Proposed Generic Communication; Managing Gas Intrusion in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems, 29010-29015 [07-2557]
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Federal Register / Vol. 72, No. 99 / Wednesday, May 23, 2007 / Notices
Appendix A to 10 CFR Part 50 as its
regulatory requirement. The TSTF
stated the improved BPWS provides the
following benefits: (1) Allows the plant
to reach the all-rods-in condition prior
to significant reactor cool down, which
reduces the potential for re-criticality as
the reactor cools down; (2) reduces the
potential for an operator reactivity
control error by reducing the total
number of control rod manipulations;
(3) minimizes the need for manual
scrams during plant shutdowns,
resulting in less wear on control rod
drive (CRD) system components and
CRD mechanisms; and (4) eliminates
unnecessary control rod manipulations
at low power, resulting in less wear on
reactor manual control and CRD system
components. The addition of procedural
requirements and verifications specified
in NEDO–33091–A, along with the
proper use of the BPWS will prevent a
control rod drop accident (CRDA) from
occurring while power is below the low
power setpoint (LPSP). The net change
to the margin of safety is insignificant.
Therefore, this change does not involve
a significant reduction in a margin of
safety.
Based upon the above discussion of
the amendment request, the requested
change does not involve a significant
hazards consideration.
Dated at Rockville, Maryland, this 10th day
of May 2007.
For the Nuclear Regulatory Commission.
Timothy J. Kobetz,
Branch Chief, Technical Specifications
Branch, Division of Inspection & Regional
Support, Office of Nuclear Reactor
Regulation.
[FR Doc. 07–2563 Filed 5–22–07; 8:45 am]
BILLING CODE 7590–01–P
NUCLEAR REGULATORY
COMMISSION
Addresses
Proposed Generic Communication;
Managing Gas Intrusion in Emergency
Core Cooling, Decay Heat Removal,
and Containment Spray Systems
Nuclear Regulatory
Commission.
AGENCY:
Notice of opportunity for public
comment.
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ACTION:
SUMMARY: The U.S. Nuclear Regulatory
Commission (NRC) is proposing to issue
a generic letter (GL) to address the issue
of gas intrusion into the emergency core
cooling, decay heat removal, and
containment spray systems (hereinafter
referred to as the ‘‘subject systems’’).
Specifically, the NRC is issuing this GL
for the following two purposes:
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(1) to request addressees to submit
information demonstrating that the
subject systems are in compliance with
the current licensing and design bases,
and applicable regulatory requirements,
and that suitable design, operational,
and testing control measures are in
place for maintaining this compliance,
and
(2) to collect the requested
information to determine if additional
regulatory action is required.
This Federal Register notice is
available through the NRC’s
Agencywide Documents Access and
Management System (ADAMS) under
accession number ML0704001003.
DATES: Comment period expires July 23,
2007. Comments submitted after this
date will be considered if it is practical
to do so, but assurance of consideration
cannot be given except for comments
received on or before this date.
ADDRESSES: Submit written comments
to the Chief, Rulemaking, Directives,
and Editing Branch, Division of
Administrative Services, Office of
Administration, U.S. Nuclear Regulatory
Commission, Mail Stop T6–D59,
Washington, DC 20555–0001, and cite
the publication date and page number of
this Federal Register notice. Written
comments may also be delivered to NRC
Headquarters, 11545 Rockville Pike
(Room T–6D59), Rockville, Maryland,
between 7:30 a.m. and 4:15 p.m. on
Federal workdays.
FOR FURTHER INFORMATION, CONTACT:
Warren C. Lyon, NRR, at 301–415–2897
or by e-mail: wcl@nrc.gov or David P.
Beaulieu, NRR, at 301–415–3243 or by
e-mail: dpb@nrc.gov.
SUPPLEMENTARY INFORMATION:
NRC Generic Letter 2007–XX,
Managing Gas Intrusion in Emergency
Core Cooling, Decay Heat Removal, and
Containment Spray Systems
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All holders of operating licenses for
nuclear power reactors, except those
who have permanently ceased
operations and have certified that fuel
has been permanently removed from the
reactor vessel.
Purpose
The U.S. Nuclear Regulatory
Commission (NRC) is issuing this
generic letter (GL) to address the issue
of gas 1 intrusion into the emergency
core cooling, decay heat removal 2, and
1 Gas as used here includes, air, nitrogen,
hydrogen, water vapor, or any other void that is not
filled with liquid water.
2 Decay heat removal (DHR), residual heat
removal (RHR), and shutdown cooling (SDC) are
common names for systems used to cool the reactor
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containment spray systems (hereinafter
referred to as the ‘‘subject systems’’).
Specifically, the NRC is issuing this GL:
(1) To request addressees to submit
information to demonstrate that the
subject systems are in compliance with
the current licensing and design bases
and applicable regulatory requirements,
and that suitable design, operational,
and testing control measures are in
place for maintaining this compliance,
and
(2) to collect the requested
information to determine if additional
regulatory action is required.
Pursuant to Title 10 of the Code of
Federal Regulations (10 CFR) Section
50.54(f), addressees are required to
submit a written response to this GL.
Background
Instances of gas intrusion into the
subject systems have occurred since the
beginning of commercial nuclear power
plant operation. The NRC has published
20 information notices (INs), two GLs,
and a NUREG 3 that are related to this
issue and has interacted with the
nuclear industry many times in relation
to these publications and in response to
gas intrusion events. The following
paragraphs summarize a few events to
illustrate some of the technical and
regulatory requirements issues.
In May 1997, at Oconee Nuclear
Station Unit 3, hydrogen ingestion
during plant cooldown damaged and
rendered nonfunctional two highpressure injection (HPI) pumps. If the
operators had started the remaining HPI
pump, it too would have been damaged.
The NRC responded with an augmented
inspection team (IN 97–38, ‘‘LevelSensing System Initiates Common-Mode
Failure of High-Pressure-Injection
Pumps,’’ Agencywide Documents
Access and Management System
(ADAMS) Accession No. ML031050514,
June 24, 1997). The NRC team reported
that there had been a total lack of HPI
capability during power operation, a
failure to meet technical specification
(TS) HPI operability requirements,
design deficiencies, inadequate
maintenance practices, operators that
were less than attentive to plant
parameters, a failure to adequately
assess operating experience, and a
violation of 10 CFR part 50, Appendix
coolant system (RCS) during some phases of
shutdown operation. The NRC staff generally uses
DHR here.
3 GL 88–17, ‘‘Loss of Decay Heat Removal,’’
October 17, 1988 (ML031200496); GL 97–04,
‘‘Assurance of Sufficient Net Positive Suction Head
for Emergency Core Cooling and Containment Heat
Removal Pumps,’’ October 7, 1997 (ML031110062);
and NUREG–0897, Revision 1, ‘‘Containment
Emergency Sump Performance—Technical Findings
Related to USI A–43,’’ October 1985.
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B, Criterion III (‘‘Notice of Violation and
Proposed Imposition of Civil Penalties
—$330,000,’’ August 27, 1997, https://
www.nrc.gov/reading-rm/doccollections/enforcement/actions/
reactors/ea97297.html).
As a result of this Oconee Unit 3
event, the industry initiated an
industry-wide improvement activity to
address the gas issue. Based on the
industry actions, the NRC concluded
that no generic action was necessary.
However, significant gas events that
jeopardized the operability of the
subject systems continued to occur, as
illustrated in the following paragraphs.
Dresden Nuclear Power Station Unit 3
experienced a reactor scram on July 5,
2001, that was accompanied by a water
hammer as a result of high pressure
coolant injection (HPCI) system voids
due to inadequate pipe venting. The
licensee discovered a damaged pipe
support that rendered the HPCI system
inoperable on July 19, 2001. On
September 28, 2001, NRC inspectors
discovered discrepancies in another
HPCI hanger that may have been caused
by the water hammer. The licensee
repaired the hangers on September 30,
2001, and vented the system. An NRC
inspector identified a high point that
had not been vented and air was
removed when the licensee vented that
location. The HPCI system was
inoperable from July 5, 2001, to
September 30, 2001 (NRC Supplemental
Inspection Report 50–237, 50–239/
2003–012, ML033530204, December 18,
2003). The NRC found violations of 10
CFR 50.9, a TS, and 10 CFR part 50,
Appendix B, Criterion XVI (‘‘Notice of
Violation and Proposed Imposition of
Civil Penalty—$60,000, and Final
Significance Determination for a White
Finding,’’ ML031740755, June 23, 2003).
