[Federal Register Volume 71, Number 56 (Thursday, March 23, 2006)]
[Notices]
[Pages 14726-14745]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-2803]
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NUCLEAR REGULATORY COMMISSION
Notice of Availability of Model Application Concerning Technical
Specifications for Boiling Water Reactor Plants to Risk-Inform
Requirements Regarding Selected Required Action End States Using the
Consolidated Line Item Improvement Process
AGENCY: Nuclear Regulatory Commission.
ACTION: Notice of availability.
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SUMMARY: Notice is hereby given that the staff of the Nuclear
Regulatory Commission (NRC) has prepared a model application related to
the revision of Boiling Water Reactor (BWR) plant required action end
state requirements in technical specifications (TS). The purpose of
this model is to permit the NRC to efficiently process amendments that
propose to revise BWR TS required action end state requirements.
Licensees of nuclear power reactors to which the model applies may
request amendments utilizing the model application.
DATES: The NRC staff issued a Federal Register Notice (70 FR 74037,
December 14, 2005) that provided a model safety evaluation (SE) and a
model no significant hazards consideration (NSHC) determination
relating to changing BWR TS required action end state requirements. The
NRC staff hereby announces that the model SE and NSHC determination may
be referenced in plant-specific applications to adopt the changes. The
staff has posted a model application on the NRC Web site to assist
licensees in using the consolidated line item improvement process
(CLIIP) to revise the BWR TS required action end state requirements.
The NRC staff can most efficiently consider applications based upon the
model application if the application is submitted within a year of this
Federal Register Notice.
FOR FURTHER INFORMATION CONTACT: T. R. Tjader, Mail Stop: O12H2,
Division of Inspection and Regional Support, Office of Nuclear Reactor
Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-
0001, telephone 301-415-1187.
SUPPLEMENTARY INFORMATION:
Background
Regulatory Issue Summary 2000-06, ``Consolidated Line Item
Improvement Process for Adopting Standard Technical Specification
Changes for Power Reactors,'' was issued on March 20, 2000. The
Consolidated Line Item Improvement Process (CLIIP) is intended to
improve the efficiency of NRC licensing processes. This is accomplished
by processing changes to the standard TS (STS) in a manner that
supports subsequent license amendment applications. The CLIIP includes
an opportunity for the public to comment on proposed changes to the STS
following a preliminary safety assessment by the NRC staff and finding
that the change will likely be offered for adoption by licensees. The
CLIIP includes NRC staff evaluation of any comments received for a
proposed change to the STS, and either a reconsideration of the change
or an announcement of the availability of the change for adoption by
licensees. Those licensees opting to apply for the subject change to
their TS are responsible for reviewing the staff's evaluation,
referencing the applicable technical justifications, and providing any
necessary plant-specific information. Each amendment application made
in response to the notice of availability will be processed and noticed
in accordance with applicable rules and NRC procedures.
This notice involves the revision of BWR TS required action end
state requirements. This change was proposed for incorporation into the
STS by participants in the Owners Groups Technical Specification Task
Force (TSTF) and is designated TSTF-423, Revision 0. TSTF-423, as well
as the NRC staff's safety evaluation and model application, may be
examined, and/or copied for a fee, at the NRC's Public Document Room,
located at One White Flint North, 11555 Rockville Pike (first floor),
Rockville, Maryland. Publicly available records are accessible
electronically from the ADAMS Public Library component on the NRC Web
site, (the Electronic Reading Room). TSTF-423, the NRC staff's safety
evaluation, and the model application, can be viewed on the NRC Web
site at: (http://www.nrc.gov/reactors/operating/licensing/techspecs.html).
Applicability
This proposal to modify technical specification requirements by the
adoption of TSTF-423 is applicable to all licensees of BWR plants who
have adopted or will adopt, in conjunction with the change, technical
specification requirements for a Bases control program consistent with
the TS Bases Control Program described in Section 5.5 of the BWR STS.
Licensees that have not adopted requirements for a Bases control
program by converting to the improved STS or by other means, are
requested to include the requirements
[[Page 14727]]
for a Bases control program consistent with the STS in their
application for the change. The need for a Bases control program stems
from the need for adequate regulatory control of some key elements of
the proposal that are contained in the Bases in TSTF-423. The staff is
requesting that the Bases changes be included with the proposed license
amendments consistent with the Bases in TSTF-423, prior to implementing
TSTF-423. To ensure that the overall change, including the Bases,
includes appropriate regulatory controls, the staff plans to condition
the issuance of each license amendment on the licensee's incorporation
of the changes into the Bases document and on requiring the licensee to
control the changes in accordance with the Bases Control Program. The
CLIIP does not prevent licensees from requesting an alternative
approach or proposing the changes without the requested Bases and Bases
control program. However, deviations from the approach recommended in
this notice may require additional review by the NRC staff and may
increase the time and resources needed for the review. Significant
variations from the approach, or inclusion of additional changes to the
license, will result in staff rejection of the submittal. Instead,
licensees desiring significant variations and/or additional changes
should submit a LAR that does not claim to adopt TSTF-423.
Public Notices
In a notice in the Federal Register dated December 14, 2005 (70 FR
74037), the staff requested comment on the use of the CLIIP to process
requests to revise the BWR TS regarding required action end state
requirements, designated as TSTF-423.
In response to the notice soliciting comments from interested
members of the public about modifying the TS requirements regarding
revising required action end state requirements, the staff received one
set of comments (from the Owners Groups TSTF, representing licensees).
Specific comments on the model SE were offered, and are summarized and
discussed below:
1. Comment: We commend the staff for adopting a draft Safety
Evaluation format that simplifies the application of the model Safety
Evaluation for TSTF-423 to individual licensees. For example, providing
blanks for plant name, operating license number, etc. We encourage the
staff to follow this example for future CLIIP model Safety Evaluations.
Response: The NRC staff acknowledges the comment; no action taken.
2. Comment: The ``Applicability'' portion of the notice states that
each licensee applying for the changes proposed in TSTF-423 should
include Bases for the proposed Technical Specifications (TS) consistent
with the Bases proposed in TSTF-423. We request that the section be
revised to not require licensees to submit Bases changes. The Bases
changes in TSTF-423 are not integral to the change and both licensee
and NRC resources could be saved by allowing licensees to adopt the
necessary Bases changes using the Technical Specifications Bases
Control Program. As a precedent, the CLIIP for TSTF-460 (Notice of
Availability published in the Federal Register on August 23, 2004)
allowed licensees to commit to updating their TS Bases under the TS
Bases Control Program instead of requiring licensees to submit their
Bases changes for NRC review. We propose that the TSTF-423 CLIIP take a
similar approach.
Response: The NRC staff does not agree with the comment. The
associated TS Bases changes are an essential and integral element of
the change, must be consistent with the Bases in TSTF-423, and should
be submitted by the licensees with the license amendment request for
adoption of TSTF-423.
3. Comment: Section 1.0 of the model Safety Evaluation, in the
first paragraph, states that TSTF-423 was proposed by the Nuclear
Energy Institute Risk Informed Technical Specification Task Force. That
is incorrect. TSTF-423, Revision 0, was submitted by the Owners Group
Technical Specifications Task Force in a letter to the NRC dated August
12, 2003.
Response: The NRC staff agrees with the comment. The correction has
been made.
4. Comment: Section 1.0 of the model Safety Evaluation, the last
sentence of section, states, ``Short duration repairs are on the order
of 2-to-3 days, but not more than a week.'' We recommend replacing this
sentence with the statement from the Implementation Guidance (TSTF-IG-
05-02), which states, ``A `short duration' is envisioned to be the
duration that boiling water reactors (BWRs) are most physically and
practicably able to remain in the hot shutdown condition (i.e., from a
few days to approximately one week).'' This clarifies that the time
frames are a statement of fact rather than a restriction which must be
incorporated in plant operating controls.
Response: The NRC staff does not agree with the comment. This issue
was discussed thoroughly and the one week limit was determined
appropriate. The one week limit is explicitly stated in the
Implementation Guidance (Reference 8 to the SE) submitted by industry,
agreed to by the NRC staff, and to which the licensees must commit.
Section 1 paragraph 6 of the Implementation Guidance (TSTF-IG-05-02)
states, ``Any entry into Mode 3 using this TS allowance must be limited
to no more than seven days.'' No action has been taken.
5. Comment: In Section 3.2, ``Assessment of TS Changes,'' of the
model Safety Evaluation, each subsection is titled with the applicable
Topical Report section number and the ITS LCO number. The abbreviation
``TS'' is used to indicate the Topical Report section number (e.g.,
``TS 4.5.1.2 and LCO 3.4.3 (BWR/4); TS 4.5.2.2 and LCO 3.4.4 (BWR/6),
Safety/Relief Valves (SRVs).'' The labels ``4.5.1.2'' and ``4.5.2.2''
are the Topical Report sections associated with these LCO changes.
These references also appear in the text of Section 3.2. This
presentation is confusing as ``TS'' is defined in the model Safety
Evaluation as ``Technical Specifications'' and non-ITS plants have
Technical Specification requirements with numbers similar to the
Topical Report numbers. We recommend replacing this use of the
abbreviation ``TS'' with either ``Topical Report section'' or defining
another acronym, such as ``TR.''
Response: The NRC staff agrees with the comment. The abbreviation
for the Topical Report Section was poorly chosen, in that it was easily
confused with the abbreviation for Technical Specification. The Topical
Report Section abbreviation has been changed to ``TRS.''
6. Comment: In Section 3.2.4 of the model Safety Evaluation, in the
title and in the first paragraph, the LCO name ``Low-Low Set Logic
(LLS) Valves'' is used. The word ``logic'' should not appear in the LCO
name. The document should be revised to state ``Low-Low Set (LLS)
Valves.''
Response: The NRC staff agrees with the comment. The correction has
been made.
7. Comment: Section 5.0, ``Environmental Consideration,'' of the
model Safety Evaluation states that the amendments meet the eligibility
criteria for categorical exclusion set forth in ``10 CFR 51.22(c)(9)
[and (c)(10)].'' 10 CFR 51.22(c)(10) pertains to issuance of an
amendment pursuant to ``parts 30, 31, 32, 33, 34, 35, 36, 39, 40, 50,
60, 61, 70 or part 72 of this chapter which (i) changes surety,
insurance and/or indemnity requirements, or (ii) changes
[[Page 14728]]
recordkeeping, reporting, or administrative procedures or
requirements.'' Paragraph (c)(10) is not applicable to this change and
the reference should be deleted.
Response: The NRC staff agrees with the comment. The correction has
been made.
8. Comment: Section 7.0, ``References,'' of the model Safety
Evaluation, Reference 1, states the date of NEDC-32988-A, Revision 2,
as September 2005. The correct date of the document is December 2002.
Response: The NRC staff agrees with the comment. The correction has
been made.
The NRC staff has made editorial changes to the previously
published model SE related to TSTF-423 resulting from the disposition
of comments 3, 5, 6, 7, and 8. The staff finds that technically the
previously published SE remains unaltered. Below are the republished
model SE and model NSHC determination (previously published in the
Federal Register; 70 FR 23238, December 14, 2005), and the model
application prepared by the staff that licensees may reference in their
plant-specific applications.
Dated at Rockville, Maryland, this 16th day of March 2006.
For the Nuclear Regulatory Commission.
Thomas H. Boyce,
Branch Chief, Technical Specifications Branch, Division of Inspection
and Regional Support, Office of Nuclear Reactor Regulation.
Model Plant Specific Safety Evaluation for Technical Specification Task
Force (TSTF) Change TSTF-423, Risk Informed Modification to Selected
Required Action End States, a Consolidated Line Item Improvement
U.S. Nuclear Regulatory Commission, Safety Evaluation by the Office of
Nuclear Reactor Regulation Related to Amendment No. [------] to
Facility Operating License NFP-[----[lowbarm]] [Utility Name] [Plant
Name], [Unit ------] Docket No. -[----]
1.0 Introduction
By letter dated ----------, 20--, [Utility Name] (the licensee)
proposed changes to the technical specifications (TS) for [plant name].
The requested changes are the adoption of TSTF-423, Revision 0, to the
Boiling Water Reactor (BWR) Standard Technical Specifications (STS)
(NUREG 1433 and NUREG 1434), which was proposed by the Owners Groups
Technical Specifications Task Force (TSTF) on August 12, 2003, on
behalf of the industry. TSTF-423, Revision 0, incorporates the BWR
Owners Group (BWROG) approved Topical Report NEDC-32988, Revision 2,
``Technical Justification to Support Risk Informed Modification to
Selected Required Action End States for BWR Plants'' (Reference 1),
into the BWR STS (NOTE: The changes in TSTF-423 are made with respect
to Revision 2 of the BWR STS NUREGs).
TSTF-423 is one of the industry's initiatives developed under the
Risk Management Technical Specifications (RMTS) program. These
initiatives are intended to maintain or improve safety through the
incorporation of risk assessment and management techniques in TS, while
reducing unnecessary burden and making TS requirements consistent with
the Commission's other risk-informed regulatory requirements, in
particular the maintenance rule.
The Code of Federal Regulations, 10 CFR 50.36, ``Technical
Specifications,'' states: ``When a limiting condition for operation of
a nuclear reactor is not met, the licensee shall shut down the reactor
or follow the remedial action permitted by the technical specification
until the condition can be met.'' The STS and most plant TS provide a
completion time (CT) for the plant to meet the limiting condition for
operation (LCO). If the LCO or the remedial action cannot be met, then
the reactor is required to be shut down. When the STS and individual
plant technical specifications were written, the shutdown condition or
end state specified was usually cold shutdown.
Topical Report NEDC-32988, Revision 2, provides the technical basis
to change certain required end states when the TS Actions for remaining
in power operation cannot be met within the CTs. Most of the requested
TS changes permit an end state of hot shutdown (Mode 3), if risk is
assessed and managed, rather than an end state of cold shutdown (Mode
4) contained in the current TS. The request was limited to those end
states where: (1) entry into the shutdown mode is for a short interval,
(2) entry is initiated by inoperability of a single train of equipment
or a restriction on a plant operational parameter, unless otherwise
stated in the applicable TS, and (3) the primary purpose is to correct
the initiating condition and return to power operation as soon as is
practical.
The STS for BWR plants define five operational modes. In general,
they are:
Mode 1--Power Operation. The reactor mode switch is in run
position.
