OMB Control No.: 3150-0011 

UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

OFFICE OF NUCLEAR REACTOR REGULATION 

WASHINGTON, DC 20555-0001 

January 11, 2008 

NRC GENERIC LETTER 2008-01: MANAGING GAS ACCUMULATION IN EMERGENCY 

CORE COOLING, DECAY HEAT REMOVAL, AND 

CONTAINMENT SPRAY SYSTEMS 

ADDRESSEES

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 gas1

 accumulation in the emergency core cooling, decay heat removal (DHR)2, and 

containment spray systems (hereinafter referred to as the “subject systems”). Specifically, the 

NRC is issuing this GL for two purposes: 

(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 

(2) to collect the requested information to determine if additional regulatory action is 

required 

Pursuant to Title 10 Section 50.54(f) of the Code of Federal Regulations (10 CFR 50.54(f)), 

addressees are required to submit a written response to this GL. 

ML072910759 

 

1

“Gas” as used here includes air, nitrogen, hydrogen, water vapor, or any other void that is not filled with 

liquid water.

2

DHR, residual heat removal (RHR), and shutdown cooling are common names for systems used to cool the 

reactor coolant system (RCS) during some phases of shutdown operation. In this GL, the NRC staff 

generally uses “DHR.”
GL 2008-01 

Page 2 of 13 

BACKGROUND

Instances of gas accumulation in 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 NUREG3

 related to this issue and has interacted with the nuclear industry 

many times in relation to these publications and in response to gas accumulation 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 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,” June 24, 1997, ADAMS Accession No. 

ML031050514. 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 who were less than attentive 

to plant parameters, a failure to adequately assess operating experience, and a violation of 

Criterion III of Appendix B to 10 CFR Part 50. The NRC’s followup actions are summarized in 

“Notice of Violation and Proposed Imposition of Civil Penalties - $330,000,” August 27, 1997, 

http://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 improvement activity to address 

the gas issue. Based on the anticipated actions, the NRC concluded that no generic action was 

necessary. However, significant gas events that can adversely impact 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 hammer4

 due to high pressure coolant injection (HPCI) system voids 

resulting from 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, December 18, 2003, ADAMS Accession No. ML033530204). The NRC found 

violations of 10 CFR 50.9, a TS, and 10 CFR Part 50, Criterion XVI of Appendix B to 10 CFR 

Part 50 (“Notice of Violation and Proposed Imposition of Civil Penalty - $60,000, and Final 

 

3

GL 88-17, “Loss of Decay Heat Removal,” October 17, 1988 (Agencywide Documents Management and 

Access System (ADAMS) Accession No. ML031200496); GL 97-04, “Assurance of Sufficient Net Positive 

Suction Head for Emergency Core Cooling and Containment Heat Removal Pumps,” October 7, 1997 

(ADAMS Accession No. ML031110062); and NUREG-0897, Revision 1, “Containment Emergency Sump 

Performance—Technical Findings Related to USI A-43,” October 1985.

4

“Water hammer” refers to any transient pressure condition that is caused by or exacerbated by the 

presence of a void in a system regardless of whether the pressure condition was benign or resulted in 

damage.
GL 2008-01 

Page 3 of 13 

Significance Determination for a White Finding,” June 23, 2003, ADAMS Accession No. 

ML031740755). 

On June 4, 2003, Quad Cities operators performed a monthly TS surveillance to demonstrate 

that the 1B core spray pump discharge piping was full of water. The piping was vented for 

12 minutes before water flow was observed and the NRC inspectors determined that the 

licensee had failed to provide a correct venting procedure that would ensure continued pump 

operability. The system engineer estimated that the piping was about one-half empty. A water 

hammer with the potential to cause damage would have occurred if the core spray pump had 

been started and the core spray system was determined to be inoperable in the as-found 

condition. The NRC inspectors also determined that the emergency core cooling system 

(ECCS) surveillance procedures were incorrect, that licensee review in response to the excess 

gas was inadequate, and that TS 3.0.4 had been violated. This was considered to be a 

licensee-identified violation, the finding was greater than minor because of the pump 

inoperability, and the finding was considered to be of very low safety significance because it did 

not result in an actual loss of function. It was dispositioned as a noncited violation and entered 

into the corrective action program (NRC Inspection Report 50-254/03-05, 50-265/03-05, 

July 17, 2003, ADAMS Accession No. ML031980621). 

On August 14, 2003, the Perry Nuclear Power Plant scrammed from 100 percent power 

because of a loss of offsite power. This caused a momentary loss of common water leg pumps5

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 had occurred. If the RHR and/or the low-pressure core spray 

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, October 10, 2003, 

ADAMS Accession No. ML032880107, and January 30, 2004, ADAMS Accession No. 