On August 14, 2003, the Perry
Nuclear Power Plant scrammed from
100 percent power due to a loss of
offsite power. This caused a momentary
loss of common water leg pumps 4 and
a discharge pressure decrease from 44
psig to 7 psig allowed accumulated gas
to completely void a water leg pump
and the associated feedwater leakage
control system piping. Pump operation
was restored by venting the pump
casing but a piping high point that was
not included in fill and vent procedures
was not vented. On September 10, 2003,
the licensee vented enough gas from the
high point that would have caused the
pump to be non-functional if another
4 These are 40 gpm pumps used to compensate for
back-leakage through check valves in RHR and LPSI
piping into the suppression pool. The purpose is to
keep piping full of water where the pipe elevation
is higher than the suppression pool. The system is
often referred to as a ‘‘keep-full’’ system.
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loss of offsite power would occur. If the
RHR and/or the LPCS pumps had
started while the leakage control system
piping was voided, the resulting water
hammer could have caused the system
piping to rupture. The NRC
characterized the inspection finding as
white; the finding resulted in a TS
violation, escalated enforcement action,
and a supplemental inspection (NRC
Inspection Report 50–440/2003–009,
ML032880107, October 10, 2003, and
ML040330980, January 30, 2004).
On July 28, 2004, the Palo Verde
licensee identified that emergency core
cooling system (ECCS) suction piping
voids in all three Palo Verde units could
have resulted in a loss of the ECCS
during transfer to the recirculation
mode for some loss-of-coolant accident
(LOCA) conditions. The condition had
existed since plant startups in 1986, was
contrary to the Palo Verde final safety
analysis reports (FSARs), and would not
be identified during testing because
water is not drawn from the
containment emergency sumps. The
NRC inspectors identified multiple
violations of 10 CFR part 50, Appendix
B, Criteria III and V, and violations of
10 CFR 50.59. The NRC responded with
a special inspection, issued a yellow
finding, and imposed a civil penalty of
$50,000 (NRC Special Inspection Report
50–328, 50–329, 50–330/2004–014,
ML050050287, January 5, 2005). The
Palo Verde licensee identified the ECCS
piping suction voids after being
contacted by engineer from another
plant where an NRC inspector identified
the same problem.
In February 2005, an HPI pump at
Indian Point Energy Center Unit 2 was
found inoperable because the pump
casing was filled with gas. The licensee
then found numerous locations in the
ECCS piping with gas accumulation.
The licensee did not initially
understand the implications of the gas
condition, and the licensee’s early
assessments were inadequate,
particularly with respect to assessing
the operability of the other two HPI
pumps. The NRC conducted a special
inspection that found one HPI pump
was not functional and the other two
HPI pumps had a 75 percent failure
probability. The NRC found several
violations of 10 CFR part 50, Appendix
B, Criterion XVI, and issued a white
finding (NRC Inspection Report 50–247/
2005–006, ML051680119, June 17,
2005).
In March 2005, the NRC reported that
Diablo Canyon had a sustained history
of gas voiding in piping that could
possibly result in gas binding or damage
to the centrifugal charging pumps or the
HPSI pumps during switchover from
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29011
cold-leg to hot-leg injection.5 The NRC
inspectors concluded that the licensee
focused on managing the symptom of
the problem rather than finding and
eliminating the cause, which is contrary
to 10 CFR part 50, Appendix B,
Criterion XVI (NRC Inspection Report
50–275, 50–323/2005–006,
ML050910120, March 31, 2005).
In September 2005, operators
discovered a void in the HPCI pump
discharge piping at the Duane Arnold
Energy Center due to ‘‘turbulent
penetration’’ that caused hot water from
the feedwater pipe to penetrate
downward into the HPCI discharge
pipe. This heated the HPCI pipe on the
low pressure side of a closed valve to
greater than the saturation temperature
and caused steam to be generated in the
low pressure pipe as fast as it was
vented. The condition had existed since
plant startup (Licensee Event Report 50–
331/2005–004, ML053360261,
November 28, 2005). The NRC opened
an unresolved item (URI 05000331/
2006002–03) for further NRC review of
the licensee’s piping analysis that
evaluated HPSI system operability with
the voided piping (NRC Inspection
Report 50–331/2006–002,
ML061210448, April 27, 2006, and NRC
Inspection Report 50–331/2006–008,
ML070640515, March 2, 2007).
In October 2005, an NRC inspection
team at the Palo Verde Nuclear
Generating Station identified that,
following a postulated accident when
refueling water tank (RWT) level
reached the setpoint for containment
sump recirculation, the licensee’s
design basis credited containment
pressure for preventing the ECCS pumps
from continuing to reduce RWT level
and drawing air into the ECCS.
However, a recent licensee analysis
showed that the minimum containment
pressure would be less than needed.
The licensee declared the ECCS
inoperable at all three units, requiring a
shutdown of Units 2 and 3 (Unit 1 was
already shut down). The NRC found
multiple violations of 10 CFR part 50,
Appendix B, Criteria III and V (NRC
Supplemental Inspection Report 50–
528, 50–529, 50–530/2005–012,
ML060300193, January 27, 2006).
These are a few of the more than 60
gas intrusion events reported during
recent years involving the subject
5 A similar gas accumulation problem under
closed valves in the recirculation piping from the
DHR discharge to the HPSI and charging pump
suctions has occurred at several plants. This has the
potential to cause loss of all high pressure RCS
makeup capability when shifting suction to the
emergency containment sump from the refueling
water or borated water storage tank following a
LOCA.
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systems. The number is larger if other
similar events at the same plant are
counted. Further, many events do not
have to be reported to the NRC, and
many of them have not been addressed
during the NRC’s inspections. For
example, at least 40 RHR water hammer
events have occurred at the Sequoyah
Nuclear Plant, although none of them
rendered the RHR system inoperable.
Additionally, if an ECCS pump has been
damaged because of gas but is repaired
and tested operable within the TS
completion time (typically, 72 hours),
the licensee is not required to report the
occurrence to the NRC. The frequency
and the significance of these events and
the likelihood that unidentified gas
issues exist require licensee action to
ensure compliance with regulatory
requirements that will maintain
operability of the subject systems.
Applicable Regulatory Requirements
10 CFR part 50 Appendix A or similar
plant-specific principal design criteria 6
provide design requirements, and 10
CFR part 50 Appendix B, TSs, and
licensee quality assurance programs
provide operating requirements.
Appendix A requirements applicable to
gas management in the subject systems
include the following:
• General Design Criterion (GDC) 1
requires that the subject systems be
designed, fabricated, erected, and tested
to quality standards.
• GDC 34 requires an RHR system
designed to maintain specified
acceptable fuel design limits and to
meet design conditions that are not
exceeded if a single failure occurs and
specified electrical power systems fail.
• GDC 35, 36, and 37 require an ECCS
design that meets performance,
inspection, and testing requirements.
Specified performance criteria are
provided in 10 CFR 50.46.
• GDC 38, 39, and 40 require a
containment heat removal system
design that meets performance,
inspection, and testing requirements.
Quality assurance criteria provided in
Appendix B that apply to gas
management in the subject systems
include the following:
• Criteria III and V require measures
to assure that applicable regulatory
requirements and the design basis, as
defined in 10 CFR 50.2, ‘‘Definitions,’’
and as specified in the license
application, are correctly translated into
controlled specifications, drawings,
procedures, and instructions.
• Criterion XI requires a test program
to assure that the subject systems will
6 For facilities with a construction permit issued
prior to May 21, 1972, that are not licensed to
Appendix A.
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perform satisfactorily in service. Test
results shall be documented and
evaluated to assure that test
requirements have been satisfied.
• Criterion XVI requires measures to
assure that conditions adverse to
quality, such as failures, malfunctions,
deficiencies, deviations, defective
material and equipment, and
nonconformances, are promptly
identified, corrected, documented, and
reported to management.
• Criterion XVII requires maintenance
of records of activities affecting quality.
Further, as part of the licensing basis,
licensees have committed to certain
quality assurance provisions that are
identified in both their TSs and quality
assurance programs. Licensees have
committed to use the guidance of
Regulatory Guide (RG) 1.33, ‘‘Quality
Assurance Requirements (Operation),’’
which endorses American National
Standards Institute (ANSI) N18.7–1976/
American Nuclear Society 3.2,
‘‘Administrative Controls and Quality
Assurance for the Operational Phase of
Nuclear Power Plants,’’ or equivalent
licensee-specific guidance. Section
5.3.4.4, ‘‘Process Monitoring
Procedures,’’ of ANSI N18.7 that states
that procedures for monitoring
performance of plant systems shall be
required to assure that engineered safety
features and emergency equipment are
in a state of readiness to maintain the
plant in a safe condition if needed. The
limits (maximum and minimum) for
significant process parameters shall be
identified. Operating procedures shall
address the nature and frequency of this
monitoring, as appropriate.
10 CFR 50.36(c)(3) defines TS
surveillance requirements (SRs) as
‘‘relating to test, calibration, or
inspection to assure’’ maintenance of
quality, operation within safety limits,
and operability. Typically, TS Section 5
or 6 requires that licensees establish,
implement, and maintain written
procedures covering the applicable
procedures recommended in Appendix
A to RG 1.33, Revision 2 (February
1978). Appendix A to RG 1.33 identifies
instructions for filling and venting the
ECCS and DHR system, as well as for
draining and refilling heat exchangers.
