Proceedings of the Eleventh 

NRC/ASME Symposium on 

Valves, Pumps, and Inservice 

Testing

Held at Hilton Washington DC/Rockville Hotel

Rockville, MD

August 15-16, 2011

Sponsored by:

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Board of Nuclear Codes and Standards

of the American Society of Mechanical Engineers

Three Park Avenue

New York, NY 10016-5990

Office of Nuclear Reactor Regulation

NUREG/CP-0152, Vol. 8
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the U. S. Regulatory Commission.
Proceedings of the Eleventh 

NRC/ASME Symposium on 

Valves, Pumps, and Inservice 

Testing

Held at Hilton Washington DC/Rockville Hotel

Rockville, MD

August 15-16, 2011

Manuscript Completed: August 2011

Date Published: August 2011

Edited by:

Michael D. Orenak

Division of Component Integrity

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Sponsored by:

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Board of Nuclear Codes and Standards

of the American Society of Mechanical Engineers

Three Park Avenue

New York, NY 10016-5990

Office of Nuclear Reactor Regulation

 

NUREG/CP-0152, Vol. 8
NUREG/CP-0152, Volume 8, has been

reproduced from the best available copy.
iii

Abstract

The 2011 Symposium on Valves, Pumps and Inservice Testing, jointly sponsored by the Board of Nuclear

Codes and Standards of the American Society of Mechanical Engineers and by the U.S. Nuclear 

Regulatory Commission, provides a forum for exchanging information on technical, programmatic and 

regulatory issues associated with inservice testing programs at nuclear power plants, including the design, 

operation and testing of valves, pumps and dynamic restraints. The symposium provides an opportunity to 

discuss improvements in design, operation and testing of valves, pumps and dynamic restraints that help to 

ensure their reliable performance. The participation of industry representatives, regulatory personnel, and 

consultants ensures the presentation of a broad spectrum of ideas and perspectives to be discussed 

regarding the improvement of testing programs and methods for valves and pumps at nuclear power plants.

Paperwork Reduction Act Statement

This NUREG does not contain information collection requirements and, therefore, is not subject to the 

requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.).

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.

v

Steering Committee

John E. Allen

Chairman, Symposium Steering Committee

Robert Horvath

American Society of Mechanical Engineers

Dr. Claude L. Thibault

Consultant Wyle Laboratories

Robert Kershaw

Arizona Public Service Company

Kevin G. DeWall

Idaho National Laboratory

Artin Dermenjian

Sargent & Lundy, LLC

Michael D. Orenak

U.S. Nuclear Regulatory Commission

Anthony C. McMurtray

U.S. Nuclear Regulatory Commission

vii

Acknowledgments

The Steering Committee, the American Society of Mechanical Engineers (ASME), and the U.S. Nuclear

Regulatory Commission gratefully acknowledge the efforts of the Opening Session Speakers, Session 

Chairs, authors, and panel members for their invaluable contribution to the success of the symposium. We 

recognize the participation by international representatives in providing a broad perspective to the valve 

and pump issues under consideration in the United States. We sincerely appreciate the excellent work of 

Mr. Robert Horvath of ASME in coordinating the symposium. We also thank the NRC publications and 

graphics staff for their extensive efforts in preparing the symposium proceedings.
viii

Disclaimer and Editorial Comment

Statements and opinions advanced in the papers presented at the Eleventh NRC/ASME Symposium on 

Valves, Pumps and Inservice Testing are to be understood as individual expressions of the authors and not 

those of either the American Society of Mechanical Engineers or the U.S. Nuclear Regulatory 

Commission. The papers have been copy edited and recast into a standard format. By consensus, Metric 

units have been used as an expression of current industry practice with English units also indicated where 

possible.
ix

Contents

Abstract ......................................................................................................................................................iii

Steering Committee.....................................................................................................................................v

Acknowledgments.......................................................................................................................................vii

Disclaimer and Editorial Comment.............................................................................................................viii

General Session

Welcome:

John E. Allen

American Society of Mechanical Engineers (ASME)

Symposium Co-Chair

John W. Lubinski

Deputy Director

Division of Component Integrity

U.S. Nuclear Regulatory Commission (U.S. NRC)

Symposium Co-Chair

Opening Addresses:

John Zudans

Chairman, Committee on Operation and Maintenance of Nuclear Power Plants, ASME

Jack A. Grobe

Deputy Director for Engineering and Corporate Support, Office of Nuclear Reactor Regulation, U.S. NRC

Users Group Updates:

USA/STARS Motor-Operated Valve Team

Motor Operated Valve Users Group

Inservice Testing Owners Group

Fluid Leak Management Users Group

Pump Users Group

Snubber Users Group

Appendix J Program Owners Group
x

Session 1: Inservice Testing of Dynamic Restraints

Session Chair: Artin Dermenjian, Sargent & Lundy, LLC

1. Exploring Alternatives To Snubber Sample Plan Testing................................................. 3

Mark Shutt, Duke Energy

2. Nuclear Power Plant Dynamic Restraints (Snubbers) Inservice Examination and 

Testing................................................................................................. 12

Gurjendra S. Bedi, Office of Nuclear Reactor Regulation, U.S. NRC

3. ISTD Requirements....................................................................................................... 25

Glen Palmer, Palmer Group International; Raj Rana, Energy Northwest

Session 2(a): Valves I

Session Chair: Kevin G. DeWall, Idaho National Laboratory

1. A Study on an Analytical Approach with Fluid-Structure Interaction Technology for 

the Design of High-temperature Check Valves in Nuclear Power Plants........................... 37

Sangho Song, Jae Hyung Kim, Chi Sung Song, Han Soo Kim, Sung Chang Hong, 

Center for Reliability Assessment of Nuclear Equipments and Machinery, Korea 

Institute of Machinery and Materials; Won Hee Lee, Samshin Limited Co.

2. Systematic Evaluation of Significant Check Valve Application to Improve Reliability 

to Enhance In-Service Test Performance and Plant Availability........................................ 48

Vinod Sharma, Roland Huet, Exponent, Inc.; Domingo A. Cruz, Richard Burge, 

Steven Quan, Palo Verde Nuclear Generating Station

3. Practical Approaches to Gain Operability Margin of Safety Related Gate and Globe 

Valves.................................................................................................... 63

L. Ike Ezekoye, Jeffrey J. Taylor, Terrence J. Matty, Colin P. Arnold, Westinghouse 

Electric Company

4. Online Valve Monitoring Helps Shell Achieve Goals at the Ormen Lange Gas Plant in 

Norway....................................................................................................................... 74

Stan Hale, Score Atlanta, Inc.
xi

Session 2(b): Valves II

Session Chair: Dr. Claude L. Thibault, Consultant Wyle Laboratories

1. OM Code requirements for MOVs - OMN-1 and Appendix III......................................... 93

Kevin G. DeWall, Idaho National Laboratory

2. Palo Verde Implementation of ASME OM Mandatory Appendix III................................ 99

Domingo Cruz, Palo Verde Nuclear Generating Station

3. Code Case OMN-1: An Individual’s Perspective................................................................ 103

Bret Collier, Enercon Services, Inc.

4. Appendix IV for AOVs.............................................................................. 110

5. Technical Review of Recent Packing/Gasket Failures (Operating Experience OE)........ 123

Kenneth A. Hart, AP Services LLC

Session 2(c): Valves III

Session Chair: Dr. Claude L. Thibault, Consultant Wyle Laboratories

1. Case Study of Valve Differential Pressure Calculation Under the Condition of Valve 

Degradation .......................... ................................................................................ 137

Zhilin Dong, Mike Whitehead, Mike Brenner, Callaway Plant

2. Advances in the Design and Qualification of Main Steam and Feedwater Isolation 

Valves (MSIV & MFIV) with Gas Hydraulic Actuators.............................................. 141

Floyd A. Bensinger, Richard J. Gradle, Flowserve Corp. 

3. A Practical Method to Baseline Check Valve UT............................................................... 153

Shawn Comstock, True North Consulting LLC

4. Addressing MOVs in Transition to NFPA 805.................... ......................................... 163

Paul Knittle, MPR Associates, Inc.; Bob Rhodes, Mark Bailey, Progress 

Energy – Shearon Harris
xii

Session 3: New Reactors

Session Chair: Michael Norato, U.S. NRC

1. New Reactors OM Code Pump and Valve Testing Overview......................................... 185

Ron Lippy, True North Consulting LLC; Thomas Ruggiero, Exelon Energy Corporation

2. Inservice Testing Program Improvements for New Reactors........................................ 207

Thomas Scarbrough, Office of New Reactors, U.S. NRC

3. Design and Baseline Testing of Motor Operated Valves for Generation 3+ Nuclear 

Power Generating Plants....................................................................................... 218

Floyd A. Bensinger, Matthew E. Hobbs, Richard J. Gradle, Flowserve Corp.

4. Nuclear Standards for Small Modular Reactors................................................................. 231

James F. Gleason, ARES Corporation

Session 4: Pumps

Session Chair: Robert Kershaw, Arizona Public Service Company

1. Comprehensive Pump Inservice Testing (IST) Issues - Seeking Resolution of Two

Long Standing Regulatory Concerns................................................................................... 239

Robert I. Parry, NextEra Energy Seabrook LLC; 

Thomas Robinson, Nebraska Public Power

2. Allowable Variance from Reference Value for IST Test Flow........................................... 261

Ed Cavey, Fermi 2

3. High Pressure Safety Injection Pump Mechanical Seal Leakage Cause Analysis........... 271

Robert Kershaw, Arizona Public Service Company
xiii

Session 5: Regulatory Interactive 

Session Chair: Anthony C. McMurtray, U.S. NRC

1. Interface between IST Program and Design Engineering............................................... 293

Ed Cavey, Fermi 2

2. Inservice Testing Is About Operability.................................................................. 300

Kevin Mangan, Frank Arner, Region II, U.S. NRC

3. NRC Perspective on Transitioning to ASME OM-2009 Division 1, Mandatory 

Appendix III, "Preservice and Inservice Testing of Active Electric Motor Operated 

Valve Assemblies in Light-Water Reactor Power Plants." (Formerly ASME OM Code 

Case OMN-1)....................................................................................................................... 314

Michael F. Farnan, Office of Nuclear Reactor Regulation, U.S. NRC

4. History of the ASME Code and NRC Regulatory Requirements with Respect to 

Inservice Testing of Pumps and Valves.................................................................... 333

Yun-Seng Huang, Anthony M. McMurtray, Office of Nuclear Reactor Regulation, 

U.S. NRC

Papers Not Presented in a Symposium Session

1. Update on ISTOG Activities for 2011...................................................................... 351

Ed Cavey, Fermi 2

1

Session 1: Inservice Testing of Dynamic 

Restraints

Session Chair: Artin Dermenjian, Sargent & Lundy, LLC

3

Exploring Alternatives to Snubber Sample Plan Testing

Mark Shutt

Duke Energy

Charlotte, NC, USA

Abstract

This paper explores the possibility of alternatives to snubber sample plan testing 

currently required at all US nuclear power plants. The existing requirements 

often result in emergent scope expansion that can significantly impact outage 

duration, accumulated dose, and costs. In addition, the emergent scope may 

also result in risk management issues due to the potential impact on operational 

systems or trains. Alternatives to these plans that eliminate or reduce the 

unplanned scope expansions are available, and some may even provide a higher 

degree of population reliability.

Many plants incorporate preventive maintenance and condition monitoring 

programs under the umbrella term of Service Life Monitoring. In many instances 

these programs are extensive and provide a heightened degree of population 

reliability such that the continued use of sample plan testing is redundant. 

