ML16174A094
| ML16174A094 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 06/22/2016 |
| From: | Jeffers M Division of Reactor Safety III |
| To: | Bryan Hanson Exelon Generation Co |
| References | |
| IR 2016007 | |
| Download: ML16174A094 (47) | |
See also: IR 05000373/2016007
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE RD. SUITE 210
LISLE, IL 60532-4352
June 22, 2016
Mr. Bryan C. Hanson
Senior VP, Exelon Generation Company, LLC
President and CNO, Exelon Nuclear
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2 - NRC COMPONENT
DESIGN BASES INSPECTION, INSPECTION REPORT 05000373/2016007;
Dear Mr. Hanson:
On May 13, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed a Component
Design Bases Inspection at your LaSalle County Station, Units 1 and 2. The enclosed report
documents the results of this inspection, which were discussed on May 13, 2016, with
Mr. Trafton, Site Vice President, and other members of your staff.
Based on the results of this inspection, four NRC-identified findings of very-low safety
significance were identified. The findings involved violations of NRC requirements. However,
because of their very-low safety significance, and because the issues were entered into your
Corrective Action Program, the NRC is treating the issues as Non-Cited Violations in
accordance with Section 2.3.2 of the NRC Enforcement Policy.
If you contest the subject or severity to any of these Non-Cited-Violations, 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 copies to the Regional Administrator, Region III; the Director, Office of
Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the
NRC Resident Inspector at the LaSalle County 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 LaSalle County Station.
B. Hanson -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, 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 NRCs Public Document Room or from the Publicly Available Records (PARS)
component of the NRC's Agencywide Documents 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/
Mark T. Jeffers, Chief
Engineering Branch 2
Division of Reactor Safety
Docket Nos. 50-373; 50-374
Enclosure:
IR 05000373/2016007; 05000374/2016007
cc: Distribution via LISTSERV
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No: 50-373; 50-374
Report No: 05000373/2016007; 05000374/2016007
Licensee: Exelon Generation Company, LLC
Facility: LaSalle County Station, Units 1 and 2
Location: Marseilles, IL
Dates: April 4, 2016 - May 13, 2016
Inspectors: N. Féliz Adorno, Senior Reactor Inspector, Lead
A Dahbur, Senior Reactor Inspector, Electrical
J. Corujo Sandín, Reactor Inspector, Mechanical
D. Reeser, Operations Inspector
J. Leivo, Electrical Contractor
C. Edwards, Mechanical Contractor
Approved by: M. Jeffers, Chief
Engineering Branch 2
Division of Reactor Safety
Enclosure
TABLE OF CONTENTS
SUMMARY ................................................................................................................................ 2
REPORT DETAILS .................................................................................................................... 5
1. REACTOR SAFETY ......................................................................................... 5
1R21 Component Design Bases Inspection (71111.21) ...................................... 5
4. OTHER ACTIVITIES .......................................................................................22
4OA2 Identification and Resolution of Problems.................................................22
4OA6 Management Meetings .............................................................................26
SUPPLEMENTAL INFORMATION............................................................................................. 1
KEY POINTS OF CONTACT .................................................................................................. 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ....................................................... 1
LIST OF DOCUMENTS REVIEWED ...................................................................................... 2
LIST OF ACRONYMS USED.................................................................................................17
SUMMARY
Inspection Report 05000373/2016007; 05000374/2016007, 04/04/2016 - 05/13/2016; LaSalle
County Station, Units 1 and 2; Component Design Bases Inspection.
The inspection was a 3-week onsite baseline inspection that focused on the design
of components. The inspection was conducted by four regional engineering and
operations inspectors, and two consultants. Four Green findings were identified by the
team. These findings were considered Non-Cited Violations (NCVs) of U.S Nuclear Regulatory
Commission (NRC) regulations. The significance of inspection findings is indicated by their
color (i.e., greater than Green; or Green, White, Yellow, and Red) and determined using
Inspection Manual Chapter 0609, Significance Determination Process, dated April 29, 2015.
Cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects Within
the Cross-Cutting Areas, dated December 4, 2014. All violations of NRC requirements are
dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The
NRCs program for overseeing the safe operation of commercial nuclear power reactors is
described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.
NRC-Identified and Self-Revealed Findings
Cornerstone: Mitigating Systems
Green. The team identified a finding of very-low safety significance (Green) and an
associated NCV of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, for the failure to monitor the
fouling conditions of the core standby cooling system (CSCS) equipment area coolers.
Specifically, the licensee did not develop performance test procedures to assess the
fouling conditions of the safety-related CSCS equipment area coolers and did not
have acceptance criteria that delineate when to remove accumulations. The licensee
captured this issue in their Corrective Action Program (CAP) as Action Request
(AR) 02665463 and established a standing order for operations to impose more
restrictive service water temperature limits to reasonably assure the operability of
the affected coolers until long term corrective actions were implemented to restore
compliance.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating System cornerstone attribute of equipment performance
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 finding screened as of very low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee reviewed actual service water temperature values measured
during the last 12 months, performed an operability evaluation, and concluded that the
historical temperatures did not exceed the operability limits established by the operability
evaluation. The team did not identify a cross-cutting aspect associated with this finding
because it was not confirmed to reflect current performance. Specifically, the test
program for the CSCS equipment area coolers was developed in the decade of 1990s.
(Section 1R21.3.b(1))
2
Green. The team identified a finding of very-low safety significance (Green) and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the
failure to have the capability to verify the supply breakers of both reactor units feeding
the swing diesel generator (DG) components were closed during normal plant operation.
Specifically, the circuit design and procedures for the swing DG room fan, fuel oil
transfer pump, and fuel storage tank room exhaust fan did not ensure the detection of
the condition where one of these feeder breakers was tripped in the open position during
normal plant operation. The licensee captured this issue in their CAP as AR 02668759
and created a special log to monitor the associated breakers once per day.
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating System cornerstone attribute of equipment performance
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 finding screened as of very low safety significance (Green) because
it did not result in the loss of system and/or function, represent an actual loss of function
of at least a single train or two separate safety systems out-of-service for greater than its
Technical Specifications (TS) allowable outage time, and represent an actual loss of
function of one or more non-TS trains of equipment designated as high safety-significant
for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, a historical review did not find an example where
the swing DG was non-functional for a period greater than the applicable TS allowable
outage time as a result of this finding during the last year. The team did not identify a
cross-cutting aspect associated with this finding because it was not confirmed to reflect
current performance due to the age of the performance deficiency. Specifically, the
mean to detect an opened breaker associated with the affected loads was established
more than 3 years ago. (Section 1R21.3.b(2))
Green. The team identified a finding of very-low safety significance (Green) and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, for the failure to establish procedures that were appropriate to manage
containment debris consistent with the emergency core cooling system strainer debris
loading design basis and supporting design information. Specifically, the procedures did
not contain instructions for evaluating containment debris sources consistent with the
associated analyses and other design documents. The licensee captured the team
concerns in their CAP as AR 02663076 and AR 02656299. The immediate corrective
actions included an operability evaluation that reasonably determined all of the affected
emergency core cooling system strainers remained operable.
The performance deficiency was determined to be more than minor because it was
associated with the procedure quality attribute of the Mitigating Systems cornerstone,
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 finding screened as of very-low safety significance (Green)
because it did not result in the loss of operability or functionality of mitigating systems.
Specifically, the licensee performed an operability review and reasonably determined
that only a portion of the unqualified coatings would be available for transport to the
strainers and this quantity was bounded by the associated design basis analysis. In
addition, this review reasonably determined that sufficient analytical margin existed to
accommodate the quantities of the other debris types found during recent inspections.
The team did not identify a cross-cutting aspect associated with this finding because it
was not confirmed to reflect current performance due to the age of the performance
deficiency. Specifically, the associated procedures were established more than 3 years
ago. (Section 1R21.4.b(1))
3
Green. The team identified a finding of very-low safety significance (Green) and
associated NCV of the LaSalle County Station Operating License for the failure to
ensure that procedures were in effect to implement the alternate shutdown capability.
Specifically, the abnormal operating procedures (AOPs) established to respond to a fire
at the main control room did not include instructions for verifying that supply breakers for
three reactor core isolation cooling motor-operated valves (MOVs) were closed to
ensure they could be operated from the remote shutdown panel. Fire-induced failures
could result in tripping MOV power supply breakers prior to tripping the MOV control
power fuses. The licensee captured the team concerns in their CAP as AR 02668854
and established compensatory actions to reset the affected breakers, if required
The performance deficiency was determined to be more than minor because it was
associated with the Mitigating Systems Cornerstone attribute of protection against
external events (fire), and affected the cornerstone objective of ensuring the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. The finding screened as of very-low safety significance
(Green) because it was assigned a low degradation factor. Specifically, the procedural
deficiencies could be compensated by operator experience/familiarity and the fact that
the AOPs included steps to verify other breakers at the same locations were closed
would likely prompt operators to close the remaining breakers. The team determined
that this finding had a cross cutting aspect in the area of problem identification and
resolution because the licensee failed to take effective corrective actions for a similar
issue identified in 2014. Specifically, the resolution of this issue included actions to
revise the affected AOPs to include verifying all the reactor core isolation cooling MOVs
supplied breakers were closed. However, the licensee failed to include all of the MOVs
in the revised AOPs. [P.3] (Section 4OA2.b(1))
4
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R21 Component Design Bases Inspection (71111.21)
.1 Introduction
The objective of the Component Design Bases Inspection (CDBI) is to verify that design
bases have been correctly implemented for the selected risk-significant components
and that operating procedures and operator actions were consistent with design and
licensing bases. As plants age, their design bases may be difficult to determine and
an important design feature may be altered or disabled during a modification. The
Probabilistic Risk Assessment (PRA) Model assumes the capability of safety systems
and components to perform their intended safety function successfully. This inspectable
area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity
cornerstones for which there are no indicators to measure performance.
Specific documents reviewed during the inspection are listed in the Attachment of this
report.
.2 Inspection Sample Selection Process
The team used information contained in the licensees PRA and the LaSalle County
Station, Unit 1 and 2, Standardized Plant Analysis Risk Model to identify one scenario to
use as the basis for component selection. The scenario selected was a loss of offsite
power (LOOP) event. Based on this scenario, a number of risk-significant components
were selected for the inspection. In addition, the team selected a risk-significant
component with Large Early Release Frequency (LERF) implications using information
contained in the licensees PRA and the LaSalle County Station, Units 1 and 2,
Standardized Plant Analysis Risk Model.
The team also used additional component information such as a margin assessment in
the selection process. This design margin assessment considered original design
reductions caused by design modifications, power uprates, or reductions due to
degraded material condition. Equipment reliability issues were also considered in the
selection of components for detailed review. These included items such as performance
test results, significant corrective actions, repeated maintenance activities, Maintenance
Rule (a)(1) status, components requiring an operability evaluation, system health
reports, and U.S. Nuclear Regulatory Commission (NRC) resident inspector input of
problem areas and/or equipment. Consideration was also given to the uniqueness and
complexity of the design, operating experience, and the available defense in depth
margins. A summary of the reviews performed and the specific inspection findings
identified are included in the following sections of this report.
The team also identified procedures and modifications for review that were associated
with the selected components. In addition, the team selected operating experience
issues associated with the selected components.
5
This inspection constituted 17 samples (i.e., 11 components, 1 component with
LERF implications, and 5 operating experiences) as defined in Inspection
Procedure 71111.21-05.
.3 Component Design
a. Inspection Scope
The team reviewed the Updated Final Safety Analysis Report (UFSAR), Technical
Specification (TS), Technical Requirements Manual, drawings, calculations, and other
available design and licensing basis information to determine the performance
requirements of the selected components. The team used applicable industry
standards, such as the American Society of Mechanical Engineers Code, Institute of
Electrical and Electronics Engineers Standards, and the National Electric Code, to
assess the systems design. The team also reviewed licensee actions, if any, taken in
response to NRC issued operating experience, such as Generic Letters (GL) and
Information Notices (INs). The team reviewed the selected components design to
assess their capability to perform their required functions and support proper operation
of the associated systems. The attributes that were needed for a component to perform
its required function included process medium, energy sources, control systems,
operator actions, and heat removal. The attributes that verified component condition
and tested component capability were appropriate and consistent with the design bases
may have included installed configuration, system operation, detailed design, system
testing, equipment and environmental qualification, equipment protection, component
inputs and outputs, operating experience, and component degradation.
For each of the components selected, the team reviewed the maintenance history,
preventive maintenance activities, system health reports, operating experience-related
information, vendor manuals, electrical and mechanical drawings, operating procedures,
and licensee Corrective Action Program (CAP) documents. Field walkdowns were
conducted for all accessible components selected to assess material condition,
including age-related degradation, configuration, potential vulnerabilities to hazards,
and consistency between the as-built condition and the design. In addition, the
team interviewed licensee personnel from multiple disciplines such as operations,
engineering, and maintenance. Other attributes reviewed are included as part of the
scope for each individual component.
The following 12 components (i.e., samples), including a component with LERF
implications, were reviewed:
Unit 2, Reactor Core Insolation Cooking (RCIC) Pump (2E51-C001): The team
reviewed the following hydraulic calculations to assess the pump capability to
perform its required mitigating functions: pump minimum required flow, runout
flow, flow capacity, and minimum required net positive suction head (NPSH). In
addition, the team reviewed analyses associated with water hammer and other
gas intrusion considerations, such as the condensate storage tank minimum
water level setpoint and instrument uncertainty calculations. The team also
reviewed test procedures and completed surveillance tests, including quarterly
and comprehensive in-service testing, to assess the associated methodology,
acceptance criteria, and test results. In addition, the team reviewed design
analyses and test documents of the equipment area cooler to assess its
6
capability to maintain room temperature below the maximum qualification
temperature value of the RCIC pump support components. The team also
assessed the pump protective measures against flooding, seismic, and
high-energy line break (HELB) effects.