Surveillance requirements to verify that
at least some of the subject system
piping is filled are provided in standard
technical specifications (STSs) and in
most licensee TSs.
Discussion
The events discussed in the
BACKGROUND section illustrate that
many of the regulatory requirements
identified in the APPLICABLE
REGULATORY REQUIREMENTS
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section are not being met. The NRC
inspectors often find that the 10 CFR
part 50 Appendix B criteria identified
above are not adequately addressed in
plant venting procedures. In some cases,
venting procedures were almost
nonexistent, there were no records of
gas quantities that were vented and
licensees unsuccessfully attempted to
recreate the history by asking operators
for their recollections. Consequently,
there was no foundation for establishing
that the subject systems were operable
prior to venting. In addition, the venting
processes sometimes did not ensure that
all gas was removed from the venting
location and often did not adequately
establish the quantity of vented gas.
Further, examination of ultrasonic test
(UT) processes at several licensee sites
established that one licensee initially
did not know how to acceptably
determine liquid level via UT.
Additional issues include TSs, which
often do not require venting of suction
piping despite voids in suction pipes
generally being of more concern than in
discharge piping, and do not adequately
address operability of the subject
systems prior to surveillance and for the
time span until the next surveillance.
This GL and the anticipated NRC
followup to this GL are intended to
correct such conditions.
It is important that the subject
systems are sufficiently filled with
water to ensure that they can reliably
perform their intended functions under
all LOCA and non-LOCA conditions
that require makeup to the RCS.
Portions of these systems and some of
the associated pumps are normally in a
standby condition while other pumps
provide both ECCS and operational
functions. For example, some highpressure pumps are used for normal
RCS makeup, and some low-pressure
pumps provide a normal DHR
capability.
The following safety issues are
associated with gas intrusion into the
subject systems:
(1) The introduction of gas into a
pump can cause the pump to become
air-bound with little or no flow,
rendering the pump inoperable. Airbinding can render more than one pump
inoperable when pumps share common
discharge or suction headers, or when
the gas accumulation process affects
more than one train, greatly increasing
the risk significance. Such a commonmode failure would result in the
inability of the ECCS or the DHR system
to provide adequate core cooling and
the inability of the containment spray
system to maintain the containment
pressure and temperature below design
limits. An air-bound pump can become
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damaged quickly, eliminating the
possibility of recovering the pump
during an event by simply subsequently
venting the pump and suction piping.
(2) Gas introduced into a pump can
render the pump inoperable, even if the
gas does not air bind the pump, because
the gas can reduce the pump discharge
pressure and flow capacity to the point
that the pump cannot perform its design
function. For example, an HPI pump
that is pumping air-entrained water may
not develop sufficient discharge
pressure to inject under certain small
break LOCA scenarios.
(3) Gas accumulation can result in
water hammer or a system pressure
transient, particularly in pump
discharge piping following a pump start,
which can cause piping and component
damage or failure. Gas accumulation in
the DHR system has resulted in pressure
transients that have caused DHR system
relief valves to open. In some plants, the
relief valve reseating pressure is less
than the existing RCS pressure, a
condition that complicates recovery.
(4) Pump cavitation caused by
entrained gas results in additional
stresses that can lead to premature
failure of pump components that can
render the pump inoperable.
(5) Gas intrusion can result in
pumping noncondensible gas into the
reactor vessel that may affect core
cooling flow.
(6) The time needed to fill voided
discharge piping can delay delivery of
water beyond the time frame assumed in
the accident analysis.
The scope and number of identified
gas intrusion problems at some facilities
raise concerns about whether similar
unrecognized design, configuration, and
operability problems exist at other
reactor facilities.
A review of the operating experience
has identified the following concerns,
which are the focus of this GL:
(1) TS SRs, as implemented by
associated surveillance procedures,
have not reliably precluded gas
problems. Operating experience shows
many instances in which substantive
gas voiding in the system piping has not
been identified. The surveillance
procedures may not reliably reveal asfound conditions in which the system
may be inoperable or degraded because
of gas. Additionally, some plants have
no TS SR to verify that the subject
systems’ piping is sufficiently full of
water. Still other plants have
incomplete TS SRs that cover only
portions of the system. For example, the
TS may require verifying that ECCS
discharge piping is full of water but may
not include verification of the suction
piping or containment spray piping.
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Although the TS and FSAR at many
facilities indicate that the subject
systems are full of water, in practice it
is not uncommon for licensees to vent
some gas during periodic surveillances.
Further, there may be some parts of
these systems where it is not possible or
practical to verify them to be full of
water. Hence, the current TS and FSAR
may establish a standard that may not
be realistic to establish system
operability. A realistic standard should
bound the volume of gas that may
impact pump operability and the
volume for which water-hammerinduced stress limits may be exceeded.
Criterion XI of Appendix B to 10 CFR
part 50 requires licensees to perform
testing using written test procedures,
which include but are not limited to
procedures for TS SRs, that incorporate
the requirements and acceptance limits
contained in applicable design
documents. TSs often require
surveillance of discharge piping but do
not mention suction piping.
Consequently, suction piping
surveillances may not be performed.
However, since the subject systems may
be rendered inoperable or degraded
because of gas in suction piping, the
regulations require that presence of gas
in all piping be assessed to establish
operability.
(2) Typically the FSAR describes that
the subject systems are filled with
water. The wording of TS SRs further
confirms that the design-basis
configuration calls for the specified
piping to be filled with water. Operating
experience provides many examples of
licensees treating the accumulation of
gas as an expected condition (rather
than a nonconforming condition) that
was not documented even when it
involved a substantial volume of gas
that clearly constituted a significant
condition adverse to quality. In such
cases, Criterion XVI of Appendix B to 10
CFR part 50 requires that the cause of
the condition be determined and
corrective action taken to preclude
repetition. Based on the as-found
volume and location of gas, corrective
actions beyond simply refilling a system
may be necessary to provide reasonable
assurance that the affected system will
remain operable until the next
surveillance.
(3) Although the subject systems are
often susceptible to gas intrusion, not all
plants have vent valves at one or more
system high points. Some licensees have
installed additional vent valves at
system high points after operational
events. For example, one licensee
installed an additional 21 high-point
vent valves. Another licensee, who
installed an additional 17 vent valves,
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determined that the primary cause of
the gas voiding problem was that the
original design specification did not call
for a sufficient number of vent valves.
No specific NRC requirement mandates
the installation of vent valves on the
subject systems. However, failure to
translate the design basis of assuring the
system is maintained sufficiently full of
water to maintain operability into
drawings, specifications, procedures,
and instructions is a violation of
Criterion III in Appendix B of 10 CFR
part 50.
Further, Criterion V requires
documented instructions, procedures, or
drawings that include appropriate
quantitative or qualitative acceptance
criteria for determining that important
activities have been satisfactorily
accomplished. This means that each
addressee must have suitable
documentation and records, including
acceptance criteria, to establish that the
subject systems have been and are
maintained sufficiently full of water to
ensure system operability. Vent valves
and their use are often a key ingredient
for satisfying these requirements.
The NRC staff is initiating a Technical
Specifications Task Force (TSTF)
activity to address the recognized TS
weaknesses associated with gas
intrusion concerns. In the interim, until
new TSs are developed, the NRC staff
will treat a SR that the piping be full of
water as satisfied if the piping and
pumps of the subject systems are
maintained sufficiently full of water to
ensure system operability when
operability is required. This condition
must be shown to be satisfied during the
time between surveillances, and either
venting or UT surveillances are
acceptable means of obtaining void data.
Further, the NRC staff will consider
justification for not conducting a
periodic surveillance or for extending
the time between surveillances of
certain sections of piping if an
addressee considers surveillance to be
unnecessary. For example, some three
loop plants designed by Westinghouse
maintain HPSI discharge lines at a
pressure greater than the RCS operating
pressure. This eliminates the potential
for leakage from the accumulators or the
RCS as a possible means to introduce
gas into the discharge lines. An
assessment for such plants that (1)
acceptably eliminates other means of
introducing gas, (2) establishes
acceptable verification that the lines are
essentially full following a condition
that reduces the discharge line pressure,
and (3) establishes an operating history
confirming that gas has not accumulated
will be adequate justification for not
conducting surveillances inside
E:\FR\FM\23MYN1.SGM
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29014
Federal Register / Vol. 72, No. 99 / Wednesday, May 23, 2007 / Notices
containment or at locations that
constitute a hazard to personnel
performing the assessment. The NRC
memorandum, ‘‘Technical
Considerations for Reasonably Assuring
Emergency Core Cooling, Decay Heat
Removal, and Containment Spray
Systems Operability,’’ ML071030382,
April 17, 2007, provides some operating
experience insights. The NRC staff plans
to use this information during
inspection activities that are planned as
a followup to this GL and for guidance
in the TSTF program to develop
improved TSs.