Mode 2--Reactor Startup. The reactor mode switch is in
refuel position (with all reactor vessel head closure bolts fully
tensioned) or in startup/hot standby position.
Mode 3--Hot Shutdown. The reactor coolant system (RCS)
temperature is above 200 degrees F (TS specific) and the reactor mode
switch is in shutdown position (with all reactor vessel head closure
bolts fully tensioned).
Mode 4--Cold Shutdown. The RCS temperature is equal to or
less than 200 degrees F and the reactor mode switch is in shutdown
position (with all reactor vessel head closure bolts fully tensioned).
Mode 5--Refueling. The reactor mode switch is in shutdown
or refuel position, and one or more reactor vessel head closure bolts
are less than fully tensioned.
Criticality is not allowed in Modes 3 through 5.
TSTF-423 generally allows a Mode 3 end state rather than a Mode 4
end state for selected initiating conditions in order to perform short-
duration repairs which necessitate exiting the original Mode of
operation. Short duration repairs are on the order of 2-to-3 days, but
not more than a week.
2.0 Regulatory Evaluation
In 10 CFR 50.36, the Commission established its regulatory
requirements related to the content of TS. Pursuant to 10 CFR 50.36(c),
TS are required to include items in the following five specific
categories related to station operation: (1) Safety limits, limiting
safety system settings, and limiting control settings; (2) limiting
conditions for operation (LCOs); (3) surveillance requirements (SRs);
(4) design features; and (5) administrative controls. The rule does not
specify the particular requirements to be included in a plant's TS. As
stated in 10 CFR 50.36(c)(2)(i), the ``Limiting conditions for
operation are the lowest functional capability or performance levels of
equipment required for safe operation of the facility. When a limiting
condition for operation of a nuclear reactor is not met, the licensee
shall shut down the reactor or follow any remedial action permitted by
the technical specifications * * *.''
Reference 1 states: ``Cold shutdown is normally required when an
inoperable system or train cannot be restored to an operable status
within the allowed time. Going to cold shutdown results in the loss of
steam-driven systems, challenges the shutdown heat removal systems, and
requires restarting the plant. A more preferred operational mode is one
that maintains adequate risk levels while repairs are completed without
causing unnecessary challenges to plant equipment during shutdown and
startup transitions.'' In the end state changes under consideration
here, a problem
[[Page 14729]]
with a component or train has or will result in a failure to meet a TS,
and a controlled shutdown has begun because a TS Action requirement
cannot be met within the TS CT.
Most of today's TS and the design basis analyses were developed
under the perception that putting a plant in cold shutdown would result
in the safest condition and the design basis analyses would bound
credible shutdown accidents. In the late 1980s and early 1990s, the NRC
and licensees recognized that this perception was incorrect and took
corrective actions to improve shutdown operation. At the same time,
standard TS were developed and many licensees improved their TS. Since
enactment of a shutdown rule was expected, almost all TS changes
involving power operation, including a revised end state requirement,
were postponed (see, for example the Final Policy Statement on TS
Improvements, Reference 2). However, in the mid 1990s, the Commission
decided a shutdown rule was not necessary in light of industry
improvements.
Controlling shutdown risk encompasses control of conditions that
can cause potential initiating events and responses to those initiating
events that do occur. Initiating events are a function of equipment
malfunctions and human error. Responses to events are a function of
plant sensitivity, ongoing activities, human error, defense-in-depth,
and additional equipment malfunctions.
In practice, the risk during shutdown operations is often addressed
via voluntary actions and application of 10 CFR 50.65 (Reference 3),
the maintenance rule. Section 50.65(a)(4) states: ``Before performing
maintenance activities * * * the licensee shall assess and manage the
increase in risk that may result from the proposed maintenance
activities. The scope of the assessment may be limited to structures,
systems, and components that a risk-informed evaluation process has
shown to be significant to public health and safety.'' Regulatory Guide
(RG) 1.182 (Reference 4) provides guidance on implementing the
provisions of 10 CFR 50.65(a)(4) by endorsing the revised Section 11
(published separately) to NUMARC 93-01, Revision 2. The revised Section
11 of NUMARC 93-01, Revision 2, was subsequently incorporated into
Revision 3 of NUMARC 93-01 (Reference 5). However, Revision 3 has not
yet been formally endorsed by the NRC. The changes in TSTF-423 are
consistent with the rules, regulations and associated regulatory
guidance, as noted above.
3.0 Technical Evaluation
The changes proposed in TSTF-423 are consistent with the changes
proposed and justified in Topical Report GE NEDC-32988-A, Revision 2,
(Reference 1) and approved by the associated NRC SE (Reference 6). The
evaluation included in Reference 6, as appropriate and applicable to
the changes of TSTF-423 (Reference 7), is reiterated here and
differences from the SE are justified. In its application the licensee
commits to TSTF-IG-05-02, Implementation Guidance for TSTF-423,
Revision 0, ``Technical Specifications End States, NEDC-32988-A,''
(Reference 8), which addresses a variety of issues such as
considerations and compensatory actions for risk-significant plant
configurations. An overview of the generic evaluation and associated
risk assessment is provided below, along with a summary of the
associated TS changes justified by Reference 1.
3.1 Risk Assessment
The objective of the BWROG topical report (Reference 1) risk
assessment was to show that any risk increases associated with the
changes in TS end states are either negligible or negative (i.e., a net
decrease in risk).
The BWROG topical report documents a risk-informed analysis of the
proposed TS change. Probabilistic Risk Assessment (PRA) results and
insights are used, in combination with results of deterministic
assessments, to identify and propose changes in ``end states'' for all
BWR plants. This is in accordance with guidance provided in RG 1.174
(Reference 9) and RG 1.177 (Reference 10). The three-tiered approach
documented in RG 1.177, ``An Approach for Plant-Specific, Risk-Informed
Decision Making: Technical Specifications,'' was followed. The first
tier of the three-tiered approach includes the assessment of the risk
impact of the proposed change for comparison to acceptance guidelines
consistent with the Commission's Safety Goal Policy Statement, as
documented in RG 1.174. The first tier aims at ensuring that there are
no unacceptable temporary risk increases as a result of the TS change,
such as when equipment is taken out of service. The second tier
addresses the need to preclude potentially high-risk configurations
which could result if equipment is taken out of service concurrently
with the equipment out of service as allowed by this TS change. The
third tier addresses the application of 10 CFR 50.65(a)(4) of the
Maintenance Rule for identifying risk-significant configurations
resulting from maintenance related activities and taking appropriate
compensatory measures to avoid such configurations. This TS invokes a
risk assessment because 10 CFR 50.65(a)(4) is applicable to maintenance
related activities and does not cover other operational activities
beyond the effect they may have on existing maintenance related risk.
BWROG's risk assessment approach was found comprehensive and
acceptable in the SE for the topical report. In addition, the analyses
show that the three-tiered approach criteria for allowing TS changes
are met as follows:
Risk Impact of the Proposed Change (Tier 1). The risk
changes associated with the TS changes in TSTF-423, in terms of mean
yearly increases in core damage frequency (CDF) and large early release
frequency (LERF), are risk neutral or risk beneficial. In addition,
there are no significant temporary risk increases, as defined by RG
1.177 criteria, associated with the implementation of the TS end state
changes.
Avoidance of Risk-Significant Configurations (Tier 2). The
performed risk analyses, which are based on single LCOs, shows that
there are no high-risk configurations associated with the TS end state
changes. The reliability of redundant trains is normally covered by a
single LCO. When multiple LCOs occur, which affect trains in several
systems, the plant's risk-informed configuration risk management
program (CRMP), or the risk assessment and management program
implemented in response to the Maintenance Rule 10 CFR 50.65(a)(4),
shall ensure that high-risk configurations are avoided. As part of the
implementation of TSTF-423, the licensee has committed to follow
Section 11 of NUMARC 93-01, Revision 3, and include guidance in
appropriate plant procedures and/or administrative controls to preclude
high-risk plant configurations when the plant is at the proposed end
state. The staff finds that such guidance is adequate for preventing
risk-significant plant configurations.
Configuration Risk Management (Tier 3). The licensee has a
program, as described above, in place to comply with 10 CFR 50.65(a)(4)
to assess and manage the risk from maintenance activities. This program
can support a licensee decision in selecting the appropriate actions to
control risk for most cases in which a risk-informed TS is entered.
The generic risk impact of the end state mode change was evaluated
subject to the following assumptions
[[Page 14730]]
which are incorporated into the TS, TS Bases, and TSTF-IG-05-02
(Reference 8):
1. The entry into the end state is initiated by the inoperability
of a single train of equipment or a restriction on a plant operational
parameter, unless otherwise stated in the applicable technical
specification.
2. The primary purpose of entering the end state is to correct the
initiating condition and return to power as soon as is practical.
3. When Mode 3 is entered as the repair end state, the time the
reactor coolant pressure is above 500 psig will be minimized. If
reactor coolant pressure is above 500 psig for more than 12 hours, the
associated plant risk will be assessed and managed.
These assumptions are consistent with typical entries into Mode 3
for short duration repairs, which is the intended use of the TS end
state changes.
The staff concludes that, in general, going to Mode 3 (hot
shutdown) instead of going to Mode 4 (cold shutdown) to carry out
equipment repairs that are of short duration, does not have any adverse
effect on plant risk.
3.2 Assessment of TS Changes
The changes proposed by the licensee and in TSTF-423 are consistent
with the changes in topical report GE NEDC-32988 (Reference 1), and
approved by the NRC SE (Reference 6). The following are the changes,
including a synopsis of the STS LCO, and a conclusion of acceptability.
3.2.1 Topical Report Section (TRS) 4.5.1.2 and LCO 3.4.3 (BWR/4);
TRS 4.5.2.2 and LCO 3.4.4 (BWR/6), Safety/Relief Valves (SRVs).
The function of the SRVs is to protect the plant against severe
overpressurization events. These TS provide the operability
requirements for the SRVs as described below. The TS change allows the
plant to remain in Mode 3 until the repairs are completed.
[Note:
Plant Applicability, BWR4/6]
LCO: The safety function of 11 SRVs must be operable (BWR/4
plants). The safety function of seven SRVs must be operable and the
relief function of seven additional SRVs must be operable (BWR/6
plants).
Condition requiring entry into end state: If the LCO cannot be met
with one or two SRVs inoperable, the inoperable valves must be returned
to operability within 14 days. If the SRVs cannot be returned to
operable status within that time, the plant must be placed in Mode 3
within 12 hours and in Mode 4 within 36 hours.
Modification for end state required actions: If the LCO cannot be
met with one or two SRVs inoperable, the inoperable valves must be
returned to operability within 14 days. If the one or two inoperable
SRVs cannot be returned to operable status within 14 days, the plant
must be placed in Mode 3 within 12 hours. If three or more SRVs become
inoperable, the plant must be placed in Mode 4 within 36 hours.
Assessment: The BWROG topical report did a comparative PRA
evaluation of the core damage risks of operation in the current end
state and in the Mode 3 end state. The evaluation indicates that the
core damage risks are lower in Mode 3 than in Mode 4. Going to Mode 4
for one inoperable SRV would cause loss of the high-pressure steam-
driven injection system (reactor core isolation cooling (RCIC)/high
pressure coolant injection (HPCI)), and loss of the power conversion
system (condenser/feedwater), and require activating the residual heat
removal (RHR) system. In addition, emergency operating procedures
(EOPs) direct the operator to take control of the depressurization
function if low pressure injection/spray systems are needed for reactor
pressure vessel (RPV) water makeup and cooling. Based on the low
probability of loss of the necessary overpressure protection function
and the number of systems available in Mode 3, the staff concluded in
the SE (reference 6) for the BWROG topical report that the risks of
staying in Mode 3 are approximately the same as, and in some cases
lower than, the risks of going to the Mode 4 end state. The change
allows the inoperable SRV to be repaired in a plant operating mode with
lower risks. After repairs are made, the plant can be brought to full-
power operation with less potential for transients and errors. The
plant is taken into cold shutdown only when three or more SRVs are
inoperable.
Finding: Based on the above assessment, and because the time spent
in Mode 3 to perform the repair is infrequent and limited, and in light
of defense-in-depth considerations (discussed in Reference 1), the
staff finds that the requested change to allow operation in Mode 3 with
a minimum number of SRVs inoperable, after plant risk has been assessed
and managed, is acceptable.
3.2.2 TRS 4.5.1.3 and LCO 3.5.1(BWR/4); TRS 4.5.2.3 and LCO 3.5.1
(BWR/6), Emergency Core Cooling Systems (ECCS) (Operating).
The ECCS systems provide cooling water to the core in the event of
a loss-of-coolant accident (LOCA). This set of ECCS TS provide the
operability requirements for the various ECCS subsystems as described
below. This TS change would delete the secondary actions. The plant can
remain in Mode 3 until the required repair actions are completed. The
reactor is not depressurized.
[Note:
Plant Applicability, BWR4/6]
LCO: Each ECCS injection/spray subsystem and the automatic
depressurization system (ADS) function of seven BWR/4, or eight BWR/6,
SRVs must be operable.
Conditions requiring entry into end state: If the LCO cannot be
met, the following actions must be taken for the listed conditions:
a. If one low-pressure ECCS injection/spray subsystem is
inoperable, the subsystem must be restored to operable status in 7
days.
b. If the inoperable ECCS injection/core spray cannot be restored
to operable status, the plant must be placed in Mode 3 within 12 hours
and Mode 4 within 36 hours (BWR/4 plants only).
c. If two ECCS injection subsystems are inoperable or one ECCS
injection subsystem and one ECCS spray system are inoperable, one ECCS
injection/spray subsystem must be restored to operable status within 72
hours. If this required action cannot be met, the plant must be placed
in Mode 3 within 12 hours and in Mode 4 within 36 hours (BWR/6 plants
only).
d. If the HPCI/High Pressure Core Spray (HPCS) system is
inoperable, the RCIC system must be verified to be operable by
administrative means within 1 hour and the HPCI/HPCS system restored to
operable status within 14 days.
e. If one ADS valve is inoperable, it must be restored to operable
status within 14 days.
f. If one ADS valve is inoperable and one low-pressure ECCS
injection/spray subsystem is inoperable, the ADS valve must be restored
to operable status within 72 hours or the low-pressure ECCS injection/
spray subsystem must be restored to operable status within 72 hours.
g. If two or more ADS valves become inoperable, or the required
actions described in items e and/or f cannot be met, the plant must be
placed in Mode 3 within 12 hours and the reactor steam dome pressure
reduced to less than 150 psig within 36 hours.
