- Drawing 12E-3438A, Schematic Diagram LPCI Containment Cooling System
- DOP 2000-180, Drywell Sump Operation With Unit On-Line, Revision 04
- Appendix A, Unit Daily Surveillance Log, Attachment A, Eight Hour Shifts, Revision 129
- DES 0040-02, 600 Volt Butyl Cable EQ Surveillance, Revision 10
- DFPS 4123-05, 2/3 Diesel Fire Pump Operability, Revision 50
- Electrical Drawing 12E-2750A, Sheet 1, Wiring Diagram Feedwater and Recirculation
Panel 9
- Electrical Drawing 12E-2424, Sheet 1, Schematic Diagram Recirculating Pump Speed
Control
- WO 1396238, D2 2Y PM&C Recirc Flow Dual Limiter 262-26B
- WO 1579759, D2 QTR TS LPCI System Pump Run and IST Surveillance
1EP6 Drill Evaluation (71114.06)
- IR 1472861, EP DEP Failure During TSC Focus Area Drill, February 8, 2013
- IR 1474238, NOS ID: DEP Failures Identified as Level 4 Issue Reports, February 12, 2013
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
- RWP 10014505; 2013 Radwaste Concentrated Waste Vault Sludge Removal; Revision 0
- Unit 2/3 Radwaste EL 517 Reboiler Area Survey Map; January 8, 2013
- Unit 2/3 Radwaste EL 517 Reboiler Area Survey Map; January 16, 2013
- Unit 3 reactor 570 Fuel Pool Cleanup Pump/Heat Exchanger Area; January 8, 2013
6 Attachment
- RWP 10014505; 2013 Radwaste Concentrated Waste Vault Sludge Removal; WO 1221622;
Vacuum Vessel Full Sludge from the Concentrated Waste Vault; ALARA Plan; January 29,
2013
- RWP 10014505; 2013 Radwaste Concentrated Waste Vault Sludge Removal; Barnhart to
Remove Floor Plugs in the B Concentrator Vault for Prep of the CW Vault; January 24, 2013
- RWP 10014505; 2013 Radwaste Concentrated Waste Vault: Decon Area Remove Misc Bags
and Parts from Area at 517 Reboiler; ALARA Briefing Checklist RP-AA-401
2RS6 Radioactive Gaseous and Liquid Effluent Treatment (71124.06)
- CY-DR-170-220; Revision 5; Unit 2 and 3 Reactor Building Vent Noble Gas Sampling;
January 31, 2013
- DIS-1700-14; Unit2/3 Reactor Building Vent Stack SPING Calibration; November 2, 2012
- RP-AA-605; Waste Stream Results Review Part 61; May 11, 2012
- R-01398192; Document Request of the Licensees Process Monitor Setpoint Bases;
August 7, 2012
- DIS-1700-14; Unit2/3 Main Chimney SPING Calibration; February 2, 2012
- DIS-1700-14; Unit2/3 Main Chimney SPING Calibration; February 19, 2012
- WC-AA-104;Quarterly Tech Spec Reactor Building Vent Radiation Monitor Calibration and
Functional Tests; January 24, 2013
- L53233; Teledyne Brown; Report of Analysis/Certificate of Conformance; Waste Surge Tanks
Sampling Wells; January 15, 2013
- L533074; Teledyne Brown; Report of Analysis/Certificate of Conformance; Steam Dryer
Mausoleum Sampling Wells; January 30, 2013,
- AR-01322619; Unable to Complete Sample Line Inspection for Chimney SPING; February 3,
2012
- AR-01322619; Engineering Evaluation for Visual Inspection of Sample Lines from the SPING
to Chimney; March 23, 2012
- WO 1337345; 24 Month Tech Spec.(TS) Reactor Building Vent Sampler Flowmeter
Calibration; May 5, 2012
- WO 1575796; D3 Quarterly TS Reactor Vent Radiation Monitor Calibration and Functional;
December 20, 2012
- WO 1236618; D3 TS Reactor Building Vent Sampler Flowmeter Calibration; April 15, 2011
- AR-01305481; D2/3 Main Chimney SPING not Responding During Calibration; February 4,
2012
- AR-01329443; Unexpected Alarm on the Liquid Process Rad Monitor; February 12, 2012
- AR-01330334; Liquid Process Rad Monitor Downscale; February 22, 2012
- AR-01397142; Liquid Process Rad Monitor Alarms on Unit-2 and Unit-3; August 4, 2012
- AR-01392741; HPGE Detector Failed Multiple Performance Checks; July 27, 2012
- AR-01392819; Out of Calibration RP Instrument Found in Plant; July 25, 2012