Unit 2, RCIC Turbine (2E51-C002): The team reviewed analyses for turbine
minimum required steam flow, turbine required speed, and water hammer in the
steam exhaust line to assess the RCIC turbine capability to perform its required
mitigating functions. The team also reviewed turbine speed control and trip test
procedures, results, and trends, as well as vendor information, such as General
Electric Service Information Letters, to assess the turbine control system
capability to perform its function. In addition, the team reviewed design analyses
and test documents of the equipment area cooler to assess its capability to
maintain room temperature below the maximum qualification temperature value
of the RCIC turbine support components. The team also assessed the turbine
protective measures against flooding, seismic, and HELB effects.
Unit 2, RCIC Steam Supply MOV (2E51-F045): The team reviewed analyses for
maximum differential pressure, weak link, and minimum required thrust to assess
the valve capability to provide its required mitigating functions. In addition, the
team reviewed test procedures and recently completed surveillance tests to
assess the associated methodology, acceptance criteria, and test results. The
team also reviewed the valve seismic and HELB analyses to assess the
associated protective measures. In addition, the team reviewed electrical load
flow calculations to assess the motor capability to operate the valve under
degraded voltage conditions. The team also reviewed the protective relaying
scheme, including drawings, calculations and schematic diagrams, to assess its
capability to provide motor protection and to preclude spurious tripping under
accident conditions.
Unit 2, Drywell Purge Isolation Air-Operated Valve (2VQ-34): The team reviewed
analyses for maximum differential pressure, weak link, and minimum required
thrust to assess the valve capability to provide its function. The team reviewed
leak rate test procedures and recently completed surveillance tests to assess the
associated methodology, acceptance criteria, and test results, and ultimately
assess the valve capability to perform its containment barrier function. In
addition, the team reviewed the valve seismic and HELB analyses to assess the
associated protective measures. This review constituted one component sample
with LERF implications.
Swing Diesel Generator (DG) (0DG01K): The team reviewed the following
DG test procedures and completed surveillance tests to assess the associated
methodologies, acceptance criteria, and test results: single load rejection, full
load rejection, and capability to accept load within it design bases time. In
addition, the team reviewed tests and calculations associated with room heat up,
combustion air, and exhaust design. The team also reviewed the DG protective
measures against flooding, HELB, and tornado generated missiles. The
following loading calculations were reviewed to assess the DG capability to
perform its safety function: voltage, frequency, current, and loading sequences
during postulated LOOP and loss-of-coolant accident (LOCA) conditions. The
team also reviewed protective relay setpoint calculations and setpoint calibration
7
test results to assess the DG protection during testing and emergency
operations. A sample of TS surveillance results were reviewed to assess
compliance with the acceptance criteria and test frequency requirements.
In addition, the team reviewed the following DG auxiliary sub-components:
Air Start Receivers (0DG06TA/B) and Motors (0DG08KA/B/C/D): The
team reviewed the pre-operational test results of the air start receivers to
assess their capacity to support the minimum number of required DG
starts. In addition, test procedures and completed surveillance tests were
reviewed to assess the air start receivers and motors capability to start
the DG.
Jacket Water Cooler (0DG01A): The team reviewed the jacket water
cooler thermal analysis to assess its capability to maintain engine
temperature within design limits and verified that the licensee had
updated the analysis to reflect the latest design bases ultimate heat
sink temperature limit changes. In addition, the team reviewed the
implementation of the GL 89-13 Program and its commitments associated
with the jacket water cooler. Specifically, the team reviewed thermal
performance test and inspect-and-clean procedures and completed
surveillances to assess the associated methodologies, acceptance
criteria, and test results.
Fuel Oil Storage Tank (0DO2T): The team reviewed fuel oil consumption
calculations, and main storage and day tank capacity calculations,
including the associated level instrument setpoints and uncertainty
analyses, to assess the availability of the required DG fuel oil supply.
The team also reviewed test procedures for fuel oil quality. In addition,
the team reviewed the licensees evaluation and resolution of related
operating experiences and a Non-Cited Violation (NCV) identified in a
previous CDBI as discussed in Section 1R21.4.a and Section 4OA2.1.a
of this report.
Fuel Oil Transfer Pump (0DO01P): The team reviewed hydraulic
calculations to assess flow capacity, NPSH, and air-entraining vortices
preventive measures. The team also reviewed the control circuit design
and the pump protective devices.
Swing DG Room Fan (0VD01C) and Ventilation Balancing Dampers
(0VD01/2/3YA/B): The team reviewed air flow calculations to assess the fan
capability to maintain the swing DG room within its design bases temperature
limit. The team also reviewed design documentation and procedures associated
with the DG room temperature and fan intake filter differential pressure
instrumentation to assess the licensee capability to detect and address
degraded ventilation conditions. In addition, the team reviewed the preventative
maintenance documents for the fan and dampers, including sub-components
such as hydramotors and control logic circuitry, to assess their periodicity and
consistency with vendor information. The team also reviewed the protective
measures against flooding, seismic, and tornado generated missiles. The supply
fan maximum brake horsepower requirements were reviewed to assess the
motor capability to supply power during worse case design basis conditions.
8
The results of load flow and voltage regulation analyses were reviewed to assess
the motor capability to start and run during degraded offsite voltage conditions
coincident with a postulated design basis accident. The team also reviewed the
motor breaker settings to assess the motor overcurrent protection during the
most limiting design basis operating conditions. The DG operating and standby
readiness procedures were reviewed to assess the consistency between the DG
ventilation system operation and the design requirements. The team also
reviewed the design of the instrumentation relied upon for the automatic room
ventilation operation, including power supplies and setpoints, to assess the
system operation.
Unit 2, RCIC High-Temperature and High-Steam Flow Isolation Instrumentation
(TE-2E31-N004A/B, TE-2E31-N005A/B, TS-2E31-N602A/B, TS-2E31-N603A/B,
2E31-N013BA): The team reviewed schematic diagrams, instrument
specifications such as range and accuracy, setpoint and uncertainty calculations,
and the installation configuration to assess the temperature and flow
instrumentation capability to perform its function. In addition, the team reviewed
test and calibration procedures as well as recently completed surveillances to
assess the associated methodology, acceptance criteria, and test results. The
team also considered the protective measures against flooding, seismic, and
HELB when reviewing the described analyses and during field walkdowns.
Unit 2, Suppression Pool Water Temperature and Level Instrumentation
(2TE-CM-057/037, 2UY-CM037, 2LT-CM-030, 2LS-E22-N002): The team
reviewed schematic diagrams, instrument specifications such as range and
accuracy, margin and uncertainty calculations, and the installation configuration
to assess the capability of the temperature and level instrumentation to perform
its function. In addition, the team assessed the consistency between plant
surveillance procedures and the methodology for determining average water
temperature and data quality allowances described in vendor documentation.
The team also reviewed test and calibration procedures as well as recently
completed surveillances to assess the associated methodology, acceptance
criteria, and test results. In addition, the team considered the protective
measures against flooding, seismic, and HELB when reviewing the described
analyses and during field walkdowns.
Unit 2, 125 Volts Direct Current (Vdc) Distribution Panels 211Y/212Y
(2DC11E/13E): The team reviewed design calculations for the loading, short
circuit, voltage drop, ground detection/management, and electrical protection
for the distribution panels and a sample of loads to assess the ratings and
capability of the panels to serve the loads under design basis conditions, provide
coordinated protection, and to preclude premature tripping. In addition, the team
also reviewed the station blackout (SBO) load shedding procedures to assess
their consistency with the design margins established by the calculations and the
operators capability to perform the associated actions within the times assumed
in the calculations. The team also reviewed test procedures and recently
completed surveillances to assess the associated methodology, acceptance
criteria, and test results. In addition, the team considered the protective
measures against flooding and seismic when reviewing the described analyses
and during field walkdowns.
9
Unit 2, RCIC Instrumentation 125Vdc to 120 Volts Alternating Current (Vac)
Inverter (2E51-K603): The team reviewed the loading and protection
specifications and features for the inverter to assess its capability to serve the
instrument power supply loads under design basis conditions, including operation
under minimum direct current (DC) input voltage conditions. The team also
reviewed the basis for the inverter qualification, including surge protection and
electromagnetic compatibility. In addition, the team reviewed the modification
discussed in Section 1R21.5.a of this report. The team also reviewed test
procedures and recently completed surveillances to assess the associated
methodology, acceptance criteria, and test results. In addition, the team
considered the protective measures against flooding and seismic when
reviewing the described analyses and during field walkdowns.
Unit 2, 250Vdc Motor Control Center (MCC) 221Y (2DC06E): The team
reviewed the system short circuit and loading calculations to assess the available
short circuit current under faulted conditions and the capability to serve the
maximum anticipated bus load. The team also reviewed the bus, breaker, and
cable ratings to assess their capability to carry maximum loading and interrupt
maximum faulted conditions. In addition, the team reviewed cable separation
design to assess compliance with single failure and Title 10, Code of Federal
Regulations (CFR), Part 50, Appendix R criteria. Breaker coordination was also
reviewed to assess their capability to interrupt overloads and faulted conditions.
The team also reviewed recent engineering changes (ECs) to assess the bus
current capability to support design requirements. In addition, the team reviewed
test procedures and recently completed surveillances to assess the associated
methodology, acceptance criteria, and test results.
Unit 2, 4 Kilovolt (kV) Switchgear 241Y (2AP04E): The team reviewed the
design of the 4.16kV bus degraded voltage protection scheme, including
degraded voltage relay setpoint calculations, to assess its capability to supply
the required voltage to safety-related devices at all voltage distribution levels.
The team also reviewed 125Vdc system voltage drop calculations to assess
the 4.16kV bus circuit breakers control voltage. In addition, the team reviewed
supply breaker control logic and wiring diagrams to assess the capability to
automatically transfer between the normal and alternate sources under
postulated conditions as described in the UFSAR and in accordance with
operating procedures. This review included an assessment of the automatic and
manual transfer schemes between alternate offsite sources and the swing DG.
The team also reviewed the control circuit voltage to assess the circuit breakers
capability to close and trip. In addition, the team reviewed test procedures and
recently completed surveillances to assess the associated methodology,
acceptance criteria, and test results.
b. Findings
(1) Failure to Monitor the Fouling Conditions of the Core Standby Cooling System
Equipment Area Coolers
Introduction: The team identified a finding of very-low safety significance (Green)
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, for the failure to monitor the fouling conditions of the core
10
standby cooling system (CSCS) equipment area coolers. Specifically, the licensee
did not develop performance test procedures to assess the fouling conditions of the
safety-related CSCS equipment area coolers and did not have acceptance criteria
that delineate when to remove accumulations.
Description: On July 18, 1983, the NRC issued GL 89-13, Service Water System
Problems Affecting Safety-Related Equipment, to alert licensees about operating
experience and studies that raised concerns regarding service water systems in nuclear
power plants. The GL requested licensees, in part, to provide a response describing the
actions planned or taken to ensure that their service water systems were and will be
maintained in compliance with applicable regulatory requirements. The licensee
provided its response in a letter to the NRC titled Response to Generic Letter 89-13,
dated January 29, 1990. Subsequent reviews revealed weaknesses in the licensee
original GL 89-13 Program. As a result, the licensee re-baselined the program and
revised its original response in a letter to the NRC titled Generic Letter 89-13 Revised
Response, dated July 28, 1998. The revised response stated that the CSCS equipment
area cooler testing program would include tube-side (chemical) cleaning on condition,
air-side coil inspection, component flushing, air-side flow verification, cooling water
flow verification, and cooling water dP [differential pressure] monitoring.
During this inspection period, the licensee controlled the implementation of GL 89-13
activities with Revision 7 of Procedure ER-AA-340, GL 89-13 Program Implementing
Procedure. Step 4.2.3 stated Implement a heat exchanger performance-testing
program. It also stated Develop performance test procedures that will verify the
capabilities of the safety related heat exchangers, including test procedure and
instrument uncertainties, and contain acceptance criteria based on the design
requirements of the systems. In addition, Revision 9 of Procedure ER-AA-340-1001,
GL 89-13 Program Implementation Instructional Guide, provided detailed guidance for
the implementation of GL 89-13 activities. Step 4.1.1.1.C stated The program shall
inspect/test for macroscopic biological fouling organisms, sediment, corrosion and
general component condition. It also stated The inspection/test program shall have
acceptance criteria that delineate when to remove accumulations.
The team noted that the licensee developed a test procedure to measure flowrate and
dP for the CSCS cooler for the room containing the low pressure core spray and RCIC
systems (i.e., cooler 2VY04A) on a biennial basis and to evaluate the flowrate results
against an acceptance criterion. However, the dP results were only trended because an
associated acceptance criterion was not established. In addition, the team noted that
the cooler was cleaned four times since the GL 83-13 Program was established but was
unable to determine the trigger for these cleaning activities. The team was concerned
because flow verification by itself was insufficient to assess the cooler fouling condition.
Moreover, the team was concerned about the actual cooler fouling conditions because
the dP trend data since year 2010 showed a dP of approximately 8 times the dP
measured in the early 1990s when dP was first measured. A simplified calculation,
which assumed tube blockage was the cause for the increased dP results, determined
that approximately 60 percent of the tubes were completely blocked. In contrast, the
design basis analysis for the cooler only assumed 5 percent of the tubes were blocked.
11
The licensee captured the team concerns in their CAP as AR 2665463. The immediate
corrective actions included an extent of condition that determined this concern was
applicable to all four CSCS room coolers of each reactor unit. The other coolers
supported the residual heat removal (RHR) and high-pressure core spray systems.
The licensee also performed an operability evaluation that reasonably determined all
of the affected equipment were operable based, in part, on the actual service water
temperatures. In addition, because operability could not be supported at the service
water temperature TS limit, the licensee established a control room standing order to
declare some of the affected coolers inoperable at reduced service water temperature
limits until the coolers were cleaned. The licensee proposed plan to restore compliance
at the time of this inspection was to clean the affected coolers and revise the GL 89-13
Program documents to incorporate applicable Electric Power Research Institute
monitoring guidance.