Modification for End State Required Actions:
a. No change
b. If the ECCS injection or spray system is inoperable, the plant
must be
[[Page 14731]]
restored to operable status within 12 hours. The plant is not taken
into Mode 4 (cold shutdown).
c. If two ECCS injection subsystems are inoperable or one ECCS
injection subsystem and one ECCS spray system are inoperable, one ECCS
injection/spray subsystem must be restored to operable status within 72
hours. If this required action cannot be met, the plant must be placed
in Mode 3 within 12 hours. The plant is not taken into Mode 4 (BWR/6
plants only).
d. No change
e. No change
f. No change
g. If two or more ADS valves become inoperable or the required
actions described in item e and/or f cannot be met, the plant must be
placed in Mode 3 within 12 hours. The reactor is not depressurized and
not taken to Mode 4.
Assessment: The BWROG topical report did a comparative PRA
evaluation of the core damage risks of operation in the current end
state and the Mode 3 end state. The evaluation indicates that the core
damage risks are lower in Mode 3 than in the current end state Mode 4.
Going to Mode 4 for one ECCS subsystem or one ADS valve would cause
loss of the high-pressure steam-driven injection system (RCIC/HPCI),
and loss of the power conversion system (condenser/feedwater), and
require activating the RHR system. In addition, Plant Emergency
Operating Procedures (EOPs) direct the operator to take control of the
depressurization function if low-pressure injection/spray systems are
needed for RPV water makeup and cooling. Based on the low probability
of loss of the reactor coolant inventory and the number of systems
available in Mode 3, the staff concludes in the SE to the BWR topical
report that the risks of staying in Mode 3 are approximately the same
as, and in some cases lower than, the risks of going to the Mode 4 end
state.
Finding: Based on the above assessment, and because the time spent
in Mode 3 to perform the repair is infrequent and limited, and in light
of defense-in-depth considerations (discussed in Reference 1), the
change is acceptable.
3.2.3 TRS 4.5.1.4 and LCO 3.5.3 (BWR/4 only), Reactor Core
Isolation Cooling (RCIC) System.
The function of the RCIC system is to provide reactor coolant
makeup during loss of feedwater and other transient events. This TS
provides the operability requirements for the RCIC system as described
below. The TS change allows the plant to remain in Mode 3 until the
repairs are completed.
[Note:
Plant Applicability, BWR/4]
LCO: The RCIC system must be operable during Modes 1, 2 and 3 when
the reactor steam dome pressure is greater than 150 psig.
Condition requiring entry into end state: If the LCO cannot be met,
the following actions must be taken: (a) Verify by administrative means
within 1 hour that the HPCI system is operable, (b) restore the RCIC
system to operable status within 14 days. If either or both actions
cannot be completed within the allotted time, the plant must be placed
in Mode 3 within 12 hours and the reactor steam dome pressure reduced
to less than 150 psig within 36 hours.
Modification for end state required actions: This TS change keeps
the plant in Mode 3 (hot shutdown) until the required repairs are
completed. The reactor steam dome pressure is not reduced to less than
150 psig.
Assessment: This change would allow the inoperable RCIC system to
be repaired in a plant operating mode with lower risk and without
challenging the normal shutdown systems. The BWROG topical report did a
comparative PRA evaluation of the core damage risks of operation in the
current end state and in the Mode 3 end state. The evaluation indicates
that the core damage risks are lower in Mode 3 than in Mode 4. Going to
Mode 3 with reactor steam dome pressure less than 150 psig for
inoperability of RCIC would also cause loss of the high-pressure steam-
driven injection system HPCI and loss of the power conversion system
(condenser/ feedwater), and would require activating the RHR system. In
addition, Plant EOPs direct the operator to take control of the
depressurization function if low pressure injection/spray systems are
needed for RPV water makeup and cooling. Based on the low probability
of loss of the necessary overpressure protection function and the
number of systems available in Mode 3, the staff concludes in the SE to
the BWR topical report that the risks of staying in Mode 3 are
approximately the same as, and in some cases lower than, the risks of
going to the Mode 4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.4 TRS 4.5.1.6 and LCO 3.6.1.6 (BWR/4); TRS 5.5.2.5 and LCO
3.6.1.6 (BWR/6), Low-Low Set (LLS) Valves.
The function of LLS is to prevent excessive short-duration SRV
cycling during an overpressure event. This TS provides operability
requirements for the four LLS SRVs as described below. The TS change
allows the plant to remain in Mode 3 until the repairs are completed.
[Note:
Plant Applicability, BWR 4/6]
Conditions requiring entry into end state: If one LLS valve is
inoperable, it must be returned to operability within 14 days. If the
LLS valve cannot be returned to operable status within the allotted
time, the plant must be placed in Mode 3 within 12 hours and in Mode 4
within 36 hours.
Modification for end state required actions: The TS change would
keep the plant in Mode 3 until the required repair actions are
completed. The plant would not be taken into Mode 4 (cold shutdown).
Assessment: The BWROG topical report did a comparative PRA
evaluation of the core damage risks of operation in the current end
state and the Mode 3 end state. The evaluation indicates that the core
damage risks are lower in Mode 3 than in Mode 4, the current end state.
Going to Mode 4 for one LLS inoperable SRV would cause loss of the
high-pressure steam-driven injection system (RCIC/HPCI), and loss of
the power conversion system (condenser/feedwater), and would require
activating the RHR system. With one LLS valve inoperable, the remaining
valves are adequate to perform the required function. EOPs direct the
operator to take control of the depressurization function if low
pressure injection/spray systems are needed for RPV water makeup and
cooling. Based on the low probability of loss of the necessary
overpressure protection function during the infrequent and limited time
in Mode 3 and the number of systems available in Mode 3, the staff
concludes in the SE to the BWR topical report that the risks of staying
in Mode 3 are approximately the same as and in some cases lower than
the risks of going to the Mode 4 end state. The change allows repairs
of the inoperable SRV to be performed in a plant operating mode with
lower risks.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.5 TRS 4.5.1.1, TRS 4.5.2.1 and LCO 3.3.8.2, Reactor Protection
System (RPS) Electric Power Monitoring.
RPS Electric Power Monitoring System is provided to isolate the RPS
bus from the motor generator (MG) set or an alternate power supply in
the event of over voltage, under voltage, or under frequency. This
system protects
[[Page 14732]]
the load connected to the RPS bus against unacceptable voltage and
frequency conditions and forms an important part of the primary success
path of the essential safety circuits. Some of the essential equipment
powered from the RPS buses includes the RPS logic, scram solenoids, and
various valve isolation logic. The TS change allows the plant to remain
in Mode 3 until the repairs are completed.
[Note:
Plant Applicability, BWR 4/6]
LCO: For Modes 1, 2, 3 and Modes 4 and 5 (with any control rod
withdrawn from a core cell containing one or more fuel assemblies), two
RPS electric power monitoring assemblies shall be operable for each in-
service RPS motor generator set or alternate power supply.
Condition Requiring Entry into End State: If the LCO cannot be met,
the associated in-service power supply(s) must be removed from service
within 72 hours for one Electric Power Assembly (EPA) inoperable or
within one hour for both EPAs inoperable. In Modes 1, 2, and 3, if the
in-service power supply(s) cannot be removed from service within the
allotted time, the plant must be placed in Mode 3 within 12 hours and
Mode 4 within 36 hours.
Modification: The change is to keep the plant in Mode 3 until the
repair actions are completed. Delete required action in C.2 which
required the plant to be in Mode 4.
Assessment: To reach Mode 3 per the TS, there must be a functioning
power supply with degraded protective circuitry in operation. However,
the over voltage, under voltage, or under frequency condition must
exist for an extended time period to cause damage. There is a low
probability of this occurring in the short period of time that the
plant would remain in Mode 3 without this protection.
The specific failure condition of interest is not risk significant
for BWR PRAs. If the required restoration actions cannot be completed
within the specified time, going into Mode 4 would cause loss of the
high-pressure steam-driven injection system (RCIC/HPCI) and loss of the
power conversion system (condenser/feedwater), and would require
activating the RHR system. In addition, EOPs direct the operator to
take control of the depressurization function if low pressure
injection/spray systems are needed for RPV water makeup and cooling.
Based on the low probability of loss of the RPS power monitoring system
during the infrequent and limited time in Mode 3 and the number of
systems available in Mode 3, the staff concludes in the SE to the BWR
topical report that the risks of staying in Mode 3 are approximately
the same as and in some cases lower than the risks of going to the Mode
4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.6 TRS 4.5.1.19 and LCO 3.8.1(BWR/4); TRS 4.5.2.17 and LCO
3.8.1(BWR/6), AC Sources (Operating).
The purpose of the AC electrical system is to provide during all
situations the power required to put and maintain the plant in a safe
condition and prevent the release of radioactivity to the environment.
The Class 1E electrical power distribution system AC sources
consist of the offsite power source (preferred power sources, normal
and alternate(s)), and the onsite standby power sources (e.g.,
emergency diesel generators (EDGs)). In addition, many sites provide a
crosstie capability between units.
As required by General Design Criterion (GDC) 17 of 10 CFR Part 50,
Appendix A, the design of the AC electrical system provides
independence and redundancy. The onsite Class 1E AC distribution system
is divided into redundant divisions so that the loss of any one
division does not prevent the minimum safety functions from being
performed. Each division has connections to two preferred offsite power
sources and a single EDG or other Class 1E Standby AC power source.
Offsite power is supplied to the unit switchyard(s) from the
transmission network by two transmission lines. From the switchyard(s),
two electrically and physically separated circuits provide AC power
through a stepdown transformer(s) to the 4.16-kV emergency buses.
In the event of a loss of offsite power, the emergency electrical
loads are automatically connected to the EDGs in sufficient time to
provide for a safe reactor shutdown and to mitigate the consequence of
a design basis accident (DBA) such as a LOCA.
[Note:
Plant Applicability, BWR 4/6]
LCO: The following AC electrical power sources shall be operable in
Modes 1, 2, and 3:
a. Two qualified circuits between the offsite transmission network
and the onsite Class1E AC Electric Power Distribution System,
b. Three EDGs,
c. Automatic Load Sequencers.
Condition requiring entry into end state: Plant operators must
bring the plant to Mode 4 within 36 hours following the sustained
inoperability of one required Automatic Load Sequencer; either or both
required offsite circuits; either one, two or three required EDGs; or
one required offsite circuit and one, two or three required EDGs.
Modification for end state require actions: Delete required action
G.2 to go to Mode 4 (cold shutdown). The plant will remain in Mode 3
(hot shutdown).
Assessment: Entry into any of the conditions for the AC power
sources implies that the AC power sources have been degraded and the
single failure protection for the safe shutdown equipment may be
ineffective. Consequently, as specified in TS 3.8.1 at present, the
plant operators must bring the plant to Mode 4 when the required action
is not completed by the specified time for the associated action.
The BWROG topical report did a comparative PRA evaluation of the
core damage risks of operation in the current end state and in the Mode
3 end state. Events initiated by the loss of offsite power are dominant
contributors to core damage frequency in most BWR PRAs, and the steam-
driven core cooling systems, RCIC and HPCI, play a major role in
mitigating these events. The evaluation indicates that the core damage
risks are lower in Mode 3 than in Mode 4 for one inoperable AC power
source. Going to Mode 4 for one inoperable AC power source would cause
loss of the high-pressure steam-driven injection system (RCIC/HPCI),
and loss of the power conversion system (condenser/feedwater), and
require activating the RHR system. In addition, EOPs direct the
operator to take control of the depressurization function if low
pressure injection/spray systems are needed for RPV water makeup and
cooling. Based on the low probability of loss of the AC power and the
number of steam-driven systems available in Mode 3, the staff concludes
in the SE to the BWR topical report that the risks of staying in Mode 3
are lower than going to the Mode 4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.7 TRS 4.5.1.20 and LCO 3.8.4 (BWR/4); TRS 4.5.2.18 and LCO
3.8.4 DC Sources (Operating).
The purpose of the DC power system is to provide a reliable source
of DC power for both normal and abnormal conditions. It must supply
power in an emergency for an adequate length of
[[Page 14733]]
time until normal supplies can be restored.
The DC electrical system:
a. Provides the AC emergency power system with control power,
b. Provides motive and control power to selected safety related
equipment, and
c. Provides power to preferred AC vital buses (via inverters).
[Note:
Plant Applicability, BWR 4/6]
LCO: For Modes 1, 2 and 3, the following DC sources are required to
be operable: BWR/4: The (Division 1 and Division 2 station service, and
DG 1B, 2A, and 2C) DC electrical power systems shall be operable.
BWR/6: The (Divisions 1, 2, and 3) DC electrical power subsystems
shall be operable.
Condition requiring entry into end state: The plant operators must
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours
following the sustained inoperability of one DC electrical power
subsystem for a period of 2 hours.
Modification for end state required actions: The TS change is to
remove the requirement to place the plant in Mode 4, Required Actions
in D.2 (BWR/4) and E.2 (BWR/6) are deleted.
Assessment: If one of the DC electrical power subsystems is
inoperable, the remaining DC electrical power subsystems have the
capacity to support a safe shutdown and to mitigate an accident
condition. The BWROG topical report did a comparative PRA evaluation of
the core damage risks of operation in the current end state and in the
Mode 3 end state, with one DC system inoperable. Events initiated by
the loss of offsite power are dominant contributors to core damage
frequency in most BWR PRAs, and the steam-driven core cooling systems,
RCIC and HPCI, play a major role in mitigating these events. The
evaluation indicates that the core damage risks are lower in Mode 3
than in Mode 4. Going to Mode 4 for one inoperable DC power source
would cause loss of the high-pressure steam-driven injection system
(RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs
direct the operator to take control of the depressurization function if
low pressure injection/spray systems are needed for RPV water makeup
and cooling. Based on the low probability of loss of the DC power and
the number of systems available in Mode 3, the staff concludes in the
SE to the BWR topical report that the risks of staying in Mode 3 are
approximately the same as and in some cases lower than the risks of
going to the Mode 4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.8 TRS 4.5.1.21 and LCO 3.8.7 (BWR/4); TRS 4.5.2.19 and 3.8.7
(BWR/6), Inverters (Operating).