4OA1 Performance Indicators (71151)
- NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6
- Unit 2 and 3 Performance Indicator data for First through Fourth Quarter 2012
4OA2 Identification and Resolution of Problems (71152)
- EP-AA-1004, Radiological Emergency Plan Annex For Dresden Station, Revision 29
- IR 1453073, NRC Question on TSG 3 Strategies
- IR 1469502, CDBI-2013 IC Diesel Makeup Pump Building Foundation Buoyancy
7 Attachment
- IR 1485203, NRC Question Regarding External Flooding
- IR 1482141, EC 391644 Approved Prior to Affected Calculation Approval
- EP-AA-1004, Exelon Nuclear Radiological Emergency Plan Annex For Dresden Station,
Revision 29
- DOA 0010-04, Floods, Revision 32
- DOA 0010-04, Floods, Revision 37
- Calculation DRE01-030, Probable Maximum Flood Effects at the ISFSI Pad, Revision 0
- Drawing M-23 Sheet 3, Diagram of Fire Protection Piping
- Drawing M-33, Diagram of Standby Liquid Control Piping
- TSG-3, Operational Contingency Action Guidelines, Revision 10
- TSG-3, Attachment H, RPV Injection Using Portable Diesel Driven Pump
- TSG-3, Attachment T, Provide RPV Make Up From Fire Protection System Via SBLC
- COM-02-041-2, Plant Unique Analysis Report Volume 2, Suppression Chamber Analysis,
Revision 0, May 1983
- SC02-10, GE Nuclear Energy Safety Communication, Drywell-to-Wetwell Differential
Pressure Control Technical Specification for Some Mark I Containments, July 26, 2002
- SA-1115, Significance of Seismic-Induced LOCAs at Dresden, Revision 1
- OP-AA-102-104, U2/3 Standing Order, Tech Spec LCO 3.6.2.5 Supplemental Administrative
Actions, Revision 0
- Commitment Letter from Commonwealth Edison to Mr. Paul OConnor, SEP Topic II-3.B,
Flooding Potential and Protective Requirements; II-3.B.1, Capability of Operating Plants to
Cope with Design Basis Flood Conditions; and II-3.C, Safety Related Water Supply (Ultimate
Heat Sink), Dated November 17, 1982
- Letter from NRC to Licensee, Request for a Written Response to NRC Observations and
Concerns Regarding Dresden Station Response Plan for External Flooding Events, Dated
November 1, 2012
- Letter from Mr. David Czufin to NRC, Response to NRC Request for a Written Response to
NRC Observations and Concerns Regarding Dresden Station Response Plan for External
Flooding Events, Dated December 1, 2012
- Letter from NRC to Licensee, Acknowledgement of Response to NRC Request for a Written
Response to NRC Observations and Concerns Regarding Dresden Response Plan for
External Flooding Events, Dated January 3, 2013
- Letter from Mr. David Czufin to NRC, Response to Acknowledgement of Response to NRC
Request for a Written Response to NRC Observations and Concerns Regarding Dresden
Response Plan for External Flooding Events, Dated January 31, 2013
- GE Safety Information Communication, Drywell to Wetwell Differential Pressure Control
Technical Specification for Some Mark I Containments, July 26, 2002
- Letter from J. Henry, Evaluation of Entry Into Technical Specification Limiting Condition of
Operation 3.6.25 for Drywell to Suppression Chamber Differential Pressure, October 16, 2002
- IR 117545, DW to Torus DP Control Tech Spec for a Mark I Containment
- 50.59 Screening Form, TRM 3.6 C, 2003-0349, Revision 0
- IR 1490293, De-energized Relay Picked Up
- Letter from NRC to Licensee, Mark I Containment Long Term Program, dated
September 18, 1985
4OA3 Follow Up of Events and Notices of Enforcement Discretion (71153)
- IR 1467631, Unexpected Alarm; 903-8 E-12 U3 Gen/Exc Ground
- IR 1468057, U3 Turbine Shaft Grounding Brushes Found Not Fully Tensioned
- IR 1468569, Follow-Up Actions for Unit 3 Bearing no. 11 Issue
