[Federal Register Volume 70, Number 214 (Monday, November 7, 2005)]
[Proposed Rules]
[Pages 67598-67630]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E5-6090]
[[Page 67597]]
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Part IV
Nuclear Regulatory Commission
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10 CFR Part 50
Risk-Informed Changes to Loss-of-Coolant Accident Technical
Requirements; Proposed Rule
Federal Register / Vol. 70, No. 214 / Monday, November 7, 2005 /
Proposed Rules
[[Page 67598]]
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NUCLEAR REGULATORY COMMISSION
10 CFR Part 50
RIN 3150-AH29
Risk-Informed Changes to Loss-of-Coolant Accident Technical
Requirements
AGENCY: Nuclear Regulatory Commission.
ACTION: Proposed rule.
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SUMMARY: The Nuclear Regulatory Commission (NRC) proposes to amend its
regulations to permit current power reactor licensees to implement a
voluntary, risk-informed alternative to the current requirements for
analyzing the performance of emergency core cooling systems (ECCS)
during loss-of-coolant accidents (LOCAs). In addition, the proposed
rule would establish procedures and criteria for requesting changes in
plant design and procedures based upon the results of the new analyses
of ECCS performance during LOCAs.
DATES: Submit comments by February 6, 2006. Submit comments specific to
the information collections aspects of this proposed rule by December
7, 2005. Comments received after the above dates will be considered if
it is practical to do so, but assurance of consideration cannot be
given to comments received after these dates.
ADDRESSES: You may submit comments on the proposed rule by any one of
the following methods. Please include the following number, RIN 3150-
AH29, in the subject line of your comments. Comments on rulemakings
submitted in writing or in electronic form will be made available for
public inspection. Because your comments will not be edited to remove
any identifying or contact information, the NRC cautions you against
including any information in your submission that you do not want to be
publicly disclosed.
Mail comments to: Secretary, U.S. Nuclear Regulatory Commission,
Washington, DC 20555-0001, ATTN: Rulemakings and Adjudications Staff.
E-mail comments to: [email protected]. If you do not receive a reply e-
mail confirming that we have received your comments, contact us
directly at (301) 415-1966. You may also submit comments via the NRC's
rulemaking Web site at http://ruleforum.llnl.gov. Address questions
about our rulemaking Web site to Carol Gallagher (301) 415-5905; e-mail
[email protected]. Comments can also be submitted via the Federal eRulemaking
Portal http://www.regulations.gov.
Hand deliver comments to: 11555 Rockville Pike, Rockville, Maryland
20852, between 7:30 a.m. and 4:15 p.m. Federal workdays. (Telephone
(301) 415-1966).
Fax comments to: Secretary, U.S. Nuclear Regulatory Commission at
(301) 415-1101.
You may submit comments on the information collections by the
methods indicated in the Paperwork Reduction Act Statement.
Publicly available documents related to this rulemaking may be
viewed electronically on the public computers located at the NRC's
Public Document Room (PDR), O1 F21, One White Flint North, 11555
Rockville Pike, Rockville, Maryland. The PDR reproduction contractor
will copy documents for a fee. Selected documents, including comments,
may be viewed and downloaded electronically via the NRC rulemaking Web
site at http://ruleforum.llnl.gov.
Publicly available documents created or received at the NRC after
November 1, 1999, are available electronically at the NRC's Electronic
Reading Room at http://www.nrc.gov/reading-rm/adams.html. From this
site, the public can gain entry into the NRC's Agencywide Document
Access and Management System (ADAMS), which provides text and image
files of NRC's public documents. If you do not have access to ADAMS or
if there are problems in accessing the documents located in ADAMS,
contact the NRC Public Document Room (PDR) Reference staff at 1-800-
397-4209, (301) 415-4737 or by e-mail to [email protected].
FOR FURTHER INFORMATION CONTACT: Richard Dudley, Office of Nuclear
Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington DC
20555-0001; telephone (301) 415-1116; e-mail: [email protected],
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Background
A. Deterministic Approach
B. History of Requirements and Design for LOCAs
C. Probabilistic Approach
D. Commission Policy on Risk-Informed Regulation
II. Rulemaking Initiation
III. Proposed Action
A. Overview of Rule Framework
B. Determination of the Transition Break Size (TBS)
1. Historical Estimates of LOCA Frequencies
2. Expert Opinion Elicitation Process
3. Adjustments To Address Failure Mechanisms Not Considered by
the Expert Elicitation
a. LOCAs caused by failure of active components, such as stuck-
open valves and blown out seals or gaskets.
b. Seismically-induced LOCAs, both with and without material
degradation.
c. LOCAs caused by dropped heavy loads.
4. Consideration of Connected Auxiliary Piping
5. Considerations of Break Location and Flow Characteristic
6. Effects of Future Plant Modifications on TBS
7. Future Adjustments to TBS
C. Alternative ECCS Analysis Requirements and Acceptance
Criteria
1. Acceptable Methodologies and Analysis Assumptions
2. Acceptance Criteria
3. Plant Operational Requirements Related to ECCS Analyses
4. Restrictions on Reactor Operation
D. Risk-Informed Changes to the Facility, Technical
Specifications, or Procedures
1. Requirements for the Risk-Informed Integrated Safety
Performance (RISP) Assessment Process
a. Risk acceptance criteria for plant changes under 10 CFR 50.90
b. Risk acceptance criteria for plant changes under 10 CFR 50.59
c. Cumulative risk acceptance criteria
d. Defense-in-depth
e. Safety margins
f. Performance measuring programs
2. Requirements for risk assessments
a. Probabilistic Risk Assessment (PRA) requirements
b. Requirements for risk assessments other than PRA
3. Operational Requirements
a. Maintain ECCS model(s) and/or analysis method(s)
b. Do not place the plant in unanalyzed at-power operating
configurations
c. Evaluate all facility changes using the RISP assessment
process
d. Implement adequate performance-measurement programs
e. Periodically re-evaluate and update risk assessments
E. Reporting Requirements
1. ECCS analysis of record and reporting requirements
2. Risk assessment reporting requirements
3. Minimal risk plant change reporting requirement
F. Documentation Requirements
G. Submittal and Review of Applications Under Sec. 50.46a
1. Initial application for implementing alternative Sec. 50.46a
requirements
2. Subsequent applications for plant changes under Sec. 50.46a
requirements
H. Potential Revisions Based on LOCA Frequency Reevaluations
I. Changes to General Design Criteria
J. Specific Topics Identified for Public Comment
IV. Public Meeting During Development of Proposed Rule
V. Section-by-Section Analysis of Substantive Changes
VI. Criminal Penalties
VII. Compatibility of Agreement State Regulations
VIII. Availability of Documents
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IX. Plain Language
X. Voluntary Consensus Standards
XI. Finding of No Significant Environmental Impact: Environmental
Assessment
XII. Paperwork Reduction Act Statement
XIII. Regulatory Analysis
XIV. Regulatory Flexibility Certification
XV. Backfit Analysis
I. Background
During the last few years, the NRC has had numerous initiatives
underway to make improvements in its regulatory requirements that would
reflect current knowledge about reactor risk. The overall objectives of
risk-informed modifications to reactor regulations include:
(1) Enhancing safety by focusing NRC and licensee resources in
areas commensurate with their importance to health and safety;
(2) Providing NRC with the framework to use risk information to
take action in reactor regulatory matters, and
(3) Allowing use of risk information to provide flexibility in
plant operation and design, which can result in reduction of burden
without compromising safety, improvements in safety, or both.
In stakeholder interactions, one candidate area identified for
possible revision was emergency core cooling system (ECCS) requirements
in response to postulated loss-of-coolant accidents (LOCAs). The NRC
considers that large break LOCAs to be very rare events. Requiring
reactors to conservatively withstand such events focuses attention and
resources on extremely unlikely events. This could have a detrimental
effect on mitigating accidents initiated by other more likely events.
Nevertheless, because of the interrelationships between design features
and regulatory requirements, making changes to technical requirements
of certain parts of the regulations on ECCS performance has the
potential to affect many other aspects of plant design and operation.
The NRC has evaluated various aspects of its requirements for ECCS and
LOCAs in light of the very low estimated frequency of the large LOCA
initiating event.
A. Deterministic Approach
The NRC has established a set of regulatory requirements for
commercial nuclear reactors to ensure that a reactor facility does not
impose an undue risk to the health and safety of the public, thereby
providing reasonable assurance of adequate protection to public health
and safety. The current body of NRC regulations and their
implementation are largely based on a ``deterministic'' approach.
This deterministic approach establishes requirements for
engineering margin and quality assurance in design, manufacture, and
construction. In addition, it assumes that adverse conditions can exist
(e.g., equipment failures and human errors) and establishes a specific
set of design basis events (DBEs) for which specified acceptance
criteria must be satisfied. Each DBE encompasses a spectrum of similar
but less severe accidents. The deterministic approach then requires
that the licensed facility include safety systems capable of preventing
and/or mitigating the consequences of those DBEs to protect public
health and safety. While the requirements are stated in deterministic
terms, the approach contains implied elements of probability
(qualitative risk considerations), from the selection of accidents to
be analyzed to the system level requirements for emergency core cooling
(e.g., safety train redundancy and protection against single failure).
Structures, systems or components (SSC) necessary to defend against the
DBEs were defined as ``safety-related,'' and these SSCs were the
subject of many regulatory requirements designed to ensure that they
were of high quality, high reliability, and had the capability to
perform during postulated design basis conditions.
Defense-in-depth is an element of the NRC's safety philosophy that
employs successive measures, and often layers of measures, to prevent
accidents or mitigate damage if a malfunction, accident, or naturally
caused event occurs at a nuclear facility. Defense-in-depth is used by
the NRC to provide redundancy through the use of a multiple-barrier
approach against fission product releases. The defense-in-depth
philosophy ensures that safety will not be wholly dependent on any
single element of the design, construction, maintenance, or operation
of a nuclear facility. The net effect of incorporating defense-in-depth
into reactor design, construction, maintenance and operation is that
the facility or system in question tends to be less susceptible to, as
well as more tolerant of failures and external challenges.
The LOCA is one of the design basis accidents established under the
deterministic approach. If coolant is lost from the reactor coolant
system and the event cannot be terminated (isolated) or the coolant is
not restored by normally operating systems, it is considered an
``accident'' and then subject to mitigation and consideration of
potential consequences. If the amount of coolant in the reactor is
insufficient to provide cooling of the reactor fuel, the fuel would be
damaged, resulting in loss of fuel integrity and release of radiation.
B. History of Requirements and Design for LOCAs
When the first commercial reactors were being licensed, design-
basis LOCAs were assumed to have the potential of leading to
substantial fuel melting. Therefore, emphasis was placed on containment
capability, low containment leak rate, heat transfer out of the
containment to prevent unacceptable pressure buildup, and containment
atmospheric cleanup systems. The earliest commercial reactor
containments were designed to confine the fluid release from a double-
ended guillotine break (DEGB) of the largest pipe in the reactor
coolant system (RCS). These early designs had long-term core cooling
capability, but before 1966, high-capacity emergency makeup systems
were not required.
During the review of applications for construction permits for
large power reactors in 1966, evaluations of the possibility of
containment basemat melt-through made it apparent to the Atomic Energy
Commission (AEC) and the Advisory Committee on Reactor Safeguards
(ACRS) that a containment might not survive a core meltdown accident.
An ECCS task force was appointed to study the problem. In 1967, the
task force concluded that a more reliable, high-capacity ECCS was
needed to ensure that larger plants could safely cope with a major
LOCA. The General Design Criteria (GDC) in Appendix A to 10 CFR Part
50, which were being developed at the time, included requirements to
this effect. The ECCS was to be designed to accommodate pipe breaks up
to and including a DEGB of the largest pipe in the RCS.
In 1971, General Design Criterion 35 was finalized (36 FR 3256;
February 20, 1971, as corrected, 36 FR 12733; July 7, 1971). GDC 35
states:
Emergency core cooling. A system to provide abundant emergency
core cooling shall be provided. The system safety function shall be
to transfer heat from the reactor core following any loss of reactor
coolant at a rate such that (1) fuel and clad damage that could
interfere with continued effective core cooling is prevented and (2)
clad metal-water reaction is limited to negligible amounts.
Suitable redundancy in components and features, and suitable
interconnections, leak detection, and isolation capabilities shall
be provided to assure that for onsite electric power system
operation (assuming offsite power is not available) and for offsite
electric power system operation (assuming onsite
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power is not available) the system safety function can be
accomplished, assuming a single failure.
On January 4, 1974, (39 FR 1002) the Commission adopted 10 CFR
50.46, Acceptance Criteria for Emergency Core Cooling for Light Water
Cooled Nuclear Power Reactors. Appendix K to 10 CFR 50 was promulgated
with 10 CFR 50.46 to specify required and acceptable features of ECCS
evaluation models. Appendix K included assumptions regarding initial
and boundary conditions, acceptable models, and imposed conditions for
the analysis. In developing Appendix K, conservative assumptions and
models were imposed to cover areas where data were lacking or
uncertainties were large or unquantifiable.
Later in 1974, the Commission began an effort to quantify the
conservatism in the Sec. 50.46 rule and Appendix K to 10 CFR Part 50.
From 1974 until the mid-1980's, the AEC, and subsequently the NRC, as
well as the regulated industry; embarked on an extensive research
program to quantify the conservative safety margins. In 1988, as a
result of these research programs, 10 CFR 50.46 was revised to permit
the use of realistic (or best-estimate) analyses in lieu of the more
conservative Appendix K calculations, provided that uncertainties in
the best-estimate calculations are quantified (53 FR 36004; September
16, 1988). Regulatory Guide 1.157 presents acceptable procedures and
methods for realistic ECCS evaluation models.
The ECCS cooling performance must be calculated for a number of
LOCA sizes (up to and including a double-ended rupture \1\ of the
largest pipe in the RCS), locations and other properties sufficient to
provide assurance that the most severe postulated LOCAs are calculated,
using one of the following two types of acceptable evaluation models:
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\1\ In this document, the terms ``rupture'' and ``break'' are
used interchangeably with no intended difference in meaning.
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(1) An ECCS model with the required and acceptable features of 10
CFR Part 50, Appendix K, or
(2) A best-estimate ECCS evaluation model which realistically
represents the behavior of the reactor system during a LOCA, and
includes an assessment of uncertainties which demonstrates that there
is a high level of probability that the above acceptance criteria are
not exceeded.
The requirements of 10 CFR 50.46 are in addition to any other
requirements applicable to ECCS set forth in Part 50, and implement the
general requirements for ECCS cooling performance design set forth in
GDC 35. Thus, in order to mitigate LOCAs, an ECCS is required to be
included in the design of light water reactors. The ECCS is currently
required to be designed to mitigate a LOCA from breaks in RCS pipes up
to and including a break equivalent in size to a DEGB of the largest
diameter RCS pipe. The ECCS is required to have sufficient redundancy
that it can successfully perform its function with or without the
availability of offsite power and with the occurrence of an additional
single active failure.
GDC 35 requires that the ECCS be capable of providing sufficient
core cooling during a LOCA even when a single failure is assumed.
Standard Review Plan 6.3 interprets this as requiring the ECCS to
perform its function during the short-term injection mode in the event
of the failure of a single active component and to perform its long-
term recirculation function in the event of a single active or passive
failure.
All power reactors operating in the United States have multiple
trains of ECCS capable of mitigating the full spectrum of LOCAs.
Redundant divisions of electrical power and trains of cooling water are
also available in pressurized-water reactors (PWRs) and boiling water
reactors (BWRs) to support ECCS operation and together, provide the
redundancy necessary to meet the single failure criterion.
C. Probabilistic Approach
A probabilistic approach to regulation enhances and extends the
traditional deterministic approach by allowing consideration of a
broader set of potential challenges to safety, providing a logical
means for prioritizing these challenges based on safety significance,
and allowing consideration of a broader set of resources to defend
against these challenges. In contrast to the deterministic approach,
PRAs address a very wide range of credible initiating events and assess
the event frequency. Mitigating system reliability is then assessed,
including the potential for common cause failures. The probabilistic
treatment considers the possibility of multiple failures, not just the
single failure requirements used in the deterministic approach. The
probabilistic approach to regulation is therefore considered an
extension and enhancement of traditional regulation that considers risk
(i.e. product of probability and consequences) in a more coherent and
complete manner.
D. Commission Policy on Risk-Informed Regulation
The Commission published a Policy Statement on the Use of
Probabilistic Risk Assessment (PRA) on August 16, 1995 (60 FR 42622).
In the policy statement, the Commission stated that the use of PRA
technology should be increased in all regulatory matters to the extent
supported by the state-of-the-art in PRA methods and data, and in a
manner that complements the deterministic approach and that supports
the NRC's defense-in-depth philosophy. PRA evaluations in support of
regulatory decisions should be as realistic as practicable and
appropriate supporting data should be publicly available. The policy
statement also stated that, in making regulatory judgments, the
Commission's safety goals for nuclear power reactors and subsidiary
numerical objectives (on core damage frequency and containment
performance) should be used with appropriate consideration of
uncertainties.
In addition to quantitative risk estimates, the defense-in-depth
philosophy is invoked in risk-informed decision-making as a strategy to
ensure public safety because both unquantified and unquantifiable
uncertainties exist in engineering analyses (both deterministic
analyses and risk assessments). The primary need with respect to
defense-in-depth in a risk-informed regulatory system is guidance to
determine which measures are appropriate and how good these should be
to provide sufficient defense-in-depth.
Risk insights can clarify the elements of defense-in-depth by
quantifying their benefit to the extent practicable. Although the
uncertainties associated with the importance of some elements of
defense-in-depth may be substantial, the quantification of the
resulting safety enhancement can aid in determining how best to achieve
defense-in-depth. Decisions on the adequacy of, or the necessity for,
elements of defense should reflect risk insights gained through
identification of the individual performance of each defense system in
relation to overall performance.
To implement the Commission Policy Statement, the NRC developed
guidance on the use of risk information for reactor license amendments
and issued Regulatory Guide (RG) 1.174, ``An Approach for Using
Probabilistic Risk Assessments in Risk-Informed Decisions on Plant
Specific Changes to the Licensing Basis,'' (ADAMS No. ML023240437).
This RG provided guidance on an acceptable approach to risk-informed
decision-making
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consistent with the Commission's policy, including a set of key
principles. These principles include:
(1) Being consistent with the defense-in-depth philosophy;
(2) Maintaining sufficient safety margins;
(3) Allowing only changes that result in no more than a small
increase in core damage frequency or risk (consistent with the intent
of the Commission's Safety Goal Policy Statement); and
(4) Incorporating monitoring and performance measurement
strategies.
Regulatory Guide 1.174 further clarifies that in implementing these
principles, the NRC expects that all safety impacts of the proposed
change are evaluated in an integrated manner as part of an overall risk
management approach in which the licensee is using risk analysis to
improve operational and engineering decisions broadly by identifying
and taking advantage of opportunities to reduce risk; and not just to
eliminate requirements that a licensee sees as burdensome or
undesirable.
II. Rulemaking Initiation
The process described in RG 1.174 is applicable to changes to plant
licensing bases. As experience with the process and applications grew,
the Commission recognized that further development of risk-informed
regulation would require making changes to the regulations. In June
1999, the Commission decided to implement risk-informed changes to the
technical requirements of Part 50. The first risk-informed revision to
the technical requirements of Part 50 consisted of changes to the
combustible gas control requirements in 10 CFR 50.44 (68 FR 54123;
September 16, 2003). The NRC also decided to examine the requirements
for large break LOCAs. A number of possible changes were considered,
including changes to GDC 35 and changes to Sec. 50.46 acceptance
criteria, evaluation models, and functional reliability requirements.
The NRC also proposed to refine previous estimates of LOCA frequency
for various sizes of LOCAs to more accurately reflect the current state
of knowledge with respect to the mechanisms and likelihood of primary
coolant system rupture.
Industry interest in a redefined LOCA was shown by filing of a
Petition for Rulemaking (PRM 50-75) by the Nuclear Energy Institute
(NEI) in February 2002 (ADAMS No. ML020630082). Notice of that petition
was published in the Federal Register for comment on April 8, 2002 (67
FR16654). The petition requested the NRC to amend Sec. 50.46 and
Appendices A and K to allow an option [to the double-ended rupture of
the largest pipe in the RCS] for the maximum LOCA break size as ``up to
and including an alternate maximum break size that is approved by the
Director of the Office of Nuclear Reactor Regulation.'' Seventeen sets
of comments were received, mostly from the power reactor industry in
favor of granting the petition. A few stakeholders were concerned about
potential impacts on defense-in-depth or safety margins if significant
changes were made to reactor designs based upon use of a smaller break
size. The Commission is addressing the technical issues raised by the
petitioner and stakeholders in this proposed rulemaking.
During public meetings, industry representatives expressed interest
in a number of possible changes to licensed power reactors resulting
from redefinition of the large break LOCA. These include: containment
spray system design optimization, fuel management improvements,
elimination of potentially required actions for postulated sump
blockage issues, power uprates, and changes to the required number of
accumulators, diesel start times, sequencing of equipment, and valve
stroke times; among others. In later written comments provided after an
August 17, 2004, public meeting, the Westinghouse Owners Group
concluded that the redefinition of the large break LOCA should have a
substantial safety benefit (September 16, 2004; ADAMS No. ML042680079).
NEI submitted comments (September 17, 2004; ADAMS No. ML042680080)
which included a discussion of six possible plant changes made possible
by such a rule. NEI stated its expectation that all six changes would
most likely result in a safety benefit. The submittal from the Boiling
Water Reactors Owners' Group (BWROG) (September 10, 2004; ADAMS No. ML
042680077) did not specifically address potential safety benefits from
redefining the large break LOCA. The BWROG stated that certain design
changes (recovering some operating margin, reducing blowdown loads,
reducing use of snubbers, etc.) could be made possible by the
redefinition.
The Commission SRM of March 31, 2003, (ML030910476), on SECY-02-
0057, ``Update to SECY-01-0133, `Fourth Status Report on Study of Risk-
Informed Changes to the Technical Requirements of 10 CFR Part 50
(Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.46
(ECCS Acceptance Criteria)' '' (ML020660607), approved most of the NRC
staff recommendations related to possible changes to LOCA requirements
and also directed the NRC staff to prepare a proposed rule that would
provide a risk-informed alternative maximum break size. The NRC began
to prepare a proposed rule responsive to the SRM direction. However,
after holding two public meetings, the NRC found that there were
significant differences between stated Commission and industry
interests. The original concept for Option 3 in SECY-98-300, ``Options
for Risk-Informed Revisions to 10 CFR Part 50--`Domestic Licensing of
Production and Utilization Facilities','' (ML992870048) was to make
risk-informed changes to technical requirements in all of Part 50. The
March 2003 SRM, as it related to LOCA redefinition, preserved design
basis functional requirements (i.e., retaining installed structures,
systems and components), but allowed relaxation in more operational
aspects, such as sequencing of emergency diesel generator loads. The
Commission supported a rule that allowed for operational flexibility,
but did not support risk-informed removal of installed safety systems
and components. Stakeholders expressed varying expectations about how
broadly LOCA redefinition should be applied and the extent of changes
to equipment that might result, based upon their understanding of the
intended purpose of the Option 3 initiative.
To reach a common understanding about the objectives of the LOCA
redefinition rulemaking, the NRC staff requested additional direction
and guidance from the Commission in SECY-04-0037, ``Issues Related to
Proposed Rulemaking to Risk-Inform Requirements Related to Large Break
Loss-of-Coolant Accident (LOCA) Break Size and Plans for Rulemaking on
LOCA with Coincident Loss-of-Offsite Power,'' (March 3, 2004;
ML040490133). The Commission provided direction in a SRM dated July 1,
2004 (ML041830412). The Commission stated that the NRC staff should
determine an appropriate risk-informed alternative break size and that
breaks larger than this size should be removed from the design basis
event category. The Commission indicated that the proposed rule should
be structured to allow operational as well as design changes and should
include requirements for licensees to maintain capability to mitigate
the full spectrum of LOCAs up to the DEGB of the largest RCS pipe. The
Commission stated that the mitigation capabilities for beyond design-
basis events should be controlled by NRC requirements commensurate with
the safety significance of these capabilities. The Commission also
[[Page 67602]]
stated that LOCA frequencies should be periodically reevaluated and
should increases in frequency require licensees to restore the facility
to its original design basis or make other compensating changes, the
backfit rule (10 CFR 50.109) would not apply. Regarding the current
requirement to assume a loss-of-offsite power (LOOP) coincident with
all LOCAs, the Commission accepted the NRC staff recommendation to
first evaluate the BWROG pilot exemption request before proceeding with
a separate rulemaking on that topic.