In Modes 1,2,and 3, the inverters provide the preferred source of
power for the 120-VAC vital buses which power the reactor protection
system (RPS) and the Emergency Core Cooling Systems (ECCS) initiation.
The inverter can be powered from an internal AC source/rectifier or
from the station battery.
[Note:
Plant Applicability, BWR 4/6]
LCO: For Modes 1, 2, and 3 the following Inverters shall be
operable:
BWR/4: The (Division 1 and Division 2) shall be operable.
BWR/6: The (Divisions 1, 2, and 3) shall be operable.
Condition requiring entry into end state: The plant operators must
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours
following the sustained inoperability of the required inverter for a
period of 24 hours.
Modification for end state required actions: The TS change is to
remove the requirement to place the plant in Mode 4. Required Actions
in B.2 (BWR/4) and C.2 (BWR/6) are deleted.
Assessment: If one of the Inverters is inoperable, the remaining
Inverters have the capacity to support a safe shutdown and to mitigate
an accident condition. The BWROG topical report did a comparative PRA
evaluation of the core damage risks of operation in the current end
state and in the Mode 3 end state, with an inoperable Inverter. Events
initiated by the loss of offsite power are dominant contributors to
core damage frequency in most BWR PRAs, and the steam-driven core
cooling systems, RCIC and HPCI, play a major role in mitigating these
events. The evaluation indicates that the core damage risks are lower
in Mode 3 than in Mode 4. Going to Mode 4 for one inoperable Inverter
power source would cause loss of the high-pressure steam-driven
injection system (RCIC/HPCI), and loss of the power conversion system
(condenser/feedwater), and require activating the RHR system. In
addition, EOPs direct the operator to take control of the
depressurization function if low pressure injection/spray systems are
needed for RPV water makeup and cooling. Based on the low probability
of loss of the Inverters during the infrequent and limited time in Mode
3 and the number of systems available in Mode 3, the staff concludes in
the SE to the BWR topical report that the risks of staying in Mode 3
are approximately the same as and in some cases lower than the risks of
going to the Mode 4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.9 TRS 4.5.1.22 and LCO 3.8.9 (BWR/4); TRS 4.5.2.20 and LCO
3.8.9 (BWR/6), Distribution Systems(Operating).
The onsite Class 1E AC and DC electrical power distribution system
is divided into redundant and independent AC, DC, and AC vital bus
electrical power distribution systems. The primary AC electrical power
distribution subsystem for each division consists of a 4.16-kV
Engineered Safety Feature (ESF) bus having an offsite source of power
as well as a dedicated onsite EDG source. The secondary plant
distribution subsystems include 600-VAC emergency buses and associated
load centers, motor control centers, distribution panels and
transformers. The 120-VAC vital buses are arranged in four load groups
and normally powered from DC via the inverters. There are two
independent 125/250-VDC station service electrical power distribution
systems and three independent 125-VDC DG electrical power distribution
subsystems that support the necessary power for ESF functions. Each
subsystem consists of a 125-VDC and 250-VDC bus and associated
distribution panels.
[Note:
Plant Applicability, BWR 4/6]
LCO: For Modes 1,2, and 3, the following electrical power
distribution subsystems shall be operable:
BWR/4: The Division 1 and Division 2 AC, DC, and AC vital buses
shall be operable.
BWR/6: The Divisions 1, 2, and 3 AC, DC, and AC vital buses shall
be operable.
Condition requiring entry into end state: The plant operators must
bring the plant to Mode 3 within 12 hours and Mode 4 within 36 hours
following the sustained inoperability of one AC or one DC or one AC
vital bus electrical power subsystem for a period of 8 hours, 2 hours
and 2 hours, respectively (with a maximum 16 hour Completion Time limit
from initial discovery of failure to
[[Page 14734]]
meet the LCO, to preclude being in the LCO indefinitely).
Modification for end state required actions: The TS change is to
remove the requirement to place the plant in Mode 4, Required Action in
D.2 (BWR/4) and D.2 (BWR/6) are deleted.
Assessment: If one of the AC/DC/AC vital subsystems is inoperable,
the remaining AC/DC/AC vital subsystems have the capacity to support a
safe shutdown and to mitigate an accident condition. The BWROG topical
report did a comparative PRA evaluation of the core damage risks of
operation in the current end state and in the Mode 3 end state, with
one of the AC/DC/AC vital subsystems inoperable. Events initiated by
the loss of offsite power are dominant contributors to core damage
frequency in most BWR PRAs, and the steam-driven core cooling systems,
RCIC and HPCI, play a major role in mitigating these events. The
evaluation indicates that the core damage risks are lower in Mode 3
than in Mode 4. Going to Mode 4 for one inoperable AC/DC/AC vital
subsystem would cause loss of the high-pressure steam-driven injection
system (RCIC/HPCI), and loss of the power conversion system (condenser/
feedwater), and require activating the RHR system. In addition, EOPs
direct the operator to take control of the depressurization function if
low pressure injection/spray systems are needed for RPV water makeup
and cooling. Based on the low probability of loss of the AC/DC/AC vital
electrical subsystems during the infrequent and limited time in Mode 3
and the number of systems available in Mode 3, the staff concludes in
the SE to the BWR topical report that the risks of staying in Mode 3
are approximately the same as and in some cases lower than the risks of
going to the Mode 4 end state.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.10 TRS 4.5.1.5 and LCO 3.6.1.1, Primary Containment.
The function of the primary containment is to isolate and contain
fission products released from the Reactor Primary System following a
design basis LOCA and to confine the postulated release of
radioactivity. The primary containment consists of a steel-lined,
reinforced concrete vessel, which surrounds the Reactor Primary System
and provides an essentially leak-tight barrier against an uncontrolled
release of radioactivity to the environment. Additionally, this
structure provides shielding from the fission products that may be
present in the primary containment atmosphere following accident
conditions.
[Note:
Plant Applicability, BWR 4/6]
LCO: The primary containment shall be operable.
Condition Requiring Entry into End State: If the LCO cannot be met,
the primary containment must be returned to operability within one hour
(Required Action A.1). If the primary containment cannot be returned to
operable status within the allotted time, the plant must be placed in
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36
hours (Required Action B.2).
Modification for End State Required Actions: Delete Required Action
B.2.
Assessment: The primary containment is one of the three primary
boundaries to the release of radioactivity. (The other two are the fuel
cladding and the Reactor Primary System pressure boundary.) Compliance
with this LCO ensures that a primary containment configuration exists,
including equipment hatches and penetrations, that is structurally
sound and will limit leakage to those leakage rates assumed in the
safety analyses. This LCO entry condition does not include leakage
through an unisolated release path. The BWROG topical report has
determined that previous generic PRA work related to Appendix J
requirements has shown that containment leakage is not risk
significant. Should a fission product release from the primary
containment occur, the secondary containment and related functions
would remain operable to contain the release, and the standby gas
treatment system would remain available to filter fission products from
being released to the environment. By remaining in Mode 3, HPCI, RCIC,
and the power conversion system (condensate/feedwater) remain available
for water makeup and decay heat removal. Additionally, the EOPs direct
the operators to take control of the depressurization function if low
pressure injection/spray are needed for reactor coolant makeup and
cooling. Therefore, defense-in-depth is maintained with respect to
water makeup and decay heat removal by remaining in Mode 3.
Finding: The requested change is acceptable. Note that the staff's
approval relies upon the secondary containment and the standby gas
treatment system for maintaining defense-in-depth while in this reduced
end state.
3.2.11 TRS 4.5.1.7 and LCO 3.6.1.7, Reactor Building-to-Suppression
Chamber Vacuum Breakers(BWR/4 only).
The reactor building-to-suppression chamber vacuum breakers relieve
vacuum when the primary containment depressurizes below the pressure of
the reactor building, thereby serving to preserve the integrity of the
primary containment.
[Note:
Plant Applicability, BWR/4]
LCO: Each reactor building-to-suppression chamber vacuum breaker
shall be operable.
Condition Requiring Entry into End State: If one line has one or
more reactor building-to-suppression chamber vacuum breakers inoperable
for opening, the breaker(s) must be returned to operability within 72
hours (Required Action C.1). If the vacuum breaker(s) cannot be
returned to operability within the allotted time, the plant must be
placed in Mode 3 within 12 hours (Required Action E.1) and in Mode 4
within 36 hours (Required Action E.2).
Modification for End State Required Actions: Modify the Required
Actions so that if vacuum breaker(s) cannot be returned to operable
status within the required Completion Times, the plant is place in hot
shutdown. That is, modify Condition E to relate only to Condition C,
delete Required Action E.2, and add Condition F, with Required Actions
F.1 and F.2, shutting down the plant to Mode 3 and then Mode 4
respectively, to address an inability to comply with the required
actions related to the other Conditions (i.e., Conditions A, B, and D).
Assessment: The BWROG topical report has determined that the
specific failure condition of interest is not risk significant in BWR
PRAs. The reduced end state would only be applicable to the situation
where the vacuum breaker(s) in one line are inoperable for opening,
with the remaining operable vacuum breakers capable of providing the
necessary vacuum relief function. The existing end state remains
unchanged, as established by new Condition F, for conditions involving
more than one inoperable line or vacuum breaker since they are needed
in Modes 1, 2, and 3. In Mode 3, for other accident considerations,
HPCI, RCIC, and the power conversion system (condensate/feedwater)
remain available for water makeup and decay heat removal. Additionally,
the EOPs direct the operators to take control of the depressurization
function if low pressure injection/spray are needed for reactor coolant
makeup and cooling. Therefore, defense-in-depth is maintained with
respect to water
[[Page 14735]]
makeup and decay heat removal by remaining in Mode 3.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.12 TRS 4.5.1.8 and LCO 3.6.1.8, Suppression Chamber-to-Drywell
Vacuum Breakers(BWR/4 only).
The function of the suppression chamber-to-drywell vacuum breakers
is to relieve vacuum in the drywell, thereby preventing an excessive
negative differential pressure across the wetwell/drywell boundary.
[Note:
Plant Applicability, BWR/4]
LCO: Nine suppression chamber-to-drywell vacuum breakers shall be
operable for opening.
Condition Requiring Entry into End State: If one suppression
chamber-to-drywell vacuum breaker is inoperable for opening, the
breaker must be returned to operability within 72 hours (Required
Action A.1). If the vacuum breaker cannot be returned to operability
within the allotted time, the plant must be placed in Mode 3 within 12
hours (Required Action C.1) and in Mode 4 within 36 hours (Required
Action C.2).
Modification for End State Required Actions: Modify the Required
Actions so that if vacuum breaker(s) cannot be returned to operable
status within the required Completion Times, the plant is placed in hot
shutdown. That is, modify Condition C to relate only to Condition A,
and delete Required Action C.2, and add Condition D, with Required
Actions D.1 and D.2, shutting down the plant to Mode 3 and then Mode 4
respectively, to address an inability to comply with the required
actions related to Condition B, to close the vacuum breaker.
Assessment: The BWROG topical report has determined that the
specific failure of interest is not risk significant in BWR PRAs. The
reduced end state would only be applicable to the situation where one
suppression chamber-to-drywell vacuum breaker is inoperable for
opening, with the remaining operable vacuum breakers capable of
providing the necessary vacuum relief function, since they are required
in Modes 1, 2, and 3. By remaining in Mode 3, HPCI, RCIC, and the power
conversion system (condensate/feedwater) remain available for water
makeup and decay heat removal. Additionally, the EOPs direct the
operators to take control of the depressurization function if low
pressure injection/spray are needed for RCS makeup and cooling.
Therefore, defense-in-depth is maintained with respect to water makeup
and decay heat removal by remaining in Mode 3. The existing end state
remains unchanged for conditions involving any suppression chamber-to-
drywell vacuum breakers that are stuck open, as established by new
Condition D.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.13 TRS 4.5.1.9, TRS 4.5.2.8, and LCO 3.6.1.9, Main Steam
Isolation Valve (MSIV) Leakage Control System (LCS).
The MSIV LCS supplements the isolation function of the MSIVs by
processing the fission products that could leak through the closed
MSIVs after core damage, assuming leakage rate limits which are based
on a large LOCA.
[Note:
Plant Applicability, BWR 4/6]
LCO: Two MSIV LCS subsystems shall be operable.
Condition Requiring Entry into End State: If one MSIV LCS subsystem
is inoperable, it must be restored to operable status within 30 days
(Required Action A.1). If both MSIV LCS subsystems are inoperable, one
of the MSIV LCS subsystems must be restored to operable status within
seven days (Required Action B.1). If the MSIV LCS subsystems cannot be
restored to operable status within the allotted time, the plant must be
placed in Mode 3 within 12 hours (Required Action C.1) and in Mode 4
within 36 hours (Required Action C.2).
Modification for End State Required Actions: Delete Required Action
C.2.
Assessment: The BWROG topical report has determined that this
system is not significant in BWR PRAs and, based on a BWROG program,
many plants have eliminated the system altogether. The unavailability
of one or both MSIV LCS subsystems has no impact on CDF or LERF,
irrespective of the mode of operation at the time of the accident.
Furthermore, the challenge frequency of the MSIV LCS system (i.e., the
frequency with which the system is expected to be challenged to
mitigate offsite radiation releases resulting from MSIV leaks above TS
limits) is less than 1.0E-6/yr. Consequently, the conditional
probability that this system will be challenged during the repair time
interval while the plant is at either the current or the proposed end
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This
probability is considerably smaller than probabilities considered
``negligible'' in Regulatory Guide 1.177 for much higher consequence
risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.9, TRS 4.5.2.8, and LCO 3.6.1.9, ``Main Steam
Isolation Valve (MSIV) Leakage Control System (LCS).'' The argument for
staying in Mode 3 instead of going to Mode 4 to repair the MSIV LCS
system (one or both trains) is also supported by defense-in-depth
considerations. Section 6.2 makes a comparison between the Mode 3 and
the Mode 4 end state, with respect to the means available to perform
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and
containment failure and mitigate radiation releases. The risk and
defense-in-depth arguments, used according to the ``integrated
decision-making'' process of Regulatory Guides 1.174 and 1.177, support
the conclusion that the plant in Mode 3 is as safe as Mode 4 (if not
safer) for repairing an inoperable MSIV LCS system. Personnel safety
must be considered separately.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.14 TRS 4.5.1.11 and LCO 3.6.2.4, Residual Heat Removal (RHR)
Suppression Pool Spray(BWR/4 only).