ML040330980). 

On July 28, 2004, the Palo Verde licensee identified that 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 Criteria III and V in 

Appendix B to 10 CFR Part 50 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, January 5, 2005, ADAMS Accession No. 

 5

These are 40 gallon per minute (gpm) pumps used to compensate for back-leakage through check valves 

in RHR and low-pressure core spray piping into the suppression pool. Their 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.
GL 2008-01 

Page 4 of 13 

ML050050287). The Palo Verde licensee identified the ECCS piping suction voids after being 

contacted by an engineer from another plant where an NRC inspector had 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 several 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 Criterion XVI of Appendix B 

to 10 CFR Part 50 and issued a white finding (NRC Inspection Report 50-247/2005-006, 

June 17, 2005, ADAMS Accession No. ML051680119). 

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 high pressure safety injection (HPSI) pumps during switchover from cold-leg to hot-leg 

injection.6

 The inspection report listed 10 recent gas voiding occurrences and 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 Criterion XVI of Appendix B to 

10 CFR Part 50. The finding was more than minor in that the voiding could have caused 

mitigating equipment to fail but was of very low safety significance because the inspectors 

concluded that there was no loss of function. This was a noncited Violation (NRC Inspection 

Report 50-275, 50-323/2005-006, March 31, 2005, ADAMS Accession No. ML050910120). 

In September 2005, a void was discovered in the HPCI pump discharge piping at the Duane 

Arnold Energy Center resulting from “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, November 28, 2005, 

ADAMS Accession No. ML053360261). The NRC opened an unresolved item 

(URI 05000331/2006002-03) for further NRC review of the licensee’s piping analysis that 

evaluated HPCI system operability with the voided piping. NRC determined the condition to be 

adverse to quality since it was not identified by the licensee, was uncorrected, and was a 

violation of Criterion XVI to Appendix B of 10 CFR Part 50. The issue was found to be of very 

low safety significance and entered into the corrective action program. The violation was 

treated as a noncited Violation. (NRC Inspection Report 50-331/2006-002, April 27, 2006, 

ADAMS Accession No. ML061210448, and NRC Inspection Report 50-331/2006-008, 

March 2, 2007, ADAMS Accession No. ML070640515). 

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 

 6

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.
GL 2008-01 

Page 5 of 13 

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 Criteria III and V of Appendix B to 10 CFR Part 50 (NRC 

Supplemental Inspection Report 50-528, 50-529, 50-530/2005-012, January 27, 2006, ADAMS 

Accession No. ML060300193). 

These are a few of the more than 60 gas accumulation events reported since the 1997 Oconee 

Unit 3 event. The NRC staff has assessed these and other events and has concluded that there 

is reasonable assurance that plants can continue to operate safely while this GL is addressed. 

APPLICABLE REGULATORY REQUIREMENTS

The regulations in Appendix A to 10 CFR Part 50 or similar plant-specific principal design 

criteria7

 provide design requirements, and Appendix B to 10 CFR Part 50, 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. The regulations in 10 CFR 50.46 provide specified performance 

criteria. 

• 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 ensure 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. 

 

7

These apply to facilities with a construction permit issued before May 21, 1972, that are not licensed under 

Appendix A.
GL 2008-01 

Page 6 of 13 

• Criterion XI requires a test program to ensure that the subject systems will perform 

satisfactorily in service. Test results shall be documented and evaluated to ensure that 

test requirements have been satisfied. 

• Criterion XVI requires measures to ensure that conditions adverse to quality, such as 

failures, malfunctions, deficiencies, deviations, defective material and equipment, and 

nonconformances, are promptly identified and corrected, and that significant conditions 

adverse to quality are documented and reported to management. 

• Criterion XVII requires maintenance of records of activities affecting quality. 

Furthermore, 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),” revision 2, issued February 1978, 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 states that procedures for monitoring performance of plant systems 

shall be required to ensure 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. 

In 10 CFR 50.36(c)(3), the NRC 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. 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. Standard TSs and most 

licensee TSs provide SRs to verify that at least some of the subject systems piping is filled with 

water. 

DISCUSSION

The events discussed in the Background section illustrate that the licensee was not meeting 

some of the regulatory requirements identified in the Applicable Regulatory Requirements 

section. The operating license and regulations require adequate design, tests, procedures, 

records, and corrective actions, whereas operating experience and NRC inspections have 

revealed inadequate designs, test programs, procedures, test result documentation, and 

corrective actions at licensed facilities. This GL requests licensees to provide information on 

methods used to comply with these NRC requirements. The NRC will evaluate this information 

to determine if further regulatory action is necessary to ensure compliance. 