Examples of these programs are explored in this paper as potential alternatives 

to sample testing. These may include rebuild programs, in-place verification 

programs, or other preventive maintenance or service life programs that provide 

sufficient reliability data to replace the sample testing programs.

Introduction

Introduction Testing of snubbers has been a requirement for nuclear power plants 

in the US since the early 1980’s. Testing requirements were initially contained in 

individual plant licensing commitments and took many forms, but all involved 

some variation of a statistically based sample of the snubber population. 

Generally the test plans also involved some degree of randomness in the 

sampling technique used. One key aspect of every plan was a requirement to 

extend the testing into additional (usually random) samples for each 

unacceptable snubber identified. Sampling and testing continued until a certain 

mathematical formula was satisfied or all snubbers were tested. This testing 

requirement remains in effect today in various forms.

Current sample plan testing has other drawbacks in addition to the scope 

expansion. Sample testing as performed can identify a population once it has 

degraded to a certain point, and through scope expansion can “clean up” a 

population. This satisfied the original intent to identify and correct existing 

problems. But such testing provides only a snapshot picture in time. Drawing 
4

conclusions with regard to future reliability is beyond the scope of the statistics 

involved. The testing is not a good reliability tool, in that it is neither predictive 

nor preventive in nature. As plants age, better tools are needed to maintain and 

enhance reliability.

Background

Testing of snubbers is a requirement for US plants as detailed in Title 10 of the 

Code of Federal Regulations (10 CFR) Part 50.55a rulemaking. In simplest 

terms, the rulemaking requires that licensees test snubbers in accordance with 

the ASME Section XI and OM Codes, or else seek regulatory relief to perform 

equivalent testing under some other program. Many plants test snubbers in 

accordance with their Technical Specifications or Technical Requirement Manuals 

(TRMs) using such relief.

Snubber testing was originally required by regulators in response to numerous 

concerns identified during the late 1970’s and early 1980’s. Test requirements 

were included in Standard Technical Specifications, and were often modified 

somewhat for individual plant specifications. However, in all cases some 

statistical sample of installed snubbers is required to be tested, with expanded 

sampling required for any unacceptable snubbers found. With few exceptions, 

testing must be performed each cycle. 

Generally, the sample plans used for snubber testing are one of two options 

available, the 10% Plan or the 37 Plan. Although some variations of these plans 

are used in accordance with plant specific licensing documents, these are the 

two most common plans. For the purposes of this document, these two plans as 

outlined in the OM Code are used for discussion and comparison. 

When using the 10% Plan, a sample of snubbers equal in number to 10% of the 

sampled snubber population is initially selected for functional testing. The 

sample is to be representative of the tested population based upon the significant 

features of snubbers within the population and based upon the ratio of snubbers 

of each feature within the overall population as well. The plan also includes an 

option to include snubbers that are concurrently scheduled for seal replacement 

or similar activities.

In the event of finding an unacceptable snubber in the initial sample, a 

supplemental sample must be tested for each unacceptable snubber identified. 

Supplemental samples must be at least one-half the size of the original sample. 

Additional supplemental samples must be tested for any unacceptable snubbers 

found in supplemental tests as well.

Under the 37 Plan, a sample of 37 snubbers is chosen from the population. The 

sample snubbers are chosen entirely at random. In the event of an unacceptable 

snubber, an additional sample of either 18 or 19 snubbers must be selected for 
5

each such case. Additional samples are also chosen randomly for each 

subsequent failure.

Under both plans there are options to focus testing using Failure Mode Grouping. 

In addition, under the 37 Plan, one supplemental random sample must be tested 

from the overall population for each Failure Mode Group identified and tested.

As seen above, the randomness of the snubbers selected for testing varies 

between the plans. However, there is a random element of selection involved in 

both processes. In addition, the use of Failure Mode Grouping introduces a 

selection process that, while not entirely random, is not predictable prior to 

beginning the test campaign.

Concerns

The concerns with regard to sample testing requirements generally fall into two 

areas. One area of concern involves issues related to the emergent and 

unscheduled work scope that results from supplemental testing requirements. 

The other area of concern relates to weaknesses and limitations of the sample 

testing methodology as an effective reliability tool.

Emergent Work Scope Issues

As noted previously, sample testing often results in supplemental samples that 

can only be identified as emergent work. The actual snubbers selected for 

supplemental tests are dependent upon the conditions associated with the 

original as-found unacceptable snubber (or snubbers) and any identified extent of 

condition concerns. Failure modes and causes must be identified for the original 

snubbers before additional snubbers to be tested can be selected based upon 

that information. This can result in significant concerns with regard to outage 

scheduling, costs, and dose. 

In today’s environment, outage activities are scheduled very tightly and managed 

in great detail. Emergent work scope that has not been carefully planned 

beforehand can result in a cascade effect of delays that impact unrelated areas 

of work. Such delays inevitably result in additional costs. More significant, 

perhaps, is the impact to operational scheduling. Supplemental scope will often 

include snubbers located on systems or trains which have already seen their 

outage maintenance windows closed. The removal of those snubbers for testing 

presents operational challenges as it may affect system availability, require 

operability assessments, or result in entering Technical Specification Required 

Actions.

Likewise, unpredictable scope expansion can result in a direct increase in 

manpower requirements and associated labor costs. Additional personnel may 

be needed to perform the added snubber scope. The emergent scope may 
6

require significantly more scaffolding or other support activities than the original 

scope. In addition, personnel required to continue working on the emergent 

scope are unavailable for other scheduled tasks, resulting in further delays or a 

need for even more additional personnel.

Hand in hand with the increased labor costs, the additional personnel 

involvement will result in increased dose exposure. More person-hours 

expended in completing the field work results in more cumulative dose. Added to 

that is the possibility that at least some of the emergent scope will include 

snubbers in higher dose areas or areas where no additional shielding was 

planned. Overall the dose due to expanded testing scope can be significant. 

Obviously some impact of a supplemental testing scope can be mitigated with 

contingency planning. But since the exact scope of additional work cannot be 

identified ahead of time, contingency planning is often guesswork. Many of the 

above listed factors will inevitably result in significant difficulties. 

Reliability Effectiveness

The second major area of concern is not as directly measurable as the 

scheduling, cost, and dose impacts noted above. This area of concern centers 

on the weaknesses and limitations of the sample testing methodology with 

regards to maintaining the snubber population reliability. As noted previously, 

sample testing of snubbers was initially required in response to a significant 

number of concerns noted during the early years of the nuclear power industry. 

The intention of the sample plan testing was to provide an immediate measure of 

the population reliability at the time of testing. As such, the sample plans proved 

effective at identifying “bad” populations and cleaning them up through the 

supplemental testing process. Statistically speaking, for large populations the 37 

Plan is especially effective for this purpose.

However, this testing provides only a statistical snapshot of a population at the 

time of testing. As such, the tests are not truly predictive – one cannot 

extrapolate future results from a given test campaign. Sample testing as 

practiced today can identify a significantly degraded or “bad” population once it 

reaches a certain level of degradation, and may restore a population by testing a 

large percentage of the snubbers in it. But this typically only occurs through a 

large number of unacceptable snubber tests and large scale supplemental 

testing. In other words, sample testing does a good job of identifying that you 

have a problem once it occurs, but is not reliable in telling you that the problem is 

approaching. Sample test data is very limited in usefulness with regard to 

trending results, as it serves mostly as a “go/no-go” gauge. As such, from a 

component reliability viewpoint it is simply a measure, and a “reactive” rather 

than a “proactive” tool. 
7

There are also some weaknesses inherent within the existing sample plan 

methodology. As a statistical tool, a sample is generally expected to be 

representative of a larger but homogeneous parent population. As currently 

allowed in industry testing requirements, snubber populations sampled are of a 

widely varying degree of homogeny. Many samples are representative by ratio of 

the multiple types of snubbers in the total population, but they vary greatly in type 

and design. While the relevance of this difference is statistically arguable when 

using the sample as a point in time measure of the population condition, it is 

certainly a major weakness in any attempt to forecast any meaningful data from 

the results.

Need For Alternatives

The underlying basis for component testing is to verify function and to assure 

reliability. In the case of large groups of components, such as snubbers, it is 

generally unrealistic to test each individual component. Therefore a method is 

needed to provide some reasonable assurance of reliability that can be 

extrapolated to an entire population of similar components. In the case of 

snubbers, existing regulatory and code requirements attempt to do this through 

the combination of testing and service life monitoring. As noted previously, 

snubbers first became a component of interest due to many real and perceived 

issues identified in the early stages of the nuclear power industry. In response, 

the focus of early requirements was centered upon testing, with the identification 

and correction of “bad” populations as the primary goal.

Due to that focus, both regulatory and code guidance devote the majority of 

emphasis and detail on the sample testing process. This process is expounded 

in great detail over multiple pages of code and licensing documentation. On the 

other hand, service life monitoring is barely mentioned by comparison – with 

generally a simple paragraph or two stating that such monitoring is required. 

This contrast in emphasis has often led to a perception of Service Life Monitoring 

as a “by the way” program. In fact, for a significant number of operating plants 

the “Service Life Monitoring Program” in place consists simply of tracking the 

sample testing results and assuming that the data corroborates their assumed 

service life values as long as they do not result in 100% testing. Almost without 

fail, the vast majority of resources allocated to snubber programs are solely for 

the purpose of completing the required sample testing. 

Thus it has come to pass that the entire industry focuses on the testing of 

snubbers as the primary requirement and most important aspect of a snubber 

program, losing sight of the underlying basis of maintaining population reliability. 

For this reason, alternatives to the existing sample testing methodology are 

needed that will enable resources to be reallocated to fulfilling this basis through 

effective monitoring and preventive maintenance programs that serve to be 

measures of effectiveness as well as predictive in nature. 
8

Potential Alternatives

Obviously, any viable alternative to the sample testing requirements would have 

to provide a current measure of reliability as well as addressing both preventive 

and predictive aspects of reliability. The optimum solution would be a program 

that could accomplish those goals while eliminating or at least reducing the 

amount of emergent work scope required by the program.

There are currently no such alternatives available to the industry. While Code 

Case OMN-15 provides a methodology for extending the required frequency of 

testing, it still relies on a sample testing process that includes potential emergent 

scope. And though the use of the Code Case requires a service life monitoring 

program, there is little guidance as to how that is accomplished or how to 

measure its effectiveness. 

It would appear that the best approach to develop such an alternative program is 

to expand on programs already in place, adding elements to enhance the 

programmatic capabilities to meet the needs described previously. Elements 

required to replace the emergent and random aspects of sample testing would 

have to include the following:

• Verification of functionality 

• Addressing the entire population

• Sufficient data trending to identify adverse trends and corrective 

actions prior to a conservatively estimated end of life

Programs using this approach would obviously have to have extensive service 

life monitoring or condition monitoring programs. While these programs can also 

be costly, they can be designed such that unacceptable snubbers found under 

those programs are addressed using pre-planned corrective action processes 

that avoid the emergent scope aspect (Unless significant generic issues are 

found, in which case normal extent of condition requirements would have to be 

applied). Following are some examples of potential approaches. Effective 

programs may use similar approaches either alone or in combination to result in 

the most efficient program for a given population. The examples included herein 

are not all inclusive. There are a number of alternatives and variations that may 

apply to specific cases. The key element is to be able to verify the population 

reliability to at least the same degree as sample test, without the added burden of 

extensive unplanned scope expansion.