III. Proposed Action
The Commission proposes to establish an alternative set of risk-
informed requirements with which licensees may voluntarily choose to
comply in lieu of meeting the current emergency core cooling system
requirements in 10 CFR 50.46. Using the alternative ECCS requirements
will provide some licensees with opportunities to change other aspects
of facility design. The overall structure of the risk-informed
alternative is described below. The initial focus for this rulemaking
is on operating plants. The Commission does not now have enough
information to develop generic ECCS evaluation requirements appropriate
to the potentially wide variations in designs for new nuclear power
reactors. Promulgation of a similar rule applicable to future plants
may be undertaken separately, at a later time, as the Commission's
understanding of advanced reactor designs increases.\2\ The potential
rule changes discussed in this document would, at this time, only apply
to nuclear power reactors which currently hold operating licenses.
Proposed changes would consist of a new Sec. 50.46a and conforming
changes to existing Sec. Sec. 50.34, 50.46, 50.46a (to be redesignated
as Sec. 50.46b), 50.109, 10 CFR Part 50, Appendix A, General Design
Criteria 17, 35, 38, 41, 44, and 50.
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\2\ The Commission notes that it is undertaking an effort to
develop a technology-neutral licensing framework applicable to
future advanced reactor designs. See 70 FR 5228 (February 1, 2005).
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A. Overview of Rule Framework
The proposed rule would divide the current spectrum of LOCA break
sizes into two regions. The division between the two regions is
delineated by a ``transition break size'' (TBS).\3\ The first region
includes small size breaks up to and including the TBS. The second
region includes breaks larger than the TBS up to and including the DEGB
of the largest RCS pipe. ``Break'' in the term, ``TBS'', does not mean
a double-ended offset break. Rather, it relates to an equivalent
opening in the reactor coolant boundary. Details on selection of the
risk-informed LOCA TBS are presented in Section III.B of this
supplementary information.
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\3\ Different TBSs for pressurized water reactors and boiling
water reactors would be established due to the differences in design
between those two types of reactors.
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Pipe breaks in the smaller break size region are considered more
likely than pipe breaks in the larger break size region. Consequently,
each break size region will be subject to different ECCS requirements,
commensurate with likelihood of the break. LOCAs in the smaller break
size region must be analyzed by the methods, assumptions and criteria
currently used for LOCA analysis; accidents in the larger break size
region will be analyzed by less stringent methods based on their lower
likelihood. Although LOCAs for break sizes larger than the transition
break will become ``beyond design-basis accidents,'' the NRC would
promulgate regulations ensuring that licensees maintain the ability to
mitigate all LOCAs up to and including the DEGB of the largest RCS
pipe. Design information for systems and components addressing the
capability to mitigate LOCAs in the larger than TBS region would still
be part of a plant's ``design basis,'' as that term is defined in Sec.
50.2, even though that equipment would be used to mitigate a beyond
design-basis accident. Since they would be mitigated to prevent core
damage, LOCAs in the larger than TBS region would not be considered
``severe accidents,'' which are addressed by voluntary industry
guidelines. The ECCS requirements for both regions are discussed in
detail in Section III.C of this supplementary information.
Licensees who perform LOCA analyses using the risk-informed
alternative requirements may find that their plant designs are no
longer limited by certain parameters associated with previous DEGB
analyses. Reducing the DEGB limitations could enable licensees to
propose a wide scope of design or operational changes up to the point
of being limited by some other parameter associated with any of the
required accident analyses. Potential design changes include
optimization of containment spray designs, modifying core peaking
factors, optimizing setpoints on accumulators or removing some from
service, eliminating fast starting of one or more emergency diesel
generators, increasing power, etc. Some of these design and operational
changes could increase plant safety since a licensee could optimize its
systems to better mitigate the more likely LOCAs. The risk-informed
Sec. 50.46a option would establish risk acceptance criteria for
evaluating all design changes, including those that are made possible
by the revised ECCS requirements. These acceptance criteria would be
consistent with the criteria for risk-informed license amendments
contained in RG 1.174. These criteria would ensure both the
acceptability of the changes from a risk perspective and the
maintenance of sufficient defense-in-depth. They are discussed in
detail in Section III.D of this supplementary information.
The rule would require that all future changes \4\ to a facility,
technical specifications,\5\ or operating procedures made by licensees
who adopt 10 CFR 50.46a be evaluated by a risk-informed integrated
safety performance (RISP) assessment process which has been reviewed
and approved by the NRC via the routine process for license
amendments.\6\ The RISP assessment process would ensure that all plant
changes involved acceptable changes in risk and were consistent with
other criteria from RG 1.174 to ensure adequate defense-in-depth,
safety margins and performance measurement. Licensees with an approved
RISP assessment process would be allowed to make certain facility
changes without NRC review if they met Sec. 50.59 \7\ and Sec. 50.46a
requirements, including the criterion that risk increases cannot exceed
a ``minimal'' level. Licensees could make other facility changes after
NRC approval if they met the Sec. 50.90 requirements for license
amendments
[[Page 67603]]
and the criteria in Sec. 50.46a, including the criterion that risk
increases cannot exceed a ``small'' threshold. Potential impacts of the
plant changes on facility security would be evaluated as part of the
license amendment review process. The safety and security review
process for plant changes is discussed further in Section III.G.2 of
this supplementary information.
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\4\ The scope of changes subject to the change criteria in
paragraph (f) of the proposed rule would be greater than the changes
currently subject to Sec. 50.59, which applies only to changes to
``the facility as described in the FSAR.'' The change criteria in
the proposed rule would apply to all facility and procedure changes,
regardless of whether they are described in the FSAR.
\5\ The Commission notes that under the Atomic Energy Act of
1954, as amended, technical specifications are part of the license.
Therefore, plant-specific technical specifications must be changed
by a license amendment.
\6\ Requirements for license amendments are specified in
Sec. Sec. 50.90, 50.91 and 50.92. They include public notice of all
amendment requests in the Federal Register and an opportunity for
affected persons to request a hearing. In implementing license
amendments, the NRC typically prepares an appropriate environmental
analysis and a detailed NRC technical evaluation to ensure that the
facility will continue to provide adequate protection of public
health and safety and common defense and security after the
amendment is implemented.
\7\ Requirements in Sec. 50.59 establish a screening process
that licensees may use to determine whether facility changes require
prior review and approval by the NRC. Licensees may make changes
meeting the Sec. 50.59 requirements without requesting NRC approval
of a license amendment under Sec. 50.90.
---------------------------------------------------------------------------
The NRC would periodically evaluate LOCA frequency information. If
estimated LOCA frequencies significantly increase, the NRC would
undertake rulemaking (or issue orders, if appropriate) to change the
TBS. In such a case, the backfit rule (10 CFR 50.109) would not apply.
If previous plant changes were invalidated because of a change to
the TBS, licensees would have to modify or restore components or
systems as necessary so that the facility would continue to comply with
Sec. 50.46a acceptance criteria (see Sections III.B.6 and III.H of
this supplementary information). The backfit rule (10 CFR 50.109) also
would not apply in these cases.
B. Determination of the Transition Break Size
To help establish the TBS, the NRC developed pipe break frequencies
as a function of break size using an expert opinion elicitation process
for degradation-related pipe breaks in typical BWR and PWR RCSs (SECY-
04-0060, ``Loss-of-Coolant Accident Break Frequencies for the Option
III Risk-Informed Reevaluation of 10 CFR 50.46, Appendix K to 10 CFR
Part 50, and General Design Criteria (GDC) 35;'' April 13, 2004;
ML040860129). This elicitation process is used for quantifying
phenomenological knowledge when data or modeling approaches are
insufficient. The elicitation focused solely on determining event
frequencies that initiate by unisolable primary system side failures
related to material degradation.
A baseline TBS was established using these pipe break frequencies
as a starting point. This baseline TBS was then adjusted to account for
other significant contributing factors that were not explicitly
addressed in the expert elicitation process. The following three-step
process was used by the NRC in establishing the TBS.
(1) Break sizes for each reactor type (i.e., PWR and BWR) were
selected that corresponded to a break frequency of once per 100,000
reactor-years (i.e., 1.0E-5 per reactor-year) from the expert
elicitation results.
(2) The NRC then considered uncertainty in the elicitation process,
other potential mechanisms that could cause pipe failure that were not
explicitly considered in the expert elicitation process, and the higher
susceptibility to rupture/failure of specific piping in the RCS.
(3) The NRC adjusted the TBS upwards to account for these factors.
The remainder of this section discusses this process and the bases
for the NRC's decision in greater detail.
1. Historical Estimates of LOCA Frequencies
Previous studies documented in WASH-1400 (``Reactor Safety Study--
An Assessment of Accident Risks in U.S. Commercial Nuclear Power
Plants,'' October 1975), NUREG-1150 (``Severe Accident Risks: An
Assessment for Five U.S. Nuclear Power Plants,'' December 1990), and
NUREG/CR-5750 (``Rates of Initiating Events at U.S. Nuclear Power
Plants: 1987-1995,'' February 1999) developed pipe break frequencies as
a function of break size. The earliest studies (i.e., WASH-1400 and
NUREG-1150) were based primarily on non-nuclear industry operating
experience. A more recent study (i.e., NUREG/CR-5750) was based on a
significant amount of nuclear operating experience; however, it only
considered the LOCA frequencies associated with precursor leak events
and did not separately evaluate the effects of known degradation
mechanisms. These previous studies did not comprehensively evaluate the
contribution to LOCA frequency for non-piping components other than
steam generator tube ruptures. They also did not address all current
passive system degradation concerns and did not discriminate among
breaks having effective diameters larger than 6 inches. Because of
these limitations, these earlier studies were not sufficient to develop
a TBS for use within 10 CFR 50.46a.
With over 3,000 reactor-years of operating experience, there is now
a much better understanding of the failure frequencies for the various
types of piping systems and sizes that are found in light water
reactors. In addition, there is a more extensive knowledge of
degradation mechanisms that could cause failures in these piping
systems. To apply this operating experience and knowledge to risk-
informing ECCS requirements, the NRC formed a group of experts with
extensive knowledge of plant design, operation, and material
performance to develop LOCA frequency estimates using an expert opinion
elicitation process.
2. Expert Opinion Elicitation Process
In establishing pipe break frequencies as a function of break size,
the NRC used an expert opinion elicitation process with a panel of 12
experts as documented in SECY-04-0060, ``Loss-of-Coolant Accident Break
Frequencies for the Option III Risk-Informed Reevaluation of 10 CFR
50.46, Appendix K to 10 CFR Part 50, and General Design Criteria (GDC)
35,'' (April 13, 2004, ML040860129) and NUREG-1829, ``Estimating Loss-
of-Coolant Accident (LOCA) Frequencies Through the Elicitation Process,
Draft Report for Comment,'' (June 30, 2005; ML052010464). The LOCA
frequency contributions from pipe breaks in the reactor coolant
pressure boundary as well as non-piping passive failures were
considered in this study. Non-piping passive failure contributions were
evaluated in reactor coolant pressure boundary components including the
pressurizer, reactor vessel, steam generator, pumps, and valves, as
appropriate, for BWR and PWR plant types. LOCA frequencies under normal
operational loading and transients expected over a 60 year reactor
operating life were developed separately for PWR and BWR plant types,
which comprise all the nuclear plants in the U.S. These frequencies
represent generic values applicable to the currently operating U.S.
commercial nuclear reactor fleet, based on an important assumption
implicit in the elicitation, which is that all U.S. nuclear plant
construction and operation is in accordance with applicable codes and
standards. In addition, plant operation, inspection, and maintenance
were generally assumed to occur within the expected parameters
allowable by the regulations and technical specifications.
The uncertainty associated with each expert's generic frequency
estimates was also estimated. This uncertainty was associated with each
expert's confidence in their generic estimates and frequency
differences stemming from broad plant-specific factors, but did not
consider factors specific to any individual plants. Thus, the
uncertainty bounds of the expert elicitation do not represent LOCA
frequency estimates for individual plants that deviate from the generic
values. Variability among the various experts' results was also
examined. A number of sensitivity analyses were conducted to examine
the robustness of the LOCA frequency estimates to assumptions made
during the analysis of the experts' responses.
The LOCA frequency estimates developed using this process are
consistent with operating experience for
[[Page 67604]]
small breaks and precursor leaks and exhibit trends that are expected
based on an understanding of passive system failure processes. This is
important because it is expected from the results that the most
significant LOCA frequency contribution occurs from degradation-induced
precursors such as cracking and wall thinning. The LOCA frequency
estimates are also comparable to prior LOCA frequency estimates.
There is significant uncertainty associated with the final LOCA
frequency estimates caused by both individual expert opinion
uncertainty and variability among the experts' opinions. The estimates
also depend on certain assumptions used to process the experts' input.
In addition, the effect of licensees' safety culture can significantly
influence the cause, detection, and mitigation of degradation of safety
components.
As a starting point, the NRC selected break sizes associated with a
mean frequency of 10-5 per reactor-year using both geometric
and arithmetic aggregations of individual expert opinion. For PWRs,
this corresponds to a range of values from approximately 4 inches to 7
inches equivalent diameter, and for BWRs, from approximately 6 inches
to 14 inches equivalent diameter. To address the uncertainty in the
expert opinion elicitation estimates, the staff selected a pipe break
frequency having approximately a 95th percentile probability of
10-5 per reactor-year which resulted in a range of values
from approximately 6 inches to 10 inches equivalent diameter for PWRs
and from approximately 13 inches to 20 inches equivalent diameter for
BWRs. However, this does not account for all failure mechanisms. In
addition, the results of an expert opinion elicitation do not have the
same weight as actual failure data. Therefore, choosing the 95th
percentile values gathered from the expert opinion elicitation leaves
additional margin for uncertainty than would be necessary if the mean
frequency had been calculated from actual failure data.
3. Adjustments To Address Failure Mechanisms Not Considered by the
Expert Elicitation
The expert elicitation process was chartered to consider only LOCAs
that could result from material degradation-related failures of passive
components under normal operational conditions. There are also LOCAs
resulting from failures of active components and other LOCAs resulting
from low probability events (such as earthquakes of magnitude larger
than the safe shutdown earthquake, etc.) that contribute to the
determination of pipe break frequencies. These LOCAs have a strong
dependency on plant-specific factors. The NRC has evaluated the
applicability of both LOCAs caused by failures of active components and
those that could result from low probability events, as discussed
below.
The NRC approach for the selection of the TBS is to use the
frequency estimates of various degradation-related pipe breaks as a
starting reference point. The frequencies for degradation-related
breaks represent generic information, broadly applicable for indicating
the trend of the frequency as the break size increases. In addition to
the degradation-related frequency estimates, there are other important
considerations in estimating overall LOCA frequencies. These include
LOCAs caused by failures of active components; seismically-induced
LOCAs (both with and without pipe degradation), and LOCAs caused by
dropped heavy loads. Each is discussed below.
a. LOCAs caused by failure of active components, such as stuck-open
valves and blown out seals or gaskets.
LOCAs caused by failure of these active components have a greater
frequency of occurrence than LOCAs resulting from the failure of
passive components. LOCAs resulting from the failure of active
components are considered small-break (SB) LOCAs, when considering
components which could fail open or blow out (e.g., safety valves, pump
seals). Active LOCAs resulting from stuck-open valves are limited by
the size of the auxiliary pipe. In some PWRs, there are large loop
isolation valves in the hot and cold leg piping. However, a complete
failure of the valve stem packing is not expected to result in a large
flow area, since the valves are back-seated in the open configuration.
Based on these considerations, active LOCAs are relatively small in
size and are bounded by the selected TBS.
b. Seismically-induced LOCAs, both with and without material
degradation.
Seismically-induced LOCA break frequencies can vary greatly from
plant to plant because of factors such as site seismicity, seismic
design considerations, and plant-specific layout and spatial
configurations. Seismic break frequencies are also affected by the
amount of pipe degradation occurring prior to postulated seismic
events. Seismic PRA insights have been accumulated from the NRC Seismic
Safety Margins Research Program and the Individual Plant Examination of
External Events submittals. Based on these studies, piping and other
passive RCS components generally exhibit high seismic capacities and,
therefore, are not significant risk contributors. However, these
studies did not explicitly consider the effect of degraded component
performance on the risk contributions.
The NRC is conducting a study to evaluate the seismic performance
of undegraded and degraded passive system components. This effort is
examining operating experience, seismic probabilistic risk assessment
(PRA) insights, and models to evaluate the failure likelihood of
undegraded and degraded piping. The operating experience review is
considering passive component failures that have occurred as a result
of strong motion earthquakes in nuclear and fossil power plants as well
as other industrial facilities. No catastrophic failures of large pipes
resulting from earthquakes between 0.2g and 0.5g peak ground
acceleration have occurred in power plants. However, piping degradation
could increase the LOCA frequency associated with seismically-induced
piping failures. When completed, the results of this study could
indicate that licensees choosing to implement this voluntary rule must
perform a site-specific seismic assessment. The purpose of the
assessment would be to demonstrate that RCS piping, assuming
degradation that would not be precluded by implementing a licensee's
inspection and repair programs, will withstand earthquakes such that
the seismic contribution to the overall frequency of pipe breaks larger
than the TBS is insignificant. If needed, this assessment would be
required to be submitted as a part of a licensee's application for
approval to implement the Sec. 50.46a alternative ECCS requirements.
Specific guidance for making these determinations would be provided by
the NRC in the regulatory guide pertaining to this rule.
Plant-specific assessments could be needed because the seismically-
induced break frequencies (direct and indirect) are governed by site
hazard estimates, plant-specific configurations, and individual plant
design. The NRC's generic analysis, by its very nature, cannot
reasonably encompass all potential plant-to-plant variations. For some
plants, a plant-specific assessment could be a relatively simple
evaluation to show that the likelihood of breaks larger than the TBS is
sufficiently low because of a low seismic hazard and consequently very
low stresses. For other plants, an assessment might involve performing
more detailed plant-specific calculations to better estimate seismic
stresses and other parameters, or developing augmented plant-specific
[[Page 67605]]
in-service inspection programs for very strict control of pipe
degradation. These programs would be designed to detect and repair
piping flaws that could increase the likelihood of seismically-induced
pipe breaks with cumulative area larger than the TBS. Other approaches,
including more detailed studies, generically or for group of plants
with similar characteristics from the perspective of this issue, could
also be undertaken.
The NRC is continuing work to assess the likelihood of seismically-
induced pipe breaks larger than the TBS. These analyses are generic in
nature and make use of a combination of insights from deterministic and
probabilistic considerations. To facilitate public comment on the
technical aspects of this issue, an NRC report outlining the details
and results of the NRC's approach will be posted in December 2005 on
the NRC rulemaking Web site at http://ruleforum.llnl.gov. Stakeholders
should periodically check the NRC rulemaking web site for this
information. (See Section III.J.2 of this supplementary information.)
Since a plant-specific seismic assessment requirement might be
included in the final rule, the NRC is requesting specific public
comments on potential options and approaches to address this issue.
(See Section III.J.3. of this supplementary information)
c. LOCAs caused by dropped heavy loads.
Another consideration in selecting the TBS is the possibility of
dropping heavy loads and causing a breach of the RCS piping. During
power operation, personnel entry into the containment is typically
infrequent and of short duration. The lifting of heavy loads that if
dropped would have the potential to cause a LOCA or damage safety-
related equipment is typically performed while the plant is shutdown.
The majority of heavy loads are lifted during refueling evolutions when
the primary system is depressurized, which further reduces the risk of
a LOCA and a loss of core cooling. If loads are lifted during power
operation, they would not be loads similar to the heavy loads lifted
during plant shutdown, e.g., vessel heads and reactor internals. In
addition, the RCS is inherently protected by surrounding concrete
walls, floors, missile shields and biological shielding. Therefore,
based on this information, the contribution of heavy load drops on LOCA
frequency is not considered to be significant. Finally, the resolution
of GSI-186 (NUREG-0933; ML04250049) resulted in recommendations which
are expected to further reduce the overall risk due to heavy load drops
in the future.
4. Consideration of Connected Auxiliary Piping
Other considerations in selecting the TBS were actual piping system
design (e.g., sizes) and operating experience. For example, due to
configuration and operating environment, certain piping is considered
to be more susceptible than other piping in the same size range. For
PWRs the range of pipe break sizes determined from the various
aggregations of expert opinion was 6 to 10 inches in diameter (i.e.,
inside dimension) for the 95th percentile. This is only slightly
smaller than the PWR surge lines, which are attached to the RCS main
loop piping and are typically 12 to 14 inch diameter Schedule 160
piping (i.e., 10.1 to 11.2 inch inside diameter piping). The RCS main
loop piping is in the range of 30 inches in diameter and has
substantially thicker walls than the surge lines. The expert
elicitation panel concluded that this main loop piping is much less
likely to break than other RCS piping. The shutdown cooling lines and
safety injection lines may also be 12 to 14 inch diameter Schedule 160
piping and are likewise connected to the RCS. The difference in
diameter and thickness of the reactor coolant piping and the piping
connected to it forms a reasonable line of demarcation to define the
TBS. Therefore, to capture the surge, shutdown cooling, and safety
injection lines in the range of piping considered to be equal to or
less than the TBS, the NRC specified the TBS for PWRs as the cross-
sectional flow area of the largest piping attached to the RCS main
loop.
For BWRs, the arithmetic and geometric means of the break sizes
having approximately a 95th percentile probability of 10-5
per reactor-year ranged from values of approximately 13 inches to 20
inches equivalent diameter. The information gathered from the expert
opinion elicitation for BWRs showed that the estimated frequency of
pipe breaks dropped markedly for break sizes beyond the range of
approximately 18 to 20 inches. In looking at BWR designs, it was
determined that typical residual heat removal piping connected to the
recirculation loop piping and feedwater piping is about 20 to 24 inches
in diameter. It was also recognized that the sizes of attached pipes
vary somewhat among plants. Accordingly, the NRC chose a TBS for BWRs
based on the larger of either the feedwater or the residual heat
removal (RHR) piping inside primary containment. Selecting these pipes
results in a TBS equivalent diameter of about 20 inches. Thus, for
BWRs, the TBS is specified as the cross-sectional flow area of the
larger of either the feedwater or the RHR piping inside primary
containment.
The NRC believes these definitions of the TBS provide necessary
conservatism to address uncertainties in estimation of break
frequencies. In addition, these TBS values are within the range
supported by the expert opinion elicitation estimates when considering
the uncertainty inherent in processing the degradation-related
frequency estimates. Furthermore, the NRC expects that these values
will provide regulatory stability such that future LOCA frequency
reevaluations are less likely to result in a requirement that licensees
undo plant modifications made as a result of implementing 10 CFR
50.46a.
5. Considerations of Break Location and Flow Characteristic
Because the effects of TBS breaks on core cooling vary with the
break location, the NRC evaluated whether the frequency of TBS breaks
varies with location and whether TBS breaks should, therefore, vary in
size with location.
In PWRs, the pressurizer surge line is only connected to one hot
leg and the pipes attached to the cold legs are generally smaller than
the surge line in size. The cold legs (including the intermediate legs)
operate at slightly cooler temperatures and any degradation mechanism
that might appear would be expected to progress more slowly in the cold
leg than in the hot leg. Therefore, the NRC evaluated whether it may be
appropriate to specify a TBS for the cold leg which would be smaller in
size than the surge lines. The frequency of occurrence of a break of a
given size is composed of both the frequency of a completely severed
pipe of that size (a circumferential break) plus the frequency of a
partial break of that size in an equal or larger size pipe (a
longitudinal break). Therefore, the NRC evaluated an option where the
TBS for the hot and cold legs would be distinctly different and would
be composed of two components: (1) Complete breaks of the pipes
attached to the hot or cold legs at the limiting locations within each
attached pipe, and (2) partial breaks of a constant size, as
appropriate for either the hot or cold leg, at the limiting locations
within the hot or cold legs. The NRC attempted to estimate the
appropriate size of the partial break component for the TBS by
reviewing the expert elicitation results to determine the frequencies
of occurrence of partial breaks in the hot
[[Page 67606]]
and cold legs which would be equivalent to the frequency of a complete
surge line break. From this, it was found that frequencies of
occurrence of partial breaks of a given size are generally lower for
the cold leg than for the hot leg. However, other than this general
trend, the elicitation results do not contain enough specific detailed
information to adequately quantify any specific differences in the
frequencies compared to a complete surge line break. Because a smaller
size partial break TBS criterion in either the hot or cold legs could
not be established, it was determined that the required TBS partial
breaks in the hot and cold legs should remain equivalent in size to the
internal cross sectional area of the surge line. There is no
significant difference in piping or service conditions in BWRs compared
to the PWR hot and cold leg differences described above, where a
difference in the rates of degradation could be identified. Thus, a
smaller size partial break TBS criterion also could not be established
for BWRs.
