29010 Federal Register / Vol. 72, No. 99 / Wednesday, May 23, 2007 / Notices 

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. 

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. 

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 

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) 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 


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4These 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. 

5A 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. 

B, Criterion III (‘‘Notice of Violation and 

Proposed Imposition of Civil Penalties 

—$330,000,’’ August 27, 1997, http:// 

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 

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 

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 


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6For facilities with a construction permit issued 

prior to May 21, 1972, that are not licensed to 

Appendix A. 

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 

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 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. 

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, 

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 


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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

Document No. Document name ADAMS 

accession No. 

GL 88–17 ..................... Loss of Decay Heat Removal ................................................................................................................. ML031200496 

GL 97–04 ..................... Assurance of Sufficient Net Positive Suction Head for Emergency Core Cooling and Containment 

Heat Removal Pumps.

ML031110062 

IN 86–63 ...................... Loss of Safety Injection Capability .......................................................................................................... ML031250058 

IN 86–80 ...................... Unit Startup with Degraded High Pressure Safety Injection System ..................................................... ML031250214 

IN 87–63 ...................... Inadequate Net Positive Suction Head in Low Pressure Safety Systems ............................................. ML031180034 

IN 88–23 ...................... Potential for Gas Binding of High-Pressure Safety ................................................................................ ML031150208 

IN 88–23, Supp. 1 ....... Injection Pumps During a Loss-of-Coolant Accident .............................................................................. ML881230018 

IN 88–23, Supp. 2 ....... .................................................................................................................................................................. ML900125002 

IN 88–23, Supp. 3 ....... .................................................................................................................................................................. ML901204023 

IN 88–23, Supp. 4 ....... .................................................................................................................................................................. ML921215001 

IN 88–74 ...................... Potentially Inadequate Performance of ECCS in PWRs during Recirculation Operation Following a 

LOCA.

ML031150118 

IN 89–67 ...................... Loss of Residual Heat Removal Caused by Accumulator Nitrogen Injection ........................................ ML031180745 

IN 89–80 ...................... Potential for Water Hammer, Thermal Stratification, and Steam Binding in High-Pressure Coolant Injection Piping.ML031190089 

IN 90–64 ...................... Potential for Common-Mode Failure of High Pressure Safety Injection Pumps or Release of Reactor 

Coolant Outside Containment During a Loss-of-Coolant Accident.

ML031103251 

IN 91–50 ...................... A Review of Water Hammer Events after 1985 ..................................................................................... ML031190397 

IN 94–36 ...................... Undetected Accumulation of Gas in Reactor System ............................................................................ ML031060539 

IN 94–76 ...................... Recent Failures of Charging/Safety Injection Pump Shafts ................................................................... ML031060430 

IN 95–03 ...................... Loss of Reactor Coolant Inventory and Potential Loss of Emergency Mitigation Functions While in a 

Shutdown Condition.

ML031060404 

IN 96–55 ...................... Inadequate Net Positive Suction Head of Emergency Core Cooling and Containment Heat Removal 

Pumps under Design Basis Accident Conditions.

ML031050598 

IN 96–65 ...................... Undetected Accumulation of Gas in Reactor Coolant System and Inaccurate Reactor Water Level 

Indication During Shutdown.

ML031050500 

IN 97–38 ...................... Level-Sensing System Initiates Common-Mode Failure of High Pressure Injection Pumps ................. ML031050514 

IN 97–40 ...................... Potential Nitrogen Accumulation Resulting from Back-Leakage from Safety Injection Tanks ............... ML031050497 

IN 98–40 ...................... Design Deficiencies Can Lead to Reduced ECCS Pump Net Positive Suction Head During DesignBasis Accidents.ML031040547 

IN 02–15 ...................... Potential Hydrogen Combustion Events in BWR Piping ........................................................................ ML020980466 

IN 02–15, Supp. 1 ....... .................................................................................................................................................................. ML031210054 

IN 02–18 ...................... Effect of Adding Gas Into Water Storage Tanks on the Net Positive Suction Head for Pumps ........... ML021570158 


pwalker on PROD1PC71 with NOTICES
Federal Register / Vol. 72, No. 99 / Wednesday, May 23, 2007 / Notices 29015 

1 15 U.S.C. 78s(b)(1). 

2 17 CFR 240.19b–4. 

3See Securities Exchange Act Release No. 55661 

(April 24, 2007), 72 FR 23862 (‘‘Notice’’). 

RELATED GENERIC COMMUNICATIONS—Continued 

Document No. Document name ADAMS 

accession No. 

IN 06–21 ...................... Operating Experience Regarding Entrainment of Air Into Emergency Core Cooling and Containment 

Spray Systems.

ML062570468 

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, http:// 

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, http://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. 

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 


pwalker on PROD1PC71 with NOTICES