Rebuild Programs

A number of plants already implement a variety of snubber rebuild programs. As 

a minimum, plants with hydraulic snubbers must have a program in place to 

replace seals on a scheduled basis due to the expected seal life. But a number 

of plants have much more extensive programs, including mechanical snubber 
9

rebuilds. Some of these programs involve a systematic rebuilding of all snubbers 

at a very conservative frequency. If all snubbers are rebuilt on a conservative 

time frame, sample testing with provisions for emergent scope may be proven to 

be redundant and unnecessary.

As an example, Plant Alpha may institute a program where 100% of their 

mechanical snubbers are rebuilt on a frequency of 15 years. The generic 

manufacturers suggested service life for the snubbers was originally 40 years, 

but industry experience has proven that to be somewhat non-conservative. 

Based upon industry experience significant age related degradation is expected 

to be seen after 25 years. The plant established the rebuild program many years 

ago, and since then has completely cycled through the population at least once. 

As part of the rebuild program examination of internal parts is performed and any 

degradation indications are evaluated and trended. In addition to the rebuilding 

program, random testing under a sample plan is also performed each outage. 

Since implementing the rebuild program no test failures have been recorded.

By industry consensus, the rebuild frequency used is conservative. Information 

from the rebuild data shows that no significant age related degradation has been 

noted on a general basis. Based upon these facts and the fact that the entire 

population is covered by the program, the random outage testing has proven to 

be redundant and unnecessary to verify the reliability of the population. An 

argument could be made that there is no need to continue such testing. The 

addition of Service Life Monitoring testing may serve as an enhancement to the 

rebuild program to provide further confidence, but that testing could be performed 

on samples chosen well ahead of time using a planned approach with no need 

for random scope expansion as a result of isolated incidences. 

Service Life Monitoring Programs

An extensive Service Life Monitoring Program by itself may be sufficient to 

provide confidence in population reliability. An effective program would include 

some degree of functional testing of snubbers, using some appropriate selection 

criteria and frequency. If that testing, combined with other service life monitoring 

aspects, covers the entire population over a reasonable period of time, then that 

data could be used to extrapolate conclusions to the entire population. Such 

conclusions would render the need to perform sample testing to verify reliability 

as unneeded. 

Again, the testing required to reach such conclusions may be extensive, but it 

could be planned scope that would not normally be expected to result in 

emergent outage work. Much of service life monitoring testing and corrective 

actions could be performed in non-outage periods. The goal of such a program 

would be to collect sufficient data as to identify any significant population-wide 

concerns well before such concerns are an immediate issue.
10

Condition Monitoring Programs

Similar to Service Life Monitoring, Condition Monitoring actively assesses the 

reliability of each component, rather than extrapolating data. If such a program 

sufficiently addresses the entire population over a reasonable time period (and is 

repeated on an appropriate frequency), then the actual monitoring of the 

populations functionality can preclude the need for testing. An example of such a 

program would be one where all mechanical snubbers in a population are 

manually exercised on a periodic basis. 

Such stroking of mechanical snubbers by trained personnel serves not only to 

verify functionality, but also as a valid and recommended preventive maintenance 

activity that extends the life of the snubber. By applying this method to an entire 

population, the reliability of the population is verified to a greater degree than can 

be accomplished with sample testing that includes only a small portion of the 

snubbers. If this activity is completed on a sufficiently frequent basis, there would 

be no need to perform statistical based testing. This program could be combined 

with service life testing to obtain additional trending data to be used in a more 

predictive manner with regard to life expectancy. This program would provide 

assurance of reliability as well as early indications of significant issues. The 

scope of the work performed would be such that extent of condition concerns 

would require additional scope only in the most extreme situation. 

Rotational Testing

Another potential method to address population reliability is to perform testing on 

a rotational basis, where the entire population is tested over a finite period of 

time. This would likely be more appropriate for plants with small populations. An 

example might be a plant with a population of 100 snubbers. This plant may 

choose to test 25% of the snubbers each cycle on a rotating basis, thereby 

testing 100% of the snubbers over a 4-cycle period. Although they are testing 

more than the normal 10% each time, they could make a case for not expanding 

scope for 1 or 2 unacceptable snubbers – as long as they could show sufficient 

corrective actions and trending is performed. This program would be an effective 

reliability and service life program, with no significant need for emergent outage 

scope.

Implementation of Alternatives

In the current licensing environment, snubber testing is performed either in 

accordance with site specific licensing requirements or in accordance with ASME 

Code requirements. Therefore, in order to implement an alternative 

methodology, either a relief request or code change would be required. Although 

any licensee is permitted to request relief, the current focus within the industry is 

to move towards more consistency among snubber programs. It would appear 

then that the best approach to implement change would be through a revision to 
11

the code itself. Although it is noted that code changes are often modeled on a 

“pilot” relief request, any individual plant relief would likely be too specific to serve 

as a basis for a generic code change.

Most likely the best approach to incorporating any alternative to testing into the 

OM Code would be through a code case. This type of alternative represents a 

shift in philosophical focus for inservice testing as currently presented in the 

code, so such a code case would require a significant amount of justification and 

documentation. The wording would have to be generic enough to cover the 

multiple possible alternatives, yet specific enough to clearly delineate 

requirements regarding reliability measures and corrective actions. Although this 

represents a significant effort, this is possibly a worthwhile undertaking for an 

ISTD task group as an enhancement to the code. 

Conclusion

There are many burdens associated with sample testing of snubbers and the

emergent scope expansion that is often required. These burdens include outage 

schedule impacts, added costs, increased dose, and potential operational 

challenges. Alternatives to the sample testing methodology are possible that 

could reduce or eliminate these burdens while at the same time maintaining the 

ability to measure and maintain population reliability. Although individual plants 

may choose to pursue regulatory relief to implement an alternative specific to a 

given program, the best approach appears to be an effort to produce an ISTD 

code case to provide generic alternative guidance. Such alternatives would 

greatly benefit many plants individually, and overall could serve to increase the 

ability of the industry to focus on true component reliability improvement.

References

1. ASME OM Code (multiple editions)

2. ASME Section XI (multiple editions)

3. 10 CFR 50.55a rulemaking
12

Nuclear Power Plant Dynamic Restraints (Snubbers) 

Inservice Examination and Testing 

Gurjendra S. Bedi, P.E*

Division of Component Integrity

Component Performance and Testing Branch

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

* This paper was prepared by staff of the U.S. Nuclear Regulatory Commission. 

It may present information that does not currently represent an agreed-upon 

NRC staff position. The NRC has neither approved nor disapproved the technical 

content.

Abstract

This paper discusses recent issues related to inservice inspection (ISI) and 

testing of dynamic restraints (snubbers) at U.S. nuclear power plants. These 

issues were identified during the U. S. Nuclear Regulatory Commission (NRC) 

staff review of ISI and testing snubber programs and relief requests, and 

applicable operating experience. This discussion includes information that could 

have generic applicability in the implementation of effective snubber programs at 

U.S. nuclear power plants.

Introduction

The NRC staff has encountered a number of snubber inservice inspection (ISI) 

and testing issues since the Tenth NRC/ASME Symposium on Pumps, Valves 

and Inservice Testing in 2008. This paper discusses (1) Title 10 of the Code of 

Federal Regulations (10 CFR) 50.55a requirements for snubber inservice 

inspection and testing programs at nuclear power plants; (2) Mandatory subber

inservice examination and testing program updates; (3) Use of Relief Request 

alternatives in lieu of the ASME Code requirements; (4) Voluntary Use of Later 

Editions and Addenda to the American Society of Mechanical Engineer (ASME) 

Code; (5) Snubber Programs and their Bases; (6) General documentation and 

their submittal requirements for the snubber inservice examination and testing 
13

programs; and (7) Use of the10 CFR 50.59 processes to change the NRC 

authorized relief request alternative related to inservice examination and testing 

of snubbers. Some current staff positions and actions in these areas are also 

discussed. This discussion includes information that could have generic 

applicability in the implementation of effective inservice inspection and testing 

snubber programs at U.S. nuclear power plants. 

Regulatory Requirements for Snubber Inservice Examination and Testing 

Programs at Nuclear Power Plants

The regulations in Title 10 of the Code of Federal Regulations (10 CFR) 

50.55a(b) describe the Codes and Standards that have been approved for 

inclusion in 10 CFR 50.50a, including the effective edition and addenda of the 

ASME Boiler and Pressure (B&PV) Code and the ASME Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code).

10 CFR 50.55a(g) contains the ISI requirements that licensees must use when 

performing ISI of components (including supports). 10 CFR 50.55a(g)(4) states, 

in part, “Throughout the service life of a boiling or pressurized water-cooled 

nuclear power facility, components (including supports) which are classified as 

ASME Code Class 1, Class 2, and Class 3 must meet the requirements, except 

design and access provisions and preservice examination requirements, set forth 

in Section XI of editions of the ASME B&PV Code and Addenda.” 

Snubbers are part of component “supports.” Supports are widely used to support 

various safety or non-safety related piping systems or components in the nuclear 

power plants. The most widely used supports are (1) Rigid Supports; (2) RodHanger Supports; (3) Spring- Hanger Supports; and (4) Snubbers. Therefore, 

the regulations in 10 CFR 50.55a(g)(4) require that ASME Code Class 1, 2, and 

3 snubbers meet the ISI and testing requirements of the ASME B&PV Section XI 

or OM Code, as incorporated by reference in 10 CFR 50.55a(b).

10 CFR 50.55a also requires inservice examination and testing of snubbers 

because it incorporates by reference the ASME B&PV Code, Section XI, “Rules 

for Inservice Inspections of Nuclear Power Plant Components,” requirements 

contained in Article IWF-5000, “Inservice Inspection Requirements for Snubbers, 

and the ASME OM Code requirements in Subsection ISTD, “Preservice and 

Inservice Examination and Testing of Dynamic Restraints (Snubbers) in LightWater Reactor Nuclear Power Plants.” The inservice examination and testing of 

snubbers has been a requirement in Article IWF-5000 since Article IWF was first 
14

issued in the Winter 1978 Addendum to ASME B&PV Code, Section XI. The 

2005 Addendum and earlier editions and Addenda of Section XI, of the ASME 

B&PV Code, Article IWF-5000, provide the requirements for the examination and 

testing of snubbers in nuclear power plants. Article IWF-5000 has been deleted 

in the 2006 Addendum of the ASME B&PV Code, Section XI. Subsection ISTD 

of the ASME OM Code has included provisions for the examination and testing of 

snubbers since it was first issued in 1990. Licensees have the option of using 

the ASME B&PV Code, Section XI or the ASME OM Code for snubber inservice 

examination and testing, if their applicable “Code of Record” is 2005 Addendum 

and earlier editions Addenda of Section XI, of the ASME B&PV Code. 

10 CFR 50.55a(b)(3)(v) of the 10 CFR 50.55a(b) allows licensees using editions 

and addenda up to the 2005 Addendum of the ASME B&PV Code Section XI, to 

optionally use Subsection ISTD of the ASME OM Code, in place of the 

requirements for snubbers in Section XI. This part of regulations also states that 

snubber preservice and inservice examinations must be performed using the VT3 visual examination method as described in IWA-2213, when using Subsection 

ISTD of the ASME OM Code. The NRC imposed the VT-3 visual examination 

requirement to ensure that licensees use an appropriate visual examination 

method for the inspection of integral and nonintegral snubber attachments, such 

as lugs, bolts, and clamps, when using Subsection ISTD. 