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 
GL 2008-01 

Page 7 of 13 

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 six examples illustrate how inadequate gas control can have safety implications: 

(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 damaged quickly, eliminating the possibility of 

recovering the pump during an event by 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. This was encountered, for example, during an event at 

Sequoyah where a pressure pulse resulting from gas in RHR discharge piping caused a 

relief valve to open and rendered both RHR trains inoperable for 6 hours because the 

relief valve failed to reseat. 

(4) Unbalanced loads caused by entrained gas and the reduction in inlet pressure at a pump 

because of gas in a vertical suction line that causes pump cavitation can result in 

additional stresses that lead to premature failure of pump components. 

(5) Gas accumulation 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 

timeframe assumed in the accident analysis. 

The number of identified gas accumulation problems and their significance at some facilities 

raise concerns about whether similar unrecognized design, configuration, and operability 

problems exist at other facilities. 
GL 2008-01 

Page 8 of 13 

A review of the operating experience has identified the following four principal concerns, which 

are the focus of this GL: 

(1) Licensing Basis. The FSARs at many facilities state that the subject systems are full of 

water and TSs often require periodic surveillances to confirm this condition. Some plant 

TSs have incomplete SRs that cover only portions of the system. For example, the TSs 

may require verifying that ECCS discharge piping is full of water but may not include 

verification of the suction piping or containment spray piping despite the realistic concern 

that gas accumulation in suction piping may be more serious than gas accumulation in 

discharge piping. In addition, since the subject systems could be rendered inoperable or 

degraded by gas accumulation in any section of piping, the regulations require 

assessment of gas accumulation to establish operability. Some level of gas 

accumulation may not affect operability and, where justified, some portions of these 

systems may be excluded from testing. 

(2) Design. Criterion III of Appendix B to 10 CFR Part 50 and the operating license identify 

regulatory requirements for the design of the subject systems. The failure to translate 

the design basis, such as the system maintained full of water, into drawings, 

specifications, procedures, and instructions would be contrary to Criterion III of Appendix 

B to 10 CFR Part 50. Subject system designs vary widely regarding potential gas 

sources and capability to control gas. Potential gas sources and symptoms of gas 

leakage from these sources should be identified and potential gas accumulation 

locations should be known and provisions made to address gas accumulation at these 

locations. The NRC staff has observed high-point vents that were not located at actual 

high points, non-existent vents where drawings showed vents, and failure to provide 

vents or methods for controlling gas at high points. The NRC staff also notes that 

drawings and isometric diagrams often show piping as level whereas as-installed piping 

is sloped. 

(3) Testing. Criteria V and XI of Appendix B to 10 CFR Part 50 and the operating license 

require licensees to perform testing using written test procedures that incorporate the 

requirements and acceptance limits contained in applicable design and licensing 

documents and Criterion XVII requires appropriate records. Testing of portions of piping 

and components in the subject systems where unacceptable gas accumulation may 

occur is necessary to confirm acceptance limits and operability unless it has been 

acceptability established that some portions may be excluded. Surveillance and testing 

that do not ensure operability prior to the next surveillance are not consistent with this 

testing requirement. 
GL 2008-01 

Page 9 of 13 

(4) Corrective Actions. Some licensees have treated the accumulation of substantial gas 

quantities as an expected condition rather than a nonconforming condition and have not 

documented the condition 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 determining the cause of the condition and 

taking corrective action to preclude repetition. 

The enclosure to this GL, “Technical Considerations for Reasonably Assuring Emergency Core 

Cooling, Decay Heat Removal, and Containment Spray Systems Operability,” provides 

additional information. Addressees should consider this information when preparing responses 

to this GL. Furthermore, the NRC staff plans to use this information during activities that are 

being planned as a followup to this GL and for guidance in the Technical Specifications Task 

Force program to develop improved TSs. 

REQUESTED ACTIONS

The NRC requests that each addressee evaluate its ECCS, DHR system, and containment 

spray system licensing basis, design, testing, and corrective actions to ensure that gas 

accumulation is maintained less than the amount that challenges operability of these systems, 

and that appropriate action is taken when conditions adverse to quality are identified. 

REQUESTED INFORMATION

The NRC requests that each addressee provide the following information: (a) A description of 

the results of evaluations that were performed pursuant to the above requested actions. This 

description should provide sufficient information to demonstrate that you are or will be in 

compliance with the quality assurance criteria in Sections III, V, XI, XVI, and XVII of Appendix B 

to 10 CFR Part 50 and the licensing basis and operating license as those requirements apply to 

the subject systems; (b) A description of all corrective actions, including plant, programmatic, 

procedure, and licensing basis modifications that you determined were necessary to assure 

compliance with these regulations; and, (c) A statement regarding which corrective actions were 

completed, the schedule for completing the remaining corrective actions, and the basis for that 

schedule. 