Analysis: The team determined the failure to monitor the fouling conditions of the CSCS
room coolers was contrary to licensee Procedures ER-AA-340 and ER-AA-340-1001,
and was a performance deficiency. The performance deficiency was determined to be
more than minor because it was associated with the Mitigating System Cornerstone
attribute of equipment performance and adversely affected the cornerstone objective to
ensure the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences. Specifically, the failure to verify that the
fouling conditions of the CSCS room coolers are consistent with the associated design
analysis does not ensure that these coolers would be capable of performing their
mitigating functions.
The team determined the finding could be evaluated using the Significance Determination
Process (SDP) in accordance with Inspection Manual Chapter (IMC) 0609, Significance
Determination Process, Attachment 0609.04, Initial Characterization of Findings,
issued on June 19, 2012. Because the finding impacted the Mitigating Systems
cornerstone, the team screened the finding through IMC 0609, Appendix A, The
Significance Determination Process for Findings At-Power, issued on June 19, 2012,
using Exhibit 2, Mitigating Systems Screening Questions. The finding screened as of
very-low safety significance (Green) because it did not result in the loss of operability or
functionality of mitigating systems. Specifically, the licensee reviewed actual service
water temperature values measured during the last 12 months and concluded that these
values did not exceed the operability limits established by the operability evaluation.
The team did not identify a cross-cutting aspect associated with this finding because it
was not confirmed to reflect current performance due to the age of the performance
deficiency. Specifically, the test program for the CSCS equipment area coolers was
developed in the decade of 1990s.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, requires, in part, that activities affecting quality be
prescribed by documented procedures of a type appropriate to the circumstances
and be accomplished in accordance with these procedures. The licensee established
Revision 7 of Procedure ER-AA-340 an Revision 9 of Procedure ER-AA-340-1001 as
the implementing procedures for monitoring, in part, CSCS room coolers capability to
perform their required safety functions, an activity affecting quality.
12
Procedure ER-AA-340, Step 4.2.3, stated Implement a heat exchanger
performance-testing program. It also stated Develop performance test procedures
that will verify the capabilities of the safety-related heat exchangers, including test
procedure and instrument uncertainties, and contain acceptance criteria based on
the design requirements of the systems. In addition, Procedure ER-AA-340-1001,
Step 4.1.1.1.C, stated The program shall inspect/test for macroscopic biological fouling
organisms, sediment, corrosion and general component condition. It also stated The
inspection/test program shall have acceptance criteria that delineate when to remove
accumulations.
Contrary to the above, as of May 4, 2016, the licensee failed to follow Step 4.2.3 of
Procedure ER-AA-340 and Step 4.1.1.1.C of Procedure ER-AA-340-1001. Specifically,
the licensee did not develop performance test procedures that verify the capabilities
of the safety-related CSCS room coolers because the test program did not inspect or
test for macroscopic biological fouling organisms, sediment, corrosion and general
component condition, and did not have acceptance criteria that delineate when to
remove accumulations.
The licensee is still evaluating its planned corrective actions. However, the team
determined that this issue does not present an immediate safety concern because the
licensee established a standing order for operations to impose more restrictive service
water temperature limits to reasonably assure the operability of the affected coolers.
Because this violation was of very-low safety significance (Green) and was entered into
the licensees CAP as AR 2665463, this violation is being treated as an NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-01;
05000374/2016007-01, Failure to Monitor the Fouling Conditions of the CSCS
Equipment Area Coolers)
(2) Failure to Ensure that Both Feed Supply Breakers for Swing Diesel Generator
Components Were Closed During Normal Plant Operation
Introduction: The team identified a finding of very-low safety significance (Green) and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the
failure to have the capability to verify the supply breakers of both reactor units feeding
the swing DG components were closed during normal plant operation. Specifically, the
circuit design and procedures for the swing DG room fan, fuel oil transfer pump, and fuel
storage tank room exhaust fan did not ensure the detection of the condition where one of
these feeder breakers was tripped in the open position during normal plant operation.
Description: Section 8.1.2.2 of the UFSAR, Unit Class 1E AC [Alternating Current]
Power System, stated that All of the ESF [engineered safety feature] equipment
required to shut down the reactor safely and to remove reactor decay heat for extended
periods of time following a LOOP and/or a LOCA are supplied with AC power from the
Class 1E AC power system. This UFSAR section defined Class 1E AC power systems
as that portion of the station auxiliary power system which supplies AC power to the
ESF and stated that The unit Class 1E AC power system is divided into three divisions
(Divisions 1, 2 and 3 for Unit 1; Divisions 1, 2, and 3 for Unit 2), each of which is
supplied from a 4160-volt bus (141Y, 142Y, and 143 for Unit 1 respectively) and (241Y,
242Y, and 243 for Unit 2 respectively). It also stated that Two ESF groups (Division 2
and 3) of each unit are supplied standby power from individual diesel-generator units,
while the third ESF group (Division 1) for each unit obtains its standby power from a
13
common diesel-generator unit, "0", which serves either of the corresponding switch
groups in each unit (Bus 141Y or 241Y). In addition, it stated that With this
arrangement, alternate or redundant components of all ESF systems are supplied
from separate switch groups so that no single failure can jeopardize the proper
functioning of redundant ESF.
Because the swing DG was designed to supply power to the division 1 ESF bus for
either reactor unit, several safety-related components that supported the swing DG
operation (i.e., room vent fan, fuel storage tank room exhaust fan, and fuel transfer
pump) were designed with one power supply from each reactor unit. As an example,
Unit 1 supplied power to the swing DG room fan (i.e., 0VD01C) via compartment B4 of
MCC135X-2 while Unit 2 supplied power to this component via compartment B4 of
MCC235X-2. Schematic diagram 1E-0-4433AA, Diesel Generator Room Ventilation
System, showed the following operational sequence for the associated control circuit
design:
If both MCCs were energized with no breaker or fuse failures during normal
operation, the fan would be powered from Unit 1. In addition, the plant process
computer (PPC) alarm contact from relay 74, Overload Relay, would be closed
causing the alarm to not be displayed at the Main Control Room (MCR). During
a LOOP event, the fan control circuit would connect to the MCC of the reactor
unit with a LOCA signal. Thus, the Units 1 and 2 MCCs were not considered
redundant or backup to each other.
If the Unit 1 MCC feed breaker tripped open and/or the Unit 1 control transformer
fuse opened during normal operation, relays AR1 and AR2 would de-energize
and power would automatically transfer to the Unit 2 MCC. At the same time, the
loss of power from Unit 1 would cause relay 74 to drop out until Unit 2 power
picked up. If the PPC alarm contact from relay 74 opened before relay 74 was
energized by Unit 2 power, the PPC alarm would appear on the ESF panel.
However, the team noted that the circuit design did not preclude a contact/relay
race between relays AR1/AR2 and relay 74 and, thus, the PPC alarm contact
from relay 74 was not assured to open before relay 74 was energized by Unit 2
power to provide the alarm function.
If the Unit 2 breaker tripped and/or the Unit 2 control transformer fuse opened
when the fan was powered from Unit 1 during normal operation, no PPC or
annunciator alarm would appear at the MCR.
If both Unit 1 and 2 MCCs de-energized during normal operation, relay 74
would dropout to activate the ESF display and overload alarm at the MCR
annunciator, which would prompt operators to respond in accordance with
Procedure LOR-0PL17J-2-1, Diesel Generator Ventilation Fan 0VD01C
Automatic Trip.
If either the Unit 1 MCC or the Unit 2 MCC thermal overload relays tripped during
normal operation, the fan control circuit would de-energize. The fan would not
run from either power source until the thermal overload relays was reset. In
addition, relay 74 would drop out to activate the ESF display and overload alarm
in the MCR.
14
The circuit designs for the swing DG fuel storage tank room exhaust fan and fuel oil
transfer pump were similar.
The team was concerned because the licensee had not assure that the failure of the
Unit 1 or Unit 2 feed breakers for these swing DG components during normal plant
operation would be detected. Specifically, the licensee relied on an alarm at the MCR to
detect a failure of either feed breaker during normal operation but the associated circuit
design did not assure an alarm signal would be generated by either of these conditions.
The team further noted that an undetected breaker failure during normal operations
would allow the swing DG to be and remain inoperable during normal operations,
which would result in the loss of total DG system given a postulated accident assuming
a single failure of the redundant DG train. In addition, the team noted that a failure of
either of these breakers during normal operations was credible given recent internal
operating experience. Specifically, on July 24, 2011, an equipment operator found
the Unit 1 swing DG room fan feed breaker (i.e., MCC 135X-2, B4) tripped during
an operator round. The licensee captured the discovery of this issue in their
CAP as AR 01243373, verified that the Unit 2 swing DG room fan feed breaker
(i.e., MCC 235X-2, B4) was closed, declared the swing DG inoperable for Unit 1,
and replaced the failed Unit 1 breaker. In addition, the licensee reviewed historical
PPC data and determined that the Unit 1 breaker tripped on July 22, 2011, during the
DG monthly surveillance run. Thus, the operators missed the PPC alarm and the
previous equipment operator rounds did not identified the condition.
The licensee capture the team concern in their CAP as AR 02668759. The immediate
corrective actions was to create a special log to monitor the associated breakers once
per day. At the time of this inspection, the licensee was still evaluating its planned
corrective actions to restore compliance.
Analysis: The team determined that the failure to have the capability to verify the supply
breakers of both reactor units feeding the swing DG components were closed during
normal plant operation was contrary to 10 CFR Part 50, Appendix B, Criterion III,
Design Control, and was a performance deficiency. The performance deficiency was
determined to be more than minor because it was associated with the Mitigating
Systems cornerstone attribute of equipment performance and affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. Specifically, the failure to have
the capability to verify the supply breakers of both reactor units feeding the swing DG
components were closed during normal plant operation would allow a condition where
one of the feeder breakers is in the open position during normal plant operation to go
undetected, which did not ensure power would be available to these components to
support the swing DG operability.
The team determined the finding could be evaluated using the SDP in accordance
with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial
Characterization of Findings, issued on June 19, 2012. Because the finding impacted
the Mitigating Systems cornerstone, the team screened the finding through IMC 0609,
Appendix A, The Significance Determination Process for Findings At-Power, issued on
June 19, 2012, using Exhibit 2, Mitigating Systems Screening Questions. The finding
screened as of very-low safety significance (Green) because it did not result in the loss
of system and/or function, represent an actual loss of function of at least a single train or
two separate safety systems out-of-service for greater than its TS allowable outage time,
15
and represent an actual loss of function of one or more non-TS trains of equipment
designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, a historical
review did not find an example where the swing DG was non-functional for a period
greater than the applicable TS allowable outage time as a result of this finding during the
last year.
The team did not identify a cross-cutting aspect associated with this finding because it
was not confirmed to reflect current performance due to the age of the performance
deficiency. Specifically, the means to detect an opened breaker associated with the
affected loads were established more than 3 years ago.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in
part, that measures be established to assure that applicable regulatory requirements and
the design basis are correctly translated into specifications, drawings, procedures, and
instructions. Section 7.3.6.2 of the UFSAR stated The diesel generators are applied to
the various plant buses so that the loss of any one diesel generators will not prevent the
safe shutdown of either unit. Further, it stated The total system satisfies single-failure
criteria.
Contrary to the above, as of May 13, 2016, the licensee failed to assure that
applicable regulatory requirements and the design basis were correctly translated into
specifications, drawings, procedures, and instructions. Specifically, the licensees
design control measures did not assure that the swing DG was applied to the buses
supplying power to its room fan, fuel oil transfer pump, and fuel storage tank room
exhaust fan such that the total DG system would be able to satisfy the single-failure
criteria. The associated circuit design and procedures did not ensure the detection of
a condition where the feeder breaker of one of the associated buses was tripped in the
open position during normal plant operation.
The licensee is still evaluating its planned corrective actions. However, the team
determined that the continued non-compliance does not present an immediate safety
concern because the licensee established a special log to monitor the associated
breakers once per day.
Because this violation was of very-low safety significance (Green) and was entered into
the licensees CAP as AR 02668759, this violation is being treated as an NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-02;
05000374/2016007-02, Failure to Ensure that Both Feed Supply Breakers for Swing
DG Components Were Closed During Normal Plant Operation)
.4 Operating Experience
a. Inspection Scope
The team reviewed five samples of operating experience issues to ensure that NRC
generic concerns had been adequately evaluated and addressed by the licensee. The
operating experience issues listed below were reviewed as part of this inspection:
IN 2006-22, New Ultra-Low-Sulfur Diesel Fuel Oil Could Adversely Impact
Diesel Engine Performance;
16
IN 2009-02, Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine
Performance;
IN 2012-16, Preconditioning of Pressure Switches Before Surveillance Testing;
IN 2013-14, Potential Design Deficiency in MOV Control Circuitry; and
Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers
by Debris in Boiling-Water Reactors.
b. Findings
(1) Inadequate Procedures for Containment Debris Management
Introduction: The team identified a finding of very-low safety significance (Green) and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, for the failure to establish procedures that were appropriate to manage
containment debris consistent with the emergency core cooling system (ECCS)
strainer debris loading design basis and supporting design information. Specifically,
the procedures did not contain instructions for evaluating containment debris sources
consistent with the associated analyses and other design documents.
Description: On May 6, 1996, the NRC issued Bulletin 96-03, Potential Plugging
of Emergency Core Cooling Suction Strainers by Debris in Boiling-Water Reactors,
to request addressees to implement appropriate procedural measures and plant
modifications to minimize the potential for clogging of ECCS suppression pool suction
strainers by debris generated during a LOCA and to provide a response describing
these actions. The licensee provided an initial response in a letter to the NRC titled
LaSalle County Station Unit 1 and 2 Response to the NRC Bulletin 96-03, dated
November 1, 1996. This response stated, in part, that the licensee planned to
install larger capacity passive strainers designed using the guidance contained in
NEDO-32686, Boiling Water Reactors Owners Group Utility Resolution Guidance for
ECCS Suction Strainer Blockage, which was endorsed with exceptions by the NRC.