Licensees that use the 2006 Addendum and later editions and Addenda to 

Section XI of the ASME B&PV Code must follow the requirements of Subsection 

ISTD of the ASME OM Code for snubbers because ASME removed the 

requirements for the examination and testing of snubbers from the scope of 

Section XI in the 2006 Addendum. 10 CFR 50.55a(b)(3)(v) does not invoke the 

VT-3 visual examination and testing requirement when licensees use the 2006 

Addendum and later editions and Addenda to Section XI because ASME revised 

Figure IWF-1300-1 in the 2006 Addendum to Section XI to clarify that integral 

and nonintegral snubber attachments are within the scope of Section XI. 

Recently the NRC issued new rulemaking for 10 CFR 50.55a. In this new 

rulemaking 10 CFR 50.55a(b)(3)(v) has been updated as follows:

“Subsection ISTD. Article IWF-5000, "Inservice Inspection Requirements for 

Snubbers," of the ASME B&PV Code, Section XI, must be used when performing 

inservice inspection examinations and tests of snubbers at nuclear power plants, 

except as conditioned in (A) and (B) below:
15

(A) Licensees may use Subsection ISTD, "Preservice and Inservice 

Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water 

Reactor Power Plants," ASME OM Code, 1995 Edition through the latest 

edition and addenda incorporated by reference in paragraph (b)(3) of this 

section, in place of the requirements for snubbers in the editions and 

addenda up to the 2005 Addenda of the ASME B&PV Code, Section XI, 

IWF-5200(a) and (b) and IWF-5300(a) and (b), by making appropriate 

changes to their technical specifications or licensee-controlled documents. 

Preservice and inservice examinations must be performed using the VT-3 

visual examination method described in IWA-2213. 

(B) Licensees shall comply with the provisions for examining and testing 

snubbers in Subsection ISTD of the ASME OM Code and make 

appropriate changes to their technical specifications or licensee-controlled 

documents when using the 2006 Addenda and later editions and addenda 

of Section XI of the ASME B&PV Code.”

Mandatory Snubber Inservice Examination and Testing Program Updates

10 CFR 50.55a(g)(4)(ii) requires licensees to revise their inservice inspection 

(ISI) programs every 120 months to reflect the latest edition and addendum to 

Section XI of the ASME B&PV Code incorporated by reference into 

10 CFR 50.55a(b)(2) that is in effect 12 months before the start of the new 120-

month ISI interval. This Code is considered to be the “Code of Record” for the 

inspection interval.

Additionally, 10 CFR 50.55a(g)(4)(iv) notes that ISI of components (including 

supports) may meet the requirements set forth in subsequent editions to the 

“Code of Record” and addenda that are incorporated by reference in 

10 CFR 50.55a(b), subject to limitations and modifications listed in 

10 CFR 50.55a(b) and subject to Commission approval.

Use of Relief Request Alternatives in lieu of the ASME Code Requirements

Licensees are required to perform the ISI and testing of snubbers in accordance 

with ASME BPV Code, Section XI or the ASME OM Code and the applicable 

addenda as required by 10 CFR 50.55a(g) or 10 CFR 50.55a(b)(3)(v), except 

where the NRC has granted specific written relief, pursuant to 

10 CFR 50.55a(g)(6)(i), or authorized alternatives pursuant to 10 CFR 50.55a(3). 

10 CFR 50.55a(a)(3) states that licensees may use alternatives to the 
16

requirements of 10 CFR 50.55a(g) when authorized by the NRC if (1) the 

proposed alternatives would provide an acceptable level of quality and safety, or 

(2) compliance with the specified requirements would result in hardship or 

unusual difficulty without a compensating increase in the level of quality and 

safety.

Currently, few licensees are using the ASME OM Code to meet the requirements 

of 10 CFR 50.55a for snubber inservice examination and testing, whereas most 

of the licenses are using a variety of licensee-controlled documents or 

procedures in lieu of the applicable ASME Code requirements. These licenseecontrolled documents or procedures include the following: 

1. Technical Specification (TS)

2. Technical Requirement Manual (TRM)

3. Final Safety Analysis Report (FSAR)

4. Updated Final Analysis Report (UFSAR)

5. Selected Licensee Commitment (SLC)

6. Licensee-Controlled Specification (LCS)

7. Equipment Control Guidelines (ECG)

8. Other Licensee-Controlled Procedures

Recently, the NRC staff has identified several instances in which nuclear power 

plants licensees have used a TRM, or other licensee-controlled documents and 

procedures, which do not meet requirements of their “Code of Record” for the ISI 

and testing of snubbers. These licensees have not requested approval to use 

these alternatives from the Commission. The NRC issued Regulatory Issue 

Summary (RIS) 2010-06, “Inservice Inspection and Testing Requirements of 

Dynamic Restraints (Snubbers)” on June 1, 2010 to remind all the licensees of 

the NRC’s rules and regulations regarding snubber ISI and testing, in accordance 

with 10 CFR 50.55a(g), at nuclear power plants.

The NRC expects licensees to ensure that their snubber ISI and testing 

programs are in compliance with 10 CFR 55.55a(g) or authorized alternatives. If 

licensees discover that their programs are not meeting 10 CFR 50.55a(g) 

requirements or authorized alternatives, they should take appropriate actions to 

bring their programs back into compliance and ensure that non-compliant 

systems, structures and components are operable. In certain circumstances 

involving snubber programs at nuclear power plants that are not in compliance 

with NRC requirements, enforcement discretion has been provided by the NRC. 

The NRC’s Office of Enforcement issued Enforcement Guidance Memorandum 

(EGM)-10-001, “Dispositioning Violation of Inservice Examination and Testing 

Requirements for Dynamic Restraints (Snubbers),” on June 1, 2010 to provide 
17

NRC staff guidance for the disposition of certain 10 CFR 50.55a violations and 

the potential of granting enforcement discretion for the affected requirements. 

NRC expects that licensees of nuclear power plants, who were not meeting the 

10 CFR 50.55a requirements for snubber inservice examination and testing as 

described in RIS 2010-06, should have entered any noncompliance into the 

corrective action system by December 01, 2010, and should have scheduled to 

correct the noncompliance by June 01, 2012 or submitted a relief request to NRC 

by June 01, 2011. 

Voluntary Use of Later Editions and Addendas to the ASME Code

Licensees must conduct inservice examination and testing to verify the 

operational readiness of snubbers within the scope of the ASME Code in 

accordance with 10 CFR 50.55a(g)(4)(ii). In conducting these examinations and 

tests, licensees must comply with the provisions of the latest edition and 

addendum to the ASME Code, which 10 CFR 50.55a(b) incorporates by 

reference, 12 months before the start of the successive 120-month interval, 

subject to the limitations and modifications conditions listed in 10 CFR 50.55a(b). 

After the initial 120-month interval, 10 CFR 50.55a(g)(4)(iv) notes that the 

inservice examination and tests of components (including supports) may meet 

the requirements set forth in subsequent editions and addenda of the ASME OM 

Code or ASME B&PV Code, Section XI that 10 CFR 50.55a(b) incorporates by 

reference, subject to NRC approval. This includes the examination and testing of 

snubbers. Licensees may use portions of editions or addenda provided that all 

related requirements of the respective editions or addenda are met. When 

requesting to use editions and addenda to the ASME OM Code or ASME B&PV 

Code, Section XI Code that have not yet been incorporated by reference, 

licensees must request authorization to use these later editions and addenda as 

an alternative to the regulations under 10 CFR 50.55a(a)(3).

The amount of written documentation needed for a request to use a later ASME 

OM Code or ASME B&PV Code, Section XI Code edition and addendum that 

10 CFR 50.55a(b) incorporates by reference is significantly less than that of a 

request to use an alternative requirement. For example, licensees are not 

required to justify requests to use the later ASME OM Code editions and 

addenda that 10 CFR 50.55a(b) incorporates by reference. In contrast, when 

submitting an alternative request, licensees must provide justification that the 

proposed alternative would provide an acceptable level of quality and safety. If a 

licensee uses portions of a later ASME OM Code or ASME B&PV Code, Section 

XI edition and addendum, it must ensure that all related requirements of the 

respective editions and addenda are met. The licensee should discuss the 

related requirements in its letter to the NRC. The regulations do not specify 
18

when the licensee should submit the letter, only that it should submit the letter 

before it uses the later ASME OM Code or ASME B&PV Code, section XI edition 

and addendum. The staff issued Regulatory Issue Summary (RIS) 2004-12, 

“Clarification on Use of Later Editions and Addenda to the ASME OM Code and 

Section XI,” dated July 28, 2004, in order to clarify this matter.

Snubber Programs and Their Bases

Licensees are using TRMs or other licensee-controlled documents for snubber 

inservice examination and testing, in lieu of the ASME B&PV Code, Section XI 

requirements. TRMs or other licensee-controlled documents serve as bases for 

snubber programs and most of the snubber programs have similarities across the 

industry. Many licensees are in the process of updating their snubber programs 

as required by the ASME OM Code. Some licensees have already updated their 

programs to use ASME OM Code. The NRC staff has observed that some of the 

updated snubber programs are not consistent or complete. Some of the updated 

programs simply reference plant procedures for snubber examinations and 

testing without providing any details about sections, subsection(s) and/or 

paragraphs of the applicable ASME OM Code. Licensees should consult with 

the Snubber User Group (SNUG), when developing guidance for snubber 

programs and their bases, to help ensure consistency throughout the industry. 

The updated snubber programs should contain at least the details and bases as 

documented in the TRM, or other licensee-controlled documents in alignment 

with the ASME OM Code. Bases documents have typically included a 

description of the methodology used in preparing the snubber programs. The 

bases document should clearly state where a list of each snubber is kept and 

how it is being maintained. Although not required by the regulation, the bases 

documents will help licensees ensure the continuity of their snubber programs 

when the responsibilities of personnel or groups change. A good bases 

document will also enable the plant staff to clearly understand the reasons that 

the snubbers are either in the program or not, as well as the basis for 

examination and testing. The bases document can also serve as a useful 

reference for reviews performed under 10 CFR 50.59 when changes are made to 

a facility.

General Documentation and Their Submittal Requirements for the Snubber

Inservice Examination and Testing Programs

10 CFR 50.55a(g)(4) requires that, throughout the service life of a boiling or 

pressurized water-cooled nuclear power facility, ASME Code Class 1, 2, and 3 

components (including supports) meet the ISI and testing requirements of the 

ASME B&PV Code, Section XI or ASME OM Code as incorporated by reference 

in 10 CFR 50.55a(b). The applicable ASME B&PV Code, Section XI, Article 

IWA-1000, “General Requirements,” and ASME OM Code, Subsection ISTA, 
19

“General Requirements,” provide the documentation and submittal requirements 

for inservice testing and examination of certain components in light-water nuclear 

power plants. Therefore, based on these requirements, licensees are required to 

submit their snubber examination and testing programs and their updates every 

120 months. 

(a) Documentation requirements for snubber programs when using the 

ASME B&PV Code, Section XI 

IWA-1400(c) notes that owners, have the responsibility to prepare plans, 

schedules, and inservice inspection summary reports, and submit of these 

plans and reports to the enforcement and regulatory authorizes having 

jurisdiction at the plant site.

Article IWA-6000, Record and Reports, provides the requirements for 

preparation, submittal, and retention of records and reports.

(b) Documentation requirements for snubber programs when using the 

ASME OM Code 

ISTA-3200(a) requires that plans for inservice examination and testing of 

snubbers shall be filed with the regulatory authorities having jurisdiction at 

the plant site.