Requested Actions
Each addressee is requested to
evaluate their ECCS, DHR system, and
containment spray system designs,
operation, and test procedures to assure
that gas intrusion is minimized and
monitored in order to maintain system
operability and compliance with the
requirements of Appendix B to 10 CFR
part 50.
Requested Information
Each addressee is requested to
provide a summary description of how
the REQUESTED ACTIONS have been
addressed within 6 months of the date
of this GL. This summary description
should specifically address the quality
assurance criteria in 10 CFR part 50,
Appendix B, Sections III, V, XI, XVI,
and XVII and the TSs that apply to the
subject systems. This summary should
include a general description of: (1) The
design, (2) the operating procedures,
and (3) the test procedures to assure that
gas intrusion does not affect the ability
of the subject systems to perform their
intended functions.
If an addressee determines that
system or procedure modifications are
necessary based on the review of the
requested actions and these changes
cannot be accomplished within 6
months of the date of this GL, then the
addressee should also provide a plan
and schedule for completion of these
actions.
generic letter, an addressee is required
to submit a written response if they are
unable to provide the information or
they cannot meet the requested
completion date. The addressee must
address in its response any alternative
course of action that it proposes to take,
including the basis for the acceptability
of the proposed alternative course of
action.
The required written response should
be addressed to the U.S. Nuclear
Regulatory Commission, ATTN:
Document Control Desk, 11555
Rockville Pike, Rockville, MD 20852,
under oath or affirmation under the
provisions of section 182a of the Atomic
Energy Act of 1954, as amended, and 10
CFR 50.54(f). In addition, submit a copy
of the response to the appropriate
regional administrator.
Required Response
In accordance with 10 CFR 50.54(f), in
order to determine whether a facility
license should be modified, suspended,
or revoked, or whether other action
should be taken, an addressee is
required to respond as described below.
Within 6 months of the date of this
Reasons for Information Request
The NRC is requesting this
information because a review of
operating experience shows numerous
instances of gas intrusion events
involving the subject systems that have
rendered or potentially rendered these
risk-significant systems inoperable.
RELATED GENERIC COMMUNICATIONS
ADAMS
accession No.
Document No.
Document name
GL 88–17 .....................
GL 97–04 .....................
Loss of Decay Heat Removal .................................................................................................................
Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment
Heat Removal Pumps.
Loss of Safety Injection Capability ..........................................................................................................
Unit Startup with Degraded High Pressure Safety Injection System .....................................................
Inadequate Net Positive Suction Head in Low Pressure Safety Systems .............................................
Potential for Gas Binding of High-Pressure Safety ................................................................................
Injection Pumps During a Loss-of-Coolant Accident ..............................................................................
..................................................................................................................................................................
..................................................................................................................................................................
..................................................................................................................................................................
Potentially Inadequate Performance of ECCS in PWRs during Recirculation Operation Following a
LOCA.
Loss of Residual Heat Removal Caused by Accumulator Nitrogen Injection ........................................
Potential for Water Hammer, Thermal Stratification, and Steam Binding in High-Pressure Coolant Injection Piping.
Potential for Common-Mode Failure of High Pressure Safety Injection Pumps or Release of Reactor
Coolant Outside Containment During a Loss-of-Coolant Accident.
A Review of Water Hammer Events after 1985 .....................................................................................
Undetected Accumulation of Gas in Reactor System ............................................................................
Recent Failures of Charging/Safety Injection Pump Shafts ...................................................................
Loss of Reactor Coolant Inventory and Potential Loss of Emergency Mitigation Functions While in a
Shutdown Condition.
Inadequate Net Positive Suction Head of Emergency Core Cooling and Containment Heat Removal
Pumps under Design Basis Accident Conditions.
Undetected Accumulation of Gas in Reactor Coolant System and Inaccurate Reactor Water Level
Indication During Shutdown.
Level-Sensing System Initiates Common-Mode Failure of High Pressure Injection Pumps .................
Potential Nitrogen Accumulation Resulting from Back-Leakage from Safety Injection Tanks ...............
Design Deficiencies Can Lead to Reduced ECCS Pump Net Positive Suction Head During DesignBasis Accidents.
Potential Hydrogen Combustion Events in BWR Piping ........................................................................
..................................................................................................................................................................
Effect of Adding Gas Into Water Storage Tanks on the Net Positive Suction Head for Pumps ...........
IN
IN
IN
IN
IN
IN
IN
IN
IN
86–63 ......................
86–80 ......................
87–63 ......................
88–23 ......................
88–23, Supp. 1 .......
88–23, Supp. 2 .......
88–23, Supp. 3 .......
88–23, Supp. 4 .......
88–74 ......................
IN 89–67 ......................
IN 89–80 ......................
IN 90–64 ......................
IN
IN
IN
IN
91–50
94–36
94–76
95–03
......................
......................
......................
......................
IN 96–55 ......................
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IN 96–65 ......................
IN 97–38 ......................
IN 97–40 ......................
IN 98–40 ......................
IN 02–15 ......................
IN 02–15, Supp. 1 .......
IN 02–18 ......................
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Federal Register / Vol. 72, No. 99 / Wednesday, May 23, 2007 / Notices
RELATED GENERIC COMMUNICATIONS—Continued
ADAMS
accession No.
Document No.
Document name
IN 06–21 ......................
Operating Experience Regarding Entrainment of Air Into Emergency Core Cooling and Containment
Spray Systems.
Backfit Discussion
Under the provisions of Section 182a
of the Atomic Energy Act of 1954, as
amended, this GL requests a review and
appropriate resulting actions for the
purpose of assuring compliance with
applicable existing requirements. No
backfit is either intended or approved
by the issuance of this GL. Therefore,
the NRC staff has not performed a
backfit analysis.
Federal Register Notification
To be done after the public comment
period.
Congressional Review Act
In accordance with the Congressional
Review Act, the NRC has determined
that this GL is not a major rule and the
Office of Information and Regulatory
Affairs of the Office of Management and
Budget has confirmed this
determination.
pwalker on PROD1PC71 with NOTICES
Paperwork Reduction Act Statement
This GL contains an information
collection that is subject to the
Paperwork Reduction Act of 1995 (44
U.S.C. 3501 et seq.). The Office of
Management and Budget approved this
information collection under clearance
number 3150–0011.
The burden to the public for this
mandatory information collection is
estimated to average 300 hours per
response, including the time for
reviewing instructions, searching
existing data sources, gathering and
maintaining the data needed, and
completing and reviewing the
information collection. The NRC is
seeking public comment on the
potential impact of the information
collection contained in the GL 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?
2. Is the estimate of burden accurate?
3. Is there a way to enhance the
quality, utility, and clarity of the
information collected?
4. How can the burden of the
information collection be minimized,
including the use of automated
collection techniques?
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Jkt 211001
Send comments on any aspect of this
information collection, including
suggestions for reducing the burden, to
the Records and FOIA/Privacy Services
Branch (T5–F52), U.S. Nuclear
Regulatory Commission, Washington,
DC 20555–0001, or by Internet
electronic mail to infocollects@nrc.gov;
and to the Desk Officer, Office of
Information and Regulatory Affairs,
NEOB–10202 (3150–0011), Office of
Management and Budget, Washington,
DC 20503.
Public Protection Notification: The
NRC may not conduct or sponsor, and
a person is not required to respond to,
an information collection unless the
requesting document displays a
currently valid OMB control number.
Contact: Please direct any questions
about this matter to the technical
contact or the Lead Project Manager
listed below, or to the appropriate Office
of Nuclear Reactor Regulation (NRR)
project manager.
Michael J. Case, Director, Division of
Policy and Rulemaking, Office of
Nuclear Reactor Regulation.
Technical Contact: Warren C. Lyon,
NRR, 301–415–2897, e-mail:
wcl@nrc.gov.
Lead Project Manager: David P.
Beaulieu, NRR, 301–415–3243, e-mail:
dpb@nrc.gov.
Note: NRC generic communications may be
found on the NRC public Web site, https://
www.nrc.gov, under Electronic Reading
Room/Document Collections.
End of Draft Generic Letter
Documents may be examined, and/or
copied for a fee, at the NRC’s Public
Document Room at One White Flint
North, 11555 Rockville Pike (first floor),
Rockville, Maryland. Publicly available
records will be accessible electronically
from the Agencywide Documents
Access and Management System
(ADAMS) Public Electronic Reading
Room on the Internet at the NRC Web
site, https://www.nrc.gov/NRC/ADAMS/
index.html. If you do not have access to
ADAMS or if you have problems in
accessing the documents in ADAMS,
contact the NRC Public Document Room
(PDR) reference staff at 1–800–397–4209
or 301–415–4737 or by e-mail to
pdr@nrc.gov.
Dated at Rockville, Maryland, this 16th day
of May 2007.