By letter titled Completion Report for NRC Bulletin 96-03, dated April 28, 2000, the
licensee informed the NRC that all actions requested by the bulletin were completed,
including the implementation of procedures for periodic drywell and wetwell inspections
and periodic suppression chamber desludging. The NRC documented its review and
acceptance of the licensee responses in letter titled Completion of Actions for
Bulletin 96-03, LaSalle County Station, Units 1 and 2, dated June 2, 2000.
The licensee estimated the head loss across the debris bed formed on the strainers due
to accumulation of debris produced during a LOCA in calculation L-002051. This
calculation established separate design limits for different debris sources at specified
containment locations, such as unqualified coatings, rust flakes, and sludge. During this
inspection period, the licensee used Revision 9 of Procedure CC-AA-205, Control of
Undocumented/Unqualified Coatings inside the Containment, to control the amount of
undocumented/unqualified coatings within the design limits. In addition, Revision 8 of
Procedure LTS-600-41, Primary Containment Inspections for ECCS Suction Strainer
Debris Sources, was used to perform and document the periodic drywell and wetwell
inspections to identify and maintain containment debris quantities below their design
limits. Moreover, Revision 18 of Procedure OP-AA-108-108, Attachment 1, Engineering
Department Start-Up Checklist, step 24, required the licensee to verify that the
17
ECCS strainer debris loads were within design limits prior to unit startup. The
licensee completed this step by performing an evaluation using ECs.
However, the team noted that the procedures were inadequate to maintain containment
debris quantities consistent with the design basis and design supporting information.
Specifically,
Procedure CC-AA-205 did not contain instructions to ensure that the appropriate
coating supporting design information (i.e., thickness and density) was used
when evaluating degraded coatings that were originally considered as qualified
against the applicable strainer debris loading design basis limit. Specifically, the
licensee documented the identified areas of unqualified coatings in a log using
units of square feet. Because calculation L-002051 established a design limit of
328 pounds, the licensee converted the units from square feet to pounds.
However, the team noted that the licensee used the coating supporting design
information for the coating system that was originally installed as unqualified,
which had smaller thickness and density values than the originally qualified
coating system that was found degraded during the inspections and, thus, was
no longer qualified. As a result, the licensee underestimated the amount of
drywell unqualified coatings. Specifically, the incorrect logs showed an available
margin of about 16 percent and 44 percent for Units 1 and 2, respectively.
When the logs were corrected, the design basis limits were exceeded by about
20 percent and 7 percent for Units 1 and 2, respectively.
Procedure LTS-600-41 contained a sludge acceptance criterion that was
inconsistent with the applicable design basis limit and was non-conservative.
Specifically, calculation L-002051 established a sludge design limit of 750
pounds. However, procedure LTS-600-41 contained an acceptance criteria of
1000 pounds.
Procedure LTS-600-41 did not contain appropriate instructions to evaluate the
as-found conditions against the design basis limit for each debris type evaluated
by calculation L-002051. As a result, the licensee was not evaluating the as-
found conditions consistent with this calculation. For example, the diver
inspection report attached to Work Order 01317612 described the identified
sludge piles as The size of the material in these piles ranged from particulate to
3 [inches] long by 1 [inch] wide, but averaged in the dime to quarter size. In
contrast, the NEDO-32686 sludge particle maximum size was 0.003 inches.
Based on other documented inspection report descriptions, the team determined
that the likely debris type described by the diver was rust flakes, which had a
design basis limit of 100 pounds as opposed to 750 pounds for sludge. A second
example is documented in the next bullet.
Procedure LTS-600-41 did not contain appropriate instructions to evaluate the
aggregate effects of the debris found when performing different inspection
activities at different containment locations. Specifically, the team noted
instances when the inspection for the entire containment was not completed in a
single effort and the evaluation of the results for each inspection effort did not
account for the results for the other inspection activities when comparing the
identified condition against the design basis limits. For example, EC 392593,
which used the LTS-600-41 sludge results and was performed to meet Step 24
18
of Procedure OP-AA-108-108, Attachment 1, evaluated only the suppression
pool sludge against the design basis allowances of multiple debris sources.
Specifically, it stated Design Analysis L-002051 describes the following
suppression pool particulate matter debris assumed in the ECCS suction
strainer head loss analysis: 750 lbs. [pounds] of sludge, 300 lbs. [pounds]
of dirt/dust, 85 lbs. [pounds] of qualified paint debris, 328 lbs. [pounds] of
unqualified paint debris, and 100 lbs. [pounds] of rust flakes. It also concluded
that The estimated amount of sludge in the suppression pool at L2R14 (205 lbs.
[pounds]) and the predicated accumulation by L2R15 (365 lbs. [pounds]) are well
below the amount assumed in Design Analysis L-002051 (750 lbs. [pounds] plus
additional allowances for dust/dirt, paint, and rust. The team noted that
EC 392593 did not consider the amount of debris sources at both the drywell and
wetwell other than suppression pool sludge when crediting the design basis limits
for multiple drywell and wetwell debris sources. The team was concerned that
this licensee practice would allow a condition where the debris amount identified
in each inspection location is within the design basis limits but, in aggregate,
would exceed them. This example also illustrates the concern described in the
previous bullet. The team noted similar observations on other start-up ECs.
Overall, the team was concerned because the procedures were not adequate to ensure
that the containment debris quantities were consistent with the design basis analysis and
their relative distribution were consistent with the design information, including testing,
that supported the design basis analysis assumptions.
The licensee captured the team concerns in their CAP as AR 02663076 and
AR 02656299. The immediate corrective actions included an operability evaluation
that reasonably determined all of the affected ECCS strainers remained operable.
Specifically, the licensee reasonably concluded that only a fraction of the unqualified
coatings would be available for transport to the strainers during a LOCA and this amount
was bounded by the associated design basis limit. This determination was based, in
part, on unqualified coating testing and the documented condition of the unqualified
coatings. In addition, the licensee reviewed containment cleaning records and the
inspection results for the other debris sources and reasonably determined that the
associated design basis limits were met. The licensee proposed plan to restore
compliance at the time of this inspection was to revise the affected procedures and
the coating logs. In addition, the licensee planned to revise calculation L-002051
if additional margin is required to meet the corrected coating log values.
Analysis: The team determined the failure to establish procedures that were appropriate
to manage containment debris consistent with the ECCS strainer debris loading design
basis and supporting design information, was contrary to 10 CFR Part 50, Appendix B,
Criterion V, Instructions, Procedures, and Drawings, and was a performance
deficiency. The performance deficiency was determined to be more than minor
because it was associated with the procedure quality attribute of the Mitigating Systems
cornerstone, and adversely affected the cornerstone objective to ensure the availability,
reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Specifically, the failure to establish procedures that were
appropriate to manage containment debris does not ensure that the ECCS strainer
debris loading during a LOCA will be bounded by the associated design basis analysis.
19
The team determined the finding could be evaluated using the SDP in accordance with
IMC 0609, Significance Determination Process, Attachment 0609.04, Initial
Characterization of Findings, issued on June 19, 2012. Because the finding impacted
the Mitigating Systems cornerstone, the team screened the finding through IMC 0609,
Appendix A, The Significance Determination Process for Findings At-Power, issued on
June 19, 2012, using Exhibit 2, Mitigating Systems Screening Questions. The finding
screened as of very-low safety significance (Green) because it did not result in the loss
of operability or functionality of mitigating systems. Specifically, the licensee performed
an operability review and reasonably determined that only a portion of the unqualified
coatings would be available for transport to the strainers and this quantity was bounded
by the associated design basis analysis. In addition, this review reasonably determined
that sufficient analytical margin existed to accommodate the quantities of the other
debris types found during recent inspections.
The team did not identify a cross-cutting aspect associated with this finding because it
was not confirmed to reflect current performance due to the age of the performance
deficiency. Specifically, the associated procedures were established more than 3 years
ago.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, requires, in part, that activities affecting quality be
prescribed by documented procedures of a type appropriate to the circumstances
and be accomplished in accordance with these procedures. The licensee established
Revision 9 of Procedure CC-AA-205 and Revision 8 of Procedure LTS-600-41 as the
implementing procedures for containment debris management, an activity affecting
quality.
Contrary to the above, as of April 29, 2016, the licensee failed to have procedures of a
type appropriate to manage containment debris consistent with the ECCS strainer debris
loading design basis and supporting design information, as evidenced by the following
examples:
Procedure CC-AA-205 did not contain instructions to ensure that the appropriate
coating supporting design information (i.e., thickness and density) was used
when evaluating degraded coatings that were originally considered as qualified
against the applicable strainer debris loading design basis limit.
Procedure LTS-600-41 contained a sludge acceptance criterion that was
inconsistent with the applicable design basis limit and was non-conservative.
Procedure LTS-600-41 did not contain appropriate instructions to evaluate the
as-found conditions against the corresponding design basis debris type.
Procedure LTS-600-41 did not contain appropriate instructions to evaluate the
aggregate effects of the debris found when performing different inspection
activities at different containment locations.
The licensee is still evaluating its planned corrective actions. However, the team
determined that the continued non-compliance does not present an immediate safety
concern because the licensee performed an operability review and reasonably
determined that ECCS was operable based on the as-found conditions documented in
recent inspection reports.
20
Because this violation was of very-low safety significance (Green) and was entered
into the licensees CAP as AR 2656299 and AR 2663076, this violation is being
treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.
(NCV 05000373/2016007-03; 05000374/2016007-03, Inadequate Procedures for
Containment Debris Management)
.5 Modifications
a. Inspection Scope
The team reviewed two permanent plant modifications related to the selected risk
significant components to verify that the design bases, licensing bases, and performance
capability of the components had not been degraded through modifications. The
modifications listed below were reviewed as part of this inspection effort:
EC 396093, Install 125Vdc/120Vac Inverter to Power Existing 120Vac/24Vdc
Power Supply that Feeds Existing Containment Instrumentation; and
EC 395217, Unit 2 Division 1 and 2 DG Feed Breaker Logic Modification due to
C RHR and LPCS [Low-Pressure Core Spray] anti-Pump Logic.
b. Findings
No findings were identified.
.6 Operating Procedure Accident Scenarios
a. Inspection Scope
The team performed a detailed reviewed of the procedures listed below associated with
a loss of offsite power and a complete loss of AC power (i.e., SBO). The procedures
were compared to UFSAR, design assumptions, and training materials to asses for
constancy. The following operating procedures were reviewed in detail:
LOA-DG-101(201), DG Failure [Unit 1(2)], Revision 9(8);
LOA-FC-101(201), Unit 1(2) Fuel Pool Cooling System/Reactor Cavity Level
Abnormal, Revision 25(23);
LGA-RH-103(203), Unit 1(2) A/B RHR Operations in the LGAS/LSAMGS,
Revision 12(13);
LOP-RH-01, Filling and Venting the Residual Heat Removal System,
Revision 57;
LOP-RH-02, Venting the Residual Heat Removal System, Revision 9;
LOA-IN-101, Loss of Drywell Pneumatic Air Supply, Revision 9; and
LOP-IN 05, Replacing Nitrogen Bottles on Instrument Nitrogen System,
Revision 25.
21
For the procedures listed, time critical operator actions were reviewed for
reasonableness. This review included walkdowns of in-plant actions with a licensed
operator and the observation of licensed operator crews actions during the performance
of an SBO scenario on the station simulator to assess operator knowledge level,
procedure quality, availability of special equipment where required, and capability to
perform time critical operator actions within the required time. The simulated scenario
started with a dual unit loss of offsite power and then degraded, several minutes later,
into an SBO on Unit 1 with limited power available to Unit 2. In addition, the team
evaluated operations interfaces with other departments and the transition to beyond
licensing basis event procedures to assess the interface between licensing basis and
beyond licensing basis procedures. The following operator actions were reviewed:
establish automatic depressurization system control in the auxiliary electric
equipment room;
DC load shedding;
placement of RHR in the suppression pooling cooling mode following an SBO;
and
replacing drywell pneumatic air supply nitrogen bottles.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES
4OA2 Identification and Resolution of Problems
.1 Review of Items Entered Into the Corrective Action Program
a. Inspection Scope
The team reviewed a sample of problems identified by the licensee associated with
the selected components and that were entered into the CAP. In addition, the team
reviewed a sample of CAP documents for the last 3 years resulting from degraded
conditions. The team reviewed these issues to assess the licensees threshold for
identifying issues and the effectiveness of corrective actions related to design issues.
In addition, corrective action documents written on issues identified during the inspection
were reviewed to assess the incorporation of the problem into the CAP. The specific
corrective action documents sampled and reviewed by the team are listed in the
attachment to this report.
The team also selected three issues identified during previous CDBIs to assess the
associated licensees evaluation and resolution. The following issues were reviewed:
NCV 2007009-03, Lack of Station Blackout Analysis for Reactor Core Isolation
Cooling (RCIC);
NCV 2010006-02, DG Usable Fuel and RHR Pump NPSH Calculations Failed to
Consider Appropriate DG Frequency Variations; and
NCV 2010006-04, Fast Bus Transfer Analysis.
22
b. Findings
(1) Alternate Shutdown Procedures Failed to Ensure RCIC MOVs Supply Breakers Were
Closed
Introduction: The team identified a finding of very-low safety significance (Green) and
associated NCV of the LaSalle County Station Operating License for the failure to
ensure that procedures were in effect to implement the alternate shutdown capability.
Specifically, the AOPs established to respond to a fire at the MCR did not include
instructions for verifying that supply breakers for three RCIC MOVs were closed to
ensure they could be operated from the remote shutdown panel (RSP). Fire-induced
failures could result in tripping MOV power supply breakers prior to tripping the MOV
control power fuses.
Description: In the event of an MCR evacuation due to a fire, the safe shutdown
analysis credited the RCIC system for the alternate shutdown method from the RSP.
Specifically, RCIC was credited for reactor water makeup and decay heat removal.