ISTA-9000, Records and Reports, provides the requirements for 

preparation, submittal, and retention of records and reports.

Nonmandatory Appendix-A, and the Supplement to Nonmandatory 

Appendix-A describes voluntary guidance for licensees to develop 

snubber inservice examination and testing plans. 

(c) Documentation requirements for snubber programs when using NRC 

authorized alternative TS, TRM or other-licensee-controlled 

documents in lieu of the ASME B&PV Code, Section XI, or ASME OM 

Code

NRC authorized relief to use TRMs or other-licensee-controlled 

documents, in lieu of the ASME B&PV Code, Section XI or ASME OM

Code requirements for inservice examination and testing of snubbers, do 

not provide relief from submitting snubber programs to the regulatory 
20

authorities. Submittal is required by the applicable ASME B&PV Code, 

Section XI or ASME OM Code as noted in (a) and (b) above. 

Licensees not meeting the requirements of IWA-1400(c) or ISTA-3200(a) must 

submit appropriate documents containing snubber inservice examination and 

testing plans and submit a request for relief to the NRC pursuant to 

10 CFR 50.55a(a)(3). NRC staff will not perform a review of submitted snubber 

inservice examination and testing programs unless requesting alternatives or 

reliefs to Code requirements. 

Use of the 10 CFR 50.59 Processes to Change the NRC Authorized Relief 

Request Alternative Related to the Inservice Examination and Testing of 

Snubbers

10 CFR 50.55a, “Code and Standards,” defines the requirements for applying 

industry codes and standards to boiling- or pressurized-water-cooled nuclear 

power facilities. Each of these facilities is subject to the conditions in paragraphs 

(a), (b), (f), and (g) of 10 CFR 50.55a, as they relate to inservice inspection (ISI) 

and inservice testing (IST).

Except where alternatives have been authorized or relief has been requested by 

the licensee and granted by the Commission pursuant to Sections (a)(3)(i), 

(a)(3)(ii), (f)(6)(i) or (g)(6)(i), 10 CFR 50.55a, requires, that the ISI of ASME Code 

Class 1, 2, and 3 components (including snubbers) shall be performed in 

accordance with ASME B&PV Code, Section XI, or ASME OM Code, including 

applicable addenda. 

10 CFR 50.59 requires that licensees (1) evaluate proposed changes to their 

facilities for their effects on the licensing basis of the plant, as described in the 

Final Safety Analysis Report (as updated), and (2) obtain prior NRC approval for 

changes that meet specified criteria as having a potential impact upon the basis 

for issuance of the operating license. 

In accordance with 10 CFR 50.55a, the NRC has approved alternatives and 

granted numerous reliefs from the ASME Code requirements. Once relief is 

granted, the alternative approved for the relief request becomes a part of the 

licensee’s snubber programs and regulatory requirements. Therefore, changing 

from one alternative or relief to another would require NRC approval. In no case 

should licensees use the 10 CFR 50.59 process to supersede or overwrite a 
21

previously authorized relief request, since 10 CFR 50.55a requires these 

alternatives to ASME Code requirements be authorized by the NRC. 

Most of the licensees’ snubber examination and tests requirements are included 

in their TSs, TRMs, or other licensee-controlled documents. The TRM 

requirements and other licensee-controlled documents are controlled using the 

criteria in 10 CFR 50.59. In the case of snubber inservice examination and 

testing, the NRC has authorized the use of the TRM snubber examination and 

testing requirements or other licensee-controlled documents requirements for 

snubber examination and testing, in lieu of the ASME Code requirements, at 

numerous operating plants through the 10 CFR 50.55a relief process.

Recently the NRC has learned that a licensee used the 10 CFR 50.59 process to 

revise the snubber inservice examination and testing requirements of the TRM. 

The requirements contained in this TRM were approved by the NRC to be used 

as an alternative to the ASME Code requirements. The use of an alternative as 

authorized by the NRC becomes a regulatory requirement; thus changes to these 

requirements must be reviewed and approved by the NRC staff pursuant to 10 

CFR 50.55a(a)(3). 

Nuclear Energy Institute (NEI) Procedure, NEI 96-07, Revision 1, “Guidelines for 

10 CFR 50.59 Implementation,” notes that licensees activities which are 

controlled by regulation (e.g. 10 CFR 50.55a), take precedence over the 10 CFR 

50.59 requirements. NEI 96-07, Revision 1 was endorsed by Regulatory Guide 

(RG) 1.187. Similarly, RG 1.187, Section D, “Implementation,” notes that 10 

CFR 50.59 cannot be used in those cases in which a licensee proposes an 

acceptable alternative method for complying with the specified portion of the 

NRC’s regulations. Licensees are encouraged to use caution when revising or 

changing programs or procedures referenced in an approved relief request or 

TRM. Any changes or updates that supersede or overwrite an alternative or 

relief authorized in a relief request must be approved by the NRC unless the 

requirements of the ASME Code can be met. Utilization of the 50.59 process to 

change the requirements of an approved relief request is not appropriate. 

Conclusion

The purpose of this paper is to make licensees aware of a number of snubber 

inservice examination and testing issues that the NRC staff has encountered 

since the Tenth NRC/ASME Symposium on Pump, Valve and Inservice Testing 

in 2008. The Flowchart, Appendix-I, “Use of 10 CFR 50.55a Regulatory 
22

Requirements for Development of Snubber Inservice Examination and Testing 

Program,” is attached for quick reference to regulations applicable to snubbers 

inservice examination and testing at nuclear power plants. Licensees who 

believe that some of the items discussed are applicable to their facilities may 

wish to review their current ISI and testing programs for snubbers and modify or 

update their programs, as appropriate. 

References

NUREG/CP-0152, Vol. 7, “Proceedings of the Tenth NRC/ASME Symposium on 

Valve and Pump Testing,” July 2008.

U.S. Code of Federal Regulations, Domestic Licensing of Production and 

Utilization Facilities, Part 50, Chapter I, Title 10, AEnergy,@ Section 50.55a, Codes 

and standards.

NUREG-1482, Revision 1 “Guidelines for Inservice Testing at Nuclear Power 

Plants.”

Regulatory Guide 1.187, “Guidance for Implementation of 10 CFR 50.59, 

Changes, Tests, and Experiments.”

Nuclear Energy Institute Procedure, NEI 96-07, Revision 1, “Guidelines for 10 

CFR 50.59 Implementation.”

American Society of Mechanical Engineers Boiler and Pressure Vessel Code, 

Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components.

American Society of Mechanical Engineers (ASME)/American Nuclear Standards 

Institute (ANSI) Operation and Maintenance of Nuclear Power Plants (OM), Part 

4 (OM-4), 1987 Edition with OMa-1988 Addenda. 

ASME/ANSI, Code for Operation and Maintenance of Nuclear Power Plants, 2004 

Edition: with 2005 addenda and 2006 addendas

Regulatory Issue Summary (RIS) 2010-06, “Inservice Inspection and Testing 

Requirements of Dynamic Restraints (Snubbers), dated June 1, 2010 

(ML101310338). 
23

Enforcement Guidance Memorandum- EGM-10-01, “Dispositioning Violation of 

Inservice Examination and Testing Requirements for Dynamic Restraints 

(Snubbers), dated June 1, 2010 (ML101390020).

Regulatory Issue Summary (RIS) 2004-12, “Clarification on Use of Later Editions 

and Addenda to the ASME OM Code and Section XI,” dated July 28, 2004 

(ML042090436).
24

Flowchart - Development Inservice Examination and Testing Program for 

Snubbers*

Regulatory Requirements for 

(1) Snubber Inservice Examination and 

Testing Program (10 CFR 50.55a), and

(2) Mandatory update of Snubber Program 

Every 10-Year Interval 

[10 CFR 50.55a(f) or 10 CFR 50.55a(g)], 

[Regulatory Issue Summary (RIS) 2010-06]

Licensee must use following ASME Code 

for Snubber Program:

(1) ASME OM Code 

or 

(2) ASME B&PV Code, Section XI

[10 CFR 50.55a(b)]

Licensee must Submit Relief Request (RR) 

to use Alternative Requirements such as 

TS, TRM or other licensee-controlled 

document for a 10-Year Interval

[NEI Guidance for Standard Format of RR 

dated June 7, 2004 

(ADAMS No. ML070100400)]

ASME B&PV Section XI, 

Article IWF-5000

[10 CFR 50.55a(b)]

[Note: ASME Section XI, 

2006 addenda deleted 

Snubber ISI and Testing 

requirements; then, 

licensees must use ASME 

OM Code]

ASME OM Code, 

Subsection ISTD

[10 CFR 50.55a(b)(3) (v)]

IWF-1000, General Requirements

IWF-5200 and IWF-5300

(ASME/ANSI OM-1987, Part 4 

(OM-4) with OMa-1988 addenda)

Use Subsection IWF of ASME B&PV 

Code, Section XI for Integral and 

nonintegral attachments etc. of snubbers

ISTA, General Requirements

ISTD, Snubber (pin-to-pin) Inservice 

Examination & Testing Requirements

Use Subsection IWF of ASME B&PV Code 

Section XI for Integral and nonintegral 

attachments etc. of snubbers

IWA-1400(c), Requires Licensee to 

Submit Snubber Program to 

Regulatory Authority (NRC)

IWA-6000 provides “Record and 

Reports” requirements.

Note: NRC will not perform any review 

of submitted snubber program.

ISTA-3200, Requires Licensee to 

Submit Snubber Program to 

Regulatory Authority (NRC) 

ISTA-9000, provides “Record and 

Reports” requirements

Note: NRC would not perform any 

review of submitted snubber program.

NRC authorized alternative to use 

TS, TRM or other licenseecontrolled document in lieu of the 

ASME Code requirements

10 CFR50.55a(a)(3)(i)

Applicable ASME Code 

IWA-1400(c) or ISTA-3200, Requires 

Licensee to Submit Snubber Program 

to NRC 

IWA-6000 or ISTA-9000 provide 

“Reports and Records” requirements

Note: NRC would not perform any 

review of submitted snubber program.

Sunbber Examination and 

Testing Program based on 

authorized alternative TS, 

TRM or licensee-controlled 

document

Licensee Not 

using or meeting 

ASME Code 

Requirements

ASME Code Cases 

may be used, RG 

1.192 for Acceptable 

Code Cases [10 CFR 

50.55a(b)]

Licensee Using ASME 

Code Requirements

Use of 

Either 

Code Cases, which 

are not approved for 

use in RG-1.192, may 

be used by submitting 

RR and if approved 

by NRC. 

* Flow Chart is for guidance only. For complete details, see 10 CFR 50.55a
25

ISTD Requirements

Glen Palmer

Palmer Group International

Raj Rana

Consulting Engineer

Energy Northwest

Abstract

The American Society of Mechanical Engineers (ASME) Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code), Subsection ISTD, describes 

the preservice and inservice examination and testing requirements for dynamic 

restraints (Snubbers). This Code was originally published as an American 

National Standards Institute (ANSI) standard (OM-4) in 1982. Since that time the 

OM-4 Code has been revised and improved over the years. For the first time 

OM-4 was published as Subsection ISTD in the ASME OM Code in 1990, which 

has been also revised and improved over the years and is published in its latest 

version in the ASME OM Code, 2009 edition. The OM-4 document has been 

referenced for many years within the ASME Boiler and Pressure Vessel Code, 

Section XI, Rules for Inspection of Nuclear Power Plant Components. 