REQUIRED RESPONSE

In accordance with 10 CFR 50.54(f), an addressee must respond as described below. 

Within 9 months of the date of this GL, each addressee is requested to submit a written 

response consistent with the requested actions and information. If an addressee cannot meet 

the requested response date, the addressee shall provide a response within 3 months of the 

date of this GL and is requested to describe the alternative course of action that it proposes to 

take, including the basis for the acceptability of the proposed alternative course of action. 
GL 2008-01 

Page 10 of 13 

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, addressees should 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 and NRC 

inspection results shows recent instances of gas accumulation events involving the subject 

systems that have rendered or potentially rendered these risk-significant systems inoperable. 

RELATED GENERIC COMMUNICATIONS

Document 

Number

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 

IN 88-23, Supp. 1 

IN 88-23, Supp. 2 

IN 88-23, Supp. 3 

IN 88-23, Supp. 4 

Potential for Gas Binding of High-Pressure Safety 

Injection Pumps During a Loss-of-Coolant Accident 

ML031150208

ML881230018

ML900125002

ML901204023

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
GL 2008-01 

Page 11 of 13 

Document 

Number

Document Name ADAMS 

Accession No.

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 BackLeakage from Safety Injection Tanks ML031050497

IN 98-40 Design Deficiencies Can Lead to Reduced ECCS Pump 

Net Positive Suction Head During Design-Basis Accidents 

ML031040547

IN 02-15 

IN 02-15 Supp. 1 

Potential Hydrogen Combustion Events in BWR Piping ML020980466

ML031210054

IN 02-18 Effect of Adding Gas Into Water Storage Tanks on the Net

Positive Suction Head for Pumps 

ML021570158

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 ensuring 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

A notice of opportunity for public comment on this GL was published in the Federal Register

(72 FR 29010) on May 23, 2007. The NRC received seven sets of comments, all from the 

nuclear industry. The NRC staff considered all comments that were received. The NRC staff’s 

evaluation of the comments is publicly available through the NRC’s ADAMS under Accession 

No. ML072410212. 
GL 2008-01 

Page 12 of 13 

CONGRESSIONAL REVIEW ACT 

The NRC has determined that this action is not subject to the Congressional Review Act. 

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 which expires on June 30, 2010. 

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. 

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, a request for 

information or an information collection requirement unless the requesting document displays a 

currently valid OMB control number.
GL 2008-01 

Page 13 of 13 

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. 

 /RA by TQuay for/

 Michael J. Case, Director 

 Division of Policy and Rulemaking 

 Office of Nuclear Reactor Regulation 

Technical Contact: Warren C. Lyon, NRR/DSS 

 301-415-2897 

Lead Project Manager: David P. Beaulieu, NRR/DPR 

 301-415-3243 

Enclosure: 

“Technical Considerations for Reasonably Assuring Emergency Core Cooling, Decay Heat 

Removal, and Containment Spray Systems Operability” 

Note: NRC generic communications may be found on the NRC public Web site, 

http://www.nrc.gov, under Electronic Reading Room/Document Collections. 
 GL 2008-01 

 Page 13 of 13 

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. 

 /RA by TQuay for/

 Michael J. Case, Director 

 Division of Policy and Rulemaking 

 Office of Nuclear Reactor Regulation 

Technical Contact: Warren C. Lyon, NRR/DSS 

 301-415-2897 

Lead Project Manager: David P. Beaulieu, NRR/DPR 

 301-415-3243 

Enclosure: 

“Technical Considerations for Reasonably Assuring Emergency Core Cooling, Decay Heat 

Removal, and Containment Spray Systems Operability” 

Note: NRC generic communications may be found on the NRC public Web site, 

http://www.nrc.gov, under Electronic Reading Room/Document Collections. 

DISTRIBUTION: GL File 

ADAMS ACCESSION NUMBER: ML072910759 * concurred via email 

OFFICE SRXB:DSS TECH EDITOR PGCB:DPR BC:SRXB:DSS DD:DSS 

NAME WLyon LCulp* DBeaulieu GCranston JWermiel 

DATE 12/03/2007 10/24/2007 11/2/2007 11/09/2007 12/03/2007 

OFFICE D:DSS BC:DIRS:IOEB BC:CPTB:DCI BC:DIRS:ITSB D:DORL 

NAME WRuland MRoss-Lee JMcHale TKobetz CHaney (TMcGinty for)