Following a DBA, the RHR suppression pool spray system removes heat
from the suppression chamber airspace. A minimum of one RHR suppression
pool spray subsystem is required to mitigate potential bypass leakage
paths from drywell and maintain the primary containment peak pressure
below the design limits.
[Note:
Plant Applicability, BWR/4]
LCO: Two RHR suppression pool spray subsystems shall be operable.
Condition Requiring Entry into End State: If one RHR suppression
pool spray subsystem is inoperable (Condition A), it must be restored
to operable status within seven days (Required Action A.1). If both RHR
suppression pool spray subsystems are inoperable (Condition B), one of
them must be restored to operable status within eight hours (Required
Action B.1). If the RHR suppression pool spray subsystem cannot be
restored to operable status within the allotted time, the plant must be
placed in Mode 3 within 12 hours (Required Action C.1),
[[Page 14736]]
and in Mode 4 within 36 hours (Required Action C.2).
Modification for End State Required Actions: Delete Required Action
C.2.
Assessment: The main function of the RHR suppression spray system
is to remove heat from the suppression chamber so that the pressure and
temperature inside primary containment remain within analyzed design
limits. The RHR suppression spray system was designed to mitigate
potential effects of a postulated DBA, that is, a large LOCA which is
assumed to occur concurrently with the most limiting single failure and
conservative inputs, such as for initial suppression pool water volume
and temperature. Under the conditions assumed in the DBA, steam blown
down from the break could bypass the suppression pool and end up in the
suppression chamber air space and the RHR suppression spray system
could be needed to condense such steam so that the pressure and
temperature inside primary containment remain within analyzed design
basis limits. However, the frequency of a DBA is very small and the
containment has considerable margin to failure above the design limits.
For these reasons, the unavailability of one or both RHR suppression
spray subsystems has no significant impact on CDF or LERF, even for
accidents initiated during operation at power. Therefore, it is very
unlikely that the RHR suppression spray system will be challenged to
mitigate an accident occurring during power operation. This probability
becomes extremely unlikely for accidents that would occur during a
small fraction of the year (less than three days) during which the
plant would be in Mode 3 (associated with lower initial energy level
and reduced decay heat load as compared to power operation) to repair
the failed RHR suppression spray system.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.11 and LCO 3.6.2.4, ``Residual Heat Removal (RHR)
Suppression Pool Spray.'' The argument for staying in Mode 3 instead of
going to Mode 4 to repair the RHR Suppression Pool Spray system (one or
both trains) is also supported by defense-in-depth considerations.
Section 6.2 makes a comparison between the Mode 3 and the Mode 4 end
state, with respect to the means available to perform critical
functions (i.e., functions contributing to the defense-in-depth
philosophy) whose success is needed to prevent core damage and
containment failure and mitigate radiation releases, and precluding the
need for RHR suppression spray subsystems.
In addition, the probability of a DBA (large break) is much smaller
during shutdown as compared to power operation. A DBA in Mode 3 would
be considerably less severe than a DBA occurring during power operation
since Mode 3 is associated with lower initial energy level and reduced
decay heat load. Under these extremely unlikely conditions, an
alternate method that can be used to remove heat from the primary
containment (in order to keep the pressure and temperature within the
analyzed design basis limits) is containment venting. For more
realistic accidents that could occur in Mode 3, several alternate means
are available to remove heat from the primary containment, such as the
RHR system in the suppression pool cooling mode and the containment
spray mode.
The risk and defense-in-depth arguments, used according to the
``integrated decision-making'' process of Regulatory Guides 1.174 and
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not
safer) for repairing an inoperable RHR suppression spray system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.15 TRS 4.5.1.12, TRS 4.5.2.10, and LCO 3.6.4.1, Secondary
Containment.
Following a DBA, the function of the secondary containment is to
contain, dilute, and stop radioactivity (mostly fission products) that
may leak from primary containment. Its leak tightness is required to
ensure that the release of radioactivity from the primary containment
is restricted to those leakage paths and associated leakage rates
assumed in the accident analysis and that fission products entrapped
within the secondary containment structure will be treated by the
standby gas treatment system prior to discharge to the environment.
[Note:
Plant Applicability, BWR 4/6]
LCO: The secondary containment shall be operable.
Condition Requiring Entry into End State: If the secondary
containment is inoperable, it must be restored to operable status
within four hours (Required Action A.1). If it cannot be restored to
operable status within the allotted time, the plant must be placed in
Mode 3 within 12 hours (Required Action B.1), and in Mode 4 within 36
hours (Required Action B.2).
Modification for End State Required Actions: Delete Required Action
B.2.
Assessment: This LCO entry condition does not include gross leakage
through an unisolable release path. The BWROG topical report has
determined that previous generic PRA work related to Appendix J
requirements has shown that containment leakage is not risk
significant. The primary containment, and all other primary and
secondary containment-related functions would still be operable,
including the standby gas treatment system, thereby minimizing the
likelihood of an unacceptable release. By remaining in Mode 3, HPCI,
RCIC, and the power conversion system (condensate/feedwater) remain
available for water makeup and decay heat removal. Additionally, the
EOPs direct the operators to take control of the depressurization
function if low pressure injection/spray are needed for RCS makeup and
cooling. Therefore, defense-in-depth is improved with respect to water
makeup and decay heat removal by remaining in Mode 3.
Finding: The requested change is acceptable. Note that the staff's
approval relies upon the primary containment, and all other primary and
secondary containment-related functions, to still be operable,
including the standby gas treatment system, for maintaining defense-in-
depth while in this end state.
3.2.16 TRS 4.5.1.13, TRS 4.5.2.11, and LCO 3.6.4.3, Standby Gas
Treatment (SGT) System.
The function of the SGT system is to ensure that radioactive
materials that leak from the primary containment into the secondary
containment following a DBA are filtered and adsorbed prior to
exhausting to the environment.
Applicability: BWR4/6.
LCO: Two SGT subsystems shall be operable.
Condition Requiring Entry into End State: If one SGT subsystem is
inoperable, it must be restored to operable status within seven days
(Required Action A.1). If the SGT subsystem cannot be restored to
operable status within the allotted time, the plant must be placed in
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36
hours (Required Action B.2). In addition, if two SGT subsystems are
inoperable in Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately
(Required Action D.1).
Modification for End State Required Actions: Delete Required Action
B.2. Change Required Action D.1 to ``Be in Mode 3'' with a Completion
Time of ``12 hours.''
[[Page 14737]]
Assessment: The unavailability of one or both SGT subsystems has no
impact on CDF or LERF, irrespective of the mode of operation at the
time of the accident. Furthermore, the challenge frequency of the SGT
system (i.e., the frequency with which the system is expected to be
challenged to mitigate offsite radiation releases resulting from
materials that leak from the primary to the secondary containment above
TS limits) is less than 1.0E-6/yr. Consequently, the conditional
probability that this system will be challenged during the repair time
interval while the plant is at either the current or the proposed end
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This
probability is considerably smaller than probabilities considered
``negligible'' in Regulatory Guide 1.177 for much higher consequence
risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.13, TRS 4.5.2.11, and LCO 3.6.4.3, ``Standby Gas
Treatment (SGT) System.'' The argument for staying in Mode 3 instead of
going to Mode 4 to repair the SGT system (one or both trains) is also
supported by defense-in-depth considerations. Section 6.2 makes a
comparison between the Mode 3 and the Mode 4 end state, with respect to
the means available to perform critical functions (i.e., functions
contributing to the defense-in-depth philosophy) whose success is
needed to prevent core damage and containment failure and mitigate
radiation releases. The risk and defense-in-depth arguments, used
according to the ``integrated decision-making'' process of Regulatory
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe
as Mode 4 (if not safer) for repairing an inoperable SGT system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.17 TRS 4.5.1.14 and LCO 3.7.1, Residual Heat Removal Service
Water (RHRSW) System (BWR/4 only).
The RHRSW system is designed to provide cooling water for the RHR
system heat exchangers, which are required for safe shutdown following
a normal shutdown or DBA or transient.
[Note:
Plant Applicability, BWR/4]
LCO: Two RHRSW subsystems shall be operable.
Condition Requiring Entry into End State: If the LCO cannot be met,
the following actions must be taken for the listed conditions:
a. If one RHRSW pump is inoperable (Condition A), it must be
restored to operable status within 30 days (Required Action A.1).
b. If one RHRSW pump in each subsystem is inoperable (Condition B),
one RHRSW pump must be restored to operable status within seven days
(Required Action B.1).
c. If one RHRSW subsystem is inoperable for reasons other than
Condition A (Condition C), the RHRSW subsystem must be restored to
operable status within seven days (Required Action C.1).
d. If the required action and associated completion time cannot be
met within the allotted time (Condition E), the plant must be placed in
Mode 3 within 12 hours (Required Action E.1) and in Mode 4 within 36
hours (Required Action E.2). {Note: Condition D addresses both RHRSW
subsytems inoperable for reason other than Condition B, and its
Required Action D.1 is not affected by this change.
Modification for End State Required Actions: Renumber Conditions D
(and Required Action D.1), and E (and Required Actions E.1 and E.2), to
Conditions E (and Required Action E.1) and F (and Required Actions F.1
and F.2), respectively. Modify new Condition F to address new Condition
E, which maintains the existing requirements with respect to both RHR
subsystems being inoperable for reasons other than Condition B. Add a
new Condition D, which establishes requirements for existing Conditions
A, B, and C, that are similar to existing Condition E but without
Required Action E.2.
Assessment: The BWROG topical report performed a comparative PRA
evaluation of the core damage risks when operating in the current end
state versus the Mode 3 end state. The results indicated that the core
damage risks while operating in Mode 3 (assuming the individual failure
conditions) are lower or comparable to the current end state. By
remaining in Mode 3, HPCI, RCIC, and the power conversion system
(condensate/feedwater) remain available for water makeup and decay heat
removal. Additionally, the EOPs direct the operators to take control of
the depressurization function if low pressure injection/spray are
needed for RCS makeup and cooling. Therefore, defense-in-depth is
improved with respect to water makeup and decay heat removal by
remaining in Mode 3, and the required safety function can still be
performed with the RHRSW subsystem components that are still operable.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.18 TRS 4.5.1.15 and LCO 3.7.2, Plant Service Water (PSW) System
and Ultimate Heat Sink (UHS) (BWR/4 only).
The PSW system (in conjunction with the UHS) is designed to provide
cooling water for the removal of heat from certain safe shutdown-
related equipment heat exchangers following a DBA or transient.
[Note:
Plant Applicability, BWR/4]
LCO: Two PSW subsystems and UHS shall be operable.
Condition Requiring Entry into End State: If the LCO cannot be met,
the following actions must be taken for the listed conditions:
a. If one PSW pump is inoperable (Condition A), it must be restored
to operable status within 30 days (Required Action A.1).
b. If one PSW pump in each subsystem is inoperable (Condition B),
one PSW pump must be restored to operable status within seven days
(Required Action B.1).
c. If the required action and associated completion time cannot be
met within the allotted time, the plant must be placed in Mode 3 within
12 hours (Required Action E.1) and in Mode 4 within 36 hours (Required
Action E.2).
Modification: Renumber unaffected Conditions C, D, E, and F to
Conditions D, E, F, and G respectively, and renumber associated
Required Actions accordingly. Add a new Condition C, for the Required
Actions and associated Completion Time of Conditions A and B not met,
with a Required Action C.1, to be in Mode 3 in a Completion Time of 12
hours. Change the new Condition G to read, ``Required Action and
associated Completion Time of Condition E not met, OR Both [PSW
subsystems inoperable for reasons other than Condition(s) B [and D],
[OR [UHS] inoperable for reasons other than Conditions D [or E].''
Assessment: The BWROG topical report performed a comparative PRA
evaluation of the core damage risks associated with operating in the
current end state versus the Mode 3 end state. The results indicated
that the core damage risks while operating in Mode 3 (assuming the
individual failure conditions) are lower or comparable to the current
end state. With one pump inoperable in one or more subsystems, the
remaining pumps are adequate to
[[Page 14738]]
perform the PSW heat removal function. By remaining in Mode 3, HPCI,
RCIC, and the power conversion system (condensate/feedwater) remain
available for water makeup and decay heat removal. Additionally, the
EOPs direct the operators to take control of the depressurization
function if low pressure injection/spray are needed for RCS makeup and
cooling. Therefore, defense-in-depth is improved with respect to water
makeup and decay heat removal by remaining in Mode 3.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.19 TRS 4.5.1.16 and LCO 3.7.4, Main Control Room Environmental
Control (MCREC) System (BWR/4 only).
The MCREC system provides a radiologically controlled environment
from which the plant can be safely operated following a DBA.
[Note:
Plant Applicability, BWR/4]
LCO: Two MCREC subsystems shall be operable.
Condition Requiring Entry into End State: If one MCREC subsystem is
inoperable, it must be restored to operable status within seven days
(Required Action A.1). If the MCREC subsystem cannot be restored to
operable status within the allotted time, the plant must be placed in
Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36
hours (Required Action B.2). If two MCREC subsystems are inoperable in
Mode 1, 2, or 3, LCO 3.0.3 must be entered immediately (Required Action
D.1).
Modification for End State Required Actions: Delete Required Action
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a
Completion Time of ``12 hours.''
Assessment: The unavailability of one or both MCREC subsystems has
no significant impact on CDF or LERF, irrespective of the mode of
operation at the time of the accident. Furthermore, the challenge
frequency of the MCREC system (i.e., the frequency with which the
system is expected to be challenged to provide a radiologically
controlled environment in the main control room following a DBA which
leads to core damage and leaks of radiation from the containment that
can reach the control room) is less than 1.0E-6/yr. Consequently, the
conditional probability that this system will be challenged during the
repair time interval while the plant is at either the current or the
proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than
1.0E-8. This probability is considerably smaller than probabilities
considered ``negligible'' in Regulatory Guide 1.177 for much higher
consequence risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.16, and LCO 3.7.4, ``Main Control Room
Environmental Control (MCREC) System.'' The argument for staying in
Mode 3 instead of going to Mode 4 to repair the MCREC system (one or
both trains) is also supported by defense-in-depth considerations.