Specifically, the snubber inservice inspection and testing requirements were 

referenced as ASME/ANSI OM, Part 4 (OM-4), located in Section XI, Article IWF5000. While the snubber examination requirements were referenced in IWF5000, there were many owners who asked for relief from the Section XI 

referenced requirements using similar requirements located in owner’s Technical 

Specifications (TS) or owner controlled technical requirement manuals (TRM), 

relief was granted in order to avoid overlapping boundaries between the ASME 

OM requirements and the Section XI requirements. This has resulted in a wide 

range of program approaches and differing snubber inspection and testing 

programs. 

With the publication of the 2006 addenda to the Section XI Code, the 

requirements previously located in Article IWF-5000 were deleted. When Section 

IWF-5000 was deleted, the requirements for examination and testing of snubbers 

as required by 10CFR50.55a would now point to the ASME OM Code, 

Subsection ISTD. Since there is now be only one requirement within the ASME 

Code for snubber examination and testing requirements, it is anticipated there 

will be fewer relief requests when owners prepare updates to their snubber 
26

examination and testing programs. Therefore, when owners prepare their ten 

year inservice testing (IST)/inservice inspection (ISI) program updates that 

incorporate the 2006 addenda of the Section XI Inspection Code, the snubber 

requirements will be required to be in accordance with the ASME OM Code, 

Subsection ISTD. This edition of the ASME OM Code is referenced in the NRC 

Rulemaking published in Federal Register on June 21, 2011 (Federal Register, 

Vol. 76, No. 119, page 36232-36279). From this point forward, owners are 

required to meet the requirements of the ASME OM Code, Subsection ISTD, for 

snubber examination and testing requirements when they update their ISI or IST 

programs otherwise 10 CFR 50.55a requires to submit relief request to NRC to 

use alternative in lieu of the ISTD requirements. 

Since this will be a change in requirement, owners may be asking some of the 

following questions. What is the difference between our existing program 

requirements and those included in the ASME OM Code, Subsection ISTD? Will 

this change the way the current snubber examination and testing program is 

implemented? How much effort will be required to make this program change? 

Although this paper will not provide specific guidance for the implementation of 

the ISTD Code, it will generally describe the requirements of Subsection ISTD 

and identify typical areas where changes may be required to existing snubber 

examination and testing programs.

Introduction

Subsection ISTD Preservice and Inservice Examination and Testing of Dynamic 

Restraints (Snubber) in Light-Water Nuclear Power Plants is included as part of 

the ASME OM Code. Therefore when users state they are adopting the ISTD 

Code, they are also adopting the general section of the ASME OM Code, titled, 

ISTA, General Requirements. It is within Subsection ISTA of the OM Code that 

the general requirements that apply to snubber examination and testing 

programs as well as other IST programs can be found. For example, paragraph 

ISTA-3200(a) requires IST plans to be filed with the regulatory authority having 

jurisdiction at the plant site. This will now apply to snubber program plans. 

Further guidance on submittal of test plans can be found in Non-Mandatory 

Appendix A. 

ISTA-1100 establishes the scope of snubbers to be included in the snubber 

program. There are some additional general requirements found within ISTD 

that are snubber specific which are not included in ISTA. Therefore, in order to 

implement ISTD, one must satisfy both the specific and general requirements of 
27

ISTD as well as the general requirements of ISTA. Within the general 

requirements sections are included such things as applicability, definitions, owner 

responsibilities, examination boundaries, transient dynamic events, supported 

component or system evaluations, and snubber repair/replacement 

requirements. It is noted that although snubber examination and testing 

requirements are no longer appear in Section XI, IWF-5000, both repair and 

replacement actions are required to be in accordance with Section XI as 

referenced in ISTD-1500 and ISTD-1600.

Within ISTD there are three main elements that together establish the basis of 

the snubber examination and testing program. All three elements must be 

properly implemented in order to conform to the requirements of the ASME OM 

Code, Subsection ISTD. These three elements are:

Examination

Visual Examination of snubbers is the first leg of the ISTD Snubber Program. 

The examination requirements for snubbers are found in Section ISTD-4000.

Within this section are both preservice and inservice examination requirements. 

The preservice examinations confirm proper installation of the snubber and that 

the snubber will restrain load. For operating plants, there may be a new snubber 

design or location where preservice requirements must be addressed. The 

inservice examination requirements commence after power operation and are 

performed on a schedule determined in accordance with ISTD-4252 and the 

application of Table ISTD-4252-1. Visual examinations are required with a 

maximum interval not to exceed 48 months, or every other refueling outage. This 

frequency may vary depending on the results of the previous examination

interval. If the results include several visual examinations that are determined to 

be unacceptable, then the next examination interval could be reduced. On the 

Examination

Service Life 

Monitoring Testing
28

other hand, in the case of only a few unacceptable examinations, the interval 

could be extended up to the maximum as noted in ISTD Table 4252-1. 

ISTD Table ISTD-4252-1 is essentially identical to the table which was included 

in Generic Letter (GL) 90-09 issued by the NRC addressing the extension of 

snubber examination intervals. Most snubber programs are using the approach 

of GL 90-09 and that frequency table for visual examinations so the change to 

move to ISTD in this area is not significant. Further guidance on the use of ISTD 

Table ISTD-4252-1 can be found in Non-Mandatory Appendix G. 

In addition, there is also an approved Code Case, OMN-13, which allows the 

extension of the visual examination interval beyond as specified in Table ISTD4252-1, to a maximum of once every ten years after the prerequisite 

requirements of the OMN-13 Code Case have been satisfied. While using OMN13, at any time during an examination interval the cumulative number of 

unacceptable snubbers exceeds the applicable valves from Column B in Table 

ISTD-4252-1, the current examination interval shall end (more details see OMN13). In order to use this Code Case the existing snubber program must meet all 

the requirements of the ISTA and ISTD Code.

As defined by ISTD-4220, the snubber population may be considered as one 

population or may be divided based on accessibility categories for visual 

examination purposes. This may differ slightly from some owner controlled 

programs which may have allowed separate groupings by area rather than by 

accessibility. When moving a snubber program into ISTD space, this should be 

checked.

The boundary for examination as defined in ISTD-3110 is from pin to pin 

inclusive. ISTD does not cover the attachments to the building structure or the 

piping. This may differ from the previous owner controlled or TS controlled 

program where the structural attachment and piping attachment might also be 

ISTD OMN13

10 Year 

Interval
29

included in the examination program as part of the ISI Program. These structural 

attachments remain in the Section XI component support ISI examination 

program under present code requirements. Coordination with the ISI program 

manager is required to ensure that the structural attachments have the proper 

examinations performed. Some plants keep the inspections under the snubber 

program using VT-3 qualified individuals to complete the work. ISTA-1500(e) 

requires the owner to use qualified individuals which may or may not be VT-3 

qualified.

One provision defined under ISTD-4240 visual examination requirements allows 

the re-categorization of an unacceptable snubber to be considered acceptable 

after the completion of an acceptable functional test. This test must demonstrate 

snubber operational readiness and confirm the unacceptable condition did not 

affect the snubber’s operational readiness.

Testing

Functional testing of snubbers is the second leg of the ISTD snubber program. 

The testing requirements for snubbers are found in Section, ISTD-5000. Within 

this section are both preservice and inservice testing requirements. The 

preservice tests confirm proper operational readiness of the snubber before 

installation in the plant. This may be satisfied using the manufacturer’s test 

performed at the factory, or it could be satisfied with a functional test performed 

by the owner just prior to installation of the snubber. The inservice testing 

requirements begin after plant power operation and are performed once every 

fuel cycle as stated in ISTD-5200, however, testing may begin no earlier than 60 

days before a scheduled refuel outage as stated in ISTD-5240. The sample 

testing required under ISTD is intended to capture a snapshot in time to 

determine the overall condition of the snubber population.

The functional testing must utilize one of the two test sampling plans identified in 

ISTD-5260. The two plans identified are the 10% plan and the 37 plan. 

Generally the 10% plan is used for a population size less than 370 snubbers and 

the 37 plan is used for populations larger than 370 snubbers. The initial sample 

size using the 10% plan is 10% of the snubber population identified for each 

Design Test Plan Group (DTPG). The 37 plan requires an initial sample of 37 of 

the population identified for each DTPG. Further guidance on use and strategy 

for choosing one of the two sample plans can be found in the Non-Mandatory 

Appendices D and E.
30

Design Test Plan Groups 

Snubbers may be grouped in various DTPG’s according to the criteria outlined in 

ISTD-5250. The purpose of this grouping is to combine snubbers of like design, 

application, size, or type. There is some strategy involved in establishing the 

initial DTPG groupings due to additional testing being determined by test failures 

within each DTPG group. The size of the sample is a function of the size of the 

group while using the 10% plan. ISTD-5253 requires a separate DTPG for large 

equipment snubbers attached to steam generators or reactor coolant pumps on 

pressurized water reactors. 

Examples: 

Population size 900 mechanical snubbers of various sizes, however, same 

manufacture.

Depending on which of the approaches above is used, there would be a different 

result in expanded testing scope requirements if test failures were identified. 

Whichever test plan is chosen, once the testing begins it must be continued 

through until the end of testing and must be concluded in accordance with ISTD5330 for the 10% plan or ISTD-5430 for the 37 plan.

Test parameters are identified in ISTD-5210. An activation test is required for all 

snubbers, both hydraulic and mechanical. For hydraulic snubbers, a release rate 

test is also required as applicable to the snubber design. For mechanical 

snubbers, a drag force measurement is required. Tests are to be performed in 

both the tension and compression directions. ISTD does not identify acceptance 

Example 1:

Grouping – one DTPG

Use 37 test plan – initial sample size is 37 snubbers.

Use 10% plan – initial size is 90 snubbers.

Example 2:

Grouping – two DTPG’s, small snubbers = 150, all others = 

750

Use 37 test plan on large sizes – initial sample size is 37 

snubbers.

Use 10% plan on small sizes – initial size is 15 snubbers
31

criteria for these tests as they will be dependent upon the design criteria used for 

each plant. ISTD-3210 requires tests to be performed at sufficient loads to verify 

these test parameters.

Inservice tests must be performed in the “as found” condition to the fullest extent 

possible as stated in ISTD-5221. This prohibits any preconditioning to improve 

the condition of the snubber to bias the test results prior to performing the as 

found test. The purpose of the inservice test is to determine if the snubber is in 

fact ready to operate if it is called upon to do so. ISTD allows options to use 

various test methods to accomplish this test, e.g., bench test, in-place test, 

subcomponent test, indirect measurement, and qualitative tests. These differing 

approaches are described under ISTD-5220 and ISTD-5230. Additional 

information on test parameters and methods can be found in Non-Mandatory 

Appendix H, Test Parameters and Methods. If a hydraulic snubber is tested 

without the application of a load to the snubber piston rod, then per ISTD-6400, 

the snubber fluid must be evaluated and piston seal integrity verified.

All test failures must be evaluated to determine the cause of the failure (ISTD5271) and potential damage to the supported system or component (ISTD-1800). 

Test failures trigger requirements to perform additional testing until the equations 

(ISTD-5331 or ISTD-5431) of the test plan used are satisfied. When failures are 

identified and there is a distinguishable failure mode determined, a failure mode 

group (FMG) may be established. The benefit of establishing an FMG may allow 

limiting the additional testing to the group of snubbers identified to be the same 

FMG. Owner controlled programs may not have the ability to define an FMG for 

continued testing as is available in the ISTD Code. All snubbers placed in the 

same location as a previously failed snubber test, must be subjected to a retest 

during the next fuel cycle as stated in ISTD-5500. There may be some confusion 

over this requirement in some programs. However, it is the location that is 

suspect, not the specific snubber. Therefore, if a snubber is removed from 

service due to an unacceptable inservice test and then refurbished before being 

installed in a new location, that snubber will not require a retest during the next 

fuel cycle.