PO 00000
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ML062570468
For the Nuclear Regulatory Commission.
Jennifer Golder, Acting Director, Division of
Policy and Rulemaking, Office of Nuclear
Reactor Regulation.
[FR Doc. 07–2557 Filed 5–22–07; 8:45 am]
BILLING CODE 7590–01–P
SECURITIES AND EXCHANGE
COMMISSION
[Release No. 34–55776; File No. SR–Amex–
2007–29]
Self-Regulatory Organizations;
American Stock Exchange LLC; Order
Granting Accelerated Approval of a
Proposed Rule Change, as Modified by
Amendment No. 1 Thereto, Relating to
the Listing and Trading of Notes
Linked to the Performance of the Dow
Jones-AIG Commodity Index Total
Return
May 17, 2007.
I. Introduction
On March 2, 2007, the American
Stock Exchange LLC (‘‘Amex’’ or
‘‘Exchange’’) filed with the Securities
and Exchange Commission
(‘‘Commission’’) a proposed rule change
pursuant to Section 19(b)(1) of the
Securities Exchange Act of 1934
(‘‘Act’’) 1 and Rule 19b–4 thereunder.2
On April 5, 2007, Amex filed
Amendment No. 1 to the proposed rule
change. The proposed rule change, as
amended, was published for comment
in the Federal Register on May 1, 2007
for a 15-day comment period.3 The
Commission received no comments on
the proposal. This order approves the
proposed rule change, as modified by
Amendment No. 1, on an accelerated
basis.
II. Description of the Proposal
Under Section 107A of the Amex
Company Guide (‘‘Company Guide’’),
the Exchange may approve for listing
and trading securities which cannot be
readily categorized under the listing
criteria for common and preferred
stocks, bonds, debentures, or warrants,
including index and currency warrants.
Amex proposes to list for trading under
1 15
U.S.C. 78s(b)(1).
CFR 240.19b–4.
3 See Securities Exchange Act Release No. 55661
(April 24, 2007), 72 FR 23862 (‘‘Notice’’).
2 17
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]]>Agencies
[Federal Register Volume 72, Number 99 (Wednesday, May 23, 2007)]
[Notices]
[Pages 29010-29015]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 07-2557]
-----------------------------------------------------------------------
NUCLEAR REGULATORY COMMISSION
Proposed Generic Communication; Managing Gas Intrusion in
Emergency Core Cooling, Decay Heat Removal, and Containment Spray
Systems
AGENCY: Nuclear Regulatory Commission.
ACTION: Notice of opportunity for public comment.
-----------------------------------------------------------------------
SUMMARY: The U.S. Nuclear Regulatory Commission (NRC) is proposing to
issue a generic letter (GL) to address the issue of gas intrusion into
the emergency core cooling, decay heat removal, and containment spray
systems (hereinafter referred to as the ``subject systems'').
Specifically, the NRC is issuing this GL for the following two
purposes:
(1) to request addressees to submit information demonstrating that
the subject systems are in compliance with the current licensing and
design bases, and applicable regulatory requirements, and that suitable
design, operational, and testing control measures are in place for
maintaining this compliance, and
(2) to collect the requested information to determine if additional
regulatory action is required.
This Federal Register notice is available through the NRC's
Agencywide Documents Access and Management System (ADAMS) under
accession number ML0704001003.
DATES: Comment period expires July 23, 2007. Comments submitted after
this date will be considered if it is practical to do so, but assurance
of consideration cannot be given except for comments received on or
before this date.
ADDRESSES: Submit written comments to the Chief, Rulemaking,
Directives, and Editing Branch, Division of Administrative Services,
Office of Administration, U.S. Nuclear Regulatory Commission, Mail Stop
T6-D59, Washington, DC 20555-0001, and cite the publication date and
page number of this Federal Register notice. Written comments may also
be delivered to NRC Headquarters, 11545 Rockville Pike (Room T-6D59),
Rockville, Maryland, between 7:30 a.m. and 4:15 p.m. on Federal
workdays.
FOR FURTHER INFORMATION, CONTACT: Warren C. Lyon, NRR, at 301-415-2897
or by e-mail: wcl@nrc.gov or David P. Beaulieu, NRR, at 301-415-3243 or
by e-mail: dpb@nrc.gov.
SUPPLEMENTARY INFORMATION:
NRC Generic Letter 2007-XX, Managing Gas Intrusion in Emergency
Core Cooling, Decay Heat Removal, and Containment Spray Systems
Addresses
All holders of operating licenses for nuclear power reactors,
except those who have permanently ceased operations and have certified
that fuel has been permanently removed from the reactor vessel.
Purpose
The U.S. Nuclear Regulatory Commission (NRC) is issuing this
generic letter (GL) to address the issue of gas \1\ intrusion into the
emergency core cooling, decay heat removal \2\, and containment spray
systems (hereinafter referred to as the ``subject systems'').
Specifically, the NRC is issuing this GL:
---------------------------------------------------------------------------
\1\ Gas as used here includes, air, nitrogen, hydrogen, water
vapor, or any other void that is not filled with liquid water.
\2\ Decay heat removal (DHR), residual heat removal (RHR), and
shutdown cooling (SDC) are common names for systems used to cool the
reactor coolant system (RCS) during some phases of shutdown
operation. The NRC staff generally uses DHR here.
---------------------------------------------------------------------------
(1) To request addressees to submit information to demonstrate that
the subject systems are in compliance with the current licensing and
design bases and applicable regulatory requirements, and that suitable
design, operational, and testing control measures are in place for
maintaining this compliance, and
(2) to collect the requested information to determine if additional
regulatory action is required.
Pursuant to Title 10 of the Code of Federal Regulations (10 CFR)
Section 50.54(f), addressees are required to submit a written response
to this GL.
Background
Instances of gas intrusion into the subject systems have occurred
since the beginning of commercial nuclear power plant operation. The
NRC has published 20 information notices (INs), two GLs, and a NUREG
\3\ that are related to this issue and has interacted with the nuclear
industry many times in relation to these publications and in response
to gas intrusion events. The following paragraphs summarize a few
events to illustrate some of the technical and regulatory requirements
issues.
---------------------------------------------------------------------------
\3\ GL 88-17, ``Loss of Decay Heat Removal,'' October 17, 1988
(ML031200496); GL 97-04, ``Assurance of Sufficient Net Positive
Suction Head for Emergency Core Cooling and Containment Heat Removal
Pumps,'' October 7, 1997 (ML031110062); and NUREG-0897, Revision 1,
``Containment Emergency Sump Performance--Technical Findings Related
to USI A-43,'' October 1985.
---------------------------------------------------------------------------
In May 1997, at Oconee Nuclear Station Unit 3, hydrogen ingestion
during plant cooldown damaged and rendered nonfunctional two high-
pressure injection (HPI) pumps. If the operators had started the
remaining HPI pump, it too would have been damaged. The NRC responded
with an augmented inspection team (IN 97-38, ``Level-Sensing System
Initiates Common-Mode Failure of High-Pressure-Injection Pumps,''
Agencywide Documents Access and Management System (ADAMS) Accession No.
ML031050514, June 24, 1997). The NRC team reported that there had been
a total lack of HPI capability during power operation, a failure to
meet technical specification (TS) HPI operability requirements, design
deficiencies, inadequate maintenance practices, operators that were
less than attentive to plant parameters, a failure to adequately assess
operating experience, and a violation of 10 CFR part 50, Appendix
[[Page 29011]]
B, Criterion III (``Notice of Violation and Proposed Imposition of
Civil Penalties --$330,000,'' August 27, 1997, https://www.nrc.gov/
reading-rm/doc-collections/enforcement/actions/reactors/ea97297.html).
As a result of this Oconee Unit 3 event, the industry initiated an
industry-wide improvement activity to address the gas issue. Based on
the industry actions, the NRC concluded that no generic action was
necessary. However, significant gas events that jeopardized the
operability of the subject systems continued to occur, as illustrated
in the following paragraphs. Dresden Nuclear Power Station Unit 3
experienced a reactor scram on July 5, 2001, that was accompanied by a
water hammer as a result of high pressure coolant injection (HPCI)
system voids due to inadequate pipe venting. The licensee discovered a
damaged pipe support that rendered the HPCI system inoperable on July
19, 2001. On September 28, 2001, NRC inspectors discovered
discrepancies in another HPCI hanger that may have been caused by the
water hammer. The licensee repaired the hangers on September 30, 2001,
and vented the system. An NRC inspector identified a high point that
had not been vented and air was removed when the licensee vented that
location. The HPCI system was inoperable from July 5, 2001, to
September 30, 2001 (NRC Supplemental Inspection Report 50-237, 50-239/
2003-012, ML033530204, December 18, 2003). The NRC found violations of
10 CFR 50.9, a TS, and 10 CFR part 50, Appendix B, Criterion XVI
(``Notice of Violation and Proposed Imposition of Civil Penalty--
$60,000, and Final Significance Determination for a White Finding,''
ML031740755, June 23, 2003).