The NRC also evaluated whether TBS breaks should be analyzed as
single-ended or double-ended breaks. To address this issue the NRC
reviewed the expert elicitation process and the guidance given to the
experts in developing their frequency estimates. The NRC concluded that
the expert elicitation estimates are based on knowledge of physical
pressure retaining component behavior and are not premised on breaks
being either single-ended or double-ended. This is a feature of the
response of the particular system configuration to the occurrence of
the break, i.e., whether reactor coolant can feed either end of the
break.
The current design basis analysis for light water reactors requires
analysis of a DEGB of the largest pipe in the RCS. Under the proposed
rule, all breaks up to and including the TBS would be analyzed in
accordance with existing requirements. A possible reason for specifying
the TBS for PWRs as double-ended could be that a complete break of the
pressurizer surge line would result in reactor coolant exiting both
ends of the break. While this is true, the dominant effect in terms of
core cooling is loss of the fluid exiting from the hot leg side of the
break, with much less effect due to fluid exiting from the pressurizer
side. Therefore, specifying the TBS break as an area equivalent to a
double-ended break of the surge line would be overly conservative. For
BWRs, the effect of a double-ended break area is also considered to be
overly conservative. The selected TBS for BWRs based on the larger of
the RHR or main feedwater lines would bound breaks of the smaller lines
in the reactor recirculation and feedwater piping where a complete
break would result in a double-ended discharge flow. Therefore, the NRC
has determined that the assumption of a single-ended characteristic of
the TBS break reasonably represents the effect of RCS breaks. This
conclusion is not inconsistent with the expert opinion elicitation
estimates of break frequencies.
6. Effects of Future Plant Modifications on TBS
For the proposed TBS to remain valid at a particular facility,
future plant modifications must not significantly increase the LOCA
pipe break frequency estimates generated during the expert elicitation
and used as the basis for the TBS. For example, the expert elicitation
panel did not consider the effects of power uprates in deriving the
break frequency estimates. The expert elicitation panel assumed that
future plant operating characteristics would remain consistent with
past operating practices. The NRC recognizes that significant power
uprate allowances may change plant performance and relevant operating
characteristics to a degree that they might impact future LOCA
frequencies. In applications for power uprates that use or intend to
use Sec. 50.46a, the NRC will expect licensees to explain why uprate
conditions (e.g., increased flow-induced vibrations and increased
potential for flow-assisted corrosion in the reactor coolant pressure
boundary piping) do not significantly increase break frequencies.
7. Future Adjustments to TBS
The initial TBS was adjusted upward to account for uncertainties
and failure mechanisms leading to pipe rupture that were not considered
in the expert elicitation process. As the NRC obtains additional
information that may tend to reduce those uncertainties or allow for
more structured consideration of mechanisms, the NRC will assess
whether the TBS (as defined in the rule) should be adjusted, and may
initiate rulemaking to revise the TBS definition to account for this
new information. The NRC will also continue to assess the precursors
that might be indicative of an increase in pipe break frequencies in
plants operating under power uprate conditions to establish whether the
TBS would need to be adjusted.
C. Alternative ECCS Analysis Requirements and Acceptance Criteria
The proposed rule would require licensees to analyze ECCS cooling
performance for breaks up to and including a double-ended rupture of
the largest pipe in the RCS. These analyses must be performed by
acceptable methods and must demonstrate that ECCS cooling performance
conforms to the acceptance criteria set forth in the rule. For breaks
at or below the TBS, Sec. 50.46a(e)(1) of the proposed rule specifies
requirements identical to the existing ECCS analysis requirements set
forth in Sec. 50.46. However, commensurate with the lower probability
of breaks larger than the TBS, Sec. 50.46a(e)(2) of the proposed rule
specifies more realistic requirements associated with the rigor and
conservatism of the analyses and associated acceptance criteria for
breaks larger than the TBS. LOCA analyses for break sizes equal to or
smaller than the TBS should be applied to all locations in the RCS to
find the limiting break location. LOCA analyses for break sizes larger
than the TBS (but using the more realistic analysis requirements)
should also be applied to all locations in the RCS to find the limiting
break size and location. This analytical approach is consistent with
current practice.
1. Acceptable Methodologies and Analysis Assumptions
Under existing Sec. 50.46 requirements, prior NRC approval is
required for ECCS evaluation models. Acceptable evaluation models are
currently of two types; those that realistically describe the behavior
of the RCS during a LOCA, and those that conform with the required and
acceptable features specified in Appendix K. Appendix K evaluation
models incorporate conservatism as a means to justify that the
acceptance criteria are satisfied by an ECCS design. In contrast, the
realistic or best-estimate models attempt to accurately simulate the
expected phenomena. As a result, comparisons to applicable experimental
data must be made and uncertainty in the evaluation model and inputs
must be identified and assessed. This is necessary so that the
uncertainty in the results can be estimated so that when the calculated
ECCS cooling performance is compared to the acceptance criteria, there
is a high level of probability that the criteria would not be exceeded.
Appendix K, Part II contains the documentation requirements for
evaluation models. All of these existing requirements would be retained
in Sec. 50.46a(e)(1) of the proposed rule for breaks at or below the
TBS.
The NRC expects that the level of conservatism of an analysis
method used for breaks larger than the TBS would be less than for
breaks at or below the TBS. This concept is reflected
[[Page 67607]]
in the differences between paragraphs (e)(1) and (e)(2) of Sec.
50.46a, which respectively describe ECCS evaluation requirements for
breaks at or below the TBS and breaks larger than the TBS. As noted
above, for breaks at or below the TBS, all current requirements,
including use of an ECCS evaluation model as defined in the rule, are
retained. For larger breaks, paragraph (e)(2) of Sec. 50.46a indicates
that only the most important phenomena must be addressed by the
analysis method, and that the model must reasonably describe the
behavior of the RCS during the LOCA. The term ``analysis method'' is
used for the larger than TBS break sizes to indicate that these methods
need not be the same as the ECCS evaluation models required for breaks
at or below the TBS. To analyze breaks larger than the TBS, a licensee
need not use an NRC currently approved evaluation model, plant-specific
or generic. A licensee may use a presently approved best-estimate
methodology for breaks larger than the TBS. Such an evaluation model
would exceed the requirements for analysis methods, and would likely
yield margin to the acceptance criteria. Also, these approved models
are available for use at most plants for some break sizes.
Licensees would not be required to submit detailed analysis method
documentation for LOCAs larger than the TBS. Section 50.46a would not
require prior NRC approval of these analysis methods. Licensees would
only be required to describe the analysis methods used. Analyses using
methods unfamiliar to the NRC or of questionable accuracy would be
reviewed by NRC via the inspection process.
As currently required under Sec. 50.46, the analysis must
demonstrate with a high level of probability that the acceptance
criteria will not be exceeded for breaks at or below the TBS. What
constitutes a high level of probability is not delineated in the rule.
The position taken in RG 1.157 has been that 95 percent probability
constitutes an acceptably high probability. Section 50.46a(e)(1) of the
proposed rule retains the high level of probability as the statistical
acceptance criterion for breaks at or below the TBS. Because of the
much lower frequency of pipe breaks larger than the TBS, proposed Sec.
50.46a(e)(2) relaxes the criterion to ``reasonably'' describe the
system behavior for breaks larger than the TBS. The NRC is preparing a
regulatory guide which would provide more detailed guidance about
meeting this criterion.
Paragraphs 50.46a(e)(1) and (e)(2) would require that the worst
break size and location be calculated separately for breaks at or below
the TBS and for breaks larger than the TBS up to and including a
double-ended rupture of the largest pipe in the RCS. Different
methodologies, analytical assumptions, and acceptance criteria will be
used for each break size region. Consistent with current Sec. 50.46
requirements, breaks at or below the TBS will be analyzed assuming the
worst single failure concurrent with a loss-of-offsite power, limiting
operating conditions, and only crediting safety systems. For breaks
larger than the TBS, credit may be taken for operation of any and all
equipment supported by availability data, along with the use of nominal
operating conditions rather than technical specifications limits. This
would also include combining actual fuel burnup in decay heat
predictions with the corresponding operating peaking factors at the
appropriate time in the fuel cycle. The assumptions of loss-of-offsite
power and the worst single failure are not required. These more
realistic requirements are appropriate because breaks larger than the
TBS are very unlikely. Thus, less margin is needed in the analysis of
breaks in this region.
As discussed further in Section III.C.3, ``Plant operational
requirements related to ECCS analyses,'' Sec. 50.46a(d)(2) would
prohibit plant operation in any at-power operating configuration for
which maintenance of coolable geometry and long-term cooling for LOCAs
larger than the TBS has not been demonstrated. A licensee could analyze
planned operating configurations or justify that a particular
configuration is bounded by failures assumed in other analyses to limit
the number of calculations necessary to support plant operation when
equipment is out of service or equipment performance is degraded. The
NRC will provide further guidance on analysis methods and assumptions
in the regulatory guide issued with the final rule.
2. Acceptance Criteria
ECCS acceptance criteria in proposed Sec. 50.46a(e)(3) for breaks
at or below the TBS are the same as those currently required in Sec.
50.46. Therefore, licensees would be required to use an approved
methodology to demonstrate that the following acceptance criteria are
met for the limiting LOCA at or below the TBS:
i. PCT less than 2200[deg]F;
ii. Maximum local cladding oxidation (MLO) less than 17 percent;
iii. Maximum hydrogen production--core wide cladding oxidation
(CWO) less than 1 percent;
iv. Maintenance of coolable geometry; and
v. Maintenance of long-term cooling.
The first two criteria are established to ensure that the clad
retains adequate ductility as it is quenched from the elevated
temperatures anticipated during a LOCA. Loss of ductility would
potentially result in fragmentation of the fuel and loss of a coolable
geometry. Clad temperatures in the range of 2200 [deg]F result in rapid
decreases in cladding ductility and ductility is reduced when oxidation
levels reach 17 percent. The calculated maximum local cladding
oxidation must account for the pre-existing oxidation accumulated
during burnup and that generated during the LOCA. In addition,
oxidation on the inside of the clad surface must also be considered
once the clad is calculated to have ruptured. For the majority of
current plants, operation is limited by the PCT criterion, as total
oxidation levels typically calculated do not exceed approximately 10
percent for most plants. However, as the break size definition for a
design basis accident decreases, cladding oxidation can become
limiting. Small breaks result in extended periods of time at moderate
temperatures, in the range of 1800[deg]F, which can produce oxidation
levels as great or greater than short time spans at higher
temperatures. The limit on hydrogen production is important for small
breaks for the same reason--long periods at moderate temperatures can
cause greater clad oxidation and hydrogen production. Only hydrogen
calculated to be produced during the LOCA is compared to the CWO limit.
The CWO limit was not removed from the breaks at or below the TBS
because the requirements of 10 CFR 50.44, ``Combustible Gas Control for
Nuclear Power Reactors,'' ensure combustible gas control for beyond
design basis accidents only and thus can rely on non-safety systems and
less rigorous analysis techniques to demonstrate compliance.
Commensurate with the lower probability of occurrence, the
acceptance criteria in proposed Sec. 50.46a(e)(4) for breaks larger
than the TBS are less prescriptive:
i. Maintenance of coolable geometry, and
ii. Maintenance of long-term cooling.
The proposed rule would afford licensees flexibility in
establishing appropriate metrics and quantitative acceptance criteria
for maintenance of coolable geometry. A licensee's metrics and
acceptance criteria must realistically demonstrate that coolable core
geometry and long-term cooling will be maintained. Unless data or other
valid justification criteria are provided, licensees should use 2200
[deg]F and 17 percent for the limits on PCT and MLO,
[[Page 67608]]
respectively, as metrics and quantitative acceptance criteria for
meeting the proposed rule's acceptance criteria. Other less
conservative criteria would be acceptable if properly justified by
licensees. In addition, the requirements of 10 CFR 50.44 specify that
all containments have the capability for ensuring a mixed atmosphere,
thus reducing the potential for hydrogen combustion in the event of a
beyond design-basis LOCA. The rule requires that BWRs with Mark III
containments and all PWRs with ice condenser containments must have the
capability for controlling combustible gas generated from a metal-water
reaction involving 75 percent of the fuel cladding surrounding the
active fuel region, and BWRs with Mark I and II containments must have
inerted containments. Analyses performed to support the Sec. 50.44
rulemaking (68 FR 54141; September 16, 2003) demonstrated that PWRs
with large dry containments do not require additional measures to
control combustible gas generated from a metal-water reaction involving
75 percent of the fuel cladding surrounding the active fuel region.
This bounds the level of oxidation expected in the event of a LOCA
larger than the TBS.
3. Plant Operational Requirements Related to ECCS Analyses
The proposed rule would require that a facility be able to mitigate
LOCA break sizes larger than the TBS up to and including a double-ended
rupture of the largest pipe in the RCS at the limiting location. The
licensee must demonstrate this mitigative ability, in part, using
evaluation models or analysis methods under Sec. 50.46a(e)(2) to
demonstrate compliance with the acceptance criteria in Sec.
50.46a(e)(4). For LOCAs larger than the TBS, licensees must demonstrate
compliance with the acceptance criteria in Sec. 50.46a(e)(4) under all
at-power operating conditions (i.e., all modes of operation when the
reactor is critical). This demonstration is required at-power because
LOCAs are most likely to challenge the ECCS acceptance criteria during
power operation. These analyses will identify ECCS components and
trains (including sufficiently reliable non-safety related systems)
that are required to operate to mitigate LOCA break sizes larger than
the TBS.
The proposed rule would not require assuming a loss-of-offsite
power or a limiting single failure of the ECCS for LOCA analyses
performed for breaks larger than the TBS. Thus, it is possible that a
licensee's analyses would credit that the full complement of ECCS was
available. To ensure that the facility will continue to comply with the
acceptance criteria for LOCAs larger than the TBS under any at-power
operating configuration allowed by the license, the Commission would
require both that the acceptance criteria not be exceeded during any
at-power condition that has been analyzed, and that the plant not be
placed in any unanalyzed condition.
One circumstance where the ability to comply with the acceptance
criteria might be called into question would be if an ECCS train or
component was removed from service (such as for maintenance) while the
plant is in operation. For this time period, the assumed set of
mitigation systems would not be available to respond should a beyond
TBS LOCA occur, and the acceptance criteria might not be satisfied.
Thus, the licensee would either have to demonstrate that under such
conditions the acceptance criteria would not be exceeded, or not place
the facility in that configuration. To satisfy this requirement a
licensee might prepare analyses showing acceptable results with
expected complements of equipment that might be taken out of service or
could propose suitable Technical Specifications as part of its
application for the facility change that would restrict plant operation
to acceptable conditions.
Accordingly, in Sec. 50.46a(d)(2) of the proposed rule, the
Commission would require that the facility may not operate in any at-
power configuration of operable ECCS components where the ECCS cooling
performance for LOCAs larger than the TBS has not been demonstrated to
meet the acceptance criteria in Sec. 50.46a(e)(4). The evaluation must
be calculated in accordance with Sec. 50.46a(e)(2). Bounding analyses
may be performed to reduce the number of model calculations.
4. Restrictions on Reactor Operation
Proposed Sec. 50.46a(e)(5) would allow the Director of the Office
of Nuclear Reactor Regulation to impose restrictions on reactor
operation if it is determined that the evaluations of ECCS cooling
performance are not consistent with the requirements for evaluation
models and analysis methods specified in Sec. 50.46a(e)(1) through
(e)(4) of this section. Non-compliance may be due to factors such as
lack of a sufficient data base upon which to assess model uncertainty,
use of a model outside the range of an appropriate data base, models
inconsistent with the requirements of Appendix K of Part 50, or
phenomena unknown at the time of approval of the methodology. Lack of
compliance with methodological requirements would not necessarily
result in failure to meet the acceptance criteria of Sec. 50.46a(e)(3)
and (e)(4), but, rather, would provide results that could not be relied
upon to demonstrate compliance with the appropriate acceptance
criteria. Thus, depending upon the specific circumstances, it might be
necessary for the NRC to impose restrictions on operation until such
issues are settled. This requirement would be included in the proposed
rule for consistency with the current ECCS regulations, since it is
comparable to existing Sec. 50.46(a)(2).
D. Risk-Informed Changes to the Facility, Technical Specifications, or
Procedures
The Commission proposes that licensees who adopt Sec. 50.46a would
use an integrated, risk-informed change process to demonstrate the
acceptability of all future facility changes, both with and without NRC
approval, made under Sec. 50.90 or Sec. 50.59, respectively. This
risk-informed integrated safety performance assessment, or RISP
assessment, would be required to demonstrate that (1) increases in
plant risk (if any) meet appropriate risk acceptance criteria, (2)
defense-in-depth is maintained, (3) adequate safety margins are
maintained, and (4) adequate performance-measurement programs are
implemented.
The Commission considered adopting two sets of change control
criteria: One for changes enabled by the new rule,\8\ and one for all
other changes. The Commission rejected this option because it may be
difficult to distinguish between facility changes enabled by Sec.
50.46a and changes that are permitted by the current ECCS requirements
in Sec. 50.46.
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\8\ As discussed in Section III.A of this supplementary
information, licensees approved to implement Sec. 50.46a would be
able to make facility changes which would not have been permitted
without the revised ECCS analyses allowed by the rule. These are
considered to be Sec. 50.46a enabled changes. Other changes that
licensees could make after adopting this rule could be unrelated to
the new Sec. 50.46a, insofar as the basis of the changes and NRC
approval, when necessary, would rely on requirements or analyses
that do not depend on the new ECCS analyses and acceptance criteria.
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1. Requirements for the Risk-Informed Integrated Safety Performance
(RISP) Assessment Process
A licensee who wishes to implement Sec. 50.46a requirements would
submit a license amendment request under Sec. 50.90 and receive prior
NRC approval to implement the alternative requirements. As discussed in
Section III.C.1 of this supplementary information, the proposed rule
would require a description of the method(s)
[[Page 67609]]
and the results of the analyses to demonstrate compliance with the
Sec. 50.46a ECCS acceptance criteria and a description of the RISP
assessment process to be used in evaluating whether proposed changes to
the facility, technical specifications, or procedures meet the
requirements in 50.46a(f). In particular, Sec. 50.46a(c)(1)(ii)(A)
would require a description of the licensee's PRA model and risk
assessment methods, and Sec. 50.46a(c)(1)(ii)(B) would require a
description of the methods and decisionmaking process for evaluating
compliance with the risk criteria, defense-in-depth criteria, safety
margin criteria, and performance measurement criteria in Sec.
50.46a(f). The information required to be submitted in the application
would form the basis for the NRC's determination of whether the
licensee's process will ensure that the requirements of Sec.
50.46a(f)(1) are met for future changes made according to the Sec.
50.59 requirements.
The Commission could approve a licensee's application to implement
10 CFR 50.46a if the criteria in Sec. 50.46a(c)(2) were met. Section
50.46a(c)(2) would require that:
1. The licensee's ECCS analyses and results demonstrate compliance
with the ECCS acceptance criteria,
2. The RISP assessment process assures that all facility changes
meet the risk assessment requirements of Sec. 50.46a(f), and
3. The RISP assessment process ensures that changes not requiring
prior NRC review and approval are evaluated and comply with Sec.
50.59.
Compliance with the ECCS acceptance criteria is necessary to ensure
that licensed facilities are able to adequately mitigate LOCAs of
varying sizes and locations. Compliance with the Sec. 50.59
requirements is necessary to ensure that facility changes made without
NRC approval do not result in plant conditions that could impact public
health and safety. Compliance with the Sec. 50.46a(f) requirements for
RISP assessments is required to ensure that facility changes result in
acceptable changes in risk, adequate defense-in-depth and safety
margins are maintained, and acceptable performance-measurement programs
are implemented. The Sec. 50.46a(f) requirements are discussed
individually below.
Sections Sec. 50.46a(f)(1)(ii) and (f)(2)(ii) would describe the
risk acceptance criteria that the RISP assessment must demonstrate are
met. Paragraph (f)(3) would describe the requirements on the defense-
in-depth and safety margin evaluations, and on the performance
measurement programs. Paragraphs (f)(4) and (f)(5) would describe the
requirements on the PRA or non-PRA risk assessment models and
methodologies used to determine the impact of the changes on risk.
A RISP assessment process would include quantitative and
qualitative risk analysis tools, a framework for evaluating defense-in-
depth implications of changes, a framework for evaluating safety
margins, and performance-measurement programs that monitor the facility
and provide feedback of information for timely corrective actions.
These attributes have been identified by the Commission as a necessary
set of evaluation tools to ensure that changes to the facility do not
endanger the public health and safety.
a. Risk acceptance criteria for plant changes under 10 CFR 50.90.
Section 50.46a(f)(2)(ii) would require that the RISP demonstrate,
for changes made under Sec. 50.90, that the total increases in core
damage frequency (CDF) and large early release frequency (LERF) are
small and that the overall plant risk remains small. CDF and LERF are
surrogates for early and latent health effects, which are used in the
NRC's Safety Goals (Safety Goals for the Operation of Nuclear Power
Plants; Policy Statement, 51 FR 30028; August 4, 1986). The NRC has
used CDF and LERF in making regulatory decisions for over 20 years.
Most recently, the NRC endorsed the use of CDF and LERF as appropriate
measures for evaluating risk and ensuring safety in nuclear power
plants when it adopted RG 1.174 in 1997. Application-specific
regulatory guides have been developed on risk-informed IST, ISI, graded
quality assurance, and technical specifications. Since the adoption of
RG 1.174, the Commission has had eight years of experience in applying
risk-informed regulation to support a variety of applications,
including amending facility procedures and programs (e.g., IST and ISI
programs), amending facility operating licenses (e.g., power up-rates,
license renewals, and changes to the FSAR), and amending technical
specifications. On the basis of this experience, the Commission
believes that CDF and LERF are acceptable measures for evaluating
changes in risk as the result of changes to a facility, technical
specifications, and procedures, with the exception of certain changes
that affect containment performance but do not affect CDF or LERF.
Changes that affect containment performance are considered as part of
the defense-in-depth evaluation.
Paragraph 50.46a(f)(2)(ii) would require the total increases in CDF
and LERF to be small, and the overall plant risk to remain small.\9\ As
discussed in RG 1.174, whether a change in risk is small depends on a
plant's overall risk as measured by the current CDF and LERF. For
plants with an overall baseline CDF of 10-\4\ per year or
less, small CDF increases are considered to be up to 10-\5\
per year. For plants with an overall baseline CDF greater than
10-\4\ per year, small CDF increases are those of up to
10-\6\ per year. For plants with an overall baseline LERF of
10-\5\ per year or less, small LERF increases are considered
to be up to 10-\6\ per year, and for plants with an overall
baseline LERF greater than 10-\5\ per year, small LERF
increases are considered to be up to 10-\7\ per year. Since
1997, the Commission has applied these quantitative guidelines to
individual plant changes and to sequences of plant changes implemented
over time. The Commission has found these guidelines and these values
(when used together with the defense in depth, safety monitoring, and
performance-measurement criteria) are capable of differentiating
between changes, and sequences of changes, that are not expected to
endanger the public health and safety from those that might. The
Commission proposes to use these quantitative guidelines as the basis
for determining whether the total increase in CDF and LERF are small
and that the overall plant risk remains small.
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\9\ Section 2.2.4 in RG 1.174 clarifies that the acceptance
criteria for changes to CDF and LERF are to be compared with the
results of a full-scope risk assessment including internal events,
external events, full power, low power, and shutdown. All references
to CDF and LERF refer to estimates that include the risk from
internal events, external events, full power, low power, and
shutdown. Therefore the CDF and LERF estimates to be used in Sec.
50.46a evaluations are directly comparable to the acceptance
guidelines on CDF and LERF in RG 1.174.
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The Commission requests specific public comments on the
acceptability of applying the change in risk acceptance guidelines from
RG 1.174 to the total cumulative change in risk from all changes in the
plant after adoption of Sec. 50.46a. Should other risk guidelines be
used and, if so, what guidelines should be used? (See Section III.J.13
of this supplementary information.)
b. Risk acceptance criteria for plant changes under 10 CFR 50.59.
After the adoption of Sec. 50.46a by a licensee and the approval
of the proposed RISP assessment program by the NRC, a risk assessment
would be required for all changes to the facility, technical
specifications, and procedures that a licensee proposes to make.