Service Life Monitoring

Service Life Monitoring (SLM) is the third leg of the ISTD snubber program.

Although all owner controlled snubber programs will have an element of 

examination and some type of testing, they may be lacking in the documentation 

of an effective service life monitoring program as required by ISTD. Most 
32

programs monitor performance of their snubbers from a reactive viewpoint. 

When there is a problem, it is addressed. Or, they establish a seal life for 

hydraulic snubbers and replace seals before they expire calling that “Service Life 

Monitoring”. ISTD-6000 outlines a proactive approach that predicts service life in 

order to take appropriate action in advance of encountering a problem. When 

moving to an ISTD snubber program, there is usually significant work to be done 

in the area of service life monitoring. Programs may consider service life by 

performing some kind of maintenance on snubbers, but they fail to document a 

service life strategy and approach toward maintaining a healthy snubber 

population. In developing an effective service life monitoring program, the owner 

must consider alternatives and develop his own strategy to maintain the health of 

the snubber population.

Whatever the service life monitoring approach taken, it needs to be documented.

ISTD provides certain prerequisites for an SLM program and additional 

information in Non-Mandatory Appendix F. Initially, ISTD-6100 requires the 

prediction of a service life for each snubber based upon manufacturer’s 

recommendation or design review. Sometimes service life is confused with the 

design life of a snubber. ISTD-2000 defines service life as the period of time an 

item is expected to meet the operational readiness requirements without 

maintenance. Even though there is substantial documentation published to the 

contrary, many plants still consider the service life of the basic mechanical 

snubber to be 40 years. This may be true for some environments, but definitely 

not for other environments. A good SLM program will take the environment into 

consideration when establishing the service life of the snubber.

Each fuel cycle the service life for all snubbers is to be evaluated and adjusted if 

necessary based upon technical data gathered from snubbers which have seen 

service in the plant (ISTD-6200). ISTD-6300 requires an evaluation to determine 

the cause of snubber failures with consideration given to reestablishing the 

service life based upon that evaluation.

Due to differing plant conditions, there may be some snubbers that are evaluated 

more often than required by either of the sample plan testing programs. For 

example, areas where a mechanical snubber experiences excessive vibration 

may reduce the expected service life of the snubber from 20 years to 10 years. 

Or, when a hydraulic snubber is located near a high temperature heat source, the 

seals and fluid may reach the end of their service life earlier than expected. If the 

normal cycle to work through a snubber population is 15 years, then these 

snubbers will not come up for testing before the service life is exceeded. 
33

When service life testing is performed early to address this type of issue (ISTD6500), the results of such testing do not require testing of additional snubbers as 

would be required by ISTD-5320 or ISTD-5420. However, appropriate corrective 

action must be taken based on an evaluation of the failure. Performing SLM 

testing may be a prudent practice to gain additional information about the 

performance of the snubber population. However, many snubber program 

owners have difficulty scheduling optional testing that is not required by Code or 

TS due to schedule or budget concerns.

There are numerous approaches and strategies that can be implemented to 

establish an effective SLM program. Non-Mandatory Appendix F provides 

additional insights that might guide the program owner to establish this strategy.

Conclusion

The ASME OM Code, Subsection ISTD, defines the requirements necessary to 

establish a comprehensive snubber examination and testing program. ISTD 

allows the program owner significant latitude to shape the actual snubber 

program; however, the essential elements of ISTD; 1) Examination, 2) Testing, 

and 3) Service Life Monitoring must all be considered to be equally important in 

order to reach the goal of a successful snubber program. The transition from an 

owner controlled snubber program to an ISTD compliant program can usually be 

made without significant pain once there is a solid understanding of the essential 

elements of the ISTD Code. 

References

ASME OM Code, 2009 Edition

ASME Section XI, 2004 edition with 2005 and 2006 addenda

Title 10, Section 50.55a, of the Code of Federal Regulations (10 CFR 50.55a)

10 CFR 50.55a rulemaking (Federal Register, Vol. 76, No. 119, page 36232-

36279, dated June 21, 2011)

35

Session 2(a): Valves I

Session Chair: Kevin G. DeWall, Idaho National Laboratory

37

A Study on an Analytical Approach with Fluid-Structure

Interaction Technology for the Design of HighTemperature Check Valves in Nuclear Power Plants

Sangho Sohna*

Jae Hyung Kima

Chi Sung Songa

Han Soo Kima

Sung Chang Honga

Won Hee Leeb

a

Center for Reliability Assessment of Nuclear Equipments and Machinery,

Korea Institute of Machinery & Materials,

Daejon 305-343

Republic of Korea

b

Samshin Limited Co.

63-6, Dujong-Dong

Chonan Chungchongnam-Do

Republic of Korea

* corresponding author

Sangho Sohn

Center for Reliability Assessment of Nuclear Equipments and Machinery

Korea Institute of Machinery & Materials

104 Sinseoungno, Yuseong-gu

Daejon 305-343

Republic of Korea

Phone: +82-42-868-7389

Fax: +82-42-868-7932

sangho35.sohn@gmail.com
38

Abstract

A check valve is located on the water feed pipe connected to the steam 

generator in nuclear power plants. It is required that the performance test of a 

check valve at a high temperature and pressure should be performed based on 

American Society of Mechanical Engineers (ASME) QME-1, “Qualification of 

Active Mechanical Equipment used in Nuclear Power Plants,” for the practical 

use in nuclear power plants. This paper investigates the design technology 

considering design characteristics and the high temperature/pressure test of the 

check valve which is one of the important components in a nuclear power plant. 

In this research, the functionality and structural integrity is verified by experiment 

and analytical approach, such as the simulation of closing time and the analysis 

of stress and fatigue. The functionality is investigated under a reverse flow 

during an accident event. The test setup consists of the practical prototype of a

check valve with the material of ASME SA217-WC9 and support equipment 

consisting of a Tank, Sensors, Rupture disc, computer, and feed pipe. The 

structural integrity is associated with the stress and fatigue life under the loading 

conditions such as fluid pressure, end-loading, and thermal expansion. The 

structure analysis is performed based on Fluid Structure Interaction (FSI) 

technology providing the integrated solution of the coupled structural-fluid 

physics. The fluid part is first solved based on Computational Fluid Dynamics 

(CFD) modeling to calculate the fluid pressure on the solid casing structure. 

Then, the structure part is resolved based on the Finite Element Method (FEM) to 

compute displacement and stress under the pre-calculated fluid pressure and 

other loads such as end-loading and thermal expansion. Finally, the fatigue 

analysis is applied to compute the fatigue life for the closing duration of a check 

valve by utilizing the stress data derived from the previous structure analysis.

Introduction

A check valve is a mechanical device used in a wide variety of applications that 

normally allows fluid (liquid or gas) to flow through it in a single direction. The 

check valve is also regarded as one of the fundamental components widely used 

in safety systems of nuclear power plants (NPP). Figure 1 depicts an example of 

a check valve in a nuclear power plant. Practically, a check valve mounted on a 

flow line is generally used to protect a centrifugal pump and the related 

equipment, establish a flow direction, and maintain a pressure state during an 

operational mode change in the nuclear power plant. The check valve in a 

nuclear safety system also takes a role to supply sufficient fluid for safety feed 

and auxiliary feed in Design Basis Accident scenarios. Additionally, the check 
39

valve can often be exposed to severe temperatures and pressures due to 

operating conditions in the nuclear power plant. The failure of check valves can 

result in the undesirable effects such as water hammer [Reference 1], overpressurization, and damage to the flow system. Therefore, the check valve in 

NPPs should be designed to operate normally under severe operational 

temperatures and pressures and obtain the required reliability of the standard 

codes such as ASME QME-1. Additionally, the check valve should be well 

designed with sufficient sealing and shall protect against water hammer in normal 

operational mode [References 2, 3]. However, it is not convenient to totally fulfill 

the requirements of the standard codes only by experimental testing. Thus, the 

analytical approach can be a fine alternative method to support check valve 

design. The advanced analysis technology of the Fluid Structure Interaction 

(FSI) method is a promising approach that provides an integrated solution of 

multi-physics problems including thermal fluid dynamics and structural dynamics. 

Unfortunately, this advanced analytical approach is uncommon in NPP and this 

paper will demonstrate the advantages the FSI design method for NPP 

mechanical equipment analysis.

In this research, a study on an analytical approach for simulation of the check 

valve was performed based on the FSI method, which describes the integrated 

phenomena of thermal fluid flow and structural deformation. The numerical 

models of the fluid and structure parts in the check valve were constructed based 

on Computational Fluid Dynamics (CFD) and Finite Element Analysis (FEA). 

These numerical models were also verified with the experiment data and then the 

analyses were performed under loading conditions considering the effects of fluid 

pressurization, end-loading, and thermal expansion, which were required for the 

qualification of the check valve for nuclear power plant use according to ASME 

QME-1. As a result of analysis, the valve stress and life cycles were obtained 

and evaluated.

Check Valve Experimental System

The test check valve system for a reverse flow was prepared as shown in Figure 

2. This apparatus was composed of the surge tank, test check valve, pipe line, 

pool, rupture disk, various measurement systems, personal computer for storage 

of a measured signal data, etc. The test check valve system generates a reverse 

flow in the check valve through a pressure difference between the tank and 

rupture disks. The direction of reverse flow is from the tank to the rupture disks, 
40

which is caused by lowering pressure between two rupture disks. Therefore, the 

check valve is operated from the open to the closed state.

Figure 3 depicts the experimental instruments for measurement of some data 

such as pressure, position, vibration characteristics, and strain. The strain gages 

were attached to the expected weak points on the surface of the piston for 

evaluation of the deformation and stress.

Numerical Analysis and Results

This research investigated the advanced analysis technology of the FSI method 

for a more reliable approach to evaluate the integrated results of pressure, 

temperature, deformation, and stress in the structure of a check valve. FSI 

occurs when fluid flow generates forces on a solid structure, causing it to deform 

and potentially perturb the initial fluid flow. In this study, a one-way coupling 

method for FSI simulation was used by ANSYS software since the fast fluid flow 

almost dominated the structure behavior in the check valve. The numerical 

models of fluid and structure regions were constructed based on CFD and FEA. 

Figure 4 shows mesh generations of two numerical models for CFD and FEM 

analysis and Table 1 summarizes main features of each models such as solution, 

algorithm, property, node & element numbers, and element shape in the table. 

The numerical model was verified with the experiment data.

The fluid region was first resolved by the three dimensional incompressible 

steady flow analysis with the Raynolds-Averaged Navier-Stokes and continuity 

equations in ANSYS. The turbulent model was the k-e model with wall function 

and the tetra element was used for mesh generation. Boundary conditions were 

defined by imposing the design pressure (8.9 megapascals [MPa]) at the right 

side of the check valve in Figure 4 (a) as the inlet boundary and atmosphere 

pressure at the left side as the outlet boundary. The pressure and velocity of the 

fluid region were solved by CFD analysis with boundary conditions at the open 

state of the check valve. The plot results of pressure and velocity are shown in 

Figure 5. The pressure was concentrated on the base region due to the impact 

of high velocity water. This pressure distribution data was used as a loading 

condition on the internal surface of the structure region in the following FEM 

structure analysis.