Section 6.2 makes a comparison between the Mode 3 and the Mode 4 end
state, with respect to the means available to perform critical
functions (i.e., functions contributing to the defense-in-depth
philosophy) whose success is needed to prevent core damage and
containment failure and mitigate radiation releases. The risk and
defense-in-depth arguments, used according to the ``integrated
decision-making'' process of Regulatory Guides 1.174 and 1.177, support
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for
repairing an inoperable MCREC system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.20 TRS 4.5.1.17 and LCO 3.7.5, Control Room Air Conditioning
(AC) System (BWR/4 only).
The Control Room AC system provides temperature control for the
control room following control room isolation during accident
conditions.
[Note:
Plant Applicability, BWR/4]
LCO: Two control room AC subsystems shall be operable.
Condition Requiring Entry into End State: If one control room AC
subsystem is inoperable, the subsystem must be restored to operable
status within 30 days (Required Action A.1). If the required actions
and associated completion times cannot be met, the plant must be placed
in Mode 3 within 12 hours (Required Action B.1) and in Mode 4 within 36
hours (Required Action B.2). If two control room AC subsystems are
inoperable, LCO 3.0.3 must be entered immediately (Required Action
D.1).
Modification for End State Required Actions: Delete Required Action
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a
Completion Time of ``12 hours.''
Assessment: The unavailability of one or both AC subsystems has no
significant impact on CDF or LERF, irrespective of the mode of
operation at the time of the accident. Furthermore, the challenge
frequency of the AC system (i.e., the frequency with which the system
is expected to be challenged to provide temperature control for the
control room following control room isolation following a DBA) is less
than 1.0E-6/yr. Consequently, the conditional probability that this
system will be challenged during the repair time interval while the
plant is at either the current or the proposed end state (i.e., Mode 4
or Mode 3, respectively) is less than 1.0E-8. This probability is
considerably smaller than probabilities considered ``negligible'' in
Regulatory Guide 1.177 for much higher consequence risks, such as large
early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.17, and LCO 3.7.5, ``Control Room Air
Conditioning (AC) System.'' The argument for staying in Mode 3 instead
of going to Mode 4 to repair the AC system (one or both trains) is also
supported by defense-in-depth considerations. Section 6.2 makes a
comparison between the Mode 3 and the Mode 4 end state, with respect to
the means available to perform critical functions (i.e., functions
contributing to the defense-in-depth philosophy) whose success is
needed to prevent core damage and containment failure and mitigate
radiation releases. The risk and defense-in-depth arguments, used
according to the ``integrated decision-making'' process of Regulatory
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe
as Mode 4 (if not safer) for repairing an inoperable AC system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.21 TRS 4.5.1.18 and LCO 3.7.6, Main Condenser Off gas (BWR/4
only).
The Off gas from the main condenser normally includes radioactive
gases. The gross gamma activity rate is controlled to ensure that
accident analysis assumptions are satisfied and that offsite dose
limits will not be exceeded during postulated accidents. The main
condenser Off gas (MCOG) gross gamma activity rate is an initial
condition of a DBA which assumes a gross failure of the MCOG system
pressure boundary.
[[Page 14739]]
[Note:
Plant Applicability, BWR/4]
LCO: The gross gamma activity rate of the noble gases measured at
the main condenser evacuation system pretreatment monitor station shall
be <=240 mCi/second after decay of 30 minutes.
Condition Requiring Entry into End State: If the gross gamma
activity rate of the noble gases in the main condenser Off gas (MCOG)
system is not within limits, the gross gamma activity rate of the noble
gases in the main condenser Off gas must be restored to within limits
within 72 hours (Required Action A.1). If the required action and
associated completion time cannot be met, one of the following must
occur:
a. All steam lines must be isolated within 12 hours (Required
Action B.1).
b. The steam jet air ejector (SJAE) must be isolated within 12
hours (Required Action B.2).
c. The plant must be placed in Mode 3 within 12 hours (Required
Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2).
Modification for End State Required Actions: Delete Required Action
B.3.2.
Assessment: The failure to maintain the gross gamma activity rate
of the noble gases in the main condenser Off gas (MCOG) within limits
has no significant impact on CDF or LERF, irrespective of the mode of
operation at the time of the accident. Furthermore, the challenge
frequency of the MCOG system (i.e., the frequency with which the system
is expected to be challenged to mitigate offsite radiation releases
following a DBA) is less than 1.0E-6/yr. Consequently, the conditional
probability that this system will be challenged during the repair time
interval while the plant is at either the current or the proposed end
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This
probability is considerably smaller than probabilities considered
``negligible'' in Regulatory Guide 1.177 for much higher consequence
risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.1.18 and LCO 3.7.6, ``Main Condenser Off gas.'' The
argument for staying in Mode 3 instead of going to Mode 4 to repair the
MCOG system (one or both trains) is also supported by defense-in-depth
considerations. Section 6.2 makes a comparison between the Mode 3 and
the Mode 4 end state, with respect to the means available to perform
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and
containment failure and mitigate radiation releases. The risk and
defense-in-depth arguments, used according to the ``integrated
decision-making'' process of Regulatory Guides 1.174 and 1.177, support
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for
repairing an inoperable MCOG system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.22 TRS 4.5.2.6 and LCO 3.6.1.7, Residual Heat Removal (RHR)
Containment Spray System (BWR/6 only).
The primary containment must be able to withstand a postulated
bypass leakage pathway that allows the passage of steam from the
drywell directly into the primary containment airspace, bypassing the
suppression pool. The primary containment also must be able to
withstand a low energy steam release into the primary containment
airspace. The RHR Containment Spray System is designed to mitigate the
effects of bypass leakage and low energy line breaks.
[Note:
Plant Applicability, BWR/6]
LCO: Two RHR containment spray subsystems shall be operable.
Condition Requiring Entry into End State: If one RHR Containment
Spray Subsystem is inoperable, it must be restored to operable status
within seven days (Required Action A.1). If two RHR Containment Spray
Subsystems are inoperable, one of them must be restored to operable
status within eight hours (Required Action B.1). If the RHR Containment
Spray System cannot be restored to operable status within the allotted
time, the plant must be placed in Mode 3 within 12 hours (Required
Action C.1), and in Mode 4 within 36 hours (Required Action C.2)
Modification for End State Required Actions: Delete Required Action
C.2.
Assessment: The primary containment is designed with a suppression
pool so that, in the event of a LOCA, steam released from the primary
system is channeled through the suppression pool water and condensed
without producing significant pressurization of the primary
containment. The primary containment is designed so that with the pool
initially at the minimum water level and the worst single failure of
the primary containment heat removal systems, suppression pool energy
absorption combined with subsequent operator controlled pool cooling
will prevent the primary containment pressure from exceeding its design
value. However, the primary containment must also withstand a
postulated bypass leakage pathway that allows the passage of steam from
the drywell directly into the primary containment airspace, bypassing
the suppression pool. The primary containment also must withstand a
postulated low energy steam release into the primary containment
airspace. The main function of the RHR containment spray system is to
suppress steam, which is postulated to be released into the primary
containment airspace through a bypass leakage pathway and a low energy
line break under DBA conditions, without producing significant
pressurization of the primary containment (i.e., ensure that the
pressure inside primary containment remains within analyzed design
limits).
Under the conditions assumed in the DBA, steam blown down from the
break could find its way into the primary containment through a bypass
leakage pathway. In addition to the DBA, a postulated low energy pipe
break could add more steam into the primary containment airspace. Under
such an extremely unlikely scenario (very small frequency of a DBA
combined with the likelihood of a bypass pathway and a concurrent low
energy pipe brake inside the primary containment), the RHR containment
spray system could be needed to condense steam so that the pressure
inside the primary containment remains within analyzed design limits.
Furthermore, containments have considerable margin to failure above the
design limit (it is very likely that the containment will be able to
withstand pressures as much as three times the design limit). For these
reasons, the unavailability of one or both RHR containment spray
subsystems has no significant impact on CDF or LERF, even for accidents
initiated during operation at power. Therefore, it is very unlikely
that the RHR containment spray system will be challenged to mitigate an
accident occurring during power operation. This probability becomes
extremely unlikely for accidents that would occur during a small
fraction of the year (less than three days) during which the plant
would be in Mode 3 (associated with lower initial energy level and
reduced decay heat load as compared to power operation) to repair the
failed RHR containment spray system.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.2.6 and LCO 3.6.1.7, ``Residual Heat Removal (RHR)
Containment Spray
[[Page 14740]]
System.'' The argument for staying in Mode 3 instead of going to Mode 4
to repair the RHR containment spray system (one or both trains) is also
supported by defense-in-depth considerations. Section 6.2 makes a
comparison between the Mode 3 and the Mode 4 end state, with respect to
the means available to perform critical functions (i.e., functions
contributing to the defense-in-depth philosophy) whose success is
needed to prevent core damage and containment failure and mitigate
radiation releases. The risk and defense-in-depth arguments, used
according to the ``integrated decision-making'' process of Regulatory
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe
as Mode 4 (if not safer) for repairing an inoperable RHR containment
spray system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.23 TRS 4.5.2.7 and LCO 3.6.1.8, Penetration Valve Leakage
Control System (PVLCS) (BWR/6 only).
The PVLCS supplements the isolation function of primary containment
isolation valves (PCIVs) in process lines that also penetrate the
secondary containment. These penetrations are sealed by air from the
PVLCS to prevent fission products leaking past the isolation valves and
bypassing the secondary containment after a design basis loss-of-
coolant accident (LOCA).
[Note:
Plant Applicability, BWR/6]
LCO: Two PVLCS subsystems shall be operable.
Condition Requiring Entry into End State: If one PVLCS subsystem is
inoperable, it must be restored to operable status within 30 days
(Required Action A.1). If two PVLCS subsystems are inoperable, one of
the PVLCS subsystems must be restored to operable status within seven
days (Required Action B.1). If the PVLCS subsystem cannot be restored
to operable status within the allotted time, the plant must be placed
in Mode 3 within 12 hours (Required Action C.1) and in Mode 4 within 36
hours (Required Action C.2).
Assessment: The BWROG topical report has determined that this
system is not significant in BWR PRAs. The unavailability of one or
both PVLCS subsystems has no impact on CDF or LERF, irrespective of the
mode of operation at the time of the accident. Furthermore, the
challenge frequency of the PVLCS system (i.e., the frequency with which
the system is expected to be challenged to prevent fission products
leaking past the isolation valves and bypassing the secondary
containment) is less than 1.0E-6/yr. Consequently, the conditional
probability that this system will be challenged during the repair time
interval while the plant is at either the current or the proposed end
state (i.e., Mode 4 or Mode 3, respectively) is less than 1.0E-8. This
probability is considerably smaller than probabilities considered
``negligible'' in Regulatory Guide 1.177 for much higher consequence
risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.2.7 and LCO 3.6.1.8, ``Penetration Valve Leakage
Control System (PVLCS).'' The argument for staying in Mode 3 instead of
going to Mode 4 to repair the PVLCS system (one or both trains) is also
supported by defense-in-depth considerations. Section 6.2 makes a
comparison between the Mode 3 and the Mode 4 end state, with respect to
the means available to perform critical functions (i.e., functions
contributing to the defense-in-depth philosophy) whose success is
needed to prevent core damage and containment failure and mitigate
radiation releases. The risk and defense-in-depth arguments, used
according to the ``integrated decision-making'' process of Regulatory
Guides 1.174 and 1.177, support the conclusion that Mode 3 is as safe
as Mode 4 (if not safer) for repairing an inoperable PVLCS system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.24 TRS 4.5.1.10, TRS 4.5.2.9 and LCO 3.6.2.3, Residual Heat
Removal (RHR) Suppression Pool Cooling.
Some means must be provided to remove heat from the suppression
pool so that the temperature inside the primary containment remains
within design limits. This function is provided by two redundant RHR
suppression pool cooling subsystems.
[Note:
Plant Applicability, BWR 4/6]
LCO: Two RHR suppression pool cooling subsystems shall be operable.
Condition Requiring Entry into End State: If one RHR suppression
pool cooling subsystem is inoperable (Condition A), it must be restored
to operable status within seven days (Required Action A.1). If the RHR
suppression pool spray subsystem cannot be restored to operable status
within the allotted time (Condition B), the plant must be placed in
Mode 3 within 12 hours (Required Action B.1), and in Mode 4 within 36
hours (Required Action B.2).
Modification for End State Required Actions: Delete Required Action
B.2, and retain Condition B and Required Action B.1 for one RHR
suppression pool spray subsystem inoperable. Add Condition C, with
Required Actions C.1 and C.2, identical to existing Condition B, with
Required Actions B.1 and B.2, to maintain existing requirements
unchanged for two RHR suppression pool subsystems inoperable.
Assessment: The BWROG topical report has completed a comparative
PRA evaluation of the core damage risks of operation in the current end
state versus operation in the Mode 3 end state. The results indicated
that the core damage risks while operating in Mode 3 (assuming the
individual failure conditions) are lower or comparable to the current
end state. One loop of the RHR suppression pool cooling system is
sufficient to accomplish the required safety function. By remaining in
Mode 3, HPCS, RCIC, and the power conversion system (condensate/
feedwater) remain available for water makeup and decay heat removal.
Additionally, the EOPs direct the operators to take control of the
depressurization function if low pressure injection/spray are needed
for RCS makeup and cooling. Therefore, defense-in-depth is improved
with respect to water makeup and decay heat removal by remaining in
Mode 3.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.25 TRS 4.5.2.12 and LCO 3.6.5.6, Drywell Vacuum Relief System
(BWR/6 only).
The Mark III pressure suppression containment is designed to
condense, in the suppression pool, the steam released into the drywell
in the event of a loss-of-coolant accident (LOCA). The steam
discharging to the pool carries the non-condensibles from the drywell.
Therefore, the drywell atmosphere changes from low humidity air to
nearly 100% steam (no air) as the event progresses. When the drywell
subsequently cools and depressurizes, non-condensibles in the drywell
must be replaced to avoid excessive weir wall overflow into the
drywell. Rapid weir wall overflow must be controlled in a large break
LOCA, so that essential
[[Page 14741]]
equipment and systems located above the weir wall in the drywell are
not subjected to excessive drag and impact loads. The drywell post-LOCA
and the drywell purge vacuum relief subsystems are the means by which
non-condensibles are transferred from the primary containment back to
the drywell.