Section 50.46a(f)(1)(ii) of the proposed
[[Page 67610]]
rule would require that the RISP demonstrate, for changes made under
Sec. 50.59, that any increases in the estimated risk are ``minimal''
compared to the overall \10\ plant risk profile. In the Commission's
view, plant changes which individually and taken together involve
minimal changes in risk and have no significant impact upon defense-in-
depth or safety margins (and do not involve a change to the license),
do not result in significant issues involving public health and safety
or common defense and security. For such changes, a qualitative
assessment instead of a quantitative estimate of the change in risk may
be sufficient to demonstrate that the proposed change meets the minimal
increase in risk criteria.
For plant changes for which it is possible to quantitatively
estimate the resulting change in plant risk, existing guidance in RG
1.174 for NRC review of risk-informed changes does not address a
threshold for changes that result in risk increases that might be small
enough (i.e., minimal) that the proposed plant change does not warrant
review by the NRC. Section 50.59, however, contains guidance on
determining when non risk-informed plant changes do not warrant review
by the NRC. Consequently, the Commission proposes to develop the new
criteria proposed in Sec. 50.46a(f)(1)(ii) to be consistent with
``minimal'' as it is described in supplementary information published
with the December 2001 amendment to 10 CFR 50.59 (66 FR 64738).
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\10\ As with plant changes made under Sec. 50.90, ``overall''
plant risk includes the risk from internal events, external events,
full power, low power, and shutdown.
---------------------------------------------------------------------------
The Commission believes that if a change in risk is so small that
it cannot be reasonably concluded that the risk has actually changed
(i.e., there is no clear trend toward increasing the risk), the change
need not be considered an increase in risk. If defense-in-depth, safety
margins, and performance measurement program criteria are also met,
such changes would always have a ``minimal'' increase in risk. However,
the Commission believes that the appropriate threshold for ``minimal''
should provide more flexibility than afforded by the description above.
In the December 2001 amendment to Sec. 50.59, the Commission also
stated that ``minimal'' as used in Sec. 50.59 is intended to limit the
amount of increase in probability or consequences of accidents such
that it remains substantially less than a ''significant increase'' as
referred to in Sec. 50.92. Therefore the Commission proposes that the
``minimal'' in Sec. 50.46a(f)(1)(ii) should limit the amount of
increase in risk such that it remains less than the ``small'' increase
permitted in Sec. 50.46a(f)(2)(ii).
As discussed below, RG 1.174 guidelines state that, if the overall
CDF is greater than 10-\4\ per year, an increase in CDF
greater than 10-\6\ per year is not small. Similarly, if the
overall LERF is greater than 10-\5\ per year, an increase in
LERF greater than 10-\7\ per year is not small. Conversely,
increases in CDF less than 10-\6\ per year and increases in
LERF 10-\7\ per year are always small. The Commission
proposes to define ``minimal'' as 10 percent of the risk increases that
would be small for any licensee. An alternative, consistent with RG
1.174, would be to define minimal as 10 percent of small, and allow
small to vary from plant to plant according to the overall plant
specific CDF and LERF. For example, minimal could be defined as an
increase in CDF less than 10-\6\ per year if the overall CDF
is less than 10-\4\ per year, or less than 10-\7\
per year otherwise. However, if correction of a PRA error or new
information caused the overall CDF to rise from below to above
10-\4\ per year, the acceptance criteria for minimal would
drop from 10-\6\ per year to 10-\7\ per year from
one moment to the next. Existing Sec. Sec. 50.59 and 50.92 provide
acceptance criteria that are applicable to all the plants and that do
not change with time. Therefore, the Commission believes that, when
quantified, a ``minimal'' risk increase would be an increase in CDF
less than 10-\7\ per year and an increase in LERF less than
10-\8\ per year. This permits a single risk level to be
applied to all plants and limits the likelihood of the acceptable risk
level changing as the plant overall risk changes.
Paragraph 50.46a(f)(ii) would also require that the increase in
risk from each change is minimal compared to the overall plant-specific
risk profile. For licensed facilities which have very low overall risk
estimates, the proposed criteria of 10-\7\ per year and
10-\8\ per year for CDF and LERF, respectively, may permit
increases that are significantly large compared to the overall plant
risk profile. Permitting a licensee to make changes without NRC review
that are not minimal compared to the overall plant risk is contrary to
the intent of the proposed rule. Therefore, the Commission proposes
that, when quantified, a ``minimal'' increase in CDF and LERF must also
be an increase of less than 1 percent of the overall plant-specific
risk. The Commission expects that the fixed risk threshold on
``minimal'' changes discussed above (i.e., less than 10-\7\
per year and 10-\8\ per year increase in CDF and LERF
respectively) will be applicable to most, if not all, plants.
For the reasons discussed above, the Commission proposes that a
risk increase, when evaluated quantitatively, would be considered to be
``minimal compared to the overall plant risk profile'' if it meets both
of the following criteria:
(1) The increase in CDF less than 10-\7\ per year and an
increase in LERF less than 10-\8\ per year, and
(2) The increases in CDF and LERF are increases of less than 1
percent of the overall plant-specific risk.
c. Cumulative risk acceptance criteria.
To satisfy the Commission's proposed requirement in Sec.
50.46a(f)(2)(ii) that the total increases in CDF and LERF are small and
overall plant risk remains small, the total risk from all changes since
the adoption of Sec. 50.46a must be tracked. It is important to track
the total change in risk from changes to the facility, technical
specifications, and procedures to ensure that these changes, when taken
in total as they are implemented over time, do not contribute more than
a small increase in risk. A licensee may always choose to implement a
series of changes over time. If tracking the total increase in CDF and
LERF criteria were not implemented, a number of smaller changes where
every individual change is kept below the proposed rule's risk
acceptance criteria could, considered cumulatively, result in a
significant increase in risk. The proposed rule's requirement for risk
tracking is consistent with RG 1.174, the application-specific RG's,
and current staff practice. Tracking the total risk increase caused by
implementing related changes over time and comparison of the total
against the RG 1.174 criteria has been used for risk-informed in-
service testing (IST), in-service inspection (ISI), and integrated leak
rate interval extension and is included as part of the Sec. 50.69 risk
assessment process. However, tracking the total risk increase caused by
sequential risk-informed extensions of technical specification allowed
outage times is not required under RG 1.177 guidance for risk-informed
technical specification changes. Instead, approved changes must include
provisions to control the potential total risk increase by a
configuration risk management program that prevents unacceptable risk
increases that could be caused by overlapping the extended allowed
outage times permitted by the changes.
This rule would require that the cumulative risk increase from all
changes be evaluated against the
[[Page 67611]]
``small'' criteria. Requiring that the total change in risk from a
series of changes be compared to the Sec. 50.46a acceptance criteria
instead of allowing the risk to be partitioned and individually
compared to the acceptance criteria will ensure that the total risk
increase of all changes, as they are implemented over time, would not
constitute more than a small increase in risk. Current staff practice,
consistent with RG 1.174, is to compare the cumulative risk increase
from all related changes, and only related changes, to the acceptance
guidelines. Regulatory Guide 1.174 also provides additional acceptance
guidelines that must be met before permitting unrelated plant changes
that might decrease risk to be combined (bundled) together with a group
of related changes in a change in risk estimate. Defining and tracking
related and bundled changes and separating out the cumulative impact on
risk of these changes from all other changes is a complex process. The
proposed rule would simplify this process by combining the cumulative
increase of all plant changes after adoption of the new rule consistent
with the Commission decision that all changes be evaluated using the
RISP assessment process. Under this proposal, there is no need to
differentiate between related and unrelated changes, and the total
cumulative change in risk is directly related to the change in the
overall CDF and LERF over time.
The Commission believes that including this requirement in the
proposed rule is required to ensure that risk tracking is performed by
all licensees and is a necessary element for ensuring that changes
which would be permitted by the revised ECCS analyses allowed under
Sec. 50.46a do not result in a greater change in risk than intended by
the Commission. Comparing the risk increase from each change to the
acceptance criteria independently of all previous changes would render
the use of the ``small'' criteria inadequate to monitor and control
increases in risk from a series of plant changes implemented over time.
Defining and tracking the cumulative risk impact of ``related'' changes
is complex and impracticable. Furthermore, licensees who approach the
acceptance criteria on risk increases may choose to implement other
plant changes that reduce risk in order to take advantage of further
changes that might otherwise increase risk above the criteria.
Comparing the total risk increase to the risk increase criteria will
support the Commission philosophy that, consistent with the principles
of risk-informed integrated decision making, licensees should have a
risk management philosophy in which risk insights are not just used to
systematically increase risk, but also to help reduce risk where
appropriate and where it is shown to be cost effective.
The Commission requests specific public comments on whether there
is an alternative to tracking the cumulative risk increase that is
sufficient to provide reasonable assurance of protection to public
health and safety and common defense and security. (See Section
III.J.12 of this supplementary information.)
The Commission also requests specific public comments on the
acceptability of combining Sec. 50.46a related and unrelated changes
to meet the risk acceptance criteria. (See Section III.J.11 of this
supplementary information.)
Section 50.46a(f)(2)(ii) requires tracking of all proposed plant
changes (i.e., changes to the facility, technical specifications, and
procedures), but would not require a licensee to include risk increases
caused by previous risk-informed changes that were implemented before
Sec. 50.46a was adopted. Conversely, licensees who adopt Sec. 50.46a,
will be required to include every risk increase caused by every
facility, technical specification, or procedure change. Consequently,
licensees who adopt Sec. 50.46a before implementing other risk-
informed applications, will effectively have a smaller risk increase
``available'' compared to licensees that have already incorporated some
risk-informed changes into their overall plant risk before adopting
Sec. 50.46a. The Commission does not consider this a safety issue but
requests specific public comment on whether this potential
inconsistency should be addressed and, if so, how? (See Section
III.J.14 of this supplementary information.)
d. Defense-in-depth.
Section 50.46a(f)(3)(i) would require that the RISP assessment
demonstrate that defense-in-depth is maintained. Defense-in-depth is an
element of the NRC's safety philosophy that employs successive measures
to prevent accidents or mitigate damage if a malfunction, accident, or
naturally caused event occurs at a nuclear facility. As conceived and
implemented by the NRC, defense-in-depth provides redundancy in
addition to a multiple-barrier approach against fission product
releases. Defense-in-depth continues to be an effective way to account
for uncertainties in equipment and human performance. The NRC has
determined that retention of adequate defense-in-depth must be assured
in all risk-informed regulatory activities. Upon implementation of
Sec. 50.46a, all changes to the facility, technical specifications,
and procedures will become risk-informed regulatory activities.
In RG 1.174, the NRC developed seven elements that should be
utilized in evaluating the level of defense-in-depth provided for
nuclear power plants in making risk-informed changes to the licensing
basis. Since the adoption of RG 1.174 in 1997, the Commission has had
eight years of experience in applying its guidance to a variety of
applications, as discussed above. On the basis of this experience, the
Commission believes that these elements have generally been effective
in either identifying licensee-proposed changes with unacceptable
reductions in defense-in-depth, or precluding submission of licensee-
initiated changes with unacceptable reductions in defense-in-depth.
Accordingly, proposed Sec. 50.46a(f)(3)(i)(A) through (C) would
incorporate three of the higher level defense-in-depth elements as
criteria that the Commission believes are generally applicable to all
proposed risk informed changes. They are:
(1) Preserving a reasonable balance among prevention of core
damage, prevention of containment failure (early and late), and
consequence mitigation;
(2) Preserving system redundancy, independence, and diversity
commensurate with the expected frequency and consequences of challenges
to structures, systems and components, and uncertainties; and
(3) Ensuring that the independence of barriers is not degraded.
Criterion 1 is intended to assure that licensees do not unduly rely
upon prevention for accident sequences. Demonstration of reasonable
balance requires that any increase in the probability of containment
failure (early and late) does not significantly increase the frequency
of a significant fission product release. Licensees must also retain a
level of mitigation to ensure that mitigation capabilities are
maintained for accident sequences that lead to relatively late
containment failure and result in late radiological releases to the
public. Plant changes, and in particular some changes enabled by the
new Sec. 50.46a, include a wide variety of containment related
changes, including some that may affect the frequency of late
containment failure without affecting either CDF or LERF. Thus, this
criterion explicitly includes consideration of the impact of a proposed
change on late containment failure.
The second criterion, which addresses redundancy, independence, and
[[Page 67612]]
diversity, refers to design principles that the Commission has
historically employed and that are proven concepts for maintaining
safety in the nuclear and other industries.
The third criterion, which requires that independence of barriers
is not degraded, is a fundamental aspect of defense-in-depth. As with
the second criterion, independence of barriers has long been used to
successfully ensure public health and safety.
The proposed rule states that demonstrating that a change satisfies
the above three criteria provides assurance, in part, that defense-in-
depth is maintained. The four remaining RG 1.174 elements of defense-
in-depth relate to over-reliance on programmatic activities, defenses
against common cause failures, defenses against human errors, and
compliance with the intent of the GDC in Appendix A to 10 CFR Part 50
are not included in the proposed rule. These criteria are relatively
specific and their applicability depends on the specific change under
consideration. Each of these remaining elements should be evaluated for
applicability to each change and, if applicable, the licensee should
include these effects in their integrated decision for the proposed
change.
e. Safety margins.
Proposed Sec. 50.46a(f)(3)(ii) would require that adequate safety
margins are retained to account for uncertainties. These uncertainties
include phenomenology, modeling, and how the plant was constructed or
is operated. The Commission's concern is that plant changes could
inappropriately reduce safety margins, resulting in an unacceptable
increase in risk or challenge to plant SSCs. This paragraph would
ensure that an adequate safety margin exists to account for these
uncertainties, such that there are no unacceptable results or
consequences (e.g., structural failure) if an acceptance criterion or
limit is exceeded.
f. Performance measuring programs.
Proposed Sec. 50.46a(f)(3)(iii) would require that adequate
performance measurement programs and feedback strategies are
implemented to ensure that the RISP assessment continues to reflect
actual plant design and operation. The RISP assessment includes the
risk assessment, maintenance of defense-in-depth, and adequate safety
margins. Results from implementation of monitoring and feedback
strategies can provide an early indication of unanticipated degradation
of performance of plant elements that may invalidate the demonstration
by the RISP assessment that the change satisfied all the change
criteria.
The section requires that the monitoring programs be designed to
detect degradation of SSCs before plant safety is compromised.
Permitting degradation to advance until plant safety could be
compromised would be inconsistent with the Commission's regulatory
responsibility of protecting public safety. The associated strategies
should ensure that relevant observations of the monitoring program are
fed back into the RISP assessment and result in timely corrective
actions as appropriate. Consistent with all risk informed activities,
the monitoring, feedback, and corrective action programs should target
resources and emphasis on SSCs at a level commensurate with their
safety significance.
The Commission expects that licensee will integrate the performance
measuring programs required by this section with existing programs for
monitoring equipment performance and other operating experience on
their site and throughout industry. In particular, monitoring that is
performed in conformance with the Maintenance Rule (Sec. 50.65) could
be used when the monitoring performed under the maintenance rule is
sufficient to meet the requirements in Sec. 50.46a(f)(3)(iii).
Licensees who have implemented previous risk-informed regulatory
actions have normally also been required to implement risk-informed
monitoring and feedback programs, particularly in the area of risk
assessment; for example, licensees who adopt Sec. 50.69 will need to
develop relatively extensive risk-informed monitoring and feedback
programs. These should be integrated into the proposed paragraph
(f)(3)(iii) performance measuring programs to the extent practicable.
2. Requirements for Risk Assessments
The proposed rule is based upon the regulatory premise that the
acceptability of licensee-initiated changes should be judged in a risk-
informed manner. Thus, risk assessment plays a key role in the
regulatory structure of the proposed rule. Various provisions of
proposed Sec. 50.46a require the licensee to submit risk information
for the purpose of demonstrating that one or more of the criteria in
the rule have been met. Inasmuch as PRA methodologies are generally
recognized as the best current approach for conducting risk assessments
suitable for making decisions in areas of potential safety
significance, Sec. 50.46a(f)(4) of the proposed rule requires that a
technically adequate PRA be used in demonstrating compliance with the
requirements of Sec. 50.46a that would affect the regulatory decision
in a substantive manner.
However, the Commission recognizes that non-quantitative PRA
assessment methodologies and approaches could also be used to
complement or supplement the quantitative aspects of a PRA, especially
where performance of a quantitative PRA methodology of the level needed
to support a particular decision is not technically justifiable because
the safety significance of the decision does not warrant the level of
technical sophistication inherent in a PRA. Accordingly, Sec.
50.46a(f)(5) is written to recognize that non-quantitative risk
assessment may be utilized.
Because risk information forms a key role in the agency's
decisionmaking under this proposed rule, the Commission has determined
that it would be prudent to establish in this rule minimum requirements
for PRAs and nonquantitative risk assessments to be used in
implementing the rule.\11\ Establishment of minimum requirements for
PRAs and other risk assessments would provide assurance that the
numerical and qualitative insights produced by the risk assessments are
adequate to support decisions in areas of potential safety
significance.
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\11\ These requirements are only intended to be used in
conjunction with the proposed rule, and are not intended to be
established as generic requirements applicable to other regulatory
applications at this time. Although these requirements are drawn
from RG 1.174, the Commission has not yet determined whether the
requirements should be adopted by rule for generic use outside of
Sec. 50.46a.
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a. Probabilistic Risk Assessment (PRA) requirements.
Proposed Sec. 50.46a(f)(4)(i) through (iv) would set forth the
four general attributes of an acceptable PRA for the purposes of this
proposed rule. Section 50.46a(f)(4)(i) would require that the PRA
address initiating events from internal and external sources, and for
all modes of operation including low power and shutdown, that would
affect the regulatory decision in a substantial manner. Plant risk is a
function of initiating events from both internal and external sources.
In addition, plant risk can vary significantly depending upon the
plant's operating mode. Studies (``Proposed Staff Plan for Low Power
and Shutdown Risk Analysis Research to Support Risk-informed Regulatory
Decision Making'', SECY-00-0007, January 12, 2000) have shown that
relatively high levels of risk can occur during low power and shutdown
modes. Failure to consider sources of risk from internal and external
events, or from
[[Page 67613]]
operating modes that the plant may be placed in, could result in an
inaccurate characterization of the level of risk associated with a
plant change. Therefore, initiating events from internal and external
sources and during all modes of operation must be considered by the
PRA, in order to ensure that the effect on risk from licensee-initiated
changes is adequately characterized in a manner sufficient to support a
technically defensible determination of the level of risk.
Proposed Sec. 50.46a(f)(4)(ii) would require that the PRA
calculates CDF and LERF inasmuch as this proposed rule would require
that these measures be compared against acceptance criteria established
in this proposed rule.
Proposed Sec. 50.46a(f)(4)(iii) states that the PRA must
reasonably represent the current configuration and operating practices
at the plant. A plant's risk may vary as a plant's configuration or its
procedures change. Failure to update the PRA based upon these
configuration or procedure changes may result in inaccurate or invalid
PRA results when analyzing a proposed change. Accordingly, to ensure
that estimates of CDF and LERF adequately reflect the facility for
which a decision must be made, the proposed rule would require that the
PRA address current plant configuration and operating practices.
Finally, Sec. 50.46a(f)(4)(iv) would require that the PRA have
``sufficient technical adequacy'' including consideration of
uncertainty, as well as a sufficient level of detail to provide
confidence that the total CDF and LERF, and changes in total CDF and
LERF adequately reflect the proposed change. The proposed rule would
require the PRA to consider uncertainty because the decision maker must
understand the limitations of the particular PRA that was performed to
ensure that the decision is robust and accommodates relevant
uncertainties. With respect to level of detail, failure to model the
plant (or relevant portion of the plant) at the appropriate level of
detail may result in calculated risk values that do not appropriately
capture the risk significance of the proposed change.
b. Requirements for risk assessments other than PRA.
Risk assessment need not always be performed using PRA. The
proposed rule explicitly recognizes the possibility of using risk
assessment methods other than PRA to demonstrate compliance with
various acceptance criteria in the rule. However, as with PRA
methodologies, the Commission believes that minimum quality
requirements for PRAs and risk assessments used by a licensee in
implementing the rule must be established in the rule. Accordingly,
Sec. 50.46a(f)(5) of the proposed rule would establish the minimum
requirement for risk assessment methodologies other than PRA. This
paragraph would require that the licensee demonstrate that any non-PRA
risk assessment methods used in demonstrating compliance with one or
more requirements of the proposed rule produce realistic results. The
Commission believes that this requirement would provide flexibility to
licensees to use the non-PRA risk methodology (or combination of
different methodologies) which produces results that are sufficient
upon which to base decisions that the various acceptance criteria in
the proposed rule have been met.
3. Operational Requirements
The Commission proposes five specific operational requirements that
would apply to licensees who are approved to implement Sec. 50.46a.
These requirements are set forth in Sec. 50.46a(d) and would remain in
effect until such time as the licensee permanently ceases operations by
submitting the decommissioning certifications required under Sec.
50.82(a). They are:
(1) Maintain ECCS model(s) and/or analysis method(s) meeting the
acceptance requirements of the rule,
(2) Do not exceed ECCS acceptance criteria under any allowed at-
power operating configuration and do not place the plant in any at-
power operating configuration not analyzed and shown to meet ECCS
acceptance criteria,
(3) Evaluate all changes to the facility, technical specifications,
or procedures as described in the FSAR, using the NRC-approved RISP
assessment process to demonstrate that the risk, defense-in-depth,
safety margin and performance-measurement criteria are satisfied,
(4) Implement adequate performance-measurement programs to ensure
that the RISP assessment process reflects actual plant design and
operation, and
(5) Periodically re-evaluate and update the risk assessments
required under Sec. 50.46a(f) to address changes to the plant,
operational practices, equipment performance, plant operational
experience, and PRA model, and revisions in analysis methods, model
scope, data, and modeling assumptions.
Each of the five operational requirements is discussed in detail
below.
a. Maintain ECCS model(s) and/or analysis method(s).
Section 50.46a(d)(1) and (d)(2) would require the licensee to
maintain the ECCS models and/or methods that are used to demonstrate
ECCS performance meets Section 50.46a(e). As stated above, the RISP
assessment process must be used for all changes made under Sec. 50.59
or Sec. 50.90. For changes made under Sec. 50.90, the licensee would
submit information demonstrating that the ECCS acceptance criteria in
Section 50.46a(e)(3) and (e)(4) are met for the change. For changes
made under Sec. 50.46a(f)(1), the licensee would need to assure that
any impact of the change upon the ECCS performance meets the
requirements of Sec. 50.59. Therefore, the proposed rule would require
the ECCS models and/or analysis methods to be maintained that meet the
requirements of Sec. 50.46a(e)(1) and (e)(2), to ensure that the
acceptance criteria in Sec. 50.46a(e)(3) and (e)(4) continue to be met
for the plant.
b. Do not place the plant in unanalyzed at-power operating
configurations.
The Commission would require in Sec. 50.46a(d)(2) that a facility
be provided with an ECCS designed so that its calculated cooling
performance conforms to the criteria in Sec. 50.46a(e)(4) for LOCAs
involving breaks larger than the TBS, up to and including a double-
ended rupture of the largest pipe in the RCS. For LOCAs involving
breaks larger than the TBS, the analyses performed will identify ECCS
components and trains (including sufficiently reliable non-safety
related systems) that are assumed to function in order to demonstrate
compliance with the acceptance criteria in paragraph 50.46a(e)(4). The
proposed rule would not require assumption of loss-of-offsite power or
a limiting single failure of the ECCS for the analyses performed to
show acceptance criteria in (e)(4) are met for breaks larger than TBS.
Thus, it is possible that a licensee's analysis may take credit for the
availability of the full complement of ECCS. To ensure that the
facility will continue to comply with the acceptance criteria under any
at-power operating configurations (allowed by the license), the
Commission will require both that the acceptance criteria not be
exceeded during any at-power condition that has been analyzed, and
further that the plant not be placed in any unanalyzed condition.
One circumstance where the ability to comply with the acceptance
criteria might be called into question would be if an ECCS train or
component was removed from service (such as for maintenance) while the
plant is in operation, where this would result in the available ECCS
trains or components
[[Page 67614]]
being less than that assumed in the licensee's analysis for LOCAs
involving breaks larger than the TBS. For this time period, the assumed
set of mitigation systems would not be available to respond should a
LOCA occur, and the acceptance criteria might not be satisfied. Thus,
the licensee would either have to be able to demonstrate that under
such conditions the acceptance criteria would not be exceeded, or not
place the facility in that configuration. To satisfy this requirement a
licensee might prepare analyses showing acceptable results with
expected complements of equipment that might be taken out of service or
could propose suitable technical specifications as part of its
application for the facility change that would restrict plant operation
to acceptable conditions.