DATE 11/08/2007 10/25/2007 10/24/2007 11/09/2007 10/23/2007 

OFFICE OE OGC (NLO) OGC (SBREFA) OIS PMDA 

NAME NHilton (RStarkey for) EWilliamson TRothschild MJanney (CColburn for) LHill 

DATE 10/18/2007 11/02/2007 10/15/2007 10/25/2007 10/16/2007 

OFFICE D:RES:DRA LA:PGCB:DPR PGCB:DPR BC:PGCB:DPR D:DPR 

NAME CLui* CHawes AMarkley * MMurphy TQuay for MCase 

DATE 10/24/2007 11/15/2007 11/29/2007 12/03/2007 12/03/2007 

OFFICIAL RECORD COPY
Enclosure 

Technical Considerations for Reasonably Assuring Emergency Core Cooling, 

Decay Heat Removal, and Containment Spray Systems Operability 

Overview

This enclosure provides a discussion of some of the technical issues that should be considered 

when evaluating the design, operability, testing, and corrective actions for gas accumulation 

concerns in emergency core cooling, decay heat removal (DHR), and containment spray 

systems. 

Gas accumulation in the subject nuclear power plant systems can cause water hammer, gas 

binding in pumps, and inadvertent relief valve actuation that may damage pumps, valves, 

piping, and supports and may lead to loss of system operability. Consequently, these systems 

are equipped with vents, and some of the subject systems have keep-full systems that are 

intended to avoid these problems by maintaining them full of water. However, as summarized in 

this generic letter (GL), history has shown that the subject systems, as designed and 

maintained, have been exposed to gas accumulations sufficient to cause potential and actual 

loss of operability. This enclosure provides insights that addressees should consider when 

responding to the GL. 

The root causes of gas accumulation include poor designs that allow gas introduction and 

accumulation, licensees failing to properly fill and vent the system following drain-down or 

maintenance, ineffective controls on gas accumulation during operation, inappropriate technical 

specifications (TSs), and, in some cases, unanticipated problems with keep-full systems. 

The correct objective of gas control measures is to limit the volume of gas accumulation to a 

quantity that does not jeopardize system operability. An acceptable volume depends on a 

variety of factors including, but not necessarily limited to, the location, the type of pump, the net 

positive suction head (NPSH) margin, the gas volume fraction at the pump impeller, and the 

flow rate. A gas volume downstream of an emergency core cooling system (ECCS) pump that 

would not cause a loss of system function might cause a pump failure if located upstream of the 

pump. 

The amount and location of gas are important in addressing system operability. Additional work 

is necessary to develop realistic criteria to determine the amount of gas that could impact 

operability including the following: 

• characterizations of the sources and rate of generation of gases in systems 

• ingestion of gas from tanks and recirculation sumps8

 (vortexing)

 8

This includes potential gas accumulation downstream of containment emergency sump screens and postaccumulation transport.
GL 2008-01 

Page 2 of 8 

• characterization of gas transport in the subject system piping as a function of system 

flow requirements 

• allowable limits on ingested gas volume in pump suction piping to ensure pump 

operability, as well as for the pump discharge piping to alleviate water hammer concerns 

such as slamming check valves or a water cannon effect on the piping 

• allowable limits on ingested gas volume to mitigate dynamic pressure pulsation 

• development of guidance on the sequence of venting to prevent void formation in high 

points remote from the vent location 

• identification of those portions of systems in which venting is unnecessary such as 

downstream of the containment spray isolation valve to the spray headers 

• evaluation of gas detection techniques and the associated accuracies 

This GL enclosure addresses the following six topics: 

(1) sources of gas 

(2) gas accumulation locations 

(3) determination of gas quantity 

(4) water hammer and acceptable gas quantity 

(5) pump operation and acceptable gas quantity 

(6) control of gas 

(1) Sources of Gas

Some sources of gas include the following: 

• leakage from accumulators 

• leakage from the reactor coolant system (RCS) 

• outgassing of dissolved gas because of a pressure reduction such as through control 

valves, orifices, and emergency sump screens, or because of elevation changes or 

venting 

• draining, system realignments, incorrect maintenance procedures, and failure to follow 

procedures 

• failure of level instruments to indicate correct level 

• leakage through test header valves 

• leakage through faulty vent system components when local pressure is less than the 

nominal downstream pressure 
GL 2008-01 

Page 3 of 8 

• temperatures at or above saturation temperature 

• vortexing in suction sources or gas introduced from suction sources 

Gas in discharge piping can be an indicator of potential backleakage from high-pressure 

sources such as accumulators or the RCS, and the gas may have moved into the pumps and 

the pump suction piping. Such gas may have flowed through multiple closed in-series valves. 

For this reason, it is important to reassess gas accumulation conditions following system 

operations and valve manipulations. In addition, many plants have a dozen or more test valves 

that connect to a common header and provide multiple potential leak paths. For example, the 

gas accumulation rates at the Sequoyah Nuclear Plant were significantly reduced in 2002 by 

test header valve maintenance and, at Indian Point Energy Center Unit 2, the test header 

provided a leakage pathway through multiple closed valves into both high-pressure injection 

(HPI) lines in January 2005. 