On August 14, 2003, the Perry Nuclear Power Plant scrammed from 100
percent power due to a loss of offsite power. This caused a momentary
loss of common water leg pumps \4\ and a discharge pressure decrease
from 44 psig to 7 psig allowed accumulated gas to completely void a
water leg pump and the associated feedwater leakage control system
piping. Pump operation was restored by venting the pump casing but a
piping high point that was not included in fill and vent procedures was
not vented. On September 10, 2003, the licensee vented enough gas from
the high point that would have caused the pump to be non-functional if
another loss of offsite power would occur. If the RHR and/or the LPCS
pumps had started while the leakage control system piping was voided,
the resulting water hammer could have caused the system piping to
rupture. The NRC characterized the inspection finding as white; the
finding resulted in a TS violation, escalated enforcement action, and a
supplemental inspection (NRC Inspection Report 50-440/2003-009,
ML032880107, October 10, 2003, and ML040330980, January 30, 2004).
---------------------------------------------------------------------------
\4\ These are 40 gpm pumps used to compensate for back-leakage
through check valves in RHR and LPSI piping into the suppression
pool. The purpose is to keep piping full of water where the pipe
elevation is higher than the suppression pool. The system is often
referred to as a ``keep-full'' system.
---------------------------------------------------------------------------
On July 28, 2004, the Palo Verde licensee identified that emergency
core cooling system (ECCS) suction piping voids in all three Palo Verde
units could have resulted in a loss of the ECCS during transfer to the
recirculation mode for some loss-of-coolant accident (LOCA) conditions.
The condition had existed since plant startups in 1986, was contrary to
the Palo Verde final safety analysis reports (FSARs), and would not be
identified during testing because water is not drawn from the
containment emergency sumps. The NRC inspectors identified multiple
violations of 10 CFR part 50, Appendix B, Criteria III and V, and
violations of 10 CFR 50.59. The NRC responded with a special
inspection, issued a yellow finding, and imposed a civil penalty of
$50,000 (NRC Special Inspection Report 50-328, 50-329, 50-330/2004-014,
ML050050287, January 5, 2005). The Palo Verde licensee identified the
ECCS piping suction voids after being contacted by engineer from
another plant where an NRC inspector identified the same problem.
In February 2005, an HPI pump at Indian Point Energy Center Unit 2
was found inoperable because the pump casing was filled with gas. The
licensee then found numerous locations in the ECCS piping with gas
accumulation. The licensee did not initially understand the
implications of the gas condition, and the licensee's early assessments
were inadequate, particularly with respect to assessing the operability
of the other two HPI pumps. The NRC conducted a special inspection that
found one HPI pump was not functional and the other two HPI pumps had a
75 percent failure probability. The NRC found several violations of 10
CFR part 50, Appendix B, Criterion XVI, and issued a white finding (NRC
Inspection Report 50-247/2005-006, ML051680119, June 17, 2005).
In March 2005, the NRC reported that Diablo Canyon had a sustained
history of gas voiding in piping that could possibly result in gas
binding or damage to the centrifugal charging pumps or the HPSI pumps
during switchover from cold-leg to hot-leg injection.\5\ The NRC
inspectors concluded that the licensee focused on managing the symptom
of the problem rather than finding and eliminating the cause, which is
contrary to 10 CFR part 50, Appendix B, Criterion XVI (NRC Inspection
Report 50-275, 50-323/2005-006, ML050910120, March 31, 2005).
---------------------------------------------------------------------------
\5\ A similar gas accumulation problem under closed valves in
the recirculation piping from the DHR discharge to the HPSI and
charging pump suctions has occurred at several plants. This has the
potential to cause loss of all high pressure RCS makeup capability
when shifting suction to the emergency containment sump from the
refueling water or borated water storage tank following a LOCA.
---------------------------------------------------------------------------
In September 2005, operators discovered a void in the HPCI pump
discharge piping at the Duane Arnold Energy Center due to ``turbulent
penetration'' that caused hot water from the feedwater pipe to
penetrate downward into the HPCI discharge pipe. This heated the HPCI
pipe on the low pressure side of a closed valve to greater than the
saturation temperature and caused steam to be generated in the low
pressure pipe as fast as it was vented. The condition had existed since
plant startup (Licensee Event Report 50-331/2005-004, ML053360261,
November 28, 2005). The NRC opened an unresolved item (URI 05000331/
2006002-03) for further NRC review of the licensee's piping analysis
that evaluated HPSI system operability with the voided piping (NRC
Inspection Report 50-331/2006-002, ML061210448, April 27, 2006, and NRC
Inspection Report 50-331/2006-008, ML070640515, March 2, 2007).
In October 2005, an NRC inspection team at the Palo Verde Nuclear
Generating Station identified that, following a postulated accident
when refueling water tank (RWT) level reached the setpoint for
containment sump recirculation, the licensee's design basis credited
containment pressure for preventing the ECCS pumps from continuing to
reduce RWT level and drawing air into the ECCS. However, a recent
licensee analysis showed that the minimum containment pressure would be
less than needed. The licensee declared the ECCS inoperable at all
three units, requiring a shutdown of Units 2 and 3 (Unit 1 was already
shut down). The NRC found multiple violations of 10 CFR part 50,
Appendix B, Criteria III and V (NRC Supplemental Inspection Report 50-
528, 50-529, 50-530/2005-012, ML060300193, January 27, 2006).
These are a few of the more than 60 gas intrusion events reported
during recent years involving the subject
[[Page 29012]]
systems. The number is larger if other similar events at the same plant
are counted. Further, many events do not have to be reported to the
NRC, and many of them have not been addressed during the NRC's
inspections. For example, at least 40 RHR water hammer events have
occurred at the Sequoyah Nuclear Plant, although none of them rendered
the RHR system inoperable. Additionally, if an ECCS pump has been
damaged because of gas but is repaired and tested operable within the
TS completion time (typically, 72 hours), the licensee is not required
to report the occurrence to the NRC. The frequency and the significance
of these events and the likelihood that unidentified gas issues exist
require licensee action to ensure compliance with regulatory
requirements that will maintain operability of the subject systems.
Applicable Regulatory Requirements
10 CFR part 50 Appendix A or similar plant-specific principal
design criteria \6\ provide design requirements, and 10 CFR part 50
Appendix B, TSs, and licensee quality assurance programs provide
operating requirements. Appendix A requirements applicable to gas
management in the subject systems include the following:
---------------------------------------------------------------------------
\6\ For facilities with a construction permit issued prior to
May 21, 1972, that are not licensed to Appendix A.
---------------------------------------------------------------------------
General Design Criterion (GDC) 1 requires that the subject
systems be designed, fabricated, erected, and tested to quality
standards.
GDC 34 requires an RHR system designed to maintain
specified acceptable fuel design limits and to meet design conditions
that are not exceeded if a single failure occurs and specified
electrical power systems fail.
GDC 35, 36, and 37 require an ECCS design that meets
performance, inspection, and testing requirements. Specified
performance criteria are provided in 10 CFR 50.46.
GDC 38, 39, and 40 require a containment heat removal
system design that meets performance, inspection, and testing
requirements.
Quality assurance criteria provided in Appendix B that apply to gas
management in the subject systems include the following:
Criteria III and V require measures to assure that
applicable regulatory requirements and the design basis, as defined in
10 CFR 50.2, ``Definitions,'' and as specified in the license
application, are correctly translated into controlled specifications,
drawings, procedures, and instructions.
Criterion XI requires a test program to assure that the
subject systems will perform satisfactorily in service. Test results
shall be documented and evaluated to assure that test requirements have
been satisfied.
Criterion XVI requires measures to assure that conditions
adverse to quality, such as failures, malfunctions, deficiencies,
deviations, defective material and equipment, and nonconformances, are
promptly identified, corrected, documented, and reported to management.
Criterion XVII requires maintenance of records of
activities affecting quality.
Further, as part of the licensing basis, licensees have committed
to certain quality assurance provisions that are identified in both
their TSs and quality assurance programs. Licensees have committed to
use the guidance of Regulatory Guide (RG) 1.33, ``Quality Assurance
Requirements (Operation),'' which endorses American National Standards
Institute (ANSI) N18.7-1976/American Nuclear Society 3.2,
``Administrative Controls and Quality Assurance for the Operational
Phase of Nuclear Power Plants,'' or equivalent licensee-specific
guidance. Section 5.3.4.4, ``Process Monitoring Procedures,'' of ANSI
N18.7 that states that procedures for monitoring performance of plant
systems shall be required to assure that engineered safety features and
emergency equipment are in a state of readiness to maintain the plant
in a safe condition if needed. The limits (maximum and minimum) for
significant process parameters shall be identified. Operating
procedures shall address the nature and frequency of this monitoring,
as appropriate.
