ML16174A094: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(Created page by program invented by StriderTol)
Line 1: Line 1:
{{Adams
#REDIRECT [[IR 05000346/2016007]]
| number = ML16174A094
| issue date = 06/22/2016
| title = NRC Component Design Bases Inspection Report 05000373/2016007; 05000346/2016007
| author name = Jeffers M
| author affiliation = NRC/RGN-III/DRS
| addressee name = Hanson B
| addressee affiliation = Exelon Generation Co, LLC
| docket = 05000373, 05000374
| license number = NPF-011, NPF-018
| contact person =
| document report number = IR 2016007
| document type = Inspection Report, Letter
| page count = 47
}}
See also: [[see also::IR 05000373/2016007]]
 
=Text=
{{#Wiki_filter: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;
              05000374/2016007
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
License Nos. NPF-11; NPF-18
Enclosure:
  IR 05000373/2016007; 05000374/2016007
cc: Distribution via LISTSERV
 
          U.S. NUCLEAR REGULATORY COMMISSION
                          REGION III
Docket No:          50-373; 50-374
License No:        NPF-11; NPF-18
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 hours. 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 hours. 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 hours. 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 Debris
05000374/2016007-03                  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
                  1E51-F045
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
                RHR and LPCS Anti-Pump Logic
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
              2DC08E-CB3B
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
HELB  High Energy Line Break
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
RHR  Residual Heat Removal
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
License Nos. NPF-11; NPF-18
Enclosure:
  IR 05000373/2016007; 05000374/2016007
cc: Distribution via LISTSERV
DISTRIBUTION:
Jeremy Bowen
RidsNrrDorlLpl3-2 Resource
RidsNrrPMLaSalle
RidsNrrDirsIrib Resource
Cynthia Pederson
Darrell Roberts
Richard Skokowski
Allan Barker
Carole Ariano
Linda Linn
DRPIII
DRSIII
ROPreports.Resource@nrc.gov
ADAMS Accession Number ML16174A094
    Publicly Available                        Non-Publicly Available                      Sensitive                Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
OFFICE              RIII                                RIII                            RIII                              RIII
NAME                NFeliz-Adorno:cl                    MJeffers
DATE                06/20/16                            06/22/16
                                                          OFFICIAL RECORD COPY
}}

Revision as of 02:16, 5 February 2020

Redirect to:

Retrieved from "https://kanterella.com/w/index.php?title=ML16174A094&oldid=2443671"