Some pressurized-water reactors (PWRs) have experienced gas accumulation due to 

outgassing in charging pump bypass orifices. Installing multiple-stage orifices essentially 

eliminated the problem by reducing the pressure drop at each orifice to reduce or eliminate nonequilibrium conditions that caused local gas generation. 

(2) Gas Accumulation Locations

Some locations where gas can accumulate include the following: 

• in high points in pipe runs, including elevation variation in nominally horizontal pipes 

• under closed valves 

• in DHR9

 system heat exchanger U-tubes 

• in horizontal pipe diameter transitions that introduce traps at the top of the larger pipe 

• in tees where gas in flowing water can pass into a stagnant pipe where it accumulates 

• in valve bonnets 

• in pump casings 

• in piping when the temperature is at or above the saturation temperature 

Some locations, such as tees, horizontal pipes, and valve bonnets, are commonly overlooked. 

Gas accumulation resulting from the separation of liquid and gas at a tee has caused significant 

problems. In some PWRs, gas accumulates under the isolation valve in the crossover piping 

between the DHR pump discharge to the suction of the HPI pumps where there are no vents. 

 9

DHR, residual heat removal, and shutdown cooling are common names for systems used to cool the 

reactor coolant system (RCS) during some phases of shutdown operation. 
GL 2008-01 

Page 4 of 8 

The crossover piping is especially vulnerable because system testing usually does not involve 

flow through that location and licensees may not have correctly determined the acceptable gas 

volume. Furthermore, some TS surveillance requirements (SRs) do not specify suction piping. 

Often, licensees consider the crossover piping as suction piping that does not have to be 

checked for gas. 

Gas accumulation can be exacerbated by failure to adequately determine actual system high 

points and failure to have vents where gas accumulates. For example, plant isometric drawings 

sometimes indicate that a length of pipe is horizontal, but an in-plant examination may reveal 

that the pipe is sloped, sometimes by several inches. This is an important consideration for vent 

locations and for using ultrasonic testing (UT) to determine gas volume. 

(3) Determination of Gas Quantity

Some common methods to determine gas quantity in the subject systems are to measure the 

volume of gas released through vents or to determine the gas volume by UT. 

Some hard-piped vents exhaust at a remote location or into a vent manifold where it is difficult 

to determine whether any gas was released. Closed systems may have sight glasses for 

observing bubbles. When the flow rate is adequate to force the gas from the high point down 

through the vent line to a clean sight glass, and the venting period is long enough for the gas to 

have traveled through the sight glass, personnel can tell if all gas has been removed. However, 

it is difficult to accurately determine the volume of gas removed. In some cases, vent flow is 

passed into a test header with a flow meter, but the accuracy of this method of determining gas 

quantity is difficult to establish. Vents consisting of a valve with a removable blind flange 

immediately downstream of the valve allow the effluent to be observed and are often used in 

conjunction with other means to determine the vented volume. Procedures should cover 

venting and post-venting actions such as recording observations and/or gas volumes and 

should ensure a followup if specified criteria related to the gas volume are not met. 

Several conditions may effect the accuracy of a vented volume determination. In some 

locations, venting changes the pressure, and a volume estimate based on venting time may 

therefore be in error because the venting rate is not constant. In some cases, opening and 

closing or repositioning the throttle valve during venting may affect timing. Gas and water vapor 

released from the liquid during depressurization may also affect volume determinations. 

Saturated water vapor will superheat when pressure decreases and will condense if exposed to 

a temperature below the saturation temperature. Saturated water may boil during venting when 

pressure is decreased. These conditions may result in a misleading assessment of gas quantity 

if the behavior is not recognized. 

Other methods of determining gas volume are available. UT can provide accurate gas volumes 

regardless of vent locations. A known volume of water can be injected into an isolated section 

of piping (or a heat exchanger) and the void can then be calculated from the known pressures 

and injected volume. Another method is to record DHR system flow rate behavior immediately 

following pump start to estimate gas volume in the DHR system discharge piping. NRC Special 

Inspection Report 50-400/02-06 stated that this method is useful in determining whether the 

DHR heat exchangers are void free. This was used at Sequoyah where, when a DHR pump 
GL 2008-01 

Page 5 of 8 

was started for testing with the DHR system configured for injection into the RCS, the flow rate 

indicated on a local gauge immediately downstream of the DHR pump should increase 

approximately linearly for the first 8 seconds as the minimum flow line flow control valve opens 

and should then level off at approximately 550 gallons per minute (gpm) if there is no gas 

volume downstream of the pump. In this case, there would be no actual injection since the RCS 

pressure was higher than the DHR system pump discharge pressure and the flow was through 

the minimum flow line. With gas present, the flow rate would increase more rapidly to a value 

greater than approximately 550 gpm and then decrease to approximately 550 gpm within 

roughly 20 seconds. 