During this event, the MCR control circuits for the RCIC MOVs needed to be transferred
from the MCR to the RSP. To accomplish this transfer, the licensee included
instructions to the operators for placing the RCIC remote shutdown transfer switches in
the emergency position at the RSP in Procedure LOA-FX-101, Unit 1 Safe Shutdown
with a Fire in the Control Room, and Procedure LOA-FX-201, Unit 2 Safe Shutdown
with a Fire in the Control Room. This transfer was intended to ensure that the alternate
shutdown capability was independent of the MCR fire area by isolating the MCR control
circuits for the RCIC MOVs and connecting a different set of control fuses that fed from a
separate power source at the RSP for each MOV.
However, in 2014, the NRC identified that the licensee failed to ensure that the alternate
shutdown capability was independent of the MCR during the NRC Triennial Fire
Protection inspection. Specifically, the inspectors noted that the control circuit design
did not ensure the MOV control power fuses trip before the associated feeder breakers
as a result of fire-induced failures, such as a short circuit in the control circuit. A tripped
MOV feed breaker would impair the operation of the associated MOV from the RSP.
In addition, the inspectors noted that Revision 26 of LOA-FX-101 and Revision 27 of
LOA-FX-201 did not include instructions to reset the affected breakers. This issue was
documented by the inspectors as NCV 05000373/2014008-01; 05000374/2014008-01,
Failure to Ensure Circuits Associated with Alternate Shutdown Capability Free of
Fire-Induced Damage, in Inspection Report 05000373/2014008; 05000374/2014008,
dated February 27, 2015. The licensee captured this issue in their CAP as
AR 02424674 and reviewed the control circuits of the affected MOVs. Specifically,
the licensee completed analysis L-004017, 250 Vdc Breaker Fuse Coordination for
RCIC, Revision 0, which evaluated breaker-fuse coordination for all 28 RCIC MOVs
(14 per reactor unit) during a postulated MCR fire event. This analysis identified
16 MOVs (8 per reactor unit) that could be adversely affected by a postulated MCR fire
and, thus, required further evaluation for potential lack of breaker fuse coordination. In
addition, the licensee revised Procedures LOA-FX-101 and LOA-FX-201 to verify closed
the breakers associated only with these 16 MOVs after control was transferred to the
RSP.
23
During this CDBI inspection, the team noted that analysis L-004017 calculated the fault
current using the maximum DC bus voltage divided by the resistance of each cable
(using a value of 0.273 ohms per 1000 feet). Thus, shorter cable lengths led to smaller
cable resistances resulting in higher fault current values. However, the analysis did not
consider all potential fire-induced short circuits that could potentially affect breaker-fuse
coordination and, as a result, failed to evaluate short circuits that resulted in shorter
short circuit cable lengths. Specifically, the analysis only considered a short circuit
(conductor to conductor dead short) for the control cable associated with each MOV
and that provided the shortest path for each MOV from the 250Vdc power source to
the MCR. For example, the analysis determined that the existing breaker settings for
MOVs 1E51-F019, 2E51-F019, and 1E51-F059 were acceptable because their
maximum calculated fault current was less than the minimum breaker trip setting using
a cable length of 2926 feet, 3512 feet, and 1821 feet, respectively. The analysis also
determined the margins between the minimum breaker setting and maximum fault
current were 14.49 percent, 19.92 percent, and 2.57 percent for these MOVs,
respectively. However, the analysis did not consider fire-induced circuit failures such
as shorts between cables associated with these MOVs and other MOVs from the same
250Vdc power source resulting in shorter short circuit cable lengths. The analysis also
failed to consider shorts between cables associated with these MOVs and the ground,
and cables associated with other MOVs with shorter cable lengths and the ground that
would end with short circuit via the ground.
The team was concerned because the unanalyzed fire-induced circuit failures
(i.e., short between cables and short to grounds) would have the potential to result in
higher available fault current values that could trip the feeder breaker for the affected
MOVs. In addition, the team was concerned because the AOPs revisions in effect at the
time of this inspection (i.e., Revision 27 of LOA-FX-101 and Revision 29 of LOA-FX-201)
did not include instructions to verify that the feeder breakers were closed for all of the
affected MOVs based on the conclusions of analysis L-004017. The team further noted
that the AOPs required operators to open valves 1E51-F019 and 2E52-F019 as part
of the expected response for a safe shutdown with a fire in the MCR and the AOPs
did not include alternative instructions in the event these valves could not be opened.
In addition, the AOPs required operators to open valve 1E15-F059 if RCIC flow was not
within the expected range. Thus, the team determined that the inability to operate these
values would not be within the bounds of the AOPs for a safe shutdown with a fire in the
MCR.
The licensee captured the team concerns in their CAP as AR 02668854. The immediate
corrective actions included revising Standing Order S14-09 to establish compensatory
actions to reset the affected breakers, if required. The licensee proposed plan to restore
compliance at the time of this inspection was to revise the AOPs to reset the affected
breakers, if required.
Analysis: The team determined that the licensees failure to ensure that procedures
were in effect to implement the alternate shutdown capability was contrary to LaSalle
County Station Operating License conditions for the Fire Protection Program and was a
performance deficiency. The performance deficiency was determined to be more than
minor because it was associated with the Mitigating Systems Cornerstone attribute of
protection against external events (fire), and affected the cornerstone objective of
24
ensuring the availability, reliability, and capability of systems that respond to initiating
events to prevent undesirable consequences (i.e., core damage). Specifically, the
failure to ensure that procedures were in effect to transfer RCIC control from the MCR to
the RSP in the event of an MCR fire does not ensure the alternate shutdown capability
of RCIC.
The team determined the finding could be evaluated using the SDP in accordance
with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial
Characterization of Findings, issued on June 19, 2012. Because the finding affected
the ability to reach and maintain safe shutdown conditions in case of a fire, the team
screened the finding through IMC 0609, Appendix F, Fire Protection Significance
Determination Process, issued on September 20, 2013, using Attachment 1, Part 1:
Fire Protection SDP Phase 1 Worksheet, issued on September 20, 2013. The finding
screened as of very-low safety significance (Green) because it was assigned a low
degradation factor based on the criteria in IMC 0609, Appendix F, Attachment 2,
Degradation Rating Guidance, issued on February 28, 2005. Specifically, the team
assigned a low degradation factor because the procedural deficiencies could be
compensated by operator experience/familiarity and the fact that the procedure
included steps to verify other breakers at the same MCCs were closed.
The team determined that this finding had a cross cutting aspect in the area of problem
identification and resolution because the licensee failed to take effective corrective
actions. Specifically, AR 02424674 included actions to revise the affected AOPs to
include verifying all the RCIC MOVs supplied breakers were closed to correct an issue
identified on 2014. However, the licensee failed to include all of the MOVs in the revised
AOPs. [P.3]
Enforcement: License conditions 2.C.25 and 2.C.15 of the LaSalle County Station,
Unit 1 and Unit 2 Operating Licenses, respectively, require, in part, that the licensee
implement and maintain all provisions of the approved Fire Protection Program as
described in the UFSAR for LaSalle County Station, and as approved in NUREG-0519,
Safety Evaluation Report, dated March 1981 through Supplement No. 8 and all
associated amendments. The license conditions also indicate that the licensee may
make changes to the approved Fire Protection Program without prior approval of the
NRC only if those changes would not adversely affect the ability to achieve and maintain
safe shutdown in the event of a fire.
LaSalle Comparison to 10 CFR Part 50, Appendix R, in Revision 7 of the Fire Protection
Program, Section 3, stated in the 10 CFR 50 Appendix column that The shutdown
capability for specific fire areas may be unique for each such area, or it may be one
unique combination of systems for all such areas. It also stated In either case, the
alternative shutdown capability shall be independent of the specific fire area(s) and shall
accommodate post fire conditions where offsite power is not available for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In
addition, it stated Procedures shall be in effect to implement this capability. The
LaSalle Conformance column stated Comply, specific post fire safe shutdown
procedures have been developed for the Control Room and AEER. LOA-FX-101(201).
Contrary to the above, from December 12, 2015, to at least May 13, 2016, the licensee
failed to have procedures in effect to implement the alternative shutdown capability for
a fire area where alternative shutdown capability was established. Specifically, the
safe shutdown procedures developed for the MCR, a fire area, (i.e., Revision 27 of
25
LOA-FX-101 and Revision 29 of LOA-FX-201) did not include instructions for verifying
that the supply breakers for all RCIC MOVs susceptible to fire-induced failures were
closed to ensure the successful operation of the RCIC system, which is the credited
alternate shutdown system in the event of a fire in the MCR.
The licensee is still evaluating its planned corrective actions. However, the team
determined that the continued non-compliance does not present an immediate safety
concern because the licensee established compensatory actions to reset the affected
breakers, if required.
Because this violation was of very low safety significance (Green) and was entered into
the licensees CAP as AR02668854, this violation is being treated as an NCV, consistent
with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000373/2016007-04;
05000374/2016007-04, Alternate Shutdown Procedures Failed to Ensure RCIC MOVs
Supply Breakers Were Closed)
4OA6 Management Meetings
.1 Exit Meeting Summary
On May 13, 2016, the team presented the inspection results to Mr. Trafton, Site Vice
President, and other members of the licensee staff. The licensee acknowledged the
issues presented. The team asked the licensee whether any materials examined during
the inspection should be considered proprietary. Several documents reviewed by the
team were considered proprietary information and were either returned to the licensee or
handled in accordance with NRC policy on proprietary information.
ATTACHMENT: SUPPLEMENTAL INFORMATION
26
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
W. Trafton, Site Vice President
H. Vinyard, Plant Manager
J. Kowalski, Engineering Director
J. Keenan, Operations Director
V. Shah, Engineering Deputy Director
G. Ford, Regulatory Assurance Manager
M. Chouinard, Design Engineer
P. Patel, Electrical Engineer
A. Ahmad, Design Engineer
D. Murray, Regulatory Assurance Engineer
U.S. Nuclear Regulatory Commission
M. Jeffers, Chief, Engineering Branch 2
N. Féliz Adorno, Senior Reactor Inspector
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000373/2016007-01; NCV Failure to Monitor the Fouling Conditions of the CSCS
05000374/2016007-01 Equipment Area Coolers (Section 1R21.3.b(1))05000373/2016007-02; NCV Failure to Ensure that Both Feed Supply Breakers for
05000374/2016007-02 Swing DG Components Were Closed During Normal
Plant Operation (Section 1R21.3.b(2))05000373/2016007-03; NCV Inadequate Procedures for Containment Debris05000374/2016007-03 Management (Section 1R21.4.b(1))05000373/2016007-04; NCV Alternate Shutdown Procedures Failed to Ensure RCIC
05000374/2016007-04 MOVs Supply Breakers Were Closed (Section 4OA2.b(1))
Discussed
None
Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
CALCULATIONS
Number Description or Title Revision
L-002051 ECCS Strainer Head Loss Performance Analysis 2A
L-003354 ECCS & RCIC Pumps NPSH Road Map Calculation 1
ATD-0070 Limiting Operating Conditions For Net Positive Suction Head 0
(NPSH) for HPCS, LPCS, RCIC & RHR pumps
L-001222 Estimation of Worst-Case Unit 1 RMI Debris Inventory Available 2
for Transport to the Suppression Pool
MAD-72-32 Pressure Drop Calculations, RCIC System 0
L-002540 NPSH Margin for HPCS, RHR, & RCIC Pumps, Backpressure for 2
RCIC Turbine
97-1998 VY Cooler Thermal Performance Model - 1(2)VY04A A
L-001024 LPCS Pump Cubicle Cooler Ventilation System 2
066455(EMD) Generic Evaluation of 5 Degree F Increase in Suppression Pool OA
Temperature
L-003317 RCIC Lube Oil Cooler Operation with SBO Event maximum 0
Suppression Pool Temperature
MAD 72-32 Pressure Drop Calc RCIC System 0
ATD-0351 RCIC Pump Room Temperature Transient Following Station 1
Blackout with Gland Seal Leakage
L-002440 Cross Index for Environmental Qualification Parameters and Their 1A
Respective Source Documents
L-000550 Zone H5A Equipment Qualification Dose 0
L-001384 Reactor Building Environmental Transient Conditions Following 10
RWCU and RCIC HELBs and LOCA/Loss of HVAC Event
L-003263 Volume Requirements for ADS Back-up Compressed Gas System 3A
(Bottle Banks)
EC 372452 Generic Letter 2008-01 Void Calculation and Acceptance Criteria 24
EC 343185 Maximum Expected Run Hours for Suppression Pool Cooling/Full 0
Flow Test Operating Modes of RHR
110A Ventilation Air Intake Extension for Diesel Generator 2
97-195 Thermal Model of ComEd/LaSalle Station Unit 0, 1 and 2 Diesel 0
Generator Jacket Water Cooler
DG-08 NPSH for HPCS DG Fuel Pumps 1B
DO-6 Elevation Diesel Fuel Oil Tanks 0
EC 366261 Revise Setpoint of DG Fuel Oil Storage Tank Low Level Switches 0
EC 372326 0DG Thermal Performance Margin with Tube Blocked 0
EC 381640 Minimum Required On-Site Usable Diesel Fuel Required to 0
Support Both Six Days and Seven Days of Continuous Emergency
Diesel Generator Operation Per Tech Spec Bases Table B.3.8.3-1
2
CALCULATIONS
Number Description or Title Date or Revision
EC 382235 Evaluation of The NPSH For Safety Related Pumps In 0
Support of Op Eval 10-005
EC 384217 2A DG Heat Exchanger Thermal Performance Test 0
Evaluation
EC 389270 UHS Temperature Increase 0
EC 395837 2A DG Heat Exchanger Thermal Performance Test 0
Evaluation
L-002901 Verification of the Division 1 and 2 Diesel Oil Storage and 1A
Day Tank Volumes
L-003364 0DG Electrical Loading Calculation 3
L-003416 Emergency Diesel Generators Onsite Usable Fuel 0B
Volume Requirements
VD-1A Standby Diesel Generator Room Ventilation System 0
VD-1C Diesel Generator Room Vent System Duct Pressure 0
Drops
VD-2A Standby Diesel Generator Room Ventilation System 0
VD-2C Diesel Generator System Duct Pressure Drops 0
VD-3C Engine-Generator for High Pressure Core Spray System 0
3C7-0788-001 Assessment of Bulk Pool Temperature Calculation 2
Methods [I&C interface review]
DCR 990833 Change NED-I-EIC-0260 to incorporate Results of 24 03/07/00
Month Drift Analysis
EC 380464 Evaluation of Preconditioning of TS and TRM Pressure 1
Switches
L-002590 Condensate Storage Tank Level Switch Setpoint Error 1
Analysis
L-002664 Review of Design Bases for 2° F Correction Factor Used 1
in LOP-CM-03, Rev. 11 [I&C interface review]
L-002968 DC System Ground Detector Action Levels, Sections 7.6, 0
8.0
L-003447 LaSalle Units 1 and 2,125 Vdc System Analysis 001B
L-003845 RCIC Steam Line High Flow Isolation Error Analysis 0
NED-I-EIC-0196 Suppression Chamber High Level Setpoint Error Analysis 0
NED-I-EIC-0213 RCIC Equipment Area/Pipe Tunnel High Ambient and 001G
Differential Temperature Outboard and Inboard Isolation
Error Analysis
NED-I-EIC-0259 Suppression Chamber Water Temperature Indication 1
Loop Analysis
NED-I-EIC-0260 Suppression Chamber Wide Range Water Level 0
Indication Error Analysis
PC-03 Design Analysis: Suppression Pool Volume Check [I&C 0
interface review]
LAS-2E51-F046 DC Motor Operated GL96-05 Globe1 Valve 8
LAS-2E51-F045 DC Motor Operated GL96-05 Globe1 Valve 8
L-003364 Attachment C - ETAP Output Report for EDG Load 3
Flow
3
CALCULATIONS
Number Description or Title Revision
L-003897 Setpoint Analysis for DG Feed Breaker Close Time Delay Relay 1
L-002589 Instrument Setpoint Analysis for 4.16KV Undervoltage (Loss of 0
Voltage) Relay-Time Delay Function
L-002588 Loss of Voltage Relay Setpoint for 4.16 KV Buses Undervoltage 0
Function
L-003823 1AP76E(135Y-2) MCC Voltage Drop, CB and TOL Setting 0
L-000300 Thermal Overload Relay Setting for Continuous Duty Motors 2
L-003448 LaSalle Units 1 and 2, 250 VDC System Analysis 0
L-003820 1AP72E (135X-2) MCC Voltage Drop, CB and TOL Setting 0
L-004017 250 VDC Breaker Fuse Coordination for RCIC 0
CORRECTIVE ACTION DOCUMENTS GENERATED DUE TO THE INSPECTION
Number Description or Title Date
AR02665463 NRC IDd, CDBI, Tube Plugging in 2VY04A 05/04/16
AR02654987 LOA-FC-101/201 Minor editorial procedure issue. 04/13/16
AR02655443 LOA-LOOP-101/201 Contains operating guidance for the RCIC 04/14/16
System that conflicts with operating guidance found in LGA-001.