Accordingly, in Sec. 50.46a(d)(2) of the proposed rule, the
Commission would require that the facility not operate in any at-power
configuration where the ECCS cooling performance available from
operable ECCS components has not been evaluated and found to be
sufficient to assure that the acceptance criteria in paragraph (e)(4)
will be met. The evaluation must be calculated in accordance with Sec.
50.46a(e)(2). Bounding analyses may be performed to reduce the number
of model calculations.
c. Evaluate all facility changes using the RISP assessment process.
Section 50.46a(d)(3) would require that, for licensees that use
Sec. 50.46a, the integrated, risk-informed change process should be
used for all changes made under Sec. 50.59 or Sec. 50.90. For changes
made under Sec. 50.90, the licensee would submit the information
required in Sec. 50.46a(f)(2), which would include information from
the RISP assessment performed for the change. The NRC would review the
change as described above. For changes made under Sec. 50.46a(f)(1),
which must also meet the requirements of Sec. 50.59, the licensee
would be required to evaluate the change using the NRC-approved RISP
assessment process and demonstrate that the acceptance criteria in
Sec. 50.46a(f) are met.
d. Implement adequate performance-measurement programs.
The Commission acknowledged the importance of monitoring and
feedback in risk-informed decisionmaking in RG 1.174, which identified
these as one of the five key principles of risk-informed changes to a
plant's licensing basis. These programs are important to ensure that
(1) the RISP assessment conducted to examine the impact of proposed
change(s) continues to reflect the actual design and operation of the
plant and (2) no adverse safety degradation occurs as a result of
facility, technical specification or procedure changes implemented
after a licensee adopts 10 CFR 50.46a as the licensing basis for its
facility. NRC experience with RG 1.174 has confirmed that monitoring
and feedback are necessary to provide confidence that new information
that could change the results of the assessment of proposed changes or
affect the acceptability of a previously acceptable change is collected
and incorporated into the assessments. Accordingly, the Commission
proposes that licensees be required to implement appropriate monitoring
and feedback programs. Paragraph (d)(4) would require the licensee to
implement performance monitoring programs capable of meeting the
acceptance criteria for such programs as described in paragraph
(f)(3)(iii).
Section 50.46a(f)(3)(iii)(A) through (C) would require that the
performance-measurement programs be designed to detect degradation in
SSCs, monitor the SSCs at a level commensurate with their safety
significance, and provide feedback of information to allow timely
corrective actions to be implemented before plant safety is
compromised. When successfully implemented, these programs would ensure
that the RISP assessment continues to reflect the risk, defense-in-
depth and safety margin attributes during the evaluation of proposed
changes, and will ensure that the conclusions that have been drawn from
the evaluation about previous changes remain valid.
e. Periodically re-evaluate and update risk assessments.
Key components of risk-informed regulation are the monitoring of
changes in plant risk and feedback to the risk assessment and/or plant
design activities and processes which are the subject of the risk
assessment. Proposed Sec. 50.46a(d)(5) would set forth the proposed
rule's requirements governing the periodic re-evaluation and updating
of licensee's risk assessments.\12\ This paragraph would mandate that a
licensee must, following implementation of a change to its facility,
technical specifications, or procedures after adopting Sec. 50.46a,
periodically reevaluate and update the risk assessments (both PRA and
non-PRA) required under Sec. 50.46a(f)(1) and (f)(2). In particular,
Sec. 50.46a(d)(5) specifies that the reevaluation and updating must
address changes in the risk assessments; revisions in analysis methods,
model scope, and modeling assumptions; and changes to the plant,
operational practices, equipment performance, and operational data. In
addition, the risk assessments may be updated to address, among other
things, known errors or limitations in the model, or new information.
Accordingly, it is necessary that the risk assessments be updated so
that the licensee (and the NRC) will have an accurate understanding of
risk at its facility, and that changes implemented since the licencee
adopted Sec. 50.46a continue to be acceptable from a safety and risk
standpoint (i.e., the facility design and operation continue to be
consistent with the assumptions of the risk assessments used to meet
the acceptance criteria in Sec. 50.46a(f)(1) or (f)(2)).
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\12\ Reporting requirements relevant to the PRA updating
required by this paragraph are set forth in Sec. 50.46a(g)(2) of
the proposed rule.
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The updated risk assessments must continue to meet the minimum
quality requirements in Sec. 50.46a(f)(4) and (f)(5) in order to
ensure that the updated risk assessments provide the requisite level of
quality deemed by the Commission to be the minimum necessary to support
reasoned decision making under the proposed rule.
The proposed rule would specify that the reevaluation and updating
be conducted ``periodically,'' but no less often than once every two
refueling outages. The Commission believes that this is an appropriate
period because the uncertainty of risk changes occurring during the two
refueling outage period is tolerable and unlikely to result in high
risk situations developing as a result of the implementation of plant
changes. The Commission's preliminary determination in this regard is
based upon the stringent acceptance criteria governing changes
initiated under Sec. 50.46a, as well as the existing deterministic
criteria in the substantive technical requirements in Part 50 and the
criteria utilized in determining the acceptability of plant changes,
e.g., Sec. Sec. 50.46a(f)(1) and 50.59. The updating period specified
in the proposed rule is also comparable to other NRC requirements
governing updating and reporting of safety information, e.g, Sec. Sec.
50.59, 50.71(e), as well as the current ASME consensus standard on PRA
quality.
With respect to feedback, Sec. 50.46a(d)(5) would require the
licensee to take ``appropriate action'' to ensure that all facility
design and operation continue to be consistent with the risk assessment
assumptions used to meet the acceptance criteria in Sec. 50.46a(f)(1)
or (f)(2). Such actions may include (but are not limited to)
improvements or corrections to the risk
[[Page 67615]]
analyses to demonstrate compliance, implementation of changes to offset
adverse changes in risk or defense in depth, or reversal of changes
previously made under the provisions of Sec. 50.46a(f). The Commission
believes that this requirement would provide appropriate flexibility to
the licensee to determine the actions necessary to ensure continued
compliance with the Sec. 50.46a(f) acceptance criteria, and is
consistent with the concept of performance-based regulation.
Finally, Sec. 50.46a(d)(5) would specify that the reevaluation and
updating of the risk assessments, and any changes to the facility,
technical specifications, or procedures necessary as a result of this
periodic reevaluation and updating, shall not be deemed backfitting.
The Commission regards the reevaluation and updating to be an inherent
part of the regulatory concept of the proposed rule. Hence, this
activity, and any licensee action necessary to ensure the continued
validity of the associated risk assessments are understood to be part
of the regulatory process under this rulemaking, and licensees who
voluntarily choose to implement Sec. 50.46a understand that the
regulatory process involves such updating, reevaluation, and possible
need for making changes to its facility, technical specifications, or
procedures.
E. Reporting Requirements
1. ECCS Aanalysis of Record and Reporting Requirements
Reporting requirements for the proposed Sec. 50.46a would be
patterned after the existing reporting requirements in Sec. 50.46.
Existing 10 CFR 50.46(a)(1) requires that a licensee demonstrate that
its ECCS is adequate to meet the acceptance criteria using an approved
evaluation model. The results obtained with the evaluation model are
often referred to as the ``analysis of record'' (AOR). This AOR is
documented in the licensee's FSAR and is also used to establish core
operating limits for each cycle according to the licensee's approved
reload methodology. Because changes (such as changes to the moderator
temperature coefficient and peaking factors) are made to the plant on a
cycle specific basis, deviations from the AOR PCT are permitted.
Existing requirements in 10 CFR 50.46(a)(3)(i) specify that the
licensee estimate the deviation in PCT from such changes (or error
corrections). The amount of deviation is calculated by summing the
absolute value of each of the individual changes. The licensee's
estimate must be accurate but is typically not evaluated by running the
accordingly revised evaluation model. Deviations greater than 50[deg]F
are deemed ``significant.'' The purpose of the 50[deg]F restriction is
to ensure that the evaluation model accurately reflects the plant
conditions, the methodology used by the licensee is that reviewed and
approved by the NRC, and the changes made to the plant or operation of
the plant do not appreciably change the ECCS response.
Existing 10 CFR 50.46(a)(3)(ii) requires the licensee to submit an
annual report of these estimated deviations to the NRC. When they are
``significant,'' the licensee is required to contact the NRC within 30
days to schedule a re-analysis or get approval for other actions that
may be needed to show compliance with Sec. 50.46 requirements. In
establishing the schedule, the NRC will consider the safety
significance of the deviation and the proximity of the AOR PCT to the
acceptance criterion of 2200 [deg]F. To ensure safety, existing 10 CFR
50.46(a)(3)(ii) also requires the licensee to algebraically sum the
estimated individual changes in PCT to ensure that the estimated PCT
does not exceed 2200 [deg]F. If this algebraic sum exceeds 2200 [deg]F,
or if the changes cause the licensee to not comply with any other
acceptance criteria specified in 10 CFR 50.46(b), the licensee must
take immediate action to comply with 10 CFR 50.46 and report the event
per 10 CFR 50.55(e), 50.72, and 50.73.
When 10 CFR 50.46 was first promulgated, the regulations focused
primarily on large break LOCAs (LBLOCAs). Cladding oxidation is a
function of both temperature and time at temperature. In LBLOCAs,
because of the short period of time at high temperature, oxidation can
be treated as a simple function of temperature and is not expected to
change if the calculated PCT does not change (as long as the time
period at high temperature does not change either). Therefore, the PCT
reporting requirement alone was adequate to control changes to ECCS
analyses.
However, under the proposed Sec. 50.46a, ECCS capability would be
focused on the more likely small break LOCAs where the fuel is subject
to high temperatures for longer periods of time. Because time at
temperature is just as important as temperature in determining
oxidation, cladding oxidation is expected to be the controlling factor
in many instances, not PCT. Thus, the Commission proposes to include an
additional reporting requirement in Sec. 50.46a. Licensees would
report model changes or errors whenever the change in the calculated
oxidation or the sum of the absolute values of the changes equals or
exceeds 0.4 percent oxidation. This would make the proposed Sec.
50.46a oxidation reporting requirement the same, on a percentage basis,
as the existing PCT change reporting requirement.
Under the proposed Sec. 50.46a, for each change to or error
discovered in an ECCS evaluation model or analysis method that affects
the calculated temperature or level of oxidation, the licensee would be
required to report the change or error and its estimated effect on the
limiting ECCS analysis to the Commission at least annually. If the
change or error is significant, the licensee would provide this report
within 30 days and include with the report a proposed schedule for
providing a re-analysis or taking other action to show compliance with
Sec. 50.46a requirements. For any changes or errors where calculated
results exceeded the approved regulatory limit, licensees would be
required to take immediate action to come back into compliance with the
acceptance criteria.
For breaks equal to or smaller than the TBS (consistent with the
existing requirements in Sec. 50.46), Sec. 50.46a(g)(1)(i) would
define a significant change as one in which the change in calculated
peak fuel temperature differs by more than 50 [deg]F from the peak fuel
temperature calculated by the last model or is an accumulation of
changes and errors such that the sum of the absolute magnitudes of the
respective temperature changes is greater than 50 [deg]F. For
oxidation, proposed Sec. 50.46a(g)(1)(i) would define a significant
change as when the change in the calculated oxidation, or the sum of
the absolute values of the changes in calculated oxidation equals or
exceeds 0.4 percent oxidation. For breaks larger than the TBS, Sec.
50.46a(g)(1)(ii) would define a significant change as one which results
in a significant reduction in the capability to meet the ECCS
acceptance criteria in Sec. 50.46a(e)(4). Guidance for determining
what would be considered a significant reduction will be provided in
the associated regulatory guide.
2. Risk Assessment Reporting Requirements
Proposed Sec. 50.46a(g)(2) sets forth reporting requirements with
respect to the PRA reevaluation and updating required by Sec.
50.46a(d)(5). When reevaluating and updating the PRA and non-PRA risk
assessments, Sec. 50.46a(g)(2) would require the licensee to report
changes to the NRC if they result in a significant reduction in the
capability to meet the requirements of Sec. 50.46a(f).
[[Page 67616]]
Changes would be reported to the NRC within 60 days of completion of
the PRA update, and would include a description of the PRA changes, as
well as an explanation of the reasons for the increase in CDF and/or
LERF. The 60 day period is twice the time allowed for reporting of
``significant'' errors and changes to an evaluation model under the
current Sec. 50.46. This period ensures sufficient time for the
licensee to complete its evaluation and explanation of the significance
of such changes, and determine the course of action necessary to
address adverse changes in risk, while not unduly delaying the report
to the NRC and thereby delaying NRC oversight. The Commission proposed
this reporting level to establish a threshold that avoids trivial
changes in the relevant calculated risk measures, but provides for NRC
awareness of changes that may warrant further oversight. In addition,
this paragraph would require that the licensee report include a
schedule for implementation of any corrective actions required under
Sec. 50.46a(d)(5) for failure to comply with the acceptance criteria
in Sec. 50.46a(f)(1) or (f)(2). The Commission believes it should be
informed of the licensee's implementation schedule so the NRC can
ensure that the licensee takes corrective action on a timely basis,
consistent with the safety significance of the change.
3. Minimal Risk Plant Change Reporting Requirement
In Sec. 50.46a(g)(3) the Commission is proposing to require
periodic reports by licensees who make ``minimal'' risk plant changes
pursuant to Sec. 50.46a(f)(1). This process is comparable in many
respects to the Sec. 50.59 process that requires similar reports. The
NRC would rely on these reports to identify unexpected numbers of
minimal risk changes which would provide for NRC awareness of changes
that, taken together, may result in a significant increase in risk.
An alternative would be to require that the cumulative risk
increases from minimal risk changes be tracked separately from the
cumulative risk increase from all changes, and be compared to another
quantitative criterion. In Section III.J.11 of this supplementary
information, the Commission seeks public comment about whether there
are less burdensome or more effective ways of ensuring that the
cumulative impact of an unbounded number of minimal risk changes
remains minimal. The Commission notes that other reporting requirements
(FSAR updates, ECCS model changes or PRA update results) exist. If
reporting of minimal risk changes is required, should reporting be
required every 24 months, every two refueling cycles (like the PRA
updating), or on a different frequency?
F. Documentation Requirements
The proposed rule contains several documentation requirements.
Proposed Sec. 50.46a(h) contains documentation requirements for
changes made to a facility and/or operating procedures. When making
plant changes under Sec. 50.46a(f), licensees would be required to
document the bases for concluding that the acceptance criteria in Sec.
50.46a(f)(1) or (f)(2) and (f)(3) are satisfied. Licensees would also
be required under Part II of Appendix K to this part to document the
bases of evaluation models used to perform ECCS calculations for break
sizes at or below the TBS. For ECCS analysis methods used for breaks
larger than the TBS, licensees would be required under Sec.
50.46a(e)(2) to maintain sufficient supporting justification, including
the methodology used, to demonstrate that the analytical technique
reasonably describes the behavior of the reactor system during LOCAs of
varying size from the TBS up to the double-ended rupture of the largest
reactor coolant pipe. This information would be reviewed during NRC
inspections and/or audits to ensure that the risk criteria in Sec.
50.46a(f) are satisfied and to determine whether the analysis methods
(including computer codes) used by licensees adequately demonstrate
ECCS performance such that the ECCS acceptance criteria in Sec.
50.46a(e) are met.
G. Submittal and Review of Applications Under Sec. 50.46a
1. Initial Application for Implementing Alternative Sec. 50.46a
Requirements
When a licensee first decides to comply with the optional Sec.
50.46a requirements, that licensee must submit an application under 10
CFR 50.90 for NRC review and approval of a license amendment request.
The initial application must contain the information required by Sec.
50.46a(c)(1)(i). This includes information required by Sec.
50.46a(e)(1) sufficient to allow the NRC to approve the licensee's
evaluation models \13\ for design-basis accident LOCAs equal to or
smaller than the TBS and a discussion of the method used for analyzing
LOCAs larger than the TBS. Analysis methods for LOCAs larger than the
TBS would be required to meet the criteria specified in Sec.
50.46a(e)(4), but the proposed rule would not require prior NRC review
and approval of these methods.
---------------------------------------------------------------------------
\13\ If a licensee wishes to continue to use an already approved
evaluation model meeting the requirements of Appendix K to 10 CFR
Part 50, the licensee should specify the approved model that will be
utilized.
---------------------------------------------------------------------------
Licensees must also submit the results of the ECCS analyses
performed for LOCAs up to and including the TBS and LOCAs larger than
the TBS showing compliance with the acceptance criteria in Sec.
50.46a(e)(3) and (e)(4). A licensee's initial change from its existing
ECCS analysis need not be reviewed by the licensee under the provisions
of 10 CFR 50.59. Because the proposed rule would require NRC review and
approval of the initial license amendment application for compliance
with the alternative Sec. 50.46a requirements, there is no purpose
served by also requiring licensees to perform a Sec. 50.59 evaluation,
since Sec. 50.59 is a process to determine the need for prior NRC
approval of a change to a facility or its procedures as described in
the FSAR. Once the new Sec. 50.46a evaluation models and initial ECCS
LOCA analyses have been approved for use, subsequent changes would be
controlled by the existing process in Sec. 50.59 (which provides
criteria for determining which changes are within the licensee's
authority) and the other requirements in Sec. 50.46a(h) for reporting
when changes to evaluation models and analysis methods (whether from
correction of errors or changes) is significant.
Proposed Sec. 50.46a(c)(1)(ii) would require the initial
application to also contain a description of the RISP assessment
process. The RISP assessment process would contain a description of the
licensee's PRA and non-PRA risk assessment methods and a description of
the methods and decisionmaking process used to show that proposed
facility changes comply with the defense-in-depth, safety margins, and
performance measurement criteria in proposed Sec. 50.46a(f)(3). The
RISP assessment process must also ensure that all future licensee
changes to the facility, technical specifications, and procedures as
described in the FSAR be evaluated by a RISP assessment which
demonstrates that the acceptance criteria in Sec. 50.46a(f) are met
and requires that changes made pursuant to Sec. 50.46a(f)(1) are also
evaluated under Sec. 50.59.
2. Subsequent Applications for Plant Changes Under Sec. 50.46a
Requirements
After NRC approval of a licensee's initial license amendment
application addressing ECCS analyses and RISP assessment processes,
licensees may submit individual license amendment
[[Page 67617]]
applications for plant changes which may not be made under Sec. 50.59
or Sec. 50.46a(f)(1). These individual license amendment applications
must contain:
a. The information required by Sec. 50.90,
b. Information from the RISP assessment demonstrating that the risk
criteria, defense-in-depth criteria, safety margins and performance
monitoring criteria in Sec. 50.46a(f)(2) and (f)(3) are met, and
c. Information demonstrating that the ECCS acceptance criteria in
Sec. 50.46a(e)(3) and (e)(4) are met.
After review of the individual plant change license amendment
application, the NRC may approve the change if it complies with the
above criteria and all other applicable NRC regulations, including
requirements for plant physical security. The NRC would evaluate
potential impacts of the proposed change on facility security to ensure
that the change does not significantly reduce the ``built-in
capability'' of the plant to resist security threats, thus ensuring
that the change is not inimical to the common defense and security and
provides adequate protection to public health and safety.
H. Potential Revisions Based on LOCA Frequency Reevaluations
The NRC plans to periodically evaluate LOCA frequency information.
Selection of the TBS was based on several factors including the generic
frequency estimates provided by the expert elicitation process. The NRC
recognizes that due to unforeseen factors (operating experience,
identified degradation or other plant changes), our estimation of LOCA
frequencies could change in the future. Although the margins in the TBS
as defined in the proposed rule are intended to preclude plant changes
as a result of minor changes in break frequency estimates, the NRC
believes it is important to include provisions in the rule so that if
LOCA frequencies significantly increase, appropriate actions would be
taken to protect public health and safety. If an increase in LOCA
frequency were sufficient to invalidate the basis for selecting the TBS
defined in the proposed rule, the NRC would undertake rulemaking (or
issue orders to specific licensees, if appropriate) to change the TBS.
In such a case, the backfit rule (10 CFR 50.109) would not apply.
Likewise, if future reevaluations of LOCA frequency invalidate the
bases for facility changes implemented by a licensee, that licensee
would be required to take appropriate action to reduce facility risk to
acceptable levels; either by reversing previous facility changes or by
making other changes to compensate for the increased risk. In these
cases, the backfit rule (10 CFR 50.109) would also not apply (see
further discussion in section XV).
I. Changes to General Design Criteria
In several instances, the proposed Sec. 50.46a rule is not
consistent with some of the GDC for nuclear power plants contained in
10 CFR Part 50, Appendix A. To eliminate inconsistencies between the
deterministic GDC and the risk-informed Sec. 50.46a, the NRC reviewed
all of the GDC and is proposing revisions to GDC 17, Electrical power
systems, GDC 35, Emergency core cooling, GDC 38, Containment heat
removal, GDC 41, Containment atmosphere cleanup, and GDC 44, Cooling
water systems. These GDC contain design requirements related to LOCAs,
and the definition of LOCA in 10 CFR Part 50 includes breaks larger
than the TBS up to and including the DEGB of the largest RCS pipe.
Under proposed Sec. 50.46a, breaks larger than the TBS would be beyond
design-basis accidents. As a consequence, these GDC would be modified
to allow certain LOCA-related Sec. 50.46a requirements for pipe breaks
larger than the TBS to differ from the design-basis accident
requirements in the GDC. These exceptions are needed because Sec.
50.46a analysis requirements for LOCAs larger than the TBS would not
require the assumption of a LOOP and a single failure, which are
required by each of these GDC. The likelihood of these large LOCAs is
judged to be low enough that the additional mitigation capability
currently afforded by the redundancy requirements in these GDC is not
necessary. The modifications made to each of the above GDC removes the
requirements for assuming a single failure and a LOOP in the assessment
of the ECCS capability to perform its intended safety function for
beyond design-basis loss of coolant accidents involving pipe breaks
larger than the TBS. However, assessment of the ECCS capability for
LOCAs involving pipe breaks up to and including the TBS is unchanged
from current requirements and must still assume both a single failure
and LOOP.
The NRC also reviewed GDC 50, Containment design basis. GDC 50
specifies, in part, that the reactor containment structure shall be
designed to accommodate, with sufficient margin, the calculated
pressure and temperature from any LOCA. It also lists several factors
that should be considered when determining the available margin. The
NRC has determined that these factors should also be considered when
determining the available margin for accommodating LOCAs larger than
the TBS. Under Sec. 50.46a, however, LOCAs larger than the TBS are not
design-basis accidents since they are highly unlikely. Nevertheless,
reactor containment designs should continue to consider beyond TBS
LOCAs, but the methods used to calculate containment temperatures and
pressures need not be as conservative as they are for design-basis
accidents. Thus, the NRC proposes to modify GDC 50 to specify that
under Sec. 50.46a, leak tight containment capability should be
maintained for ``realistically'' calculated temperatures and pressures
for LOCAs larger than the TBS.
Should licensees make plant modifications under Sec. 50.46a
resulting in containment pressures and temperatures that exceed the
current design values by a small amount, the NRC will evaluate the
acceptability of revised containment structural integrity criteria.
Criteria will be provided in a regulatory guide for containment
structural integrity that could be used with Sec. 50.46a. However, the
acceptability of containment pressures and temperatures exceeding
current values will also be evaluated for conformance with the LERF
acceptance criteria specified in Sec. 50.46a(f)(2) and the defense-in-
depth acceptance criteria in Sec. 50.46a(f)(3). The basis for allowing
revision to containment structural integrity criteria is that LOCAs
involving pipe breaks larger than the TBS are judged to be of very low
probability and are no longer considered to be design basis accidents.
The likelihood of LOCAs involving pipe breaks larger than the TBS is
judged to be low enough that the large margins currently required in
design basis accident assessments are not necessary. However, a
realistic assessment of containment structural capability for LOCAs
involving pipe breaks larger than the TBS (without consideration of a
loss-of-offsite-power and a single failure) is still required to
provide defense-in-depth for these low probability initiating events.
The inherent physical robustness of current reactor containments
contributes significantly to the ``built-in capability'' of the plant
to resist security threats. The Commission expects licensees not to
make design modifications to the containment under Sec. 50.46a that
would reduce its structural capability (based on realistically
calculated containment pressures and temperatures for breaks larger
than the TBS) to a level that would compromise plant security.
The NRC considered modifying GDC 4, Environmental and dynamic
effects
[[Page 67618]]
design bases, based on the TBS as defined in proposed Sec. 50.46a.