10 CFR 50.36(c)(3) defines TS surveillance requirements (SRs) as
``relating to test, calibration, or inspection to assure'' maintenance
of quality, operation within safety limits, and operability. Typically,
TS Section 5 or 6 requires that licensees establish, implement, and
maintain written procedures covering the applicable procedures
recommended in Appendix A to RG 1.33, Revision 2 (February 1978).
Appendix A to RG 1.33 identifies instructions for filling and venting
the ECCS and DHR system, as well as for draining and refilling heat
exchangers. Surveillance requirements to verify that at least some of
the subject system piping is filled are provided in standard technical
specifications (STSs) and in most licensee TSs.
Discussion
The events discussed in the BACKGROUND section illustrate that many
of the regulatory requirements identified in the APPLICABLE REGULATORY
REQUIREMENTS section are not being met. The NRC inspectors often find
that the 10 CFR part 50 Appendix B criteria identified above are not
adequately addressed in plant venting procedures. In some cases,
venting procedures were almost nonexistent, there were no records of
gas quantities that were vented and licensees unsuccessfully attempted
to recreate the history by asking operators for their recollections.
Consequently, there was no foundation for establishing that the subject
systems were operable prior to venting. In addition, the venting
processes sometimes did not ensure that all gas was removed from the
venting location and often did not adequately establish the quantity of
vented gas. Further, examination of ultrasonic test (UT) processes at
several licensee sites established that one licensee initially did not
know how to acceptably determine liquid level via UT. Additional issues
include TSs, which often do not require venting of suction piping
despite voids in suction pipes generally being of more concern than in
discharge piping, and do not adequately address operability of the
subject systems prior to surveillance and for the time span until the
next surveillance. This GL and the anticipated NRC followup to this GL
are intended to correct such conditions.
It is important that the subject systems are sufficiently filled
with water to ensure that they can reliably perform their intended
functions under all LOCA and non-LOCA conditions that require makeup to
the RCS. Portions of these systems and some of the associated pumps are
normally in a standby condition while other pumps provide both ECCS and
operational functions. For example, some high-pressure pumps are used
for normal RCS makeup, and some low-pressure pumps provide a normal DHR
capability.
The following safety issues are associated with gas intrusion into
the subject systems:
(1) The introduction of gas into a pump can cause the pump to
become air-bound with little or no flow, rendering the pump inoperable.
Air-binding can render more than one pump inoperable when pumps share
common discharge or suction headers, or when the gas accumulation
process affects more than one train, greatly increasing the risk
significance. Such a common-mode failure would result in the inability
of the ECCS or the DHR system to provide adequate core cooling and the
inability of the containment spray system to maintain the containment
pressure and temperature below design limits. An air-bound pump can
become
[[Page 29013]]
damaged quickly, eliminating the possibility of recovering the pump
during an event by simply subsequently venting the pump and suction
piping.
(2) Gas introduced into a pump can render the pump inoperable, even
if the gas does not air bind the pump, because the gas can reduce the
pump discharge pressure and flow capacity to the point that the pump
cannot perform its design function. For example, an HPI pump that is
pumping air-entrained water may not develop sufficient discharge
pressure to inject under certain small break LOCA scenarios.
(3) Gas accumulation can result in water hammer or a system
pressure transient, particularly in pump discharge piping following a
pump start, which can cause piping and component damage or failure. Gas
accumulation in the DHR system has resulted in pressure transients that
have caused DHR system relief valves to open. In some plants, the
relief valve reseating pressure is less than the existing RCS pressure,
a condition that complicates recovery.
(4) Pump cavitation caused by entrained gas results in additional
stresses that can lead to premature failure of pump components that can
render the pump inoperable.
(5) Gas intrusion can result in pumping noncondensible gas into the
reactor vessel that may affect core cooling flow.
(6) The time needed to fill voided discharge piping can delay
delivery of water beyond the time frame assumed in the accident
analysis.
The scope and number of identified gas intrusion problems at some
facilities raise concerns about whether similar unrecognized design,
configuration, and operability problems exist at other reactor
facilities.
A review of the operating experience has identified the following
concerns, which are the focus of this GL:
(1) TS SRs, as implemented by associated surveillance procedures,
have not reliably precluded gas problems. Operating experience shows
many instances in which substantive gas voiding in the system piping
has not been identified. The surveillance procedures may not reliably
reveal as-found conditions in which the system may be inoperable or
degraded because of gas. Additionally, some plants have no TS SR to
verify that the subject systems' piping is sufficiently full of water.
Still other plants have incomplete TS SRs that cover only portions of
the system. For example, the TS may require verifying that ECCS
discharge piping is full of water but may not include verification of
the suction piping or containment spray piping. Although the TS and
FSAR at many facilities indicate that the subject systems are full of
water, in practice it is not uncommon for licensees to vent some gas
during periodic surveillances. Further, there may be some parts of
these systems where it is not possible or practical to verify them to
be full of water. Hence, the current TS and FSAR may establish a
standard that may not be realistic to establish system operability. A
realistic standard should bound the volume of gas that may impact pump
operability and the volume for which water-hammer-induced stress limits
may be exceeded.
Criterion XI of Appendix B to 10 CFR part 50 requires licensees to
perform testing using written test procedures, which include but are
not limited to procedures for TS SRs, that incorporate the requirements
and acceptance limits contained in applicable design documents. TSs
often require surveillance of discharge piping but do not mention
suction piping. Consequently, suction piping surveillances may not be
performed. However, since the subject systems may be rendered
inoperable or degraded because of gas in suction piping, the
regulations require that presence of gas in all piping be assessed to
establish operability.
(2) Typically the FSAR describes that the subject systems are
filled with water. The wording of TS SRs further confirms that the
design-basis configuration calls for the specified piping to be filled
with water. Operating experience provides many examples of licensees
treating the accumulation of gas as an expected condition (rather than
a nonconforming condition) that was not documented even when it
involved a substantial volume of gas that clearly constituted a
significant condition adverse to quality. In such cases, Criterion XVI
of Appendix B to 10 CFR part 50 requires that the cause of the
condition be determined and corrective action taken to preclude
repetition. Based on the as-found volume and location of gas,
corrective actions beyond simply refilling a system may be necessary to
provide reasonable assurance that the affected system will remain
operable until the next surveillance.
(3) Although the subject systems are often susceptible to gas
intrusion, not all plants have vent valves at one or more system high
points. Some licensees have installed additional vent valves at system
high points after operational events. For example, one licensee
installed an additional 21 high-point vent valves. Another licensee,
who installed an additional 17 vent valves, determined that the primary
cause of the gas voiding problem was that the original design
specification did not call for a sufficient number of vent valves. No
specific NRC requirement mandates the installation of vent valves on
the subject systems. However, failure to translate the design basis of
assuring the system is maintained sufficiently full of water to
maintain operability into drawings, specifications, procedures, and
instructions is a violation of Criterion III in Appendix B of 10 CFR
part 50.
Further, Criterion V requires documented instructions, procedures,
or drawings that include appropriate quantitative or qualitative
acceptance criteria for determining that important activities have been
satisfactorily accomplished. This means that each addressee must have
suitable documentation and records, including acceptance criteria, to
establish that the subject systems have been and are maintained
sufficiently full of water to ensure system operability. Vent valves
and their use are often a key ingredient for satisfying these
requirements.
The NRC staff is initiating a Technical Specifications Task Force
(TSTF) activity to address the recognized TS weaknesses associated with
gas intrusion concerns. In the interim, until new TSs are developed,
the NRC staff will treat a SR that the piping be full of water as
satisfied if the piping and pumps of the subject systems are maintained
sufficiently full of water to ensure system operability when
operability is required. This condition must be shown to be satisfied
during the time between surveillances, and either venting or UT
surveillances are acceptable means of obtaining void data. Further, the
NRC staff will consider justification for not conducting a periodic
surveillance or for extending the time between surveillances of certain
sections of piping if an addressee considers surveillance to be
unnecessary. For example, some three loop plants designed by
Westinghouse maintain HPSI discharge lines at a pressure greater than
the RCS operating pressure. This eliminates the potential for leakage
from the accumulators or the RCS as a possible means to introduce gas
into the discharge lines. An assessment for such plants that (1)
acceptably eliminates other means of introducing gas, (2) establishes
acceptable verification that the lines are essentially full following a
condition that reduces the discharge line pressure, and (3) establishes
an operating history confirming that gas has not accumulated will be
adequate justification for not conducting surveillances inside
[[Page 29014]]
containment or at locations that constitute a hazard to personnel
performing the assessment. The NRC memorandum, ``Technical
Considerations for Reasonably Assuring Emergency Core Cooling, Decay
Heat Removal, and Containment Spray Systems Operability,'' ML071030382,
April 17, 2007, provides some operating experience insights. The NRC
staff plans to use this information during inspection activities that
are planned as a followup to this GL and for guidance in the TSTF
program to develop improved TSs.