AR02656039 DC Load Shedding procedure enhancements. 04/15/16
AR02661078 Configuration Control (Locking Status) of RCIC Pump Water Leg 04/26/16
Pump Discharge Valve (F062).
AR02659810 NRC CDBI 2016 - UFSAR Table 8.3-3 Shows Inaccurate Rev Bar 04/22/16
AR02661013 NRC-CDBI Identified SBLC Issue with UFSAR 04/26/16
AR02666354 NRC CDBI 2016 - UFSAR, App B PG B.0-11 Shows Inaccurate 05/06/16
Rating
AR02655170 NRC CDBI Identified Packing leak 04/13/16
AR02659688 NRC CDBI Identified Calculation NED-EIC-0196 Reference Has 04/22/16
Not Been Superseded
AR02665136 NRC CDBI Identified Error in Design Analysis NED-EIC-0260 05/04/16
AR02667806 NRC CDBI Identified Concern [Reporting and Trending of 05/10/16
Conditions Identified and Corrected During PM Activities]
AR02655692 0VD02C Fan Motor LRC Discrepancy 04/14/16
AR02668854 NRC - CDBI Identified Issue Related to Breaker Coordination 05/12/16
AR02668759 NRC Concern about 0VD01C Alarm in MCR 05/12/16
AR02663076 NRC CDBI Concerns on Strainers 04/29/16
AR02656299 NRC-CDBI - IDD LTS-600-41 PCRA Sludge Weight Correction 04/15/16
AR02668855 CDBI2016 NRC Observation on Use of Measured LRC for 1EBOP 05/12/16
AR02653895 NRC-CDBI Identified Issue - HPCS UFSAR description 04/11/16
AR02668085 NRC-CDBI Identified Issue - post-TIA 2001-14 procedures 05/11/16
AR02662445 NRC CDBI L-002051 Enhancements to Microtherm Assumptions 04/28/16
AR02655171 NRC-CDBI Identified Issue - RCIC storage ladders 04/13/16
AR02655372 NRC ID - CDBI LTS-600-41 PC Inspection PCRA Needed 04/14/16
AR02656385 NRC IDD: Discrepancy in PRA Documentation 04/15/16
AR02657236 NRC Identified - CDBI - Suction Strainer Calculation Review 04/18/16
AR02659561 NRC IDD: Incorrect Reference in LTS-600-41 04/22/16
AR02661223 NRC IDS CDBI Incorrect Input Values Listed in L-002540 04/26/16
4
CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION
Number Description or Title Date
AR02637587 NRC Question Coatings in Drywell on Floor Elevation 736 03/08/16
AR02571878 Unqualified Coatings Log Discrepancy 10/16/15
AR00673099 CDBI - RCIC Ops During SBO w/Elevated Suppression Pool 09/19/07
Temps
AR01575421 CDBI - IST Instrumentation Accuracy 10/22/13
AR01177556 2E51-C002 As-Found Condition of the #7 steam Jet Body 02/20/11
AR01177586 Potential FME Noted during Disassembly of RCIC Turbine 02/20/11
AR00157514 NRC Response to TIA 2001-14 05/06/03
AR01503409 Lightning Strike in 138KV Switchyard Results in Automatic 06/20/13
Reactor Shutdown of LaSalle Units 1 and 2 - Root Cause
Investigation Report
AR01088030 Procedure to align RCIC to draw suction from CST. 07/06/10
ACIT1356743-03 Braidwood and Byron EDG Full Load Reject Practice Review 06/13/12
AR00442006 Low Flow on Cooler 2VY02A During LOS-DG-Q3 01/13/06
AR00498484 OPEX Review - Fermi Impact of EDG Frequency on Loading 06/09/06
AR00534749 Potential Issues with the Use of Ultra Low Sulfur in EDGs 02/13/12
AR00547835 IN 2006-22 Ultra Low Sulfur Fuel633 10/23/07
AR00688908 Part 21 for 0 DG Air Start Solenoid Valve Never Installed 10/24/07
AR00820843 0DG HX Inspection Found 19 Tubes Blocked 09/22/08
AR01136071 CDBI: Potential Non-Conservative Tech Spec for EDG Fuel Oil 11/05/10
AR01141618 NRC Identified, CDBI, ECCS NPSH with Increased DG 11/17/10
Frequency
AR01164421 LOS-DG-Q1 Att A4 Failure 01/19/11
AR01166990 NOS ID: OPEX Actions From NRC IN 2009-02 were Not 01/26/11
Implemented
AR01175718 0XI-DG077 0 DG Conduit Came Loose for Pyrometer Leads 02/16/11
AR01232144 0 DG Fuel Oil Transfer Pump Excessive Start Freq Alarm 06/23/11
AR01232202 Header Downstream of Engine Air Box Drain Valve Blocked 06/23/11
AR01232221 0XI-DG077 Pyrometer Reading is Erratic 06/23/11
AR01243373 Feed Breaker to 0VD01C at 135X-2 Found Tripped 07/24/11
AR01244368 0VD01C Monitoring Plan 07/27/11
AR01257379 NRC Identified Issue with 0VD01YA manual Bypass Blade 08/30/11
AR01293864 0 DG Pyrometer Reading Low 11/23/11
AR01432987 0DG A Starting Air Comp Relief Lifting 10/29/12
AR01503431 0 DG Tied to Both Units During Transient 04/18/13
AR01557106 Inline Oiler Is Not Entraining Proper Amount of Oil 09/11/13
AR02381332 0 DG HX Inspection Found Evidence of Bypass Flow 09/15/14
AR02381627 0DG01A DG Heat Exchanger Does not Have Appropriate 09/16/14
Coating
AR02382031 STS Controller Outputs Found Degraded During PM Testing 09/17/14
AR02382989 0DG01A HX Coating Repairs Needed 09/18/14
AR02382997 Common DG Cooler Leak from North Blank Flange 09/18/14
5
CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION
Number Description or Title Date
AR02425069 0 DG Cooler Leaking from North End 12/14/14
AR02460815 0 Diesel Generator Issues 02/28/15
AR02571589 0DO01T Level Low 10/15/15
AR02599071 0 DG Cooler Flange Leak Increased When 0 DG Cooling Pump 12/11/15
Run
AT1166990-06 Station Diesel Owner to Review/Audit site-Specific Fuel Oil 05/31/11
Purchase, Delivery, and Processing Logistics for Each Station
Diesel Engine Application
AR00560991 Prints Not Correct: 2E51-K603 11/21/06
AR00872658 Red Power On Lamp for DC to AC Inverter Flickering On/Off 01/27/09
AR01030566 1DC13E Top Right Bolt Is Stripped and Will Not Tighten 02/15/10
AR01124515 MCR Recorder 2TR-CM038A Backup Battery Issue 10/10/10
AR01130619 MCR Recorder 2TR-CM028 Backup Battery Issue 10/26/10
AR01184065 2TR-CM037A Recorder Pen Stuck, Does not Respond to Change 03/07/11
AR01301597 2E31-N013BA Has Chemical Buildup at Ports on Switch 12/13/11
AR01353739 2E31-N013BA Trend Code B4 04/13/12
AR01377629 During LIS-RI-201 2E31-N013BA Stop Valve Leaking By 06/13/12
AR01406112 Instrument Out of Tolerance, 1E31-N013BA, Trend Code B4 08/28/12
AR01458428 Power Light not on for 2E51-K603 01/04/13
AR01470186 2TR-CM038A Recorder Pen Sticky 02/01/13
AR01519502 1E31-N013BA Failed/No Reset Obtainable LIS-RI-101 05/30/13
AR01524753 Instrument Out-of-Tolerance, 2E31-N013BA, Trend Code B1 06/13/13
AR01552116 Instrument Out of Tolerance, 1E31-N013BA, Trend Code 3 08/29/13
AR01605840 DC to AC Power On Light not Lit 01/09/14
AR01632613 U-2 Division 1 Ground - 75 Volts 03/12/14
AR01632888 U-2 Division 1 125 Vdc Ground - 60 Volts 03/13/14
AR01658819 U-2 Division 1 Ground Received 05/12/14
AR01659226 U-2 Division 1 Ground 05/13/14
AR01661043 U-2 Division 1 DC Ground 05/16/14
AR01663544 U-2 Division 1 Ground Alarm 05/23/14
AR01669065 Division 1 Ground U-2 06/08/14
AR01669913 Division 1 Battery Ground Alarm 06/11/14
AR01673406 Division 1 Ground Alarm Received 06/20/14
AR01676713 Division 1 125 VDC Ground Alarm 06/30/14
AR01693700 1LR-CM208 Suppression Chamber Water Level Recorder not 08/18/14
Reliable, Sticks at Zero
AR01695294 U-2 Division 1 Ground 08/22/14
AR01695615 2TE-CM-057C-A Reading Abnormally High 08/22/14
AR02381644 U-2 Division 1 DC Ground 09/16/14
AR02383228 Received Division 1 125 VDC Ground Alarm 09/19/14
AR02392651 Unexpected MCR Alarm - 211X/Y Ground Detector 10/08/14
6
CORRECTIVE ACTION DOCUMENTS REVIEWED DURING THE INSPECTION
Number Description or Title Date
AR02397905 Received Division 1 125 VDC Ground Detector Alarm 10/20/14
AR02418240 Unexpected MCR Alarm - 2PM01J-A409, Division 1 DC Ground 11/28/14
AR02418638 Intermittent Division 1 Ground Alarm Alarming in MCR 11/30/14
AR02419372 Received Momentary 2PM01J-B504 Division 2 Ground Detection 12/02/14
Alarm
AR02425660 Unit 2 Division 1 125 VDC Ground Alarms 12/15/14
AR02429456 Momentary Division 1 125 VDC Ground Detector Alarm 12/24/14
AR02447974 Unit 2 Division 1 DC Ground Spiking 02/05/15
AR02449037 Unit 2 Division 125 VDC Momentary Ground Alarm 02/07/15
AR02453155 Unexpected Momentary Unit 2 Division 2 125 VDC Ground Alarm 02/15/15
AR02455840 Condenser Tube Pull Area Fire Alarm Circuit Causes Division 1 02/19/15
Ground
AR02496015 Unexpected MCR Alarm 2PM013-A409 Division 1 Ground 05/05/15
AR02509179 Need Tolerance in mA DC for 2LY-CM030 Added to Passport 06/02/15
AR02509186 Need Setpoint Tolerance in mA DC for 1LY-CM030 Added to 06/02/15
Passport
AR02520165 Division 1 DC Bus Ground Detector Alarm 06/26/15
AR02520553 Annunciator 2PM01J-A409, Division 1 Ground Detector 06/27/15
AR02523164 Unexpected MCR Alarm, Division 1 Ground Detector Trouble 07/02/15
AR02577832 1DC11E Door Handle Mechanism is Broken 10/27/15
AR02599359 Division 1 Ground Detector Alarm 2PM01J-A409 Received Alarm 12/12/15
AR02636107 Instrument Out-of-Tolerance, 1LT-CM-062, Trend Code B4 03/04/16
AR02637638 Unit 2 Division 2 125 VDC Ground Due to MDRFP Seal Failure 03/28/16
AR01139601 CDBI Potential Deficiency in Calculation L-003364 11/12/10
AR01141298 CDBI Fast Bus Transfer of 4KV Buses 11/16/10
AR01244368 0VD01C Monitoring Plan 07/27/11
AR01243373 Feed Breaker to 0VD01C at 135X-2 Found Tripped 07/24/11
AR00699172 Division 3 DG Neutral Ground Resistor Location not per Design 11/12/07
DRAWINGS
Date or
Number Description or Title
Revision
M-149, Sh. 3 P&ID Reactor Building Floor Drains H
M-92, Sh. 1 P&ID Primary Containment Vent & Purge AU
M-147, Sh. 1 P&ID Reactor Core Isolation Coolant System (RCIC) BL
M-147, Sh. 2 P&ID Reactor Core Isolation Coolant System (RCIC) AO
761E205AA Process Diagram, Reactor Core Isolation Coolant System 8
M-127 P&ID Cycled Condensate Storage System AL
D-0805 26 Wafer Stop Valve Assembly L
28SW404563 Assembly Dwg, Safety Related Cooling Coils, CSCS Equipment 07/26/76
Area
66781E RCIC Pump Outline F
M-66 Drywell Pneumatic System P&ID; Sheets 1 AC
7
DRAWINGS
Number Description or Title Revision
M-66 Drywell Pneumatic System P&ID; Sheets 2 V
M-66 Drywell Pneumatic System P&ID; Sheets 3 AI
M-66 Drywell Pneumatic System P&ID; Sheets 4 AB
M-66 Drywell Pneumatic System P&ID; Sheets 5 O
M-66 Drywell Pneumatic System P&ID; Sheets 6 O
M-66 Drywell Pneumatic System P&ID; Sheets 7 U
M-66 Drywell Pneumatic System P&ID; Sheets 8 H
M-66 Drywell Pneumatic System P&ID; Sheets 9 B
M-66 Drywell Pneumatic System P&ID; Sheets 10 A
M-66 Drywell Pneumatic System P&ID; Sheets 11 A
M-96 Residual Heat Removal System P&ID; Sheets 1 BC
M-96 Residual Heat Removal System P&ID; Sheets 2 BB
M-96 Residual Heat Removal System P&ID; Sheets 3 AU