However, the NRC decided to leave this GDC unchanged for the following
reasons. GDC 4, as currently written, contains a provision whereby
licensees can exclude designing for dynamic effects associated with
piping ruptures from their plants' design bases based on the
probability of piping ruptures being extremely low. This provision of
the GDC has historically been implemented by the NRC's review and
approval of a leak-before-break (LBB) analysis (reference Standard
Review Plan Section 3.6.3). Approval of LBB technology for PWRs only
was based, in part, on fracture mechanics and the absence of any active
degradation mechanisms. This mechanistic rationale for not having to
address dynamic effects (i.e., defined and controlled loadings) is
still necessary to ensure that piping will not tear unexpectedly,
including piping larger than the TBS. Absent an approved LBB analysis
for piping larger than the TBS (for plants implementing Sec. 50.46a),
PWR licensees would still need to consider dynamic effects because
asymmetric blowdown loads could cause fuel rods to bow which could in
turn impede control rod insertion. In addition, excluding dynamic
effects from consideration for breaks larger than the TBS would permit
removal of pipe whip restraints and jet impingement barriers at BWRs.
Without pipe whip restraints and jet impingement barriers, a double-
ended rupture of the largest pipe in the RCS could result in loss of
more than one train of ECCS and could challenge the integrity of the
containment. Finally, the dynamic loads associated with a double-ended
rupture of the largest pipe in the RCS must be considered to preclude
subcompartment pressurization and structural failure of reinforced
concrete walls inside the containment that could affect multiple trains
in multiple systems. In sum, licensees that voluntarily adopt Sec.
50.46a must continue to comply with GDC 4 and evaluate the dynamic and
environmental effects of pipe breaks larger than the TBS, unless a
leak-before-break analysis has been approved by the NRC in accordance
with GDC 4. Analyses addressing GDC 4, including dynamic effects,
approved leak-before-break, and environmental effects, will continue to
be part of the design basis of the plant.
As stated in GDC 4, ``dynamic effects associated with postulated
pipe ruptures in nuclear power units may be excluded from the design
basis when analyses reviewed and approved by the Commission demonstrate
that the probability of fluid system piping ruptures is extremely low
under conditions consistent with the design basis for the piping.''
Without such an approved analysis, licensees would be required to
address the dynamic effects (including the effects of missiles, pipe
whipping, and discharging fluids) in their piping system design and
analysis. The Commission has not historically required licensees to
consider such dynamic effects in performing the ECCS analysis required
by Sec. 50.46, containment analysis required by GDC 16 and GDC 50, and
probabilistic risk assessments (PRAs). Dynamic effects have been
excluded from these analyses because of certain design features (e.g.,
pipe whip restraints, jet impingement barriers, ECCS train separation)
or because of the extremely low likelihood of a double-ended rupture of
the largest pipe in the RCS (i.e. leak-before-break analysis). This NRC
staff position will be maintained for licensees that voluntarily adopt
Sec. 50.46a. However, licensees who voluntarily adopt Sec. 50.46a
need to consider environmental and dynamic effects in these analyses
where non-safety related equipment is credited for mitigating breaks
larger than the TBS.
J. Specific Topics Identified for Public Comment
The NRC seeks specific public comments on numerous questions and
issues. All specific topics for comment are identified in this section,
but some have been discussed elsewhere in this supplementary
information.
1. In proposed Sec. 50.46a(b), the Commission specifically
precluded the application of the Sec. 50.46a alternative requirements
to future reactors. However, future light water reactors might benefit
from Sec. 50.46a. The Commission requests specific public comments
regarding whether Sec. 50.46a should be made available to future light
water reactors.
2. The TBS specified by the NRC in the proposed rule does not
include an adjustment to address the effects of seismically-induced
LOCAs. NRC is currently performing work to obtain better estimates of
the likelihood of seismically-induced LOCAs larger than the TBS. By
limiting the extent of degradation of reactor coolant system piping,
the likelihood of seismically-induced LOCAs may not affect the basis
for selecting the proposed TBS. However, if the results of the ongoing
work indicate that seismic events could have a significant effect on
overall LOCA frequencies, the NRC may need to develop a new TBS. To
facilitate public comment on this issue, a report from this evaluation
will be posted on the NRC rulemaking Web site at http://ruleforum.llnl.gov before the end of the comment period. In December
2005, stakeholders should periodically check the NRC rulemaking web
site for this information. The NRC requests specific public comments on
the effects of pipe degradation on seismically-induced LOCA frequencies
and the potential for affecting the selection of the TBS. The NRC also
requests public comments on the results of the NRC evaluation that will
be made available during the comment period. (See Section III.B.3 of
this supplementary information.)
3. Depending on the outcome of an ongoing NRC study (see Section
III.B.3 of this supplementary information), the final rule could
include requirements for licensees to perform plant-specific
assessments of seismically-induced pipe breaks. These assessments would
need to consider piping degradation that would not be prejudiced by
implementation of the licensee's inspection and repair programs. The
assessments would have to demonstrate that reactor coolant system
piping will withstand earthquakes such that the seismic contribution to
the overall frequency of pipe breaks larger than the TBS is
insignificant. The NRC requests specific public comments on this and
any other potential options and approaches to address this issue.
4. The ACRS noted that ``a better quantitative understanding of the
possible benefits of a smaller break size is needed before finalizing
the selection of the transition break size.'' The TBS to be included in
the final rule should be selected to maximize the potential safety
improvements. Thus, the NRC is soliciting comments on the relationship
between the size of the TBS and potential safety improvements that
might be made possible by reducing the maximum design-basis accident
break size.
5. The proposed Sec. 50.46a includes an integrated, risk-informed
change process to allow for changes to the facility following
reanalysis of beyond design basis LOCAs larger than the TBS. However,
the current regulations in 10 CFR Part 50 already have requirements
addressing changes to the facility (Sec. 50.59 and Sec. 50.90). It
might be more efficient to include the integrated, risk-informed change
(RISP) requirements, for plants that use Sec. 50.46a, under these
existing change processes. The Commission solicits specific public
comments on whether to revise existing Sec. Sec. 50.59 and 50.90 to
accommodate the requirements for making plant changes under Sec.
50.46a.
[[Page 67619]]
6. The proposed Sec. 50.46a rule would rely on risk information.
The NRC has included specifically applicable PRA quality and scope
requirements in the proposed rule. However, there are other NRC
regulations that also rely on risk information (e.g. Sec. 50.65
maintenance rule and Sec. 50.69 alternative special treatment
requirements). Consistent with the Commission policy on a phased
approach to PRA quality, it might be more efficient and effective to
describe PRA requirements (e.g., contents, scope, reporting, changes,
etc.), in one location in the regulations so that the PRA requirements
would be consistent among all regulations. The NRC is seeking specific
public comments on whether it would be better to consolidate all PRA
requirements into a single location in the regulations so that they
were consistent for all applications or to locate them separately with
the specific regulatory applications that they support.
7. The proposed Sec. 50.46a rule would include the requirement
that all allowable at-power operating configurations be included in the
analysis of LOCAs larger than the TBS and demonstrated to meet the ECCS
acceptance criteria. Historically, operational restrictions have not
been contained in Sec. 50.46 but were controlled through other
requirements (e.g., technical specifications and maintenance rule
requirements). It might be more practical to control the availability
of equipment credited in the beyond design-basis LOCA analyses in a
manner more consistent with other operational restrictions. As a
result, the NRC is soliciting public comments on the most effective
means for implementing appropriate operational restrictions and
controlling equipment availability to ensure that ECCS acceptance
criteria are continually met for beyond design-basis LOCAs.
8. Given the Commission's intent (See SRM for SECY-04-0037) that
plant changes made possible by this rule should be constrained in areas
where the current design requirements ``contribute significantly to the
`built-in capability' of the plant to resist security threats,'' the
Commission seeks examples on either side of this threshold (plant
changes allowed vs. changes prohibited), and additionally any examples
of changes made possible by Sec. 50.46a that could enhance plant
security and defense against radiological sabotage or attack. (See
Section III.G.2 of this supplementary information.) The Commission also
solicits comments on whether the Sec. 50.46a rule should explicitly
include a requirement to maintain plant security when making changes
under Sec. 50.46a or otherwise rely on a separate rulemaking now being
considered by the NRC to more globally address safety and security
requirements when making plant changes under Sec. Sec. 50.59 and
50.90. Any examples of plant changes that involve Safeguards
Information should be marked and submitted using the appropriate
procedures.
9. Given the potential impact to the licensee (since the backfit
rule would not apply) of the NRC's periodic re-evaluation of estimated
LOCA frequencies which could cause the NRC to increase the TBS, should
the rule require licensees to maintain the capability to bring the
plant into compliance with an increased transition break size (TBS),
within a reasonable period of time?
10. Is the proposed rule sufficiently clear as to be
``inspectable?'' That is, does the rule language lend itself to timely
and objective NRC conclusions regarding whether or not a licensee is in
compliance with the rule, given all the facts? In particular, are the
proposed requirements for PRA quality sufficient in this regard?
11. The proposed Sec. 50.46a rule would impose no limitations on
``bundling'' of different facility changes together in a single
application. Changes which would increase plant risk substantially or
create risk outliers could be grouped with other plant changes which
would reduce risk so that the net change would meet the risk acceptance
criteria. Are the net change in risk acceptance criteria in the
proposed rule adequate or should some additional limitations be imposed
to avoid allowing facility changes which are known to increase plant
risk?
12. Is there an alternative to tracking the cumulative risk
increases associated with plant changes made after implementing Sec.
50.46a that is sufficient to provide reasonable assurance of protection
to public health and safety and common defense and security? (See
Section III.D.1 of this supplementary information.)
13. The Commission requests specific public comments on the
acceptability of applying the change in risk acceptance guidelines in
RG 1.174 to the total cumulative change in risk from all changes in the
plant after adoption of Sec. 50.46a. Should other risk guidelines be
used and, if so, what guidelines should be used? (See Section III.D.1.c
of this supplementary information.)
14. After approval to implement Sec. 50.46a, the proposed rule
would require tracking risk associated with all proposed plant changes
but would not require a licensee to include risk increases caused by
previous risk-informed changes that were implemented before Sec.
50.46a was adopted. Licensees who adopt Sec. 50.46a before
implementing other risk-informed applications will have a smaller risk
increase ``available'' compared to licensees who have already
incorporated some risk-informed changes into their overall plant risk
before adopting Sec. 50.46a. The Commission does not consider this a
safety issue but requests specific public comments on whether this
potential inconsistency should be addressed and, if so, how? (See
Section III.D.1 of this supplementary information.)
15. The proposed Sec. 50.46a would require licensees to report
every 24 months all ``minimal'' risk facility changes made under Sec.
50.46a(f)(1) without NRC review. Are there less burdensome or more
effective ways of ensuring that the cumulative impact of an unbounded
number of ``minimal'' changes remains inconsequential? (See Section
III.E.3 of this supplementary information.)
16. Should the Sec. 50.46a rule itself include high-level criteria
and requirements for the risk evaluation process and acceptance
criteria described in Reg Guide 1.174, as is currently proposed? If
these criteria were included in the regulatory guide only, and not in
the rule, how could the NRC take enforcement action for licensees who
failed to meet the acceptance criteria?
IV. Public Meeting During Development of Proposed Rule
The NRC first prepared a ``conceptual basis'' document and draft
rule language indicating the rulemaking approach that was being
considered. This conceptual basis was made public on the NRC website on
August 2, 2004 (69 FR 46110). The NRC then held a public meeting on
August 17, 2004, to inform stakeholders of the rule concept and early
draft rule language and to solicit industry stakeholder information
about possible plant design changes made possible by the draft rule and
their associated costs and benefits. Comments received from
stakeholders during the August public meeting are discussed below.
Industry stakeholders asked the NRC to clarify the rule
requirements in several areas to allow them to assess the potential
costs and benefits of the proposed rule. The NRC has clarified the
proposed rule by describing in more detail how the single failure
criterion would be applied to ECCS analysis and to other required
analyses for pipe breaks larger than the TBS.
[[Page 67620]]
Industry stakeholders stated that several GDC other than GDC 35 on
ECCS would need to be modified to be consistent with the alternative
ECCS requirements in 10 CFR 50.46a. The NRC agrees with this comment
and has proposed additional changes to GDC 17, Electrical power
systems, GDC 38, Containment heat removal, GDC 41, Containment
atmosphere cleanup, GDC 44, Cooling water systems and GDC 50,
Containment design basis.
Industry stakeholders asked the NRC (1) to define a threshold for
Sec. 50.46a plant changes below which license amendments would not be
required, and (2) if the NRC could review and approve a licensee's PRA
and process and then allow licensees to make plant changes without
further NRC review. The NRC has added language in the proposed rule
which allows a licensee to submit a PRA and a plant change evaluation
(RISP assessment) process to the NRC for approval. After NRC approval
is granted, licensees can make certain plant changes that do not exceed
a ``minimal risk'' threshold without further NRC review or approval.
Industry stakeholders asked the NRC to address how Sec. 50.46a could
be used to increase plant operational flexibility without changing
facility design. The NRC intends for licensees to make plant
operational changes under Sec. 50.46a using the same processes used to
make facility design changes. As noted above, after NRC approval of a
licensee's RISP assessment process, licensees are free to make plant
operational changes that satisfy the minimal risk change criteria. Any
operational changes that do not qualify as minimal risk changes or
involve changes to the technical specifications or the license must be
submitted to the NRC for review and approval as license amendments.
Industry stakeholders asked if the NRC could reduce the ECCS
analytical burden associated with Sec. 50.46a by reducing the number
of required analyses or eliminating the need for or reducing the extent
of required NRC reviews. The NRC has reviewed the analytical
requirements incumbent upon licensees who adopt the 10 CFR 50.46a
alternative requirements. In this case, the NRC modified its analysis
requirements to be less prescriptive, affording licensees flexibility
in demonstrating that the ECCS can successfully mitigate LOCAs up to
and including the double-ended rupture of the largest pipe in the RCS.
Analysis, documentation and code review requirements are reduced
commensurate with the lower likelihood of the larger breaks. Submittal
of detailed documentation of licensees' analysis methods used for
breaks larger than the TBS is not required, nor is formal NRC approval
of analysis methods. The NRC will explicitly define its expectations in
the regulatory guide before the final rule is promulgated.
Industry stakeholders asked the NRC to explain its position on the
effects of increasing plant power levels on the expert elicitation
process for estimating pipe break frequency. The expert elicitation
process did not consider potential increases in power. Nevertheless, in
determining the TBS, the NRC increased the break size resulting from
the expert elicitation process to account for several types of known
uncertainties while still maintaining margin for unanticipated
uncertainties. These uncertainties are discussed in Section III.B of
this supplementary information. While the NRC believes that the
proposed rule adequately accounts for modest increases in power,
significant power uprates may change plant performance and relevant
operating characteristics (e.g., temperature, environment, flow rate,
etc.) to a degree which could significantly impact LOCA frequencies.
For example, higher temperatures could increase the likelihood of
stress corrosion cracking and higher flow rates could increase flow-
induced vibration which might accelerate the growth of any pre-existing
cracks in the piping. In reviewing applications for power uprates for
licensees who comply with Sec. 50.46a, the NRC would determine whether
the information provided by the licensee is adequate to ensure that
frequencies of LOCAs larger than the TBS are not significantly affected
and that adequate performance monitoring programs were implemented
under Sec. 50.46a(f)(3)(iii). These performance measurement programs
would be required to monitor SSCs commensurate with their safety
significance, detect degradation of SSCs before plant safety was
compromised, and provide feedback to ensure timely corrective actions.
In the longer term, the NRC would continue to assess the precursors
that might indicate an increase in pipe break frequencies in plants
operating under power uprate conditions to establish whether the TBS
would need to be adjusted.
V. Section-by-Section Analysis of Substantive Changes
A. Section 50.34 Contents of Application; Technical Information
Paragraph (a)(4) of this section would clarify that Sec. 50.46a is
applicable to reactors whose construction permits were issued before
the effective date of the rule and that preliminary safety analysis
reports (PSARs) for facilities whose construction permits are issued
after the effective date of this rule and design approvals and design
certifications issued after the effective date of this rule are not
allowed to use Sec. 50.46a.
B. Section 50.46 Acceptance Criteria for Emergency Core Cooling Systems
for Light-Water Nuclear Power Plants
This section would be modified to allow the optional use of a new
Sec. 50.46a containing alternative, risk-informed requirements for
emergency core cooling systems for reactors whose operating licenses
were issued before the effective date of the rule change.
C. Section 50.46a Alternative Acceptance Criteria for Emergency Core
Cooling Systems for Light-Water Reactors
Paragraph (a) would provide definitions for terms used in other
parts of this section. Two of the definitions, loss-of-coolant
accidents and evaluation model, are based on the existing definitions
used in Sec. 50.46 but have been modified to indicate that pipe breaks
larger than the TBS are beyond design-basis accidents. The two new
definitions are: (1) Transition break size, which is used to
distinguish between requirements applicable to pipe breaks at or below
this size from those applicable to pipe breaks above this size; and (2)
operating configuration, which is used in Sec. 50.46a(d)(2) to specify
plant equipment availability conditions that must be analyzed for
conformance with acceptance criteria.
Paragraph (b) would provide the applicability and scope of the
requirements of this section. Proposed Sec. 50.46a would apply only to
the current fleet of licensed light-water nuclear power reactors
(licensed before the effective date of the rule). Its requirements
would be in addition to any other requirements applicable to ECCS set
forth in 10 CFR 50, with the exception of Sec. 50.46.
Paragraph (c) would specify the contents of and acceptance criteria
for initial licensee applications for implementing the alternative ECCS
requirements in Sec. 50.46a. Paragraph (c)(1)(i) requires that an
application contain specific information about the ECCS models and
analysis methods to be used by a licensee. Paragraph (c)(1)(ii)
requires a description of the RISP assessment process, including (A) a
description of the PRA model and other risk assessment methods
demonstrating compliance with the risk
[[Page 67621]]
assessment quality requirements in Sec. 50.46a(f)(4) & (f)(5) and (B)
a description of the methods and decisionmaking process to be used to
show compliance with the risk, defense in depth, safety margins and
performance measurement criteria specified in Sec. 50.46a(f)(1),
(f)(2) and (f)(3). Paragraph (c)(2) would specify that the acceptance
criteria that must be met by a licensee before the NRC may approve an
application to comply with Sec. 50.46a. Paragraph (c)(2)(i) would
specify the ECCS acceptance criteria; paragraph (c)(2)(ii) would
require that the RISP assessment processes meets the requirements in
Sec. 50.46a(f); and paragraph (c)(2)(iii) would require that the RISP
process ensures that plant changes made without NRC review pursuant to
Sec. 50.46a(f)(1) are also permitted under Sec. 50.59.
Paragraph (d) would specify the requirements with which licensees
approved by the NRC to utilize Sec. 50.46a must comply throughout the
operating lifetime of the facility. In paragraph (d)(1), licensees
would be required to maintain ECCS evaluation models and analysis
methods meeting the requirements in Sec. 50.46a(e)(1) & (e)(2). In
paragraph (d)(2), licensees would be required to control plant
operation to ensure that for LOCAs larger than the TBS, the ECCS
acceptance criteria in Sec. 50.46a(e)(4) would not be exceeded under
any allowed at-power operating configuration. In paragraph (d)(3),
licensees would be required to ensure that changes to the facility,
technical specifications, or procedures are evaluated by an NRC-
approved RISP which demonstrates that acceptance criteria in Sec.
50.46a(f) are met. In paragraph (d)(4), licensees would be required to
implement a performance-measurement program meeting the requirements in
Sec. 50.46a(f)(3)(iii) so that the RISP assessment process reflects
actual plant design and operation. In paragraph (d)(5), licensees would
be required to update risk assessments to address plant changes and
conditions no less often than once every 2 refueling outages. Risk
assessments would be required to continue to meet the quality
requirements in Sec. 50.46a(f)(4) and (f)(5). Licensees would be
required to take action to ensure that facility design and operation
continue to be consistent with the risk assessment assumptions used to
meet the acceptance criteria in (f)(1) or (f)(2). Any necessary changes
to facility caused by updating risk assessments would not be deemed
backfitting.
Paragraph (e) would provide the ECCS evaluation requirements and
acceptance criteria for the two LOCA break size regions. Paragraph
(e)(1) would specify methods for evaluating ECCS cooling performance
for breaks at or below the TBS. These requirements are the same as the
current requirements for LOCA analyses in existing Sec. 50.46.
Paragraph (e)(2) would specify methods for evaluating ECCS cooling
performance for breaks larger than the TBS. ECCS cooling performance
for LOCA breaks larger than the TBS may be analyzed by realistic
methods. Paragraph (e)(3) would provide ECCS acceptance criteria for
LOCAs up to and including the TBS. The criteria specified would be
equivalent to the current requirements in Sec. 50.46 (e.g., 2200
[deg]F PCT and 17 percent fuel cladding oxidation). Paragraph (e)(4)
would provide ECCS acceptance criteria for LOCAs larger than the TBS.
These acceptance criteria would be based on coolable geometry and long
term cooling and are less prescriptive than the criteria presently used
for LOCA analysis. Paragraph (e)(5) would provide that the Director of
the Office of Nuclear Reactor Regulation may impose restrictions on
reactor operation if ECCS requirements are not met. This paragraph
would be added to be consistent with existing Sec. 50.46 which also
contains this requirement.
Paragraph (f) would provide requirements for implementing changes
to the facility, technical specifications, and procedures under Sec.
50.46a.
Paragraph (f)(1) would specify that licensees may make changes
without NRC approval if (i) the changes are permitted under Sec. 50.59
and (ii) a RISP assessment has been performed which demonstrates that
any possible increases in risk are minimal and that the criteria in
paragraph (f)(3) are met.
Paragraph (f)(2) would state that for plant changes not permitted
under paragraph (f)(1), licensees must submit an application for a
license amendment containing: (i) the information required by Sec.
50.90; (ii) information from the RISP assessment demonstrating that any
increases in CDF and LERF are small, overall plant risk is small, and
that the criteria in paragraph (f)(3) are met; and (iii) information
demonstrating that the ECCS acceptance criteria in Sec. 50.46a(e)(3)
and (e)(4) are met.
Paragraph (f)(3) would specify requirements for all plant changes.
Paragraph (f)(3)(i) would require that defense-in-depth is maintained,
in part, by assuring that: (A) Reasonable balance is provided among
prevention of core damage, containment failure (early and late), and
consequence mitigation; (B) system redundancy, independence, and
diversity is commensurate with expected frequency of accidents,
consequences of those accidents, and uncertainties; and (C)
independence of barriers is not degraded. Paragraph (f)(3)(ii) would
require that (ii) adequate safety margins are maintained. Paragraph
(f)(3)(iii) would require that adequate performance-measurement
programs will be implemented that: (A) Detect degradation before plant
safety is compromised, (B) provide feedback of information and timely
corrective actions, and (C) monitor SSCs commensurate with their safety
significance.
Paragraph (f)(4) would provide the quality and scope requirements
for risk assessments using PRA. Paragraph (f)(4)(i) would require that
the PRA address internal and external events and all plant operating
modes that would affect a regulatory decision. Paragraph (f)(4)(ii)
would require that the PRA calculate both CDF and LERF. Paragraph
(f)(4)(iii) would require that the PRA reasonably represent the current
plant configuration and operating practices. Paragraph (f)(4)(iv) would
require the PRA to have sufficient technical adequacy and level of
detail to be confident that calculated CDF and LERF reflects the actual
plant risk.
Paragraph (f)(5) would require licensees using risk assessment
methods other than PRA to justify that the methods used produce
realistic results.
Paragraph (g) would provide the requirements for making reports to
the NRC. Paragraph (g)(1) would require reporting of all errors or
changes to ECCS analyses at least annually as specified in Sec. 50.4.
For significant changes or errors, licensees would be required to
report within 30 days including a schedule for reanalysis or other
action as needed to show compliance with ECCS requirements. Under
paragraph (g)(1)(i), for LOCAs involving pipe breaks equal to or
smaller than the TBS, significant changes would be defined as a change
in peak cladding temperature of greater than 50 [deg]F or a change in
calculated cladding oxidation that equals or exceeds 0.4 percent
oxidation. Under paragraph (g)(1)(ii), for LOCAs involving pipe breaks
larger than the TBS, a significant change would be defined as one
resulting in a significant reduction in the capability to meet the ECCS
acceptance criteria in Sec. 50.46a(e)(4). Paragraph (g)(2) would
contain reporting requirements for errors or changes to PRA analyses.
Errors or changes that result in a significant reduction in the
capability to meet the requirements in Sec. 50.46a(f) would be
reported within 60 days of completing a PRA update. Paragraph (g)(3)
would contain reporting requirements for plant changes made under Sec.