[Note:
Plant Applicability, BWR/6]
LCO: Two drywell post-LOCA and two drywell purge vacuum relief
subsystems shall be operable.
Condition Requiring Entry into End State: If one or two drywell
post-LOCA vacuum relief subsystems are inoperable (Condition A), or if
one drywell purge vacuum relief subsystem is inoperable (Condition B),
for reasons other than being not closed, the subsystem(s) must be
restored to operable status within 30 days (Required Actions B.1 and
C.1, respectively). If the required actions cannot be completed within
the allotted time, the plant must be placed in Mode 3 within 12 hours
and in Mode 4 within 36 hours.
Modification for End State Required Actions: Renumber Conditions D,
E, F and G, to Conditions E, F, G, and H respectively, and renumber
associated Required Actions accordingly. Add a new Condition D for when
Required Action and associated Completion Time of Condition B or C not
met, with Required Action D.1 to be in Mode 3 in a Completion Time of
12 hours. Change new Condition G to read, ``Required Action and
associated Completion Time of Condition A, E or F not met.''
Assessment: The BWROG topical report has determined that the
specific failure conditions of interest are not risk significant in BWR
PRAs. With one or two drywell post-LOCA vacuum relief subsystems
inoperable or one drywell purge vacuum relief subsystem inoperable, for
reasons other than not being closed, the remaining operable vacuum
relief subsystems are adequate to perform the depressurization
mitigation function. By remaining in Mode 3, HPCS, RCIC, and the power
conversion system (condensate/feedwater) remain available for water
makeup and decay heat removal. Additionally, the EOPs direct the
operators to take control of the depressurization function if low
pressure injection/spray are needed for RCS makeup and cooling.
Therefore, defense-in-depth is improved with respect to water makeup
and decay heat removal by remaining in Mode 3.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.26 TRS 4.5.2.13 and LCO 3.7.1, Standby Service Water (SSW)
System and Ultimate Heat Sink (UHS) (BWR/6 only).
The SSW system (in conjunction with the UHS) is designed to provide
cooling water for the removal of heat from certain safe shutdown-
related equipment heat exchangers following a DBA or transient.
[Note:
Plant Applicability, BWR/6]
LCO: Division 1 and 2 SSW subsystems and UHS shall be operable.
Condition Requiring Entry into End State: If one or more cooling
towers with one cooling tower fan is inoperable (Condition A), the
cooling tower fan(s) must be restored to operable status within seven
days (Required Action A.1). If one SSW subsystem is inoperable for
reasons other than Condition A (Condition C), the SSW subsystem must be
restored to operable status within 72 hours (Required Action C.1). If
the required action(s) and associated completion time(s) (of Conditions
A or C) cannot be met (Condition D), the plant must be placed in Mode 3
within 12 hours (Required Action D.1) and in Mode 4 within 36 hours
(Required Action D.2).
Modification: The existing second and third conditions of existing
Condition D have been transferred to a new Condition E in an unchanged
form (with Required Actions E.1 and E.2 identical to existing Required
Actions D.1 and D.2). Existing Condition B with its associated Required
Actions and Associated Completion Times, has been transferred to a new
Condition D in an unchanged form. Existing Condition C, with its
associated Required Action and Associated Completion Time, has been
moved to a new Condition B in unchanged form. A new Condition C has
been created. If the Required Actions and Associated Completion Times
for new Condition A or B are not met (new Condition C), then the plant
must be placed in Mode 3 in 12 hours (new Required Action C.1).
Assessment: The BWROG topical report determined that the specific
failure condition of interest is not risk significant in BWR PRAs. With
the specified inoperable components/subsystems, a sufficient number of
operable components/subsystems are still available to perform the heat
removal function. By remaining in Mode 3, HPCS, RCIC, and the power
conversion system (condensate/feedwater) remain available for water
makeup and decay heat removal. Additionally, the EOPs direct the
operators to take control of the depressurization function if low
pressure injection/spray are needed for RCS makeup and cooling.
Therefore, defense-in-depth is improved with respect to water makeup
and decay heat removal by remaining in Mode 3.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.27 TRS 4.5.2.14 and LCO 3.7.3, Control Room Fresh Air (CRFA)
System (BWR/6 only).
The CRFA system provides a radiologically controlled environment
from which the unit can be safely operated following a DBA. The CRFA
system consists of two independent and redundant high efficiency air
filtration subsystems for treatment of recirculated air or outside
supply air. Each subsystem consists of a demister, an electric heater,
a prefilter, a high efficiency particulate air (HEPA) filter, an
activated charcoal adsorber section, a second HEPA filter, a fan, and
the associated ductwork and dampers. Demisters remove water droplets
from the airstream. Prefilters and HEPA filters remove particulate
matter that may be radioactive. The charcoal adsorbers provide a holdup
period for gaseous iodine, allowing time for decay.
[Note:
Plant Applicability, BWR/6]
LCO: Two CRFA subsystems shall be operable.
Condition Requiring Entry into End State: If one CRFA subsystem is
inoperable (Condition A), it must be restored to operable status within
seven days (Required Action A.1). If two CRFA subsystems are inoperable
(Condition B for control room boundary and Condition E for reasons for
inoperability), one CRFA subsystem must be restored to operable status
in 24 hours (Required Action B.1) or enter LCO 3.0.3 (Required Action
E.1). If Conditions A or B, and associated Required Actions A.1 and
B.1) cannot be met in the required Completion Time (Condition C), the
plant must be placed in Mode 3 within 12 hours (Required Action C.1)
and in Mode 4 within 36 hours (Required Action C.2).
Modification for End State Required Actions: Delete Required Action
C.2, and change Required Action E.1 to ``Be in Mode 3'' within a
Completion Time of ``12 hours.''
Assessment: The unavailability of one or both CRFA subsystems has
no significant impact on CDF or LERF,
[[Page 14742]]
irrespective of the mode of operation at the time of the accident.
Furthermore, the challenge frequency of the CRFA system (i.e., the
frequency with which the system is expected to be challenged to provide
a radiologically controlled environment in the main control room
following a DBA which leads to core damage and leaks of radiation from
the containment that can reach the control room) is less than 1.0E-6/
yr. Consequently, the conditional probability that this system will be
challenged during the repair time interval while the plant is at either
the current or the proposed end state (i.e., Mode 4 or Mode 3,
respectively) is less than 1.0E-8. This probability is considerably
smaller than probabilities considered ``negligible'' in Regulatory
Guide 1.177 for much higher consequence risks, such as large early
release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.2.14 and LCO 3.7.3, ``Control Room Fresh Air (CRFA)
System.'' The argument for staying in Mode 3 instead of going to Mode 4
to repair the CRFA system (one or both trains) is also supported by
defense-in-depth considerations. Section 6.2 makes a comparison between
the Mode 3 and the Mode 4 end state, with respect to the means
available to perform critical functions (i.e., functions contributing
to the defense-in-depth philosophy) whose success is needed to prevent
core damage and containment failure and mitigate radiation releases.
The risk and defense-in-depth arguments, used according to the
``integrated decision-making'' process of Regulatory Guides 1.174 and
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not
safer) for repairing an inoperable CRFA system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.28 TRS 4.5.2.15 and LCO 3.7.4, Control Room Air Conditioning
(CRAC) System (BWR/6 only).
The control room AC system provides temperature control for the
control room following control room isolation. The control room AC
system consists of two independent, redundant subsystems that provide
cooling and heating of recirculated control room air. Each subsystem
consists of heating coils, cooling coils, fans, chillers, compressors,
ductwork, dampers, and instrumentation and controls to provide for
control room temperature control. The control room AC system is
designed to provide a controlled environment under both normal and
accident conditions. A single subsystem provides the required
temperature control to maintain a suitable control room environment for
a sustained occupancy of 12 persons.
[Note:
Plant Applicability, BWR/6]
LCO: Two control room AC subsystems shall be operable.
Condition Requiring Entry into End State: If one control room AC
subsystem is inoperable, it must be restored to operable status within
30 days (Required Action A.1). If the required actions and associated
completion times cannot be met, the plant must be placed in Mode 3
within 12 hours (Required Action B.1) and in Mode 4 within 36 hours
(Required Action B.2). If two control room AC subsystems are
inoperable, LCO 3.0.3 must be entered immediately (Condition D).
Modification for End State Required Actions: Delete Required Action
B.2, and change Required Action D.1 to ``Be in Mode 3'' with a
Completion Time of ``12 hours.''
Assessment: The unavailability of one or both AC subsystems has no
significant impact on CDF or LERF, irrespective of the mode of
operation at the time of the accident. Furthermore, the challenge
frequency of the AC system (i.e., the frequency with which the system
is expected to be challenged to provide temperature control for the
control room following control room isolation following a DBA which
leads to core damage) is less than 1.0E-6/yr. Consequently, the
conditional probability that this system will be challenged during the
repair time interval while the plant is at either the current or the
proposed end state (i.e., Mode 4 or Mode 3, respectively) is less than
1.0E-8. This probability is considerably smaller than probabilities
considered ``negligible'' in Regulatory Guide 1.177 for much higher
consequence risks, such as large early release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.2.15 and LCO 3.7.4, ``Control Room Air Conditioning
(AC) System.'' The argument for staying in Mode 3 instead of going to
Mode 4 to repair the CRAC system (one or both trains) is also supported
by defense-in-depth considerations. Section 6.2 makes a comparison
between the Mode 3 and the Mode 4 end state, with respect to the means
available to perform critical functions (i.e., functions contributing
to the defense-in-depth philosophy) whose success is needed to prevent
core damage and containment failure and mitigate radiation releases.
The risk and defense-in-depth arguments, used according to the
``integrated decision-making'' process of Regulatory Guides 1.174 and
1.177, support the conclusion that Mode 3 is as safe as Mode 4 (if not
safer) for repairing an inoperable CRAC system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
3.2.29 TRS 4.5.2.16 and LCO 3.7.5, Main Condenser Off gas (BWR/6
only).
The Off gas from the main condenser normally includes radioactive
gases. The gross gamma activity rate is controlled to ensure that
accident analysis assumptions are satisfied and that offsite dose
limits will not be exceeded during postulated accidents.
[Note:
Plant Applicability, BWR/6]
LCO: The gross gamma activity rate of the noble gases measured at
the Off gas recombiner effluent shall be <=380 mCi/second after decay
of 30 minutes.
Condition Requiring Entry into End State: If the gross gamma
activity rate of the noble gases in the main condenser Off gas is not
within limits (Condition A), the gross gamma activity rate of the noble
gases in the main condenser Off gas must be restored to within limits
within 72 hours (Required Action A.1). If the required action and
associated completion time cannot be met, one of the following must
occur:
a. All steam lines must be isolated within 12 hours (Required
Action B.1).
b. The steam jet air ejector (SJAE) must be isolated within 12
hours (Required Action B.2).
c. The plant must be placed in Mode 3 within 12 hours (Required
Action B.3.1) and in Mode 4 within 36 hours (Required Action B.3.2).
Modification for End State Required Actions: Delete Required Action
B.3.2.
Assessment: The failure to maintain the gross gamma activity rate
of the noble gases in the main condenser Off gas (MCOG) within limits
has no significant impact on CDF or LERF, irrespective of the mode of
operation at the time of the accident. Furthermore, the challenge
frequency of the MCOG system (i.e., the frequency with which the system
is expected to be challenged to mitigate offsite radiation releases
following a DBA) is less than 1.0E-6/yr. Consequently, the conditional
probability that this system will be challenged during the repair time
interval while the plant is at either the
[[Page 14743]]
current or the proposed end state (i.e., Mode 4 or Mode 3,
respectively) is less than 1.0E-8. This probability is considerably
smaller than probabilities considered ``negligible'' in Regulatory
Guide 1.177 for much higher consequence risks, such as large early
release.
Section 6 of reference 6 summarizes the staff's risk argument for
approval of TRS 4.5.2.16 and LCO 3.7.5, ``Main Condenser Off gas.'' The
argument for staying in Mode 3 instead of going to Mode 4 to repair the
MCOG system (one or both trains) is also supported by defense-in-depth
considerations. Section 6.2 makes a comparison between the Mode 3 and
the Mode 4 end state, with respect to the means available to perform
critical functions (i.e., functions contributing to the defense-in-
depth philosophy) whose success is needed to prevent core damage and
containment failure and mitigate radiation releases. The risk and
defense-in-depth arguments, used according to the ``integrated
decision-making'' process of Regulatory Guides 1.174 and 1.177, support
the conclusion that Mode 3 is as safe as Mode 4 (if not safer) for
repairing an inoperable MCOG system.
Finding: Based upon the above assessment, and because the time
spent in Mode 3 to perform the repair is infrequent and limited, and in
light of defense-in-depth considerations (discussed in Reference 1),
the change is acceptable.
4.0 State Consultation
In accordance with the Commission's regulations, the [--------]
State official was notified of the proposed issuance of the amendment.
The State official had [(1) no comments or (2) the following comments--
with subsequent disposition by the staff].
5.0 Environmental Consideration
The amendment changes requirements with respect to the installation
or use of a facility component located within the restricted area as
defined in 10 CFR Part 20. The NRC staff has determined that the
amendment involves no significant increase in the amounts and no
significant change in the types of any effluents that may be released
offsite, and that there is no significant increase in individual or
cumulative occupational radiation exposure. The Commission has
previously issued a proposed finding that adopting TSTF-423, Rev 0,
involves no significant hazards considerations, and there has been no
public comment on the finding in Federal Register Notice 70 FR 74037,
December 14, 2005. Accordingly, the amendments meet the eligibility
criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Pursuant to 10 CFR 51.22(b), no environmental impact statement or
environmental assessment need be prepared in connection with the
issuance of the amendment.
6.0 Conclusion
The Commission has concluded, on the basis of the considerations
discussed above, that (1) there is reasonable assurance that the health
and safety of the public will not be endangered by operation in the
proposed manner, (2) such activities will be conducted in compliance
with the Commission's regulations, and (3) the issuance of the
amendments will not be inimical to the common defense and security or
to the health and safety of the public.