The accuracy necessary for void determination is also of interest. An approximate void 

determination method will be adequate when the anticipated void is significantly removed from 

an operability concern based on the historical record and, in that case, recording a parameter 

that is indicative of the void quantity would be sufficient. Anticipation of more significant voids, 

sudden increases in void accumulation rate, or observation of other plant behavior such as 

decreasing accumulator level may require more accurate means to obtain the void size and/or a 

reduction in time between surveillances10. 

With respect to accuracy, UT can provide a quantitative datum that, when considered in 

combination with temperature and pressure within a pipe, will yield an accurate void volume. 

Use of vent valves to obtain a pre-test void volume is more difficult and is often more qualitative. 

Time to vent to obtain a clear liquid stream, with an acceptance criterion conservatively 

determined from a correlation of vent time to an acceptable volume for each vent location, may 

be adequate for trending purposes when anticipated vented volumes are clearly well removed 

from a region of concern. Volumes that are close to impacting operability may require more 

sophisticated measurement and may indicate that corrective action is necessary to reduce the 

gas accumulation rate. 

(4) Water Hammer and Acceptable Gas Quantity

A principal water-hammer concern is the sudden pressure increase in the pump discharge 

piping and associated components when systems are put into service. Another concern is 

pressurization of the DHR system when it is initially connected to the RCS when the RCS 

pressure is near the DHR system relief valve set pressure. A small pressure perturbation 

because of a minor water hammer can open DHR system relief valves, which then might fail to 

close. The relief valve reseating pressure could be less than the RCS pressure, which 

complicates recovery. Therefore, it is particularly important to initiate DHR system operation by 

a process that minimizes the potential to cause a pressure pulse. However, application of such 

techniques must be carefully considered if used for performing surveillances to assess 

operability. During testing, any proceduralized deviation from normal system operation must be 

evaluated for the potential to cause unacceptable preconditioning. If the ECCS must start and 

operate under accident conditions without benefit of pressure-pulse-reducing techniques, then it 

should be tested in a manner that demonstrates it is capable of doing so without those 

techniques. 

 10Item (6) discusses the variation of time between surveillances.
GL 2008-01 

Page 6 of 8 

(5) Pump Operation and Acceptable Gas Quantity

The amount of gas that can be ingested without a significant impact on pump operability and 

reliability is not well established. It is known to depend on pump design, gas dispersion, and 

flow rate. The presence of gas is undesirable because gas may initiate a long-term failure 

mechanism such as shaft fatigue, wear ring degradation, bearing wear, or seal wear. 

Unfortunately, a no-gas condition during initial pump operation or following alignment changes 

often cannot be ensured in practice, and the operational goal should be to minimize the amount 

of gas consistent with the requirement that operability must be reasonably assured. 

A single-stage pump, such as a DHR system pump with significant clearances between moving 

parts, can often withstand a large slug of gas that completely stops flow, and the pump may be 

restored to operation when the gas is removed. However, in some cases, physical pump failure 

has occurred after ingesting gas. A similar no-flow or reduced-flow condition with a multistage 

pump that has close tolerances between moving parts, such as the multi-stage pumps used in 

the ECCS, will likely cause permanent damage. 

All pumps will exhibit a loss of developed head when exposed to gas at the pump impeller. The 

following general conclusions appear reasonable for single-stage pumps that are operating at 

close to rated flow rate: 

• Less than about 0.5 to 1 percent gas by volume at the impeller may not have a 

significant effect on pump head. 

• Pump head may be degraded with 1 to 2 percent gas by volume. 

• Some pumps may fail to provide significant head at 5 percent gas by volume. 

• Most pumps may fail to provide significant head at 10 percent gas by volume. 

However, these percentages are a function of flow rate. With respect to developed head, 

NUREG/CR-279211 states that expert opinions on the level of gas ingestion giving negligible 

degradation ranged from 1 to 3 percent. These experts generally agreed that for flow rates less 

than 50 percent at best efficiency, the presence of gas might cause gas binding that would not 

occur at full flow in some pump designs. The experts apparently agreed that gas in the suction 

lines increased NPSH requirements, but no quantitative data were found. NUREG/CR-2792 

also identified a problem that does not appear to be widely recognized. At reduced flow rates 

with gas ingestion rates that are not normally a problem, gas can accumulate with time and the 

pump can eventually become gas bound. According to NUREG/CR-2792, this is possible with 

less than 2 percent gas by volume at low flow rates. Gas binding because of this effect is a 

potential concern since ECCS pumps are often initially operated at low flow rates when the gas 

volume passing through the pump may be at a maximum. 