50.46a(f)(1) involving minimal risk. A short
[[Page 67622]]
description of these changes would be reported every 24 months.
Paragraph (h) would provide documentation requirements for plant
changes. For all plant changes made under Sec. 50.46a(f), licensees
would be required to document the bases for meeting the acceptance
criteria in Sec. 50.46a(f)(1) or (f)(2) and (f)(3). These plant
changes would also be required to be reflected in updates to the
licensee's FSAR.
Paragraphs (i) through (l) would be reserved for future use.
Paragraph (m) would provide that changes made by the NRC to the TBS
and all changes required to return the plant to compliance with the
acceptance criteria after a change in the TBS are not deemed to be
backfitting under 10 CFR 50.109.
D. Section 50.46a Acceptance Criteria for Reactor Coolant System
Venting Systems
This section would be redesignated as Sec. 50.46b.
E. Section 50.109 Backfitting
This section would be modified to provide that changes made by the
NRC to the TBS and changes made by licensees to continue to comply with
are not deemed to be backfitting under 10 CFR 50.109.
F. Appendix A to Part 50--General Design Criteria for Nuclear Power
Plants
Five of the general design criteria contained in Appendix A would
be modified to remove the requirement to assume a single failure and a
loss-of-offsite power in the systems subject to these criteria for pipe
breaks larger than the TBS up to and including the DEGB of the largest
RCS pipe for those plants implementing Sec. 50.46a. The specific
criteria are: GDC 17, Electrical power systems, GDC 35, Emergency core
cooling, GDC 38, Containment heat removal, GDC 41, Containment
atmosphere cleanup, and GDC 44, Cooling water systems. General Design
Criterion 50, Containment design basis, would also be modified to
specify that for plants under Sec. 50.46a, leak tight containment
capability should maintained for ``realistically'' calculated
temperatures and pressures for LOCAs larger than the TBS.
VI. Criminal Penalties
For the purposes of Section 223 of the Atomic Energy Act (AEA), as
amended, the Commission is issuing the proposed rule to amend Sec.
50.46, add Sec. 50.46a and redesignate existing Sec. 50.46a and Sec.
50.46b under one or more of sections 161b, 161i, or 161o of the AEA.
Willful violations of the rule would be subject to criminal
enforcement. Criminal penalties, as they apply to regulations in Part
50 are discussed in Sec. 50.111.
VII. Compatibility of Agreement State Regulations
Under the ``Policy Statement on Adequacy and Compatibility of
Agreement States Programs,'' approved by the Commission on June 20,
1997, and published in the Federal Register (62 FR 46517, September 3,
1997), this rule is classified as compatibility ``NRC.'' Compatibility
is not required for Category ``NRC'' regulations. The NRC program
elements in this category are those that relate directly to areas of
regulation reserved to the NRC by the AEA or the provisions of Title 10
of the Code of Federal Regulations, and although an Agreement State may
not adopt program elements reserved to NRC, it may wish to inform its
licensees of certain requirements via a mechanism that is consistent
with the particular State's administrative procedure laws, but does not
confer regulatory authority on the State.
VIII. Availability of Documents
The NRC is making the documents identified below available to
interested persons through one or more of the following methods as
indicated.
Public Document Room (PDR). The NRC Public Document Room is located
at 11555 Rockville Pike, Rockville, Maryland.
Rulemaking Website (Web). The NRC's interactive rulemaking Website
is located at http://ruleforum.llnl.gov. These documents may be viewed
and downloaded electronically via this Web site.
NRC's Public Electronic Reading Room (PERR). The NRC's public
electronic reading room is located at www.nrc.gov/reading-rm.html.
----------------------------------------------------------------------------------------------------------------
Document PDR Web PERR
----------------------------------------------------------------------------------------------------------------
Conceptual basis and draft rule................ X X ML042160503
WOG comment letter............................. X .......... ML042680079
NEI comment letter............................. X .......... ML042680080
BWROG comment letter........................... X .......... ML042680077
SRM of March 31, 2003.......................... X X ML030910476
SECY-02-0057................................... X X ML020660607
SECY-98-300.................................... X X ML992870048
SECY-04-0037................................... X X ML040490133
SRM of July 1, 2004............................ X X ML041830412
RG 1.174....................................... X X ML023240437
Petition for Rulemaking 50-75.................. X X ML020630082
SECY-04-0060................................... X X ML040860129
NUREG-0933..................................... X X ML042540049
Regulatory Analysis............................ X .......... ML052870368
SECY-05-0052................................... X X ML050480155
SRM of July 29, 2005........................... X X ML052100416
NUREG 1829..................................... X X ML052010464
----------------------------------------------------------------------------------------------------------------
IX. Plain Language
The Presidential memorandum dated June 1, 1998, entitled ``Plain
Language in Government Writing'' directed that the Government's writing
be in plain language. This memorandum was published on June 10, 1998
(63 FR 31883). The NRC requests comments on the proposed rule
specifically with respect to the clarity and reflectiveness of the
language used. Comments should be sent to the address listed under the
ADDRESSES caption of the preamble.
X. Voluntary Consensus Standards
The National Technology Transfer and Advancement Act of 1995, Pub.
L. 104-113, requires that Federal agencies use technical standards that
are developed or adopted by voluntary consensus standards bodies unless
using such a standard is inconsistent
[[Page 67623]]
with applicable law or is otherwise impractical. In this proposed rule,
the NRC proposes to use the following Government-unique standard: 10
CFR 50.46a. The Commission notes the development of voluntary consensus
standards on PRAs, such as an ASME Standard on Probabilistic Risk
Assessment for Nuclear Power Plant Applications. The government
standards would allow the use of voluntary consensus standards, but
would not require their use. The Commission does not believe that these
other standards are sufficient to specify the necessary requirements
for licensees who wish to modify plant ECCS analysis methods and
nuclear power reactor designs based on the results of probabilistic
risk analysis. The NRC is not aware of any voluntary consensus standard
addressing risk-informed ECCS design and consequent changes in a light-
water power reactor facility, technical specifications, or procedures
that could be used instead of the proposed Government-unique standard.
The NRC will consider using a voluntary consensus standard if an
appropriate standard is identified. If a voluntary consensus standard
is identified for consideration, the submittal should explain how the
voluntary consensus standard is comparable and why it should be used
instead of the proposed Government-unique standard.
XI. Finding of No Significant Environmental Impact: Environmental
Assessment
The Commission has determined under the National Environmental
Policy Act of 1969, as amended, and the Commission's regulations in
Subpart A of 10 CFR Part 51, that this rule, if adopted, would not be a
major Federal action significantly affecting the quality of the human
environment and, therefore, an environmental impact statement is not
required. The basis for this determination is as follows:
This action stems from the Commission's ongoing efforts to risk-
inform its regulations. If adopted, the proposed rule would establish a
voluntary alternative set of risk-informed requirements for emergency
core cooling systems. Using the alternative ECCS requirements \14\ will
provide some licensees with opportunities to change other aspects of
plant design to increase safety, increase operational flexibility or
decrease costs. Accordingly, licensee actions taken under the proposed
rule could either decrease the probability of an accident or slightly
increase the probability of an accident. Mitigation of LOCAs of all
sizes would still be required but with less redundancy and margin for
the larger, low probability breaks. Increases in risk, if any, would be
required to be small enough that adequate assurance of public health
and safety is maintained. When considered together, the net effect of
the licensee actions is expected to have a negligible effect on
accident probability.
---------------------------------------------------------------------------
\14\ The alternative requirements are less stringent in the area
of large break LOCAs. The NRC believes that large break LOCAs are
very rare events; hence requiring reactors to conservatively
withstand such events focuses attention and resources on extremely
unlikely events and could have a detrimental effect on mitigating
accidents initiated by other more likely events.
---------------------------------------------------------------------------
Thus, the proposed action would not significantly increase the
probability or consequences of an accident, when considered in a risk-
informed manner. No changes would be made in the types of quantities of
radiological effluents that may be released offsite, and there is no
significant increase in public radiation exposure since there is no
change to facility operations that could create a new or significantly
affect a previously analyzed accident or release path.
With regard to non-radiological impacts, no changes would be made
to non-radiological plant effluents and there would be no changes in
activities that would adversely affect the environment. Therefore,
there are no significant non-radiological impacts associated with the
proposed action.
The primary alternative would be the no action alternative. The no
action alternative, at worst, would result in no changes to current
levels of safety, risk, or environmental impact. The no action
alternative would also prevent licensees from making certain plant
modifications that could be implemented under the proposed rule that
could increase plant safety. The no action alternative would also
continue existing regulatory burdens for which there may be little or
no safety, risk, or environmental benefit.
The determination of this environmental assessment is that there
will be no significant offsite impact to the public from this action.
However, the general public should note that the NRC is seeking public
participation on this assessment. Comments on any aspect of the
environmental assessment may be submitted to the NRC as indicated under
the ADDRESSES heading.
The NRC has sent a copy of the environmental assessment and this
proposed rule to every State Liaison Officer and requested their
comments on the environmental assessment.
XII. Paperwork Reduction Act Statement
This proposed rule contains new or amended information collection
requirements that are subject to the Paperwork Reduction Act of 1995
(44 U.S.C. 3501 et seq). This rule has been submitted to the Office of
Management and Budget for review and approval of the information
collection requirements.
Type of submission, new or revision: Revision.
The title of the information collection: 10 CFR Part 50, ``Risk-
Informed Changes to Loss-Of-Coolant Accident Technical Requirements''.
The form number if applicable: Not applicable.
How often the collection is required: One-time submission of a risk
assessment of ECCS performance, submission of PRAs and corrective
actions on occasion, ongoing recordkeeping.
Who will be required or asked to report: Licensees authorized to
operate a nuclear power reactor that choose to implement the risk-
informed alternative for analyzing the performance of emergency core
cooling systems during loss-of-coolant accidents.
An estimate of the number of annual responses: 46.
The estimated number of annual respondents: 23.
An estimate of the total number of hours needed annually to
complete the requirement or request: 324,208 hours total, including
268,640 hours for reporting (an average of 11,680 hours per respondent)
+ 55,568 hours recordkeeping (an average of 2,416 hours per
recordkeeper).
Abstract: The Nuclear Regulatory Commission (NRC) proposes to amend
its regulations to permit current power reactor licensees to implement
a voluntary, risk-informed alternative to the current requirements for
analyzing the performance of emergency core cooling systems (ECCS)
during loss-of-coolant accidents (LOCAs). In addition, the proposed
rule would establish procedures and criteria for making changes in
plant design and procedures based upon the results of the new analyses
of ECCS performance during LOCAs.
The U.S. Nuclear Regulatory Commission is seeking public comment on
the potential impact of the information collections contained in this
proposed rule and on the following issues:
1. Is the proposed information collection necessary for the proper
performance of the functions of the NRC, including whether the
information will have practical utility?
[[Page 67624]]
2. Is the estimate of burden accurate?
3. Is there a way to enhance the quality, utility, and clarity of
the information to be collected?
4. How can the burden of the information collection be minimized,
including the use of automated collection techniques?
A copy of the OMB clearance package may be viewed free of charge at
the NRC Public Document Room, One White Flint North, 11555 Rockville
Pike, Room O 1F21, Rockville, MD 20852. The OMB clearance package and
rule are available at the NRC Worldwide Web site: http://www.nrc.gov/public-involve/doc-comment/omb/index.html for 60 days after the
signature date of this notice and are also available at the rule forum
site, http://ruleforum.llnl.gov.
Send comments on any aspect of these proposed information
collections, including suggestions for reducing the burden and on the
above issues, by December 7, 2005, to the Records and FOIA/Privacy
Services Branch (T-5 F52), U.S. Nuclear Regulatory Commission,
Washington, DC 20555-0001, or by Internet electronic mail to
[email protected] and to the Desk Officer, John A. Asalone, Office
of Information and Regulatory Affairs, NEOB-10202, (3150-0011), Office
of Management and Budget, Washington, DC 20503. Comments received after
this date will be considered if it is practical to do so, but assurance
of consideration cannot be given to comments received after this date.
You may also e-mail your comments to John A. [email protected] or
comment by telephone at (202) 395-4650.
Public Protection Notification
The NRC may not conduct or sponsor, and a person is not required to
respond to, a request for information or an information collection
requirement unless the requesting document displays a currently valid
OMB control number.
XIII. Regulatory Analysis
The Commission has prepared a draft regulatory analysis on this
proposed regulation. The analysis examines the costs and benefits of
the alternatives considered by the Commission. The Commission requests
public comment on the draft regulatory analysis. Availability of the
regulatory analysis is provided in Section VIII. Comments on the draft
analysis may be submitted to the NRC as indicated under the ADDRESSES
heading.
XIV. Regulatory Flexibility Certification
In accordance with the Regulatory Flexibility Act (5 U.S.C.
605(b)), the Commission certifies that this rule will not, if
promulgated, have a significant economic impact on a substantial number
of small entities. This proposed rule affects only the licensing and
operation of nuclear power plants. The companies that own these plants
do not fall within the scope of the definition of ``small entities''
set forth in the Regulatory Flexibility Act or the size standards
established by the NRC (10 CFR 2.810).
XV. Backfit Analysis
The NRC has determined that the proposed rulemaking generally does
not constitute backfitting as defined in the Backfit Rule, 10 CFR
50.109(a)(1), and that three provisions of the proposed rule
effectively excluding certain actions from the purview of the Backfit
Rule, viz., Sec. 50.109(b)(2); Sec. 50.46a(f)(5), and Sec.
50.46a(j), are appropriate. The bases for each of these determinations
follows.
The NRC has determined that the proposed rulemaking does not
constitute backfitting because it provides a voluntary alternative to
the existing requirements in 10 CFR 50.46 for evaluating the
performance of an ECCS for light-water nuclear power plants. A licensee
may decide to either comply with the requirements of Sec. 50.46a, or
to continue to comply with the existing licensing basis of their plant
with respect to ECCS analyses. Therefore, the Backfit Rule does not
require the preparation of a backfit analysis for the proposed rule.
As discussed in Section III.H, ``Potential Revisions Based on LOCA
Frequency Reevaluations,'' the Commission may undertake future
rulemaking to revise the TBS based upon re-evaluations of LOCA
frequencies occurring after the effective date of a final rule. A
proposed amendment to the Backfit Rule, Sec. 50.109(b)(2), would
provide that future changes to the TBS would not be subject to the
Backfit Rule. The Commission has determined that there is no statutory
bar to the adoption of such a provision. The Commission also believes
that the proposed exclusion of such rulemakings from the Backfit Rule
is appropriate. The Commission intends to revise the TBS in Sec.
50.46a rarely and only if necessary based upon public health and safety
and/or common defense and security considerations. The Commission also
does not regard the proposed exclusion as allowing the Commission to
adopt cost-unjustified changes to the TBS. The NRC prepares a
regulatory analysis for each substantive regulatory action which
identifies the regulatory objectives of the proposed action, and
evaluates the costs and benefits of proposed alternatives for achieving
those regulatory objectives. The Commission has also adopted guidelines
governing treatment of individual requirements in a regulatory analysis
(69 FR 29187; May 21, 2004). The Commission believes that a regulatory
analysis performed in accordance with these guidelines will be
effective in identifying unjustified regulatory proposals. In addition,
such rulemaking as applied to licensees who have not yet transferred to
Sec. 50.46a would not constitute backfitting for those licensees,
inasmuch as the Backfit Rule does not protect a future applicant who
has no reasonable expectation that requirements will remain static. The
policies underlying the Backfit Rule apply only to licensees who have
already received regulatory approval. Accordingly, the Commission
concludes that the proposed exclusion in Sec. 50.109(b)(2) of future
changes to the TBS from the requirements of the Backfit Rule is
appropriate.
As discussed in Section III.D.3.e, Sec. 50.46a(d)(5) would require
that a PRA used to demonstrate compliance with the risk acceptance
criteria in Sec. 50.46a(f)(1) or (f)(2) be periodically re-evaluated
and updated, and that the licensee implement changes to the facility
and procedures as necessary to ensure that the acceptance criteria
continue to be met. To ensure that such re-evaluation and updating of
the PRA and any necessary changes to a facility and its procedures
under paragraph (d)(5) are not considered backfitting, Sec.
50.46a(d)(5) would provide that such re-evaluation, updating, and
changes are not deemed to be backfitting. The Commission believes that
this exclusion from the Backfit Rule is appropriate, inasmuch as
application of the Backfit Rule in this context would effectively favor
increases in risk. This is because most facility and procedure changes
involve an up-front cost to implement a change which must be recovered
over the remaining operating life of the facility in order to be
considered cost-effective. For example, assume that after a change is
implemented, subsequent PRA analyses suggest that the change should be
``rescinded'' (either the hardware is restored to the original
configuration or the new configuration is not credited in design bases
analyses) in order to maintain the assumed risk level. The cost/benefit
determination of the second, ``restoring'' change must address: (i) The
unrecovered cost of the first change; and (ii) the cost of the second,
``restoring'' change. In most cases, application of cost/benefit
[[Page 67625]]
analyses in evaluating the second, ``restoring'' change would skew the
decision-making in favor of accepting the existing plant with the
higher risk. Accumulation of such incremental increases in risk does
not appear to be an appropriate regulatory approach. Accordingly, the
Commission concludes that the backfitting exclusion in Sec.
50.46a(d)(5) is appropriate.
Section 50.46a(m) would provide that if the NRC changes the TBS
specified in Sec. 50.46a, licensees who have evaluated their ECCS
under Sec. 50.46a shall undertake additional actions to ensure that
the relevant acceptance criteria for ECCS performance are met with the
new TBSs, and that such licensee actions are not to be considered
backfitting. Consequently, the NRC may require licensees to take action
under Sec. 50.46a(m) without consideration of the Backfit Rule. The
Commission has determined that there is no statutory bar to the
adoption of this provision, and that the proposed provision represents
a justified departure from the principles underlying the Backfit Rule.
First, the Commission's decision on this matter recognizes that any
future rulemaking to alter the TBS will require preparation of a
regulatory analysis. As discussed, the regulatory analysis will
ordinarily include a cost/benefit analysis addressing whether the costs
of the TBS redefinition are justified in view of the benefits
attributable to the redefinition. Second, the licensee has substantial
flexibility under the proposed rule to determine the actions
(reanalysis, procedure and operational changes, design-related changes,
or a combination thereof) necessary to demonstrate compliance with the
relevant ECCS acceptance criteria. In this sense, the performance-based
approach of the proposed rule lends substantial flexibility to the
licensee and may tend to reduce the burden associated with changes in
the TBS. Accordingly, the Commission concludes that the backfitting
exclusion in Sec. 50.46a(m) is appropriate.
List of Subjects in 10 CFR Part 50
Antitrust, Classified information, Criminal penalties, Fire
protection, Intergovernmental relations, Nuclear power plants and
reactors, Radiation protection, Reactor siting criteria, Reporting and
recordkeeping requirements.
For the reasons set out in the preamble and under the authority of
the Atomic Energy Act of 1954, as amended; the Energy Reorganization
Act of 1974, and 5 U.S.C. 553, the NRC is proposing to adopt the
following amendments to 10 CFR part 50.
PART 50--DOMESTIC LICENSING OF PRODUCTION AND UTILIZATION
FACILITIES
1. The authority citation for part 50 continues to read as follows:
Authority: Secs. 102, 103, 104, 105, 161, 182, 183, 186, 189, 68
Stat. 936, 937, 938, 948, 953, 954, 955, 956, as amended, sec. 234,
83 Stat. 444, as amended (42 U.S.C. 2132, 2133, 2134, 2135, 2201,
2232, 2233, 2236, 2239, 2282); secs. 201, as amended, 202, 206, 88
Stat. 1242, as amended, 1244, 1246 (42 U.S.C. 5841, 5842, 5846);
sec. 1704, 112 Stat. 2750 (44 U.S.C. 3504 note).
Section 50.7 also issued under Pub. L. 95-601, sec. 10, 92 Stat.
2951 (42 U.S.C. 5841). Section 50.10 also issued under secs. 101,
185, 68 Stat. 955, as amended (42 U.S.C. 2131, 2235); sec. 102, Pub.
L. 91-190, 83 Stat. 853 (42 U.S.C. 4332).
Sections 50.13, 50.54(dd), and 50.103 also issued under sec.
108, 68 Stat. 939, as amended (42 U.S.C. 2138). Sections 50.23,
50.35, 50.55, and 50.56 also issued under sec. 185, 68 Stat. 955 (42
U.S.C. 2235). Sections 50.33a, 50.55a and Appendix Q also issued
under sec. 102, Pub. L. 91-190, 83 Stat. 853 (42 U.S.C. 4332).
Sections 50.34 and 50.54 also issued under sec. 204, 88 Stat. 1245
(42 U.S.C. 5844). Sections 50.58, 50.91, and 50.92 also issued under
Pub. L. 97-415, 96 Stat. 2073 (42 U.S.C. 2239). Section 50.78 also
issued under sec. 122, 68 Stat. 939 (42 U.S.C. 2152). Sections
50.80-50.81 also issued under sec. 184, 68 Stat. 954, as amended (42
U.S.C. 2234). Appendix F also issued under sec. 187, 68 Stat. 955
(42 U.S.C. 2237).
2. In Sec. 50.34, paragraphs (a)(4) and (b)(4) are revised to read
as follows:
Sec. 50.34 Contents of application; technical information.
(a) * * *
(4) A preliminary analysis and evaluation of the design and
performance of structures, systems, and components of the facility with
the objective of assessing the risk to public health and safety
resulting from operation of the facility and including determination of
the margins of safety during normal operations and transient conditions
anticipated during the life of the facility, and the adequacy of
structures, systems, and components provided for the prevention of
accidents and the mitigation of the consequences of accidents. Analysis
and evaluation of ECCS cooling performance and the need for high point
vents following postulated loss-of-coolant accidents must be performed
in accordance with the requirements of Sec. 50.46 or Sec. 50.46a, and
Sec. 50.46b for facilities for which construction permits may be
issued after December 28, 1974, but before [EFFECTIVE DATE OF RULE].
Such analyses must be performed in accordance with the requirements of
Sec. 50.46 and Sec. 50.46b for facilities for which construction
permits may be issued after [EFFECTIVE DATE OF RULE], and design
approvals and standard design certifications under part 52 of this
chapter issued after [EFFECTIVE DATE OF RULE].
* * * * *
(b) * * *
(4) A final analysis and evaluation of the design and performance
of structures, systems, and components with the objective stated in
paragraph (a)(4) of this section and taking into account any pertinent
information developed since the submittal of the preliminary safety
analysis report. Analysis and evaluation of ECCS cooling performance
following postulated LOCAs must be performed in accordance with the
requirements of Sec. Sec. 50.46 or 50.46a, and 50.46b for facilities
for which a license to operate may be issued after December 28, 1974,
but before [EFFECTIVE DATE OF RULE]. The analyses must be performed in
accordance with the requirements of Sec. Sec. 50.46 and 50.46b for
facilities for which construction permits may be issued after
[EFFECTIVE DATE OF RULE], and design approvals and standard design
certifications under part 52 of this chapter issued after [EFFECTIVE
DATE OF RULE].
* * * * *
3. In Sec. 50.46, paragraph (a) introductory text is added and
paragraph (a)(1)(i) is revised to read as follows:
Sec. 50.46 Acceptance criteria for emergency core cooling systems for
light-water nuclear power plants.
(a) Each boiling or pressurized light-water nuclear power reactor
fueled with uranium oxide pellets within cylindrical zircalloy or ZIRLO
cladding must be provided with an emergency core cooling system (ECCS).
Reactors whose operating licenses were issued before [EFFECTIVE DATE OF
RULE] must be designed in accordance with the requirements of either
this section or Sec. 50.46a. Reactors whose construction permits were
issued prior to, but have not received operating licenses as of
[EFFECTIVE DATE OF RULE], and those reactors whose construction permits
are issued after [EFFECTIVE DATE OF RULE] must be designed in
accordance with this section.
(1)(i) The ECCS system must be designed so that its calculated
cooling performance following postulated LOCAs conforms to the criteria
set forth in paragraph (b) of this section. ECCS cooling performance
must be calculated
[[Page 67626]]
in accordance with an acceptable evaluation model and must be
calculated for a number of postulated LOCAs of different sizes,
locations, and other properties sufficient to provide assurance that
the most severe postulated LOCAs are calculated. Except as provided in
paragraph (a)(1)(ii) of this section, the evaluation model must include
sufficient supporting justification to show that the analytical
technique realistically describes the behavior of the reactor system
during a LOCA. Comparisons to applicable experimental data must be made
and uncertainties in the analysis method and inputs must be identified
and assessed so that the uncertainty in the calculated results can be
estimated. This uncertainty must be accounted for, so that, when the
calculated ECCS cooling performance is compared to the criteria set
forth in paragraph (b) of this section, there is a high level of
probability that the criteria would not be exceeded. Appendix K, Part
II Required Documentation, sets forth the documentation requirements
for each evaluation model. This section does not apply to a nuclear
power reactor facility for which the certifications required under
Sec. 50.82(a)(1) have been submitted.