7.0 References
1. NEDC-32988-A, Revision 2, ``Technical Justification to Support
Risk-Informed Modification to Selected Required Action End States for
BWR Plants,'' December 2002.
2. Federal Register, Vol. 58, No. 139, p. 39136, ``Final Policy
Statement on Technical Specifications Improvements for Nuclear Power
Plants,'' July 22, 1993.
3. 10 CFR 50.65, Requirements for Monitoring the Effectiveness of
Maintenance at Nuclear Power Plants.''
4. Regulatory Guide 1.182, ``Assessing and Managing Risk Before
Maintenance Activities at Nuclear Power Plants,'' May 2000.
(ML003699426)
5. NUMARC 93-01, ``Industry Guideline for Monitoring the
Effectiveness of Maintenance at Nuclear Power Plants,'' Nuclear
Management and Resource Council, Revision 3, July 2000.
6. NRC Safety Evaluation for Topical Report NEDC-32988, Revision 2,
September 27, 2002. (ML022700603)
7. TSTF-423, Revision 0, ``Technical Specifications End States,
NEDC-32988-A.''
8. TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 0,
``Technical Specifications End States, NEDC-32988-A,'' September 2005.
9. Regulatory Guide 1.174, ``An Approach for Using Probabilistic
Risk Assessment in Risk-Informed Decision Making on Plant Specific
Changes to the Licensing Basis,'' USNRC, August 1998. (ML003740133)
10. Regulatory Guide 1.177, ``An Approach for Pant Specific Risk-
Informed Decision Making: Technical Specifications,'' USNRC, August
1998. (ML003740176)
Proposed No Significant Hazards Consideration Determination
Description of Amendment Request: A change is proposed to the
technical specifications (TS) of [plant name], consistent with
Technical Specifications Task Force (TSTF) change TSTF-423 to the
standard technical specifications (STS) for BWR Plants (NUREG 1433 and
NUREG 1434) to allow, for some systems, entry into hot shutdown rather
than cold shutdown to repair equipment, if risk is assessed and managed
consistent with the program in place for complying with the
requirements of 10 CFR 50.65(a)(4). Changes proposed in will be made to
the [plant name] TS for selected Required Action end states providing
this allowance.
Basis for proposed no-significant-hazards-consideration
determination: As required by 10 CFR 50.91(a), an analysis of the issue
of no-significant-hazards-consideration is presented below:
Criterion 1--The Proposed Change Does Not Involve a Significant
Increase in the Probability or Consequences of an Accident Previously
Evaluated
The proposed change allows a change to certain required end states
when the TS Completion Times for remaining in power operation will be
exceeded. Most of the requested technical specification (TS) changes
are to permit an end state of hot shutdown (Mode 3) rather than an end
state of cold shutdown (Mode 4) contained in the current TS. The
request was limited to: (1) Those end states where entry into the
shutdown mode is for a short interval, (2) entry is initiated by
inoperability of a single train of equipment or a restriction on a
plant operational parameter, unless otherwise stated in the applicable
technical specification, and (3) the primary purpose is to correct the
initiating condition and return to power operation as soon as is
practical. Risk insights from both the qualitative and quantitative
risk assessments were used in specific TS assessments. Such assessments
are documented in Section 6 of GE NEDC-32988, Revision 2, ``Technical
Justification to Support Risk Informed Modification to Selected
Required Action End States for BWR Plants.'' They provide an integrated
discussion of deterministic and probabilistic issues, focusing on
specific technical specifications, which are used to support the
proposed TS end state and associated restrictions. The staff finds that
the risk insights support the conclusions of the specific TS
assessments. Therefore, the probability
[[Page 14744]]
of an accident previously evaluated is not significantly increased, if
at all. The consequences of an accident after adopting proposed TSTF-
423, are no different than the consequences of an accident prior to
adopting TSTF-423. Therefore, the consequences of an accident
previously evaluated are not significantly affected by this change. The
addition of a requirement to assess and manage the risk introduced by
this change will further minimize possible concerns. Therefore, this
change does not involve a significant increase in the probability or
consequences of an accident previously evaluated.
Criterion 2--The Proposed Change Does Not Create the Possibility of a
New or Different Kind of Accident From Any Previously Evaluated
The proposed change does not involve a physical alteration of the
plant (no new or different type of equipment will be installed). If
risk is assessed and managed, allowing a change to certain required end
states when the TS Completion Times for remaining in power operation
are exceeded, i.e., entry into hot shutdown rather than cold shutdown
to repair equipment, will not introduce new failure modes or effects
and will not, in the absence of other unrelated failures, lead to an
accident whose consequences exceed the consequences of accidents
previously evaluated. The addition of a requirement to assess and
manage the risk introduced by this change and the commitment by the
licensee to adhere to the guidance in TSTF-IG-05-02, Implementation
Guidance for TSTF-423, Revision 0, ``Technical Specifications End
States, NEDC-32988-A,'' will further minimize possible concerns. Thus,
this change does not create the possibility of a new or different kind
of accident from an accident previously evaluated.
Criterion 3--The Proposed Change Does Not Involve a Significant
Reduction in the Margin of Safety
The proposed change allows, for some systems, entry into hot
shutdown rather than cold shutdown to repair equipment, if risk is
assessed and managed. The BWROG's risk assessment approach is
comprehensive and follows staff guidance as documented in RGs 1.174 and
1.177. In addition, the analyses show that the criteria of the three-
tiered approach for allowing TS changes are met. The risk impact of the
proposed TS changes was assessed following the three-tiered approach
recommended in RG 1.177. A risk assessment was performed to justify the
proposed TS changes. The net change to the margin of safety is
insignificant. Therefore, this change does not involve a significant
reduction in a margin of safety.
The Following Example of an Application Was Prepared by the NRC
Staff To Facilitate Use of the Consolidated Line Item Improvement
Process (CLIIP). The Model Provides the Expected Level of Detail and
Content for an Application To Adopt TSTF-423, Revisions 0, ``Risk-
Informed Modifications to Selected Required Action End States,'' for
BWR Plants (and Adoption of a Technical Specification Bases Control
Program)* Using CLIIP. Licensees Remain Responsible for Ensuring That
Their Actual Application Fulfills Their Administrative Requirements as
Well as Nuclear Regulatory Commission Regulations.
U.S. Nuclear Regular Commission,
Document Control Desk,
Washington, DC 20555.
Subject: Plant Name, Docket No. 50--Application for Technical
Specification Change TSTF-423, Risk Informed Modification To
Selected Required Action End States for BWR Plants, (and Adoption of
a Technical Specifications Bases Control Program)* Using the
Consolidated Line Item Improvement Process
Gentleman: In accordance with the provisions of 10 CFR 50.90
[Licensee] is submitting a request for an amendment to the technical
specifications (TS) for [Plant Name, Unit Nos.].
The proposed amendment would modify TS to risk-inform
requirements regarding selected Required Action End States, (and, in
conjunction with the proposed change, TS requirements for a Bases
control program consistent with TS Bases Control Program described
in Section 5.5 of the BWR Standard Technical Specifications.)*
Enclosure 1 provides a description of the proposed change, the
requested confirmation of applicability, and plant-specific
verifications. Enclosure 2 provides the existing TS pages marked up
to show the proposed change. Enclosure 3 provides revised (clean) TS
pages. Enclosure 4 provides a summary of the regulatory commitments
made in this submittal. Enclosure 5 provides the existing TS Bases
pages marked up to show the proposed change (for information only).)
[Licensee] requests approval of the proposed license amendment
by [Date], with the amendment being implemented [by Date or Within X
Days].
In accordance with 10 CFR 50.91, a copy of this application,
with enclosures, is being provided to the designated [State]
Official.
* If not already in the facility Technical Specifications.
I declare under penalty of perjury under the laws of the United
States of America that I am authorized by [Licensee] to make this
request and that the foregoing is true and correct. (Note that
request may be notarized in lieu of using this oath or affirmation
statement).
If you should have any questions regarding this submittal,
please contact [Name, Telephone Number]
Sincerely,
[Name, Title]
Enclosures:
1. Description and Assessment
2. Proposed Technical Specification Changes
3. Revised Technical Specification Pages
4. Regulatory Commitments
5. Proposed Technical Specification Bases Changes
cc: NRC Project Manager
NRC Regional Office
NRC Resident Inspector
State Contact
ENCLOSURE 1
Description and Assessment
1.0 Description
The proposed amendment would modify technical specifications to
risk-inform requirements regarding selected Required Action End
States.\1\
---------------------------------------------------------------------------
\1\ [In conjunction with the proposed change, technical
specifications (TS) requirements for a Bases Control Program,
consistent with the TS Bases Control Program described in Section
5.5 of the applicable vendor's standard TS (STS), shall be
incorporated into the licensee's TS, if not already in the TS.]
---------------------------------------------------------------------------
The changes are consistent with Nuclear Regulatory Commission
(NRC) approved Industry/Technical Specification Task Force (TSTF)
TSTF-423 Revision 0. The availability of this TS improvement was
published in the Federal Register on [Date] as part of the
consolidated line item improvement process (CLIIP).
2.0 Assessment
2.1 Applicability of Topical Report, TSTF-423, and Published Safety
Evaluation
[Licensee] has reviewed GE topical report (Reference 1), TSTF-
423 (Reference 2), and the NRC model safety evaluation (Reference 3)
as part of the CLIIP. [Licensee] has concluded that the information
in the GE topical report and TSTF-423, as well as the safety
evaluation prepared by the NRC staff are applicable to [Plant, Unit
Nos.] and justify this amendment for the incorporation of the
changes to the [Plant] TS. [Note: Only those changes proposed in
TSTF-423 are addressed in the model SE. The model SE and associated
topical report address the entire fleet of BWR plants, and the
plants adopting TSTF-423 must confirm the applicability of the
changes to their plant.]
2.2 Optional Changes and Variations
[Licensee] is not proposing any variations or deviations from
the GE topical report and the TS changes described in the TSTF-423
Revision 0 or the NRC staff's model safety evaluation dated [Date].
[Note: The CLIIP does not prevent licensees from requesting an
alternate approach or proposing changes without the requested Bases
or Bases control program. However, deviations from the approach
recommended in this notice may require additional review by the NRC
staff and may increase the time and resources needed for the review.
Significant variations
[[Page 14745]]
from the approach, or inclusion of additional changes to the
license, will result in staff rejection of the submittal. Instead,
licensees desiring significant variations and/or additional changes
should submit a LAR that does not claim to adopt TSTF-423.]
3.0 Regulatory Analysis
3.1 No Significant Hazards Consideration Determination
[Licensee] has reviewed the proposed no significant hazards
consideration determination (NSHCD) published in the Federal
Register as part of the CLIIP. [Licensee] has concluded that the
proposed NSHCD presented in the Federal Register notice is
applicable to [Plant] and is hereby incorporated by reference to
satisfy the requirements of 10 CFR 50.91(a).
3.2 Verification and Commitments
As discussed in the notice of availability published in the
Federal Register on [Date] for this TS improvement, plant-specific
verifications were performed as follows:
[Licensee] commits to the regulatory commitments in Enclosure 4.
In addition, [Licensee] has proposed TS Bases consistent with the GE
topical report and TSTF-423, which provide guidance and details on
how to implement the new requirements. Implementation of TSTF-423
requires that risk be managed and assessed, and the licensee's
configuration risk management program is adequate to satisfy this
requirement. The risk assessment need not be quantified, but may be
a qualitative assessment of the vulnerability of systems and
components when one or more systems are not able to perform their
associated function. Finally, [Licensee] has a Bases Control Program
consistent with Section 5.5 of the Standard Technical Specifications
(STS).
4.0 Environmental Evaluation
The amendment changes requirements with respect to the
installation or use of a facility component located within the
restricted area as defined in 10 CFR Part 20. The NRC staff has
determined that the amendment adopting TSTF-423, Rev 0, involves no
significant increase in the amounts and no significant change in the
types of any effluents that may be released offsite, and that there
is no significant increase in individual or cumulative occupational
radiation exposure. The Commission has previously issued a proposed
finding that TSTF-423, Rev 0, involves no significant hazards
considerations, and there has been no public comment on the finding
in Federal Register Notice 70 FR 74037, December 14, 2005.
Accordingly, the amendment meets the eligibility criteria for
categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to
10 CFR 51.22(b), no environmental impact statement or environmental
assessment need be prepared in connection with the issuance of the
amendment.
5.0 References
1. NEDC-32988-A, Revision 2, ``Technical Justification to
Support Risk-Informed Modification to Selected Required Action End
States for BWR Plants,'' December 2002.
2. TSTF-423, Revision 0, ``Technical Specifications End States,
NEDC-32988-A.''
3. Federal Register, Vol. XX, No. XX, p. XXXXX, ``Notice of
Availability of Model Application Concerning Technical
Specifications for Boiling Water Reactor Plants to Risk-Inform
Requirements Regarding Selected Required Action End States Using the
Consolidated Line Item Improvement Process, and NRC Model Safety
Evaluation,'' [Date].
Enclosure 2
Proposed Technical Specification Changes (Mark-up)
Enclosure 3
Proposed Technical Specification Pages
[Clean copies of Licensee specific Technical Specification (TS)
pages, corresponding to the TS pages changed by TSTF-423, Rev 0, are
to be included in Enclosure 3]
Enclosure 4
List of Regulatory Commitments
The following table identifies those actions committed to by
[Licensee] in this document. Any other statements in this submittal
are provided for information purposes and are not considered to be
regulatory commitments. Please direct questions regarding these
commitments to [Contact Name].
------------------------------------------------------------------------
Regulatory committments Due date/event
------------------------------------------------------------------------
[Licensee] will follow the guidance [Ongoing, or implement
established in Section 11 of NUMARC 93-01, with amendment].
``Industry Guidance for Monitoring the
Effectiveness of Maintenance at Nuclear
Power Plants,'' Nuclear Management and
Resource Council, Revision 3, July 2000.
[Licensee] will follow the guidance [Implement with
established in TSTF-IG-05-02, Implementation amendment, when TS
Guidance for TSTF-423, Revision 0, Required Action End
``Technical Specifications End States, NEDC- State remains within the
32988-A,'' September 2005. Applicability of TS].
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Enclsoure 5
Proposed Changes to Technical Specification Bases Pages
[FR Doc. 06-2803 Filed 3-22-06; 8:45 am]
BILLING CODE 7590-01-P