M-96 Residual Heat Removal System P&ID; Sheets 4 AG
M-96 Residual Heat Removal System P&ID; Sheets 5 M
19518 Performance Curve [ECCS Water Leg Pumps] 2
13251-1 DAAP-7402 Opposed Multiblade Damper Outline G
13251-2 Schedule for Drawings 13251 & 13251-1 G
1E-0-4418AA Schematic Diagram Diesel Fuel Oil System DO Part 1 U
1E-0-4433AB Schematic Diagram Diesel Generator Room Ventilation System L
VD Part 2
1E-1-4026AA Schematic Diagram Diesel Fuel Oil System DO Part 1 V
74-2131, Sh. 1 DG Storage Tank 4
74-2131, Sh. 1A DG Storage Tank 5
M-1444 P&ID Diesel Generator Room Ventilation System J
M-3444, Sh. 1 HVAC C&I Detail Diesel Generator Room Ventilation System D
Supply Fan Start-Stop & Damper Interlock
M-83, Sh. 2 P&ID Diesel Generator Auxiliary System AF
M-85, Sh. 1 P&ID Diesel Oil System AE
M-865, Sh. 1 Diesel Generator Room Misc. Piping U
M-865, Sh. 2 Diesel Generator Room Misc. Piping M
1E-1-4000LE Key Diagram, 120/208 VAC Distribution Panel at 480V MCC O
135x-2 (1AP72E)
1E-1-4018ZA Loop Schematic Diagram, Containment Monitoring System CM R
Part 1
1E-1-4018ZB Loop Schematic Diagram, Containment Monitoring System CM O
Part 2
1E-1-4018ZJ Loop Schematic Diagram, Containment Monitoring System CM AB
Part 9
1E-1-4214AA Schematic Diagram, Remote Shutdown System RS, Part 1 M
1E-2-4000FB Key Diagram 125 Vdc Distribution ESS Division 1 O
1E-2-4000FC Key Diagram 125 Vdc Distribution ESS Division 2 P
1E-2-4018ZE Loop Schematic Diagram Containment Monitoring System CM K
Part 5
8
DRAWINGS
Number Description or Title Revision
1E-2-4226AA Schematic Diagram, Reactor Core Isolation Cooling System RI R
(E51) Part 1
1E-2-4226AF Schematic Diagram, Reactor Core Isolation Cooling System RI AA
(E51)
1T-7000-E-EN-08 SOR Models 102 and 103 Equivalent Replacement, Sh. 1 F
1T-7000-E-EN-08 SOR Models 102 and 103 Equivalent Replacement, Sh. 2 D
M-1340 Instrument Installation Details, Sh. 15 J
1E-0-4412AA Schematic Diagram - 4160 SWGR 141Y, Diesel Generator 0 AD
Feed ACB 1413
1E-0-4412AB Schematic Diagram - 4160 SWGR 241Y, Diesel Generator 0 AD
Feed ACB 2413
1E-0-4412AJ Schematic Diagram - Diesel Generator 0 Generator / Engine W
Control System DG Part 9
1E-1-4026AB Schematic Diagram - Diesel Fuel Oil System DO Part 2 V
1E-1-4026AA Schematic Diagram - Diesel Fuel Oil System DO Part 1 V
1E-1-4000PG Relaying & Metering Diagram 4160 Switchgear Q
1E-1-4005AM Schematic Diagram - 4160 Switchgear N
1E-1-4226AU Schematic Diagram - Reactor Core Isolation Cooling System Z
1E-0-4418AA Schematic Diagram - Diesel Fuel Oil System DO Part 1 U
1E-2-4000EB Key Diagram - 250V DC Bus No.2 and MCC 221X M
1E-2-4000EC Key Diagram - 250V DC MCC 221Y S
1E-0-4401S Relaying and Metering Diagram Standby Diesel Generator 0 V
1E-0-4433AA Schematic Diagram - Diesel Generator Room Ventilation M
System VD Part 1
10 CFR 50.59 DOCUMENTS (SCREENINGS/SAFETY EVALUATIONS)
Number Description or Title Date
ER 9501392 Filter Bag Installation in Reactor Building, Turbine Building and 08/30/95
Auxiliary Building Floor Drains
LST-95-085 Installation of Mesh Basket/Screens in the Floor Drains 12/07/95
L03-0273 UFSAR Change LU2003-024, Suppression Pool Cooling 07/24/03
Operating Time Limitation
L13-180 New Procedure LOA-LOOP-101(201) 09/27/13
L97-180 Diesel Generator VD Bypass Damper 05/05/98
L02-0242 50.59 Review - Revise TRM 3.7.g Area Temperature 07/24/02
Monitoring
L02-0359 EDG Ventilation Modified to Control Air In-Leakage 10/18/02
L-14-104 50.59 Screening for EC 396093 02/13/15
L15-58 Unit 1 4KV Bus Transfer Logic Modification for an Open Phase 08/24/15
Condition Concurrent with LOCA
9
MISCELLANEOUS
Date or
Number Description or Title
Revision
Containment Coatings Program UDC/UQF Log 03/16/16
Spec.No.T-3763 Mechanical and Structural Work Specification 20
Maintenance/Modification Work
Containment Coatings Program Plan 1
EC392593 Evaluation of Estimated Amount of L2R14 Suppression Pool 05/29/13
Sludge
EC401088 Assessment of De-Sludeging Deferral from L2R15 02/1715
SL-2038 Letter, H. Peffer to A. Meligi, LaSalle RCIC Turbine Seismic 05/11/81
Re-Evaluation
GEH-LCS-AEP-045 LaSalle TPO Station Blackout Evaluation - Task T0903 07/07/09
22A2869AF GE Design Specification Data Sheet, RCIC System 12
EMD-029197 Seismic Requalification of Reactor Core Isolation Cooling 03/27/81
Pump (E51-C001)
EC 376896 Establishment of IST Acceptance Criteria for RCIC Pump 0
DBD-LS-M11 Topical Design Basis Document - Flood Protection E
CQD-028928 Vent and Purge Valves Qualification - CECo Mod. 1-1-84- 03/26/86
026
VM J-0395 Clow-Tricentric Valves/GH Bettis Actuators 4
Atwood & Morrill Report No. 7-25-85, Purge & Vent Valve 0
Operability Qualification Analysis
22A3008 GE Design Specification, BWR Equipment Environmental 5
Interface Data
VM J-0010 RCIC Pump Performance 8
GL 89-13 Program Basis Document 10
0024-00991 (LST-81-057) DG-Start Test on Stored Air 10/27/81
0084-02812 (LST-82-104) DG-0, 1A,1B, 2A Starts on Stored Air (Pre-Op 04/05/82
Testing)
IST-LAS-PLAN IST Program Plan 10/12/07
J-2585 DG Fan Vendor Manual 06/09/78
PES-P-006 Diesel Fuel Oil (Standard) 11
RS-10-031 Application For Technical Specifications Change Regarding 02/15/10
Risk-Informed Justification For The Relocation of Specific
Surveillance Frequency Requirements To a Licensee
Controlled Program
RS-10-136 Additional Information Supporting Request For License 08/03/10
Amendment Regarding Application Of Alternate Source Term
TE 362860 Technical Evaluation Ultra Low Sulfur Diesel Fuel Evaluation 10/06/06
TE 375645 Technical Evaluation Biodiesel Blend Fuel Oil Evaluation 05/21/09
22A1483AJ General Electric Design Specification Data Sheet, High 9
Pressure Core Spray System, Sheet 8
ACE 2607807-02 Apparent Cause Investigation Report: Main Steam Line High 02/09/16
Flow Switch 2E31-N011D not Holding Pressure
IM-025046-1 NLI Instruction Manual for Inverter Assembly, P/N NLI- 0
INV250-125-115, LaSalle Station
10
MISCELLANEOUS
Date or
Number Description or Title
Revision
L-2459 - L2462; Drift Verification for SOR Models Suffix X6, X7, X8 Pressure 12/31/15
L-2497 - L2501 Switches: Calculation Spreadsheets L-2459 through L-2462; L-
2497 through L-2501
PES-S-002 Exelon Document: Shelf Life, pp. 1, 7 8
QR-025046-1 Qualification Report for NLI Inverter Assembly P/N NLI-INV250- 0
125-115
VETIP J-0800 GE-NUMAC Suppression Pool Temperature Monitor (SPTM), 1
GEK-97056B Appendix C, SPTM Functions
Plant Engineering failure trend data for SOR switches associated 1984 to
with leak detection system present
Vickery-Sims Orifice Performance Curve, E51-N001 11/29/72
AT01553707-07 OPEX Evaluation - NRC IN 2013-14, Potential Design Deficiency 10/29/13
MODIFICATIONS
Date or
Number Description or Title
Revision
02-008 Change Request to TRM 3.7.g 09/16/02
96-034 UFSAR Revision Associated with Tech Spec Amendment 109 05/16/96
and 94
LU 2002-023 UFSAR Change Section 9.4.5.1.2 10/18/02
LUCR-181 UFSAR Chang for EC 374810 05/07/09
LUCR-216 UFSAR Changes Associated with the Alternate Source Term 11/12/10
Implementation
EC 396093 Install 125 Vdc/120 Vac Inverter to Power Existing 120 Vac/24 02/26/15
Vdc Power Supply that Feeds Existing Containment
Instrumentation
EC 395217 Unit 2 Division 1 and 2 DG Feed Breaker Logic Mod due to C 1
EC 331699 Abandonment of Diesel Fire Pump Fuel Oil Transfer Pump 07/27/01
Suction Valves 1(2)DO024
OPERABILITY EVALUATIONS
Number Description or Title Revision
EC 405589 VY Cooler Pressure Drop for Op Eval 16-003 0
EC 405581 VY Cooler Heat Transfer with Tubes Plugged for Op Eval 16- 0
003
OE 13-005 Non-compliance of Pump IST Instrumentation Accuracy with 1
ASME Code Requirements
OE 16-003 Impact of Increased Cooling Water dP Across Safety Related 0
Room Coolers on Heat Transfer Performance Capability
OE 10-005 Potential Non-Conservative Tech Spec for EDG Fuel Oil 6
11
PROCEDURES
Number Description or Title Revision
ER-AA-330-008 Exelon Service Level I, and Safety-Related (Service Level 10
III) Protective Coatings
CC-AA-205 Control of Undocumented/Unqualified Coatings Inside the 9
Containment
LTS-600-41 Primary Containment Inspections for ECCS Suction 9
Strainer Debris Sources
LMP-GM-80 Suppression Chamber Desludging 5
LOS-RI-Q5 RCIC System Pump Operability, Valve Inservice Tests in 39
Modes 1, 2, 3 and Cold Quick Start
LMP-RI-02 RCIC Turbine Maintenance 23
LTS-100-6 Primary Containment Vent and Purge Outlet Valves, 30
Local Leak Rate Test, 1(2)VQo31/32/34/35/36/40/68
OP-LA-102-106 LaSalle Station Operator Response Time Program 7
OP-LA-103-102-1002 Strategies for Successful Transient Mitigation 16
LGA-RH-103 Unit 1 A/B RHR Operations in the LGAS/LSAMGS 12
LGA-RH-203 Unit 2 A/B RHR Operations in the LGAS/LSAMGS 13
LOA-AP-101 Unit 1 AC Power System Abnormal 52
LOA-AP-201 Unit 2 AC Power System Abnormal 48
LOA-DG-101 DG Failure [Unit 1] 9
LOA-DG-201 DG Failure [Unit 2] 8
LOA-FC-101 Unit 1 Fuel Pool Cooling System/Reactor Cavity Level 25
Abnormal
LOA-FC-201 Unit 2 Fuel Pool Cooling System/Reactor Cavity Level 23
Abnormal
LOA-IN-101 Loss of Drywell Pneumatic Air Supply 9
LOA-LOOP-101 Loss of Offsite Power [Unit 1] 4
LOA-LOOP-201 Loss of Offsite Power [Unit 2] 4
ER-AA-340 GL 89-13 Program Implementing Procedure 7
ER-AA-340-1001 GL 89-13 Program Implementation Instructional Guide 9
LOP-CX-08 Uninterruptible Power Supply Startup, Operation, and 10
Shutdown
LOP-HY-04 Main Generator Hydrogen Removal 20
LOP-IN-05 Replacing Nitrogen Bottles on Instrument Nitrogen 25
System
LOP-RH-01 Filling and Venting the Residual Heat Removal System 57
LOP-RH-02 Venting the Residual Heat Removal System 9
LOP-VD-03 Startup and Operation of Ventilation Systems for Diesel 12
Generator 0DG01K Room and Associated Diesel Fuel
Storage Room
LOP-VD-05E Unit 0 Diesel Ventilation System Electrical Checklist 7
LOR-1H13-P601-C405 1A RHR PMP DSCH PRESS LO 5
LOR-1PM13J-A404 INSTRUMENT NITROGEN SYS TROUBLE 7
LOR-1PM13J-B404 INSTRUMENT NITROGEN SYS TROUBLE 6
ER-AA-200-1001 Equipment Classification 1
ER-AA-340-1002 Service Water Heat Exchanger Inspection Guide 6