* * * * *
4. Section 50.46a is redesignated as Sec. 50.46b.
5. A new Sec. 50.46a is added to read as follows:
Sec. 50.46a Alternative acceptance criteria for emergency core
cooling systems for light-water nuclear power reactors.
(a) Definitions. For the purposes of this section:
(1) Evaluation model means the calculational framework for
evaluating the behavior of the reactor system during a postulated
design-basis loss-of-coolant accident (LOCA). It includes one or more
computer programs and all other information necessary for application
of the calculational framework to a specific LOCA, such as mathematical
models used, assumptions included in the programs, procedure for
treating the program input and output information, specification of
those portions of analysis not included in computer programs, values of
parameters, and all other information necessary to specify the
calculational procedure.
(2) Loss-of-coolant accidents (LOCAs) means the hypothetical
accidents that would result from the loss of reactor coolant, at a rate
in excess of the capability of the reactor coolant makeup system, from
breaks in pipes in the reactor coolant pressure boundary up to and
including a break equivalent in size to the double-ended rupture of the
largest pipe in the reactor coolant system. LOCAs involving breaks at
or below the transition break size (TBS) are considered design-basis
accidents. LOCAs involving breaks larger than the TBS are considered
beyond design-basis accidents.
(3) Operating configuration means those plant characteristics, such
as power level, equipment unavailability (including unavailability
caused by corrective and preventive maintenance), and equipment
capability that affect plant response to a LOCA.
(4) Transition break size (TBS) is a break of area equal to the
cross-sectional flow area of the inside diameter of specified piping
for a specific reactor. The specified piping for a pressurized water
reactor is the largest piping attached to the reactor coolant system.
The specified piping for a boiling water reactor is the larger of the
feedwater line inside containment or the residual heat removal line
inside containment.
(b) Applicability and scope. (1) The requirements of this section
apply to each boiling or pressurized light-water nuclear power reactor
fueled with uranium oxide pellets within cylindrical zircalloy or ZIRLO
cladding for which a license to operate was issued prior to [EFFECTIVE
DATE OF RULE], but do not apply to such a reactor for which the
certification required under Sec. 50.82(a)(1) has been submitted.
(2) The requirements of this section are in addition to any other
requirements applicable to ECCS set forth in this part, with the
exception of Sec. 50.46. The criteria set forth in paragraphs (e)(3)
and (e)(4) of this section, with cooling performance calculated in
accordance with an acceptable evaluation model or analysis method under
paragraphs (e)(1) and (e)(2) of this section, are in implementation of
the general requirements with respect to ECCS cooling performance
design set forth in this part, including in particular Criterion 35 of
Appendix A to this part.
(c) Application. (1) A licensee voluntarily choosing to implement
this section shall submit an application for a license amendment under
Sec. 50.90 that contains the following information:
(i) A description of the method(s) for demonstrating compliance
with the ECCS criteria in paragraph (e) of this section;
(ii) A description of the risk-informed integrated safety
performance (RISP) assessment process to be used in evaluating whether
proposed changes to the facility, technical specifications, or
procedures meet the requirements in paragraph (f) of this section;
including:
(A) a description of the licensee's PRA model and non-PRA risk
assessment methods demonstrating compliance with paragraphs (f)(4) and
(f)(5) of this section, and
(B) a description of the methods and decisionmaking process for
evaluating compliance with the risk criteria, defense-in-depth
criteria, safety margin criteria, and performance measurement criteria.
(2) Acceptance criteria. The Commission may approve an application
to use this section if:
(i) The method(s) for demonstrating compliance with the ECCS
acceptance criteria in paragraphs (e)(3) and (e)(4) of this section
meet the requirements in paragraphs (e)(1) and (e)(2);
(ii) The RISP assessment process (including any PRA model and other
risk assessment methods) meets the requirements in paragraph (f) of
this section; and
(iii) The RISP assessment process ensures that changes made
pursuant to paragraph (f)(1) are permitted under Sec. 50.59.
(d) Requirements during operation. A licensee whose application
under paragraph (c) of this section is approved by the NRC shall comply
with the following requirements until the licensee submits the
certifications required by Sec. 50.82(a):
(1) The licensee shall maintain ECCS model(s) and/or analysis
method(s) meeting the acceptance requirements in paragraphs (e)(1) and
(e)(2) of this section,
(2) For LOCAs larger than the TBS, the acceptance criteria in
paragraph (e)(4) shall not be exceeded under any allowed at-power
operating configurations analyzed under paragraph (e), and the plant
may not be placed in any at-power operating configuration not addressed
under paragraph (e) of this section.
(3) The licensee shall evaluate any change to the facility as
described in the FSAR, technical specifications, or procedures using
the NRC-approved RISP assessment process and shall demonstrate that the
acceptance criteria in paragraph (f) of this section are met.
(4) The licensee shall implement adequate performance-measurement
programs to ensure that the RISP assessment process reflects actual
plant design and operation. These programs must meet the criteria in
paragraph (f)(3)(iii) of this section.
(5) The licensee shall periodically re-evaluate and update its risk
assessments required under paragraph (c)(1)(ii) of this section to
address changes to the
[[Page 67627]]
plant, operational practices, equipment performance, plant operational
experience, and PRA model, and revisions in analysis methods, model
scope, data, and modeling assumptions. The re-evaluation and updating
must be completed in a timely manner, but no less often than once every
two refueling outages. The updated risk assessments must continue to
meet the requirements in paragraphs (f)(4) and (f)(5) of this section.
Based upon the risk assessments, the licensee shall take appropriate
action to ensure that facility design and operation continue to be
consistent with the risk assessment assumptions used to meet the
acceptance criteria in paragraphs (f)(1) or (f)(2) of this section, as
applicable. The re-evaluation and updating required by this section,
and any necessary changes to the facility, technical specifications and
procedures as a result of this re-evaluation and updating, shall not be
deemed to be backfitting under any provision of this chapter.
(e) ECCS Performance. Each nuclear power reactor subject to this
section must be provided with an ECCS that must be designed so that its
ECCS calculated cooling performance following postulated LOCAs conforms
to the criteria set forth in this section. The evaluation models for
LOCAs involving breaks at or below the TBS must meet the criteria in
this paragraph, and must be approved for use by the NRC. Appendix K,
Part II, 10 CFR Part 50, sets forth the documentation requirements for
evaluation models for LOCAs involving breaks at or below the TBS. The
analysis methods for LOCAs involving breaks larger than the TBS must be
maintained, available for inspection, and include the analytical
approaches, equations, approximations and assumptions.
(1) ECCS evaluation for LOCAs involving breaks at or below the TBS.
ECCS cooling performance at or below the TBS must be calculated in
accordance with an evaluation model that meets the requirements of
either section I to Appendix K of this part, or the following
requirements, and demonstrate that the acceptance criteria in paragraph
(e)(3) of this section are satisfied. The evaluation model must be used
for a number of postulated LOCAs of different sizes, locations, and
other properties sufficient to provide assurance that the most severe
postulated LOCAs involving breaks at or below the TBS are analyzed. The
evaluation model must include sufficient supporting justification to
show that the analytical technique realistically describes the behavior
of the reactor system during a LOCA. Comparisons to applicable
experimental data must be made and uncertainties in the analysis method
and inputs must be identified and assessed so that the uncertainty in
the calculated results can be estimated. This uncertainty must be
accounted for, so that when the calculated ECCS cooling performance is
compared to the criteria set forth in paragraph (e)(3) of this section,
there is a high level of probability that the criteria would not be
exceeded.
(2) ECCS analyses for LOCAs involving breaks larger than the TBS.
ECCS cooling performance for LOCAs involving breaks larger than the TBS
must be calculated and must demonstrate that the acceptance criteria in
paragraph (e)(4) of this section are satisfied. The analysis method
must address the most important phenomena in analyzing the course of
the accident. The evaluation must be performed for a number of
postulated LOCAs of different sizes and locations sufficient to provide
assurance that the most severe postulated LOCAs larger than the TBS up
to the double-ended rupture of the largest pipe in the reactor coolant
system are analyzed. Sufficient supporting justification, including the
methodology used, must be available to show that the analytical
technique reasonably describes the behavior of the reactor system
during a LOCA from the TBS up to the double-ended rupture of the
largest reactor coolant system pipe. Comparisons to applicable
experimental data must be made. These calculations may take credit for
the availability of offsite power and do not require the assumption of
a single failure. Realistic initial conditions and availability of
equipment may be assumed if supported by plant-specific data or
analysis.
(3) Acceptance criteria for LOCAs involving breaks at or below the
TBS. The following acceptance criteria must be used in determining the
acceptability of ECCS cooling performance:
(i) Peak cladding temperature. The calculated maximum fuel element
cladding temperature must not exceed 2200 [deg]F.
(ii) Maximum cladding oxidation. The calculated total oxidation of
the cladding must not at any location exceed 0.17 times the total
cladding thickness before oxidation. As used in this paragraph, total
oxidation means the total thickness of cladding metal that would be
locally converted to oxide if all the oxygen absorbed by and reacted
with the cladding locally were converted to stoichiometric zirconium
dioxide. If cladding rupture is calculated to occur, the inside
surfaces of the cladding must be included in the oxidation, beginning
at the calculated time of rupture. Cladding thickness before oxidation
means the radial distance from inside to outside the cladding, after
any calculated rupture or swelling has occurred but before significant
oxidation. Where the calculated conditions of transient pressure and
temperature lead to a prediction of cladding swelling, with or without
cladding rupture, the unoxidized cladding thickness must be defined as
the cladding cross-sectional area, taken at a horizontal plane at the
elevation of the rupture, if it occurs, or at the elevation of the
highest cladding temperature if no rupture is calculated to occur,
divided by the average circumference at that elevation. For ruptured
cladding the circumference does not include the rupture opening.
(iii) Maximum hydrogen generation. The calculated total amount of
hydrogen generated from the chemical reaction of the cladding with
water or steam must not exceed 0.01 times the hypothetical amount that
would be generated if all of the metal in the cladding cylinders
surrounding the fuel, excluding the cladding surrounding the plenum
volume, were to react.
(iv) Coolable geometry. Calculated changes in core geometry must be
such that the core remains amenable to cooling.
(v) Long term cooling. After any calculated successful initial
operation of the ECCS, the calculated core temperature must be
maintained at an acceptably low value and decay heat must be removed
for the extended period of time required by the long-lived
radioactivity remaining in the core.
(4) Acceptance criteria for LOCAs involving breaks larger than the
TBS. The following acceptance criteria must be used in determining the
acceptability of ECCS cooling performance:
(i) Coolable geometry. Calculated changes in core geometry must be
such that the core remains amenable to cooling.
(ii) Long term cooling. After any calculated successful initial
operation of the ECCS, the calculated core temperature must be
maintained at an acceptably low value and decay heat must be removed
for the extended period of time required by the long-lived
radioactivity remaining in the core.
(5) Imposition of restrictions. The Director of the Office of
Nuclear Reactor Regulation may impose restrictions on reactor operation
if it is found that the evaluations of ECCS cooling performance
submitted are not consistent with paragraph (e) of this section.
[[Page 67628]]
(f) Changes to facility, technical specifications, or procedures. A
licensee who wishes to make changes to the facility or procedures or to
the technical specifications shall perform a RISP assessment.
(1) The licensee may make such changes without prior NRC approval
if:
(i) The change is permitted under Sec. 50.59, and
(ii) The RISP assessment demonstrates that any increases in the
estimated risk are minimal compared to the overall plant risk profile,
and the criteria in paragraph (f)(3) of this section are met.
(2) For implementing changes which are not permitted under
paragraph (f)(1) of this section, the licensee must submit an
application for license amendment under Sec. 50.90. The application
must contain:
(i) The information required under Sec. 50.90;
(ii) Information from the RISP assessment demonstrating that the
total increases in core damage frequency and large early release
frequency are small and the overall risk remains small, and the
criteria in paragraph (f)(3) of this section are met; and
(iii) Information demonstrating that the criteria in paragraphs
(e)(3) and (e)(4) of this section are met.
(3) All changes to a facility or procedures or to the technical
specifications must meet the following criteria:
(i) Defense in depth is maintained, in part, by assuring that:
(A) Reasonable balance is provided among prevention of core damage,
containment failure (early and late), and consequence mitigation;
(B) System redundancy, independence, and diversity are provided
commensurate with the expected frequency of postulated accidents, the
consequences of those accidents, and uncertainties; and
(C) Independence of barriers is not degraded;
(ii) Adequate safety margins are retained to account for
uncertainties; and
(iii) Adequate performance-measurement programs are implemented to
ensure the RISP assessment continues to reflect actual plant design and
operation. These programs shall be designed to:
(A) Detect degradation of the system, structure or component before
plant safety is compromised,
(B) Provide feedback of information and timely corrective actions,
and
(C) Monitor systems, structures or components at a level
commensurate with their safety significance.
(4) Requirements for risk assessment--PRA. To the extent that a PRA
is used in the RISP assessment, the PRA must:
(i) Address initiating events from sources both internal and
external to the plant and for all modes of operation, including low
power and shutdown modes, that would affect the regulatory decision in
a substantial manner;
(ii) Calculate CDF and LERF;
(iii) Reasonably represent the current configuration and operating
practices at the plant; and
(iv) Have sufficient technical adequacy (including consideration of
uncertainty) and level of detail to provide confidence that the total
CDF and LERF and the change in total CDF and LERF adequately reflect
the plant and the effect of the proposed change on risk.
(5) Requirements for risk assessment other than PRA. To the extent
that risk assessment methods other than PRAs are used to develop
quantitative or qualitative estimates of changes to CDF and LERF in the
RISP assessment, a licensee shall justify that the methods used produce
realistic results.
(g) Reporting. (1) Each licensee shall estimate the effect of any
change to or error in evaluation models or analysis methods or in the
application of such models or methods to determine if the change or
error is significant. For each change to or error discovered in an ECCS
evaluation model or analysis method or in the application of such a
model that affects the calculated results, the licensee shall report
the nature of the change or error and its estimated effect on the
limiting ECCS analysis to the Commission at least annually as specified
in Sec. 50.4. If the change or error is significant, the licensee
shall provide this report within 30 days and include with the report a
proposed schedule for providing a reanalysis or taking other action as
may be needed to show compliance with Sec. 50.46a requirements. This
schedule may be developed using an integrated scheduling system
previously approved for the facility by the NRC. For those facilities
not using an NRC-approved integrated scheduling system, a schedule will
be established by the NRC staff within 60 days of receipt of the
proposed schedule. Any change or error correction that results in a
calculated ECCS performance that does not conform to the criteria set
forth in paragraphs (e)(3) or (e)(4) of this section is a reportable
event as described in Sec. Sec. 50.55(e), 50.72 and 50.73. The
licensee shall propose immediate steps to demonstrate compliance or
bring plant design or operation into compliance with Sec. 50.46a
requirements. For the purpose of this paragraph, a significant change
or error is:
(i) For LOCAs involving pipe breaks at or below the TBS, one which
results either in a calculated peak fuel cladding temperature different
by more than 50 [deg]F from the temperature calculated for the limiting
transient using the last acceptable model, or is a cumulation of
changes and errors such that the sum of the absolute magnitudes of the
respective temperature changes is greater than 50 [deg]F; or a change
in the calculated oxidation, or the sum of the absolute value of the
changes in calculated oxidation, equals or exceeds 0.4 percent
oxidation; or
(ii) For LOCAs involving pipe breaks larger than the TBS, one which
results in a significant reduction in the capability to meet the
requirements of paragraph (e)(4) of this section.
(2) As part of the PRA update under paragraph (d)(5) of this
section, the licensee shall report the change to the NRC if the change
results in a significant reduction in the capability to meet the
requirements in paragraph (f) of this section. The report must be filed
with the NRC no more than 60 days after completing the PRA update and
must include a description of the relevant PRA updates performed by the
licensee, an explanation of the changes in the PRA modeling, plant
design, or plant operation that led to the increase(s) in CDF or LERF
after completing the PRA update, a description of any corrective
actions required under paragraph (d)(5) of this section, and a schedule
for implementation.
(3) Every 24 months, the licensee shall submit, as specified in
Sec. 50.4, a short description of all changes involving minimal
changes in risk made under paragraph (f)(1) of this section since the
last report.
(h) Documentation of changes to facility, technical specification,
and procedures. When making changes under paragraph (f) of this
section, the licensee shall document the bases for demonstrating
compliance with the acceptance criteria in paragraphs (f)(1) or (f)(2)
and (f)(3) of this section. Upon the approval of the change under
paragraph (f)(2) of this section or licensee implementation of the
change under paragraph (f)(1) of this section, the licensee shall
update the final safety analysis report in accordance with Sec.
50.71(e).
(i) through (l)--[RESERVED]
(m) Changes to TBS. If the NRC increases the TBS specified in this
section applicable to a licensee's nuclear power plant, each licensee
subject to this section shall perform the
[[Page 67629]]
evaluations required by paragraphs (e)(1) and (e)(2) of this section
and reconfirm compliance with the acceptance criteria in paragraphs
(e)(3) and (e)(4) of this section. If the licensee cannot demonstrate
compliance with the acceptance criteria, then the licensee shall change
its facility, technical specifications or procedures so that the
acceptance criteria are met. The evaluation required by this paragraph,
and any necessary changes to the facility, technical specifications or
procedures as the result of this evaluation, must not be deemed to be
backfitting under any provision of this chapter.
6. In Sec. 50.109, paragraph (b) is revised to read as follows:
Sec. 50.109 Backfitting.
* * * * *
(b) Paragraph (a)(3) of this section shall not apply to:
(1) Backfits imposed prior to October 21, 1985; and
(2) Any changes made to the TBS specified in Sec. 50.46a or as
otherwise applied to a licensee.
* * * * *
7. In Appendix A to 10 CFR Part 50, under the heading,
``CRITERIA,'' Criterion 17, 35, 38, 41, 44 and 50 are revised to read
as follows:
Appendix A to Part 50--General Design Criteria for Nuclear Power Plants
* * * * *
Criteria
* * * * *
Criterion 17--Electrical power systems. An on-site electric
power system and an offsite electric power system shall be provided
to permit functioning of structures, systems, and components
important to safety. The safety function for each system (assuming
the other system is not functioning) shall be to provide sufficient
capacity and capability to assure that (1) specified acceptable fuel
design limits and design conditions of the reactor coolant pressure
boundary are not exceeded as a result of anticipated operational
occurrences and (2) the core is cooled and containment integrity and
other vital functions are maintained in the event of postulated
accidents.
The onsite electric power supplies, including the batteries, and
the onsite electrical distribution system, shall have sufficient
independence, redundancy and testability to perform their safety
functions assuming a single failure, except for loss of coolant
accidents involving pipe breaks larger than the transition break
size under Sec. 50.46a, where a single failure of the onsite power
supplies and electrical distribution system need not be assumed for
plants under Sec. 50.46a.
Electric power from the transmission network to the onsite
electric distribution system shall be supplied by two physically
independent circuits (not necessarily on separate rights of way)
designed and located so as to minimize to the extent practical the
likelihood of their simultaneous failure under operating and
postulated accident conditions. A switchyard common to both circuits
is acceptable. Each of these circuits shall be designed to be
available in sufficient time following a loss of all onsite
alternating current power supplies and the other offsite electric
power circuit, to assure that specified acceptable fuel design
limits and design conditions of the reactor coolant pressure
boundary are not exceeded. One of these circuits shall be designed
to be available within a few seconds following a LOCA to assure that
core cooling, containment integrity, and other vital safety
functions are maintained.
Provisions shall be included to minimize the probability of
losing electric power from any of the remaining supplies as a result
of, or coincident with, the loss of power generated by the nuclear
power unit, the loss of power from the transmission network, or the
loss of power from the onsite electric power supplies.
* * * * *
Criterion 35--Emergency core cooling. A system to provide
abundant emergency core cooling shall be provided. The system safety
function shall be to transfer heat from the reactor core following
any loss of reactor coolant at a rate such that (1) fuel and clad
damage that could interfere with continued effective core cooling is
prevented and (2) clad metal-water reaction is limited to negligible
amounts.
Suitable redundancy in components and features, and suitable
interconnections, leak detection, isolation, and containment
capabilities shall be provided to assure that for onsite electric
power system operation (assuming offsite power is not available) and
for offsite electric power system operation (assuming onsite power
is not available) the system safety function can be accomplished,
assuming a single failure, except for loss of coolant accidents
involving pipe breaks larger than the transition break size under
Sec. 50.46a. For those accidents, a single failure need not be
assumed and the unavailability of offsite power need not be assumed
for onsite electric power system operation.
* * * * *
Criterion 38--Containment heat removal. A system to remove heat
from the reactor containment shall be provided. The system safety
function shall be to reduce rapidly, consistent with the functioning
of other associated systems, the containment pressure and
temperature following any LOCA and maintain them at acceptably low
levels.
Suitable redundancy in components and features, and suitable
interconnections, leak detection, isolation, and containment
capabilities shall be provided to assure that for onsite electric
power system operation (assuming offsite power is not available) and
for offsite electric power system operation (assuming onsite power
is not available) the system safety function can be accomplished,
assuming a single failure, except for analysis of loss of coolant
accidents involving pipe breaks larger than the transition break
size under Sec. 50.46a, where a single failure and the
unavailability of offsite power need not be assumed.
* * * * *
Criterion 41--Containment atmosphere cleanup. Systems to control
fission products, hydrogen, oxygen, and other substances which may
be released into the reactor containment shall be provided as
necessary to reduce, consistent with the functioning of other
associated systems, the concentration and quality of fission
products released to the environment following postulated accidents,
and to control the concentration of hydrogen or oxygen and other
substances in the containment atmosphere following postulated
accidents to assure that containment integrity is maintained.
Each system shall have suitable redundancy in components and
features, and suitable interconnections, leak detection, isolation,
and containment capabilities to assure that for onsite electric
power system operation (assuming offsite power is not available) and
for offsite electric power system operation (assuming onsite power
is not available) its safety function can be accomplished, assuming
a single failure, except for analysis of loss of coolant accidents
involving pipe breaks larger than the transition break size under
Sec. 50.46a, where a single failure and the unavailability of
offsite power need not be assumed.
* * * * *
Criterion 44--Cooling water. A system to transfer heat from
structures, systems, and components important to safety, to an
ultimate heat sink shall be provided. The system safety function
shall be to transfer the combined heat load of these structures,
systems, and components under normal operating and accident
conditions.
Suitable redundancy in components and features, and suitable
interconnections, leak detection, and isolation capabilities shall
be provided to assure that for onsite electric power system
operation (assuming offsite power is not available) and for offsite
electric power system operation (assuming onsite power is not
available) the system safety function can be accomplished, assuming
a single failure, except for analysis of loss of coolant accidents
involving pipe breaks larger than the transition break size under
Sec. 50.46a, where a single failure and the unavailability of
offsite power need not be assumed.
* * * * *
Criterion 50--Containment design basis. The reactor containment
structure, including access openings, penetrations, and the
containment heat removal system shall be designed so that the
containment structure and its internal compartments can accommodate,
without exceeding the design leakage rate and with sufficient
margin, the calculated pressure and temperature conditions resulting
from any loss-of-coolant accident. This margin shall reflect
consideration of (1) the effects of potential energy sources which
have not been included in the determination of the peak conditions,
such as energy in steam generators and as required by Sec. 50.44
energy from metal-water and other chemical reactions that may result
from degradation but not total failure of
[[Page 67630]]
emergency core cooling functioning, (2) the limited experience and
experimental data available for defining accident phenomena and
containment responses, and (3) the conservatism of the calculational
model and input parameters.
For licensees voluntarily choosing to comply with Sec. 50.46a,
the structural and leak tight integrity of the reactor containment
structure, including access openings, penetrations, and its internal
compartments, shall be maintained for realistically calculated
pressure and temperature conditions resulting from any loss of
coolant accident larger than the transition break size.
* * * * *
Dated at Rockville, Maryland, this 28th day of October, 2005.
For the Nuclear Regulatory Commission.
Annette L. Vietti-Cook,
Secretary of the Commission.
[FR Doc. E5-6090 Filed 11-4-05; 8:45 am]
BILLING CODE 7590-01-P