8 Attachment
- IR 1468765, U3 Exciter BRG no. 11 Lube Oil Flow Measurement Not Accurate
- Root Cause Report 1468057-04, Unit 3 Bearing 11 Rising Vibration, Oil & Metal
Temperatures due to Work Order Referenced Vendor Manual Steps without Requiring Step by
Step Worker Sign Offs
- OP-AA-108-111, Unit 3 Bearing 11 Metal Temperature and Vibration, Revision 1
9 Attachment
LIST OF ACRONYMS USED
AC alternating current
ADAMS Agencywide Document Access Management System
ALARA As-Low-As-Reasonably-Achievable
AOP Abnormal Operating Procedure
ASME American Society of Mechanical Engineers
AV Apparent Violation
BWR Boiling Water Reactor
CAP Corrective Action Program
CCSW Containment Cooling Service Water
CDF Core Damage Frequency
CFR Code of Federal Regulations
CRD Control Rod Drive
DC direct currnet
DOA Dresden Abnormal Operating Procedure
DRP Division of Reactor Projects
EAL Emergency Action Level
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
FIN Finding
FLEX Diverse and FLEXIBLE equipment availability program
HPCI High Pressure Coolant Injection
IC Isolation Condenser
IMC Inspection Manual Chapter
INPO Institute of Nuclear Power Operations
IP Inspection Procedure
IR Inspection Report
IR Issue Report
ISI Inservice Inspection
JLD Japan Lessons Learned
LCO Limiting Condition for Operation
LOCA Loss of Coolant Accident
LLC Limited Liability Corporation
LORT Licensed Operator Requalification Training
LPCI Low Pressure Coolant Injection
MSL Mean Sea Level
NCV Non-Cited Violation
NEI Nuclear Energy Institute
NRC U.S. Nuclear Regulatory Commission
OCA Owner Controlled Area
PARS Publicly Available Records System
PI Performance Indicator
PM Planned or Preventative Maintenance
PMF Probable Maximum Flood
PMT Post-Maintenance Testing
psid pounds per square inch differential
psig pounds per square inch gauge
PUAR Plant Unique Analysis Report
RP Radiation Protection
10 Attachment
RTP Rated Thermal Power
SDP Significance Determination Process
SEP Systematic Evaluation Program
SERP Significance and Enforcement Review Panel
SSC Systems, Structures, and Components
SRA Senior Risk Analyst
TAF Top of Active Fuel
TS Technical Specification
TSG Technical Support Guidance
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
Vdc Volts direct current
WO Work Order 11 Attachment
M. Pacilio -2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be available electronically for public inspection in
the NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's Agencywide Document Access and Management 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 Kenneth G. OBrien for/
Steven A. Reynolds, Director
Division of Reactor Projects
Docket Nos. 50-237, 50-249
License Nos. DPR-19 and DPR-25
Enclosure: Inspection Report 05000237/2013002, 05000249/2013002
w/Attachment: Supplemental Information
cc w/encl: Distribution via ListServ
DOCUMENT NAME: G:\DRPIII\Dres\DRES 2013 002.docx See Previous Concurrence
Publicly Available Non-Publicly Available Sensitive Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" =
Copy with attach/encl "N" = No copy
OFFICE RIII RIII RIII RIII RIII
NAME JRutkowski:dtp JCameron LKozak SOrth*PL for SReynolds
- KGO for
DATE 04/25/13 04/25/13 04/25/13 04/30/13 04/07/13
- OE and NRR concurrence on 4/29 via e-mail
OFFICIAL RECORD COPY
Letter to M. Pacilio from J. Cameron dated May 7, 2013.
SUBJECT: DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3, INTEGRATED
INSPECTION REPORT 05000237/2013002, 05000249/2013002
DISTRIBUTION:
RidsNrrDorlLpl3-2 Resource
RidsNrrPMDresden Resource
RidsNrrDirsIrib Resource
Chuck Casto
Cynthia Pederson
DRPIII
DRSIII
Patricia Buckley
ROPreports.Resource@nrc.gov