LEP-EQ-127 Hydramotor Replacement 21
12
PROCEDURES
Date or
Number Description or Title
Revision
LMS-ZZ-04 Water Tight Door Inspection 6
LOP-DG-04 Diesel Generator Special Operations 66
LOP-DO-01 Receiving and sampling New Diesel Fuel Oil 39
LOP-PF-01 Closure of Water Tight Doors 6
LOR-0PL17J-1-1 Diesel Generator Room Ventilation Supply Air Filter 1
Differential Pressure High
LOS-DG-M2 1A Diesel Generator Fast Start 93
LOS-DG-Q1 0 Diesel Generator Auxiliaries Inservice Test 65
LOS-DG-Q3 1B DG Fuel Oil Transfer Pump Test 71
LOS-DO-SR2 Diesel Fuel Oil Analysis Verification (New Fuel Oil) 17
LOS-PF-M1 ECCS/CSCS Water Tight Door Surveillance 0
LTS-200-11 Diesel Generator Cooling Heat Exchanger Thermal 17
Performance Monitoring
LTS-800-101 0 Diesel Generator Start and Load Acceptance Surveillance 2
LES-GM-130 Inspection of Westinghouse Motor Control Center Equipment 23
and GE Molded Case Breakers
LIP-CM-605 Unit 2 Suppression Chamber High Level Calibration 2
LIS-CM-201 Unit 2 Suppression Chamber Wide and Narrow Range Water 17
Level Indication Calibration
LIS-RI-203A Unit 2 RCIC Equipment Room/Steam Line Tunnel High 15
Ambient and Differential Temperature Outboard Isolation
(Division 1) Calibration
LIS-RI-203B Unit 2 RCIC Equipment Room/Steam Line Tunnel High 15
Ambient and Differential Temperature Inboard Isolation
(Division 2) Calibration
LIS-RI-403A Unit 2 RCIC Equipment Room/Steam Line Tunnel High 10
Ambient and Differential Temperature Outboard Isolation
(Division 1) Functional Test
LIS-RI-403B Unit 2 RCIC Equipment Room/Steam Line Tunnel High 9
Ambient and Differential Temperature Outboard Isolation
(Division 2) Functional Test
LIS-RX-202 Unit 2 Remote Shutdown System Suppression Chamber 6
Water Temperature Indication Calibration
LOP-CM-03 Suppression Chamber Average Water Temperature 13
Determination
LOS-CM-M1 Monthly Accident Monitoring Instrumentation Channel Check, 44
Attachment 1A, Item 11, Suppression Pool Water Temperature
MA-AA-723-325 Molded Case Breaker Testing 15
OP-AA-102-106 Operator Response Time Validation Sheet [TCA 24: 30 minute 06/24/14
response time]
LOA-FX-101 Unit 1 Safe Shutdown with a Fire in the Control Room 27
LOA-FX-201 Unit 2 safe Shutdown with a Fire in the Control Room 29
LES-GM-109 Inspection of 480V Klockner-Moeller Motor Control Center 41
NES-E/I&C 10.01 Molded Case Circuit Breaker Selection and Setting Design 2
Standard
13
PROCEDURES
Number Description or Title Revision
MA-LA-773-401 Emergency Bus Loss of Voltage Relay Calibrations by OAD 6
LOP-CX-03 Attachment A - ESF Status Panel Operation and Response 14
to Panel Indication
SURVEILLANCES (COMPLETED)
Number Description or Title Date
WO 01534018 RCIC Control Sys Surveillance, LIS-RI-215 08/18/14
WO 01315081 RCIC Control Sys Surveillance, LIS-RI-215 04/09/12
WO 01602574 IM Verify APRM A, B, C, D Flow 02/19/15
WO 01885199 RCIC Cold Quick Start Quarterly Surveillance, LOS-RI-Q5 03/18/16
WO 01709225 RCIC Cold Quick Start Comprehensive Surveillance, LOS-RI- 09/08/15
Q5
WO 01885198 Unit 2 PCIS Valves Operability and Inservice Inspection Test 03/14/16
WO 01602514 Unit 2 VQ Valves Position Indication Test, Grease Inspection 12/13/14
and EQ Inspection for Primary containment Isolation Valves
WO 01182421-01 IM-CAL 0 DG Vent Damper Temp Control Loop 0VD003 07/09/14
WO 01620128-02 OP Perform LOS -DG-201 U-2 0 DG Start and Load 02/19/15
Acceptance
WO 01675903-01 IM LIP-DG-901 DG 0 Fuel Oil STG TK Level Switch & Ind Cal 07/21/14
WO 01681600-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 01/14/14
WO 01697599-14 OP Perform LOS-DG-101 For PMT of EC 395216 Div 1 03/04/16
WO 01755831-01 OP LOS-DG-M1 0 DG Idle Start ATT 0-Idle 08/20/14
WO 01799852-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 04/14/15
WO 01824458-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 07/10/15
WO 01846833-01 OP LOS-DG-M1 0 Diesel Generator Fast Start Att O-Fast 02/10/16
WO 01870155-01 OP LOS-DG-Q1 0 DG FO Transfer Pump Test ATT A1 01/12/16
WO 01906522-01 OP LOS-DG-M1 0 DG Idle Start Att 0-Idle 03/25/16
WO 01212770 IM LIS-RX-202 U2 Remote Shutdown System Suppression 08/19/10
Chamber Water Temperature
WO 01365359 IM LIS-RX-202 U2 Remote Shutdown System Suppression 08/15/12
Chamber Water Temperature
WO 01395536 2E51-K603 Inverter: Verify Proper Voltages 03/20/13
WO 01460932 IM LIS-CM-201 U2 Suppression Chamber Wide and Narrow 12/11/13
Range Water Level Indication
WO 01488819 IM LIP-CM-605 U2 Suppression Chamber High Level 10/01/14
Calibration
WO 01568087 IM LIS-RI-201 U2 Suppression Chamber Water Temperature 12/15/14
Indication Calibration
WO 01568153 IM LIS-RX-202 U2 Remote Shutdown System Suppression 10/12/14
Chamber Water Temperature
WO 01602534 RCIC Area/Pipe Tunnel High Ambient/Differential 12/12/14
Temperature Isolation Channel A & C [LIS-RI-403A]
WO 01625514 2E51-K603 Inverter: Verify Proper Voltages 03/11/15
WO 01635855 RCIC Area Pipe Tunnel High Ambient/Differential 04/07/15
Temperature Isolation Channels B&D
14
SURVEILLANCES (COMPLETED)
Number Description or Title Date
WO 01844790 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation 10/13/15
Calibration
WO 01868212 RCIC Area Pipe Tunnel High Ambient/Differential 01/04/16
Temperature Isolation Channels B&D [LIS-RI-403B]
WO 01869497 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation 01/16/16
Calibration
WO 01889791 RCIC Area/Pipe Tunnel High Ambient/Differential 04/18/16
Temperature Isolation Channel A & C [LIS-RI-403A]
WO 01890374 IM LIS-RI-201 U2 Steam Line High Flow RCIC Isolation 04/06/16
Calibration
WO 01907719 LOS-CM-M1 U2 Containment Monitoring Instrumentation 04/14/16
Att. 2A
WO 01601996 Perform LES-DG-100 Attachment 1 and 2 on 0DG01K 09/17/14
TRAINING DOCUMENTS
Number Description or Title Revision
011 EDG and Auxiliaries 14
Chapter 128 Safety Related Ventilation, VD, VY, VX 3
WORK DOCUMENTS
Number Description or Title Date
WO 01727033 Inspect U1 Primary Containment 02/27/16
WO 01522325 Inspect U1 Primary Containment 02/11/14
WO 01317612 Inspect U1 Primary Containment 03/01/12
WO 01317605 Desludge U1 Suppression Pool 02/26/12
WO 00932692 Desludge U1 Suppression Pool 02/21/08
WO 01629258 Inspect U2 Primary Containment 02/17/15
WO 01448698 Inspect U2 Primary Containment 02/28/13
WO 01330504 Desludge U2 Suppression Pool 03/07/13
WO 01214505 Inspect U2 Primary Containment 03/05/11
WO 01039324 Desludge U2 Suppression Chamber 01/28/09
WO 00637256 Desludge U2 Suppression Pool 02/22/05
WO 01235193 MM RCIC Turbine Inspection/Rebuild 03/06/11
WO 00544334-01 MM Disassemble, Inspect Heat Exchanger 10/03/07
WO 00551674-01 MM Perform 0 Diesel Generator Inspection Per LMS-DG- 03/05/04
01
WO 01445980-01 MM Disassemble, Inspect Heat Exchanger 07/09/14
WO 01501078-01 IM LIP-DG-903 DG Fuel Oil Day Tank Level Switch & Ind 07/13/15
Cal
WO 01673449-01 Inline Oiler Is Not Entraining Proper Amount of Oil 04/23/15
WO 01713585-01 0 DG Room HVAC Air Filter High D/P Alarm 04/10/15
WO 00328231 Perform LES-GM-130 for 2H13P601 at 212Y CB-3 01/23/03
(2DC13E)
WO 00584724 Perform LES-GM-130 for 2H13P612 at 211Y CB-8 02/17/05
(2DC11E)
15
WORK DOCUMENTS
Number Description or Title Date
WO 00584733 Perform LES-GM-130 for Cross-Tie 111Y at 211Y CB-23 02/16/05
WO 00584738 Perform LES-GM-130 for ESS-240 at 211Y CB-11 02/18/05
(2DC11E)
WO 00839517 Perform LES-GM-130 for X-Tie 112Y at 212Y CB23 10/27/08
(2DC13E)
WO 00839520 Perform LES-GM-130 for 2P08J at 212Y CB-15 (2DC15E) 04/03/08
WO 00839523 Perform LES-GM-130 for ESS #041 at 212Y CB-11 10/27/08
(2DC13E)
WO 01235373 Perform Breaker Inspection, Maintenance and Testing: 02/26/11
WO 01235380 Perform LES-GM-130 for 2H13P601 at 212Y CB-3 02/18/11
(2DC13E)
WO 01239529 2E51-K603 Inverter: Verify Proper Voltages 12/15/10
WO 01427028 Perform LES-GM-130 for Swgr 251-1 at 211Y CB-15 02/15/13
(2DC11E)
WO 01428173 Perform LES-GM-130 for 2H13P612 at 211Y CB-8 02/18/13
(2DC11E)
WO 01428176 Perform LES-GM-130 for 2C61P001 at 211Y CB-24 02/18/13
(2DC11E)
WO 01621668 2TE-CM-057A/C Suppression Pool Thermocouple Reads 12/15/14
too High
WO 01695411-04 IM-PMT per EC 396093: LIS-CM-201 Sections E.3 and E.4 02/22/15
WO 01695411-12 IM-PMT per EC 396093: Perform Updated LIS-RX-202 02/09/15
WO 01629492 Perform Breaker Inspection, Maintenance, and Testing 02/08/15
[MA-AB-725-110] for 212Y Feed 2DC15E-CB3B
16
LIST OF ACRONYMS USED
AC Alternating Current
ADAMS Agencywide Document Access Management System
AOP Abnormal Operating Procedure
AR Action Request
CAP Corrective Action Program
CDBI Component Design Bases Inspection
CFR Code of Federal Regulations
CSCS Core Standby Cooling System
DC Direct Current
DG Diesel Generator
dP Differential Pressure
EC Engineering Change
ECCS Emergency Core Cooling System
ESF Engineered Safety Feature
GL Generic Letter
IMC Inspection Manual Chapter
IN Information Notice
kV Kilovolt
LERF Large Early Release Frequency
LOCA Loss-Of-Coolant Accident
LOOP Loss of Off-site Power
MCC Motor Control Center
MCR Main Control Room
MOV Motor-Operated Valve
NCV Non-Cited Violation
NPSH Net Positive Suction Head
NRC U.S. Nuclear Regulatory Commission
PARS Publicly Available Records System
PPC Plant Process Computer
PRA Probabilistic Risk Assessment
RCIC Reactor Core Isolation Cooling
RSP Remote Shutdown Panel
SBO Station Blackout
SDP Significance Determination Process
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
Vac Volts Alternating Current
Vdc Volts Direct Current
17
B. Hanson -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, 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 NRCs Public Document Room or from the Publicly Available Records (PARS)
component of the NRC's Agencywide Documents 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/
Mark T. Jeffers, Chief
Engineering Branch 2
Division of Reactor Safety
Docket Nos. 50-373; 50-374
Enclosure:
IR 05000373/2016007; 05000374/2016007
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DATE 06/20/16 06/22/16
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