 

11Kamath, P. S., et al., “An Assessment of Residual Heat Removal and Containment Spray Pump 

Performance Under Air and Debris Ingesting Conditions,” Creare, Inc., NUREG/CR-2792.
GL 2008-01 

Page 7 of 8 

There is some evidence that a multistage pump can tolerate a higher fraction of incoming gas 

than a single-stage pump without completely losing developed head. This characteristic is 

attributed to compression of the gas in the early stages so that later stages are exposed to a 

lower void fraction and consequently continue to develop head. However, this is only true if the 

flow rate remains a substantial fraction of the best efficiency flow rate. A reduced flow rate may 

result in pump damage that makes the pump non-functional. For example, in large break lossof-coolant accidents (LOCAs) where there is little backpressure, the high-pressure ECCS 

pumps may continue to function with a substantial void fraction at the first stage impeller, but the 

high backpressure associated with small LOCAs could cause pump damage at the same void 

fraction. 

There is concern that more than 5 percent gas passing through a multistage pump may result in 

impeller load imbalance that could bend the shaft or initiate shaft cracks, although this did not 

occur in tests conducted by Palo Verde Nuclear Generating Station in 2004, where flow rates 

remained high. If such damage occurred, it is not clear how long the pump would continue to 

operate. Moreover, such damage may not be evident from developed head tests or pump 

vibration observation. On the other hand, a few cubic feet of finely dispersed 2 percent gas by 

volume, although undesirable in a multistage pump, may not cause pump damage that is 

immediately evident if the exposure time was short, pump flow rate remained high, and the 

exposure did not occur repeatedly. 

These considerations lead to the conclusion that the commonly used limit of 5 percent gas into 

pumps may be reasonable only if a substantial flow rate can be ensured. For low flow rates, it 

may be a nonconservative limit. Furthermore, such gas percentages are undesirable because 

of the potential to cause damage to the pump. 

(6) Control of Gas

Venting for a fixed time at what are perceived as local high points is often performed to satisfy 

TS SRs to ensure that gas accumulation in the ECCS and DHR system will not jeopardize 

operation. However, the SR should reasonably ensure that gas has not affected operability and 

will not likely accumulate in sufficient quantity to jeopardize operability before the next 

surveillance. Venting is sometimes performed where the effluent cannot be directly observed. 

The venting times are sometimes specified, but they may be too short for an unexpectedly large 

gas accumulation. In such cases, effective corrective actions may include modifying vents to 

accommodate direct observation and providing actions keyed to the observed venting results. 

Although the subject systems are often susceptible to gas accumulation, all plants may not have 

vent valves at one or more system high points. Furthermore, vents in long, nominally horizontal 

pipes might not be completely effective in eliminating gas. Licensees have also found vents that 

were supposed to be installed at a high point but were actually installed at a different location. 

Where high points are not vented, the important questions are whether the licensee is aware of 

the potential problems, whether the licensee’s controls and practices sufficiently reflect this 

awareness, and whether modifications should be accomplished. For example, where vents are 

not installed at high points, UT measurements can provide a check for gas, and a high flow rate 

may be useful to ensure that gas has been swept from high points. In other cases, design 

modifications, such as adding vent valves, may be a reasonable approach to problem 
GL 2008-01 

Page 8 of 8 

resolution. For example, one licensee found it needed to install 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 to 

10 CFR Part 50. 

In some cases, it may not be necessary to conduct a surveillance to ensure operability. 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 may be adequate justification for not conducting surveillances inside 

containment or at locations that constitute a hazard to personnel performing the assessment. 

For example, some three loop plants designed by Westinghouse maintain high pressure safety 

injection 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. 

If venting from hazardous locations is necessary to maintain operability, measures such as 

relocating vent valves could be taken in order to address principles of keeping exposures as low 

as is reasonably achievable and personnel safety considerations. 

With similar justifications and additional considerations, extending the time between 

surveillances of certain sections of piping may be reasonable. For example, consideration 

should be given to such conditions as changes in accumulator level and pressure or other 

indicators of potential gas problems. In regard to significant extension of surveillance times, 

consideration should be given to the possibility of a previous surveillance, such as a pump test, 

causing a change in gas behavior, such as a check valve failing to close as tightly as it did 

before the surveillance, a change that appears to have contributed to the Indian Point Unit 2 

event described in the GL. Finally, although not covered by existing TSs, some addressees 

have increased selected surveillance rates when problems were observed until the root cause 

of the gas accumulation could be corrected. 

Hydrogen is sometimes vented and ignition may be a concern if the area to which the hydrogen 

is vented is small and not well ventilated. The source of the gas to be vented should be 

determined and, if the gas is hydrogen, steps to monitor and control the effluent should be 

considered.