Requested Actions
Each addressee is requested to evaluate their ECCS, DHR system, and
containment spray system designs, operation, and test procedures to
assure that gas intrusion is minimized and monitored in order to
maintain system operability and compliance with the requirements of
Appendix B to 10 CFR part 50.
Requested Information
Each addressee is requested to provide a summary description of how
the REQUESTED ACTIONS have been addressed within 6 months of the date
of this GL. This summary description should specifically address the
quality assurance criteria in 10 CFR part 50, Appendix B, Sections III,
V, XI, XVI, and XVII and the TSs that apply to the subject systems.
This summary should include a general description of: (1) The design,
(2) the operating procedures, and (3) the test procedures to assure
that gas intrusion does not affect the ability of the subject systems
to perform their intended functions.
If an addressee determines that system or procedure modifications
are necessary based on the review of the requested actions and these
changes cannot be accomplished within 6 months of the date of this GL,
then the addressee should also provide a plan and schedule for
completion of these actions.
Required Response
In accordance with 10 CFR 50.54(f), in order to determine whether a
facility license should be modified, suspended, or revoked, or whether
other action should be taken, an addressee is required to respond as
described below. Within 6 months of the date of this generic letter, an
addressee is required to submit a written response if they are unable
to provide the information or they cannot meet the requested completion
date. The addressee must address in its response any alternative course
of action that it proposes to take, including the basis for the
acceptability of the proposed alternative course of action.
The required written response should be addressed to the U.S.
Nuclear Regulatory Commission, ATTN: Document Control Desk, 11555
Rockville Pike, Rockville, MD 20852, under oath or affirmation under
the provisions of section 182a of the Atomic Energy Act of 1954, as
amended, and 10 CFR 50.54(f). In addition, submit a copy of the
response to the appropriate regional administrator.
Reasons for Information Request
The NRC is requesting this information because a review of
operating experience shows numerous instances of gas intrusion events
involving the subject systems that have rendered or potentially
rendered these risk-significant systems inoperable.
Related Generic Communications
------------------------------------------------------------------------
ADAMS
Document No. Document name accession No.
------------------------------------------------------------------------
GL 88-17....................... Loss of Decay Heat ML031200496
Removal.
GL 97-04....................... Assurance of ML031110062
Sufficient Net
Positive Suction Head
for Emergency Core
Cooling and
Containment Heat
Removal Pumps.
IN 86-63....................... Loss of Safety ML031250058
Injection Capability.
IN 86-80....................... Unit Startup with ML031250214
Degraded High
Pressure Safety
Injection System.
IN 87-63....................... Inadequate Net ML031180034
Positive Suction Head
in Low Pressure
Safety Systems.
IN 88-23....................... Potential for Gas ML031150208
Binding of High-
Pressure Safety.
IN 88-23, Supp. 1.............. Injection Pumps During ML881230018
a Loss-of-Coolant
Accident.
IN 88-23, Supp. 2.............. ...................... ML900125002
IN 88-23, Supp. 3.............. ...................... ML901204023
IN 88-23, Supp. 4.............. ...................... ML921215001
IN 88-74....................... Potentially Inadequate ML031150118
Performance of ECCS
in PWRs during
Recirculation
Operation Following a
LOCA.
IN 89-67....................... Loss of Residual Heat ML031180745
Removal Caused by
Accumulator Nitrogen
Injection.
IN 89-80....................... Potential for Water ML031190089
Hammer, Thermal
Stratification, and
Steam Binding in High-
Pressure Coolant
Injection Piping.
IN 90-64....................... Potential for Common- ML031103251
Mode Failure of High
Pressure Safety
Injection Pumps or
Release of Reactor
Coolant Outside
Containment During a
Loss-of-Coolant
Accident.
IN 91-50....................... A Review of Water ML031190397
Hammer Events after
1985.
IN 94-36....................... Undetected ML031060539
Accumulation of Gas
in Reactor System.
IN 94-76....................... Recent Failures of ML031060430
Charging/Safety
Injection Pump Shafts.
IN 95-03....................... Loss of Reactor ML031060404
Coolant Inventory and
Potential Loss of
Emergency Mitigation
Functions While in a
Shutdown Condition.
IN 96-55....................... Inadequate Net ML031050598
Positive Suction Head
of Emergency Core
Cooling and
Containment Heat
Removal Pumps under
Design Basis Accident
Conditions.
IN 96-65....................... Undetected ML031050500
Accumulation of Gas
in Reactor Coolant
System and Inaccurate
Reactor Water Level
Indication During
Shutdown.
IN 97-38....................... Level-Sensing System ML031050514
Initiates Common-Mode
Failure of High
Pressure Injection
Pumps.
IN 97-40....................... Potential Nitrogen ML031050497
Accumulation
Resulting from Back-
Leakage from Safety
Injection Tanks.
IN 98-40....................... Design Deficiencies ML031040547
Can Lead to Reduced
ECCS Pump Net
Positive Suction Head
During Design-Basis
Accidents.
IN 02-15....................... Potential Hydrogen ML020980466
Combustion Events in
BWR Piping.
IN 02-15, Supp. 1.............. ...................... ML031210054
IN 02-18....................... Effect of Adding Gas ML021570158
Into Water Storage
Tanks on the Net
Positive Suction Head
for Pumps.
[[Page 29015]]
IN 06-21....................... Operating Experience ML062570468
Regarding Entrainment
of Air Into Emergency
Core Cooling and
Containment Spray
Systems.
------------------------------------------------------------------------
Backfit Discussion
Under the provisions of Section 182a of the Atomic Energy Act of
1954, as amended, this GL requests a review and appropriate resulting
actions for the purpose of assuring compliance with applicable existing
requirements. No backfit is either intended or approved by the issuance
of this GL. Therefore, the NRC staff has not performed a backfit
analysis.
Federal Register Notification
To be done after the public comment period.
Congressional Review Act
In accordance with the Congressional Review Act, the NRC has
determined that this GL is not a major rule and the Office of
Information and Regulatory Affairs of the Office of Management and
Budget has confirmed this determination.
Paperwork Reduction Act Statement
This GL contains an information collection that is subject to the
Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). The Office of
Management and Budget approved this information collection under
clearance number 3150-0011.
The burden to the public for this mandatory information collection
is estimated to average 300 hours per response, including the time for
reviewing instructions, searching existing data sources, gathering and
maintaining the data needed, and completing and reviewing the
information collection. The NRC is seeking public comment on the
potential impact of the information collection contained in the GL 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?
2. Is the estimate of burden accurate?
3. Is there a way to enhance the quality, utility, and clarity of
the information collected?
4. How can the burden of the information collection be minimized,
including the use of automated collection techniques?
Send comments on any aspect of this information collection,
including suggestions for reducing the burden, to the Records and FOIA/
Privacy Services Branch (T5-F52), U.S. Nuclear Regulatory Commission,
Washington, DC 20555-0001, or by Internet electronic mail to
infocollects@nrc.gov; and to the Desk Officer, Office of Information
and Regulatory Affairs, NEOB-10202 (3150-0011), Office of Management
and Budget, Washington, DC 20503.
Public Protection Notification: The NRC may not conduct or sponsor,
and a person is not required to respond to, an information collection
unless the requesting document displays a currently valid OMB control
number.
Contact: Please direct any questions about this matter to the
technical contact or the Lead Project Manager listed below, or to the
appropriate Office of Nuclear Reactor Regulation (NRR) project manager.
Michael J. Case, Director, Division of Policy and Rulemaking,
Office of Nuclear Reactor Regulation.
Technical Contact: Warren C. Lyon, NRR, 301-415-2897, e-mail:
wcl@nrc.gov.
Lead Project Manager: David P. Beaulieu, NRR, 301-415-3243, e-mail:
dpb@nrc.gov.
Note: NRC generic communications may be found on the NRC public
Web site, https://www.nrc.gov, under Electronic Reading Room/Document
Collections.
End of Draft Generic Letter
Documents may be examined, and/or copied for a fee, at the NRC's
Public Document Room at One White Flint North, 11555 Rockville Pike
(first floor), Rockville, Maryland. Publicly available records will be
accessible electronically from the Agencywide Documents Access and
Management System (ADAMS) Public Electronic Reading Room on the
Internet at the NRC Web site, https://www.nrc.gov/NRC/ADAMS/.
If you do not have access to ADAMS or if you have problems in accessing
the documents in ADAMS, contact the NRC Public Document Room (PDR)
reference staff at 1-800-397-4209 or 301-415-4737 or by e-mail to
pdr@nrc.gov.
Dated at Rockville, Maryland, this 16th day of May 2007.
For the Nuclear Regulatory Commission.
Jennifer Golder, Acting Director, Division of Policy and Rulemaking,
Office of Nuclear Reactor Regulation.
[FR Doc. 07-2557 Filed 5-22-07; 8:45 am]
BILLING CODE 7590-01-P