 

The structure region was also solved by the three dimensional static analysis in 

ANSYS simulation using the pressure data of the CFD analysis results. The high 
41

order hexa-element was dominantly used for the mesh generation in Figure 4 (b). 

This FEM structure model included three types of load conditions. The first load 

condition was defined by imposing fluid pressure distributions in the open and 

closed states on the internal surface of the check valve. The second load 

condition was applied by an end-loading condition which is defined in the 

functional qualification requirements for active valve assemblies for nuclear 

power plants in ASME QME-1. The equivalent moment load was used for the 

end-loading condition. The third load condition was defined by considering the 

thermal expansion from temperature gradients. Thermal expansion can be an 

important design factor since a check valve is operated at a high temperature 

during plant operation. Before the static structure analysis with thermal 

expansion was completed, thermal conduction analysis was performed to obtain 

the temperature distribution in the structure region. A geometric boundary 

condition was defined by imposing the fixed support at both end sides of the 

check valve.

Figure 6 shows the deformation and stress contour results obtained under the 

first loading condition. The maximum deformation and stress coincided closely in 

the border area between the piston part and pipeline. Figure 7 depicts contour 

results obtained under end-loading and thermal expansion with fluid 

pressurization. The maximum stress occurred at the similar position in all load 

conditions of fluid pressurization, end-loading, and thermal expansion. The result 

shows the maximum stress is approximately 155 MPa in the end-loading 

condition. This stress level did not exceed the allowable stress of the steel 

material. To support this analysis, thermal conduct analysis was carried out in 

advance to obtain the temperature distribution shown in Figure 8.

A check valve often changes from an open to a closed state during plant 

operation. This repeated loading causes premature failure in the material by 

fatigue. The fatigue can be evaluated by the stress-life (S-N) method that is 

widely used in design applications. This S-N approach is based on fatigue 

curves of stress versus number of cycles such as S-N curve shown in Figure 9. 

For fatigue evaluation, the mean and amplitude stresses were calculated by 

using the stress result from FEM structural analysis. The alternating stress level 

was obtained based on Goodman diagram [Reference 5], and its life cycle was 

determined by interpolation in S-N curve of Figure 9. Finally, the result of the life 

cycle according to loading conditions is shown in Table 2. This life cycle level 

was qualified to satisfy a conservative cycle (2,000) of the standard code and 

specification.
42

Conclusion

This research investigated the FSI analytical method for the simulation of a check 

valve. The numerical models of the fluid and structure regions in the check valve 

were solved based on CFD and FEA. The results of the FSI analysis showed the 

fluid pressure from CFD and the stress distribution from the FEM. The analysis 

results, with certain loading conditions, provide contour stresses comparing the 

effects of fluid pressurization, end-loading, and thermal expansion. Finally, the 

material fatigue was computed from the stress data of the previous static 

analysis. Therefore, it is hopeful that this design approach by using FSI method 

is a beneficial guide to solve multi-physics engineering problems of nuclear 

equipments.

Acknowledgement 

This work was supported by Samshin Limited, valve manufacturer for nuclear 

power plant, in Korea.

References

1. U.S. Nuclear Regulatory Commission, "Loss of Power and Water Hammer 

Event at San Onofre, Unit, 1, on Nov. 21", NUREG-1190, 1985 

2. S. K. Park, S. R. Hong, D. H. Lee, Y. S. Kim, D. W. Kim, S. C. Kang, 

Development of Diagnostic Method for Check Valve Performance and Failure 

Cause Analysis annual report, 2005

3. EPRI, Application Guidelines for Check Valves in Nuclear Power Plants, EPRI 

NP-5479, Rev.1, EPRI

4. J. H. Kim a, C. S. Song a, H. S. Kim a, S. C. Hong a, W. H. Lee b, 

Experimental and Analytical Study on the Lift Check Valve, Transactions of the 

Korean Nuclear Society Autumn Meeting, 2009

5. J.A. Bannantine, J.J. Comer, J.L. Handrock, “Fundamentals of metal fatigue 

analysis”, Prentical Hall, 1990

6. ASME B&PV Code, Section III, Division 1
43

Figure 1. Check valve mounted on the line in a nuclear power plant

Figure 2. Schematic of a test check valve system for a reverse flow simulation
44

Figure 3. Experimental instruments for data measurement

Figure 4. Mesh generation used for CFD and FEM analysis

Figure 5. Plot results of CFD analysis at the 100% open state
45

Figure 6. Contour results with fluid pressure load

Figure 7. Stress contour in end-loading and thermal expansion with fluid pressure 

load
46

Figure 8. Temperature distributions in thermal expansion

Figure 9. Typical stress life (S-N) curve [6]
47

Table 1. Features of CFD and FEM numerical models

Table 2. Life cycles according to loading conditions
48

Systematic Evaluation of Significant Check Valve 

Application to Improve Reliability and Enhance InService Test Performance and Plant Availability

Vinod Sharma & Roland Huet 

of Exponent, Inc. Failure Analysis Associates 

Domingo A. Cruz, Richard Burge & Steven Quan 

of the Palo Verde Nuclear Generating Station

Abstract

This paper presents an assessment of the performance of Borg/Warner (B/W) 

check valves installed at the Palo Verde Nuclear Generating Station (PVNGS). 

The objective was to systematically review the recent performance of the 

PVNGS Borg/Warner swing check valve population to develop a basis for 

improving its reliability. The range of valve sizes and different potential 

contributory failure causes identified necessitated the application of a proactive 

programmatic approach versus a piecemeal reactive approach.

This evaluation highlighted not only the uniqueness and importance of the large 

Borg/Warner check valve population to the three PVNGS operating units, but 

also underscored the importance of carefully considering remedial actions due to 

the immediate and expensive impact of unsustainable solutions. The 

Borg/Warner valve population had performed reliably for the first 10 operating 

cycles, suggesting that the design was not inherently defective. However,

“running the valve to surveillance test failure” was not an option, given the valves’ 

location inside containment and its low usage, and the associated rash of 

unreliability that challenged plant Operations, as it manifested predominantly as 

a failure to pass local leak rate tests in Mode 3 during startup. These failures 

were attributed mainly to two reasons: accumulation of deposits in narrow 

clearances, which limited articulation at sliding surfaces, and improper 

reassembly related to valve internal dimensional relationships and design 

features. 

Maintenance personnel responded vigorously to the challenge of managing this 

“field fit up valve” population of valves by developing an elaborate (90-page) 

valve assembly procedure and a test and measurement apparatus to 

compensate for the complexity of reassembly. Before this program was 

completed, a second initiative was launched to introduce sweeping changes that 

would reduce the internal clearances of the valve based on “optimized” 

dimensional data purchased from the valve vendor. The rigorous maintenance

procedures include mechanisms to detect vendor quality issues and eliminate 

maintenance errors. However, such intricate processes are inherently expensive 
49

and not sustainable in the long term, given the reality of subject-matter experts’

turnover and variance in outage crews, creating a potentially unresolved 

production risk.

This paper discusses various options for improving the reliability of the PVNGS 

Borg/Warner valve population that will enhance plant safety and availability, and 

minimize avoidable challenges to Operations and burdens to control-room 

operators, as well as unexpected impacts on operation and maintenance (O&M) 

budgets and outage schedules.

Introduction

The Palo Verde nuclear generating station has 68 Borg Warner (BW) swing 

check valves installed in the emergency core cooling systems (ECCSs) of each 

of its three identical operating pressurized boiling-water reactor units. Over time,

these 204 originally installed and now obsolete valves are proving to be 

increasing unreliable for sustaining plant operations, and with age, they have 

become burdensome to maintain. Palo Verde initiated a project to develop a 

sustainable and cost-effective approach to improve the reliability of this large 

population of check valves, to reduce burdens on the control-room operators, 

and minimize unexpected impacts on O&M budgets and outage schedules. The 

goal was to develop a strategy to alleviate undefined production risks and O&M 

costs stemming from intermittent local leak rate test (LLRT) failures during 

startup, and possible future loss of specialized valve expertise. 

Figure 1: Each unit at Palo Verde has 38 BW safety-related swing valves in the safety 

injection (SI) system and 30 valves in the chemical volume and control system (CVCS).
50

The Design Problem

The 204 swing check valves installed at the Palo Verde are all of the bonnethung design and range in size from 3 to 24 inches (Figure 1). Some of these 

valves are of the bolted bonnet design (Figure 2), while the rest are of the 

pressure-seal bonnet design (Figure 3). Palo Verde nuclear station is unique in 

having such a large population of these valves in its ECCS systems, although 

some valves of this style are installed at other U.S. power stations. 

Figure 2: Typical bolted-bonnet BW swing check valve
51

Figure 3: Typical pressure-seal bonnet BW swing check valve

The central problem stems from the inability to visually observe and adjust the 

position of the disk assembly relative to the body seat once the valve is 

assembled. The disc hangs from the bonnet, and the valve seat is welded to the 

body, so there are numerous factors that affect the final position of the disc with 

respect to the valve seat, including the fact that the position of the bonnet itself 

with respect to the body is not well defined. This last problem is further 

exacerbated in valves with a pressure-seal bonnet where the disk assembly is 

apt to move as the bonnet is hot torqued and secured in its final position. This 

requires carefully controlling a large number of internal dimensions to achieve the 

right geometric relationships that will ensure a proper disk-to-valve-body seat 

contact (Table 1). The inherent variability in these dimensions and their influence 

on assembly requires specialized valve expertise and disproportionately 

resource-intensive procedures and tooling to work the valve. 
52

Table 1: Examples of dimensions that vary 

(* indicates dimensions that significantly influence assembly)

Bonnet Assembly Body

Bonnet thickness* Height of seat centerline* from top of 

body

Clevis height* Seat angle* with respect to vertical 

Hinge-pin diameter Seat angle with respect to horizontal 

Hinge-pin hole diameter, location in 

clevis*

Seat offset* with respect to seating 

surface

Bushing ODs, IDs Seat width* 

Swing-arm length*, hole diameter / 

thickness at disc stud*, material

Diameter of seating surface* (both 

horizontally and vertically)

Spherical bearing height*, diameter, 

chamfer (some have one side)

Height of seating surface*

Disc diameter*, thickness Height of ledge where bonnet initially 

seats (pre-assembly) 

Location* / diameter of stud hole in 

disc*

Seat hard face thickness

Disc stud to disc weld size, quality Location and size of diametral chamfer 

between retainer threads and sealing 

area

Disc gap size*

When originally installed, these bonnet assemblies were custom fit to their bodies 

by the vendor. As seen in Table 2, the majority of these originally installed 

valves performed reliably for the first ten operating cycles. But the valves’ 

reliability hinged on the implicit assumption that each bonnet assembly would 

never leave its original body. This, however, was an unsustainable condition 

because of the valves’ location in containment and the need to minimize time at 

the valve to minimize as low as reasonably achievable (ALARA) exposure

required that the disk assemblies be switched. Once the link between a bonnet 

assembly and its mating valve body was lost, problems in these field-fit up valves 

multiplied rapidly. 
53

Table 1: Operating history of a sampling of valves over 12 inches in the 

population of BW swing check valves, indicating the refueling outage (Rx) 

when a valve required rework

Syste

m

RC Loop Check 

Valves

Safety Injection Tank 

Discharge SI Injection Header 

Valve 

ID

217 227 237 247 215 225 235 245 540 541 54

2 

543 

Unit 1 R6 R1

0

R1

1

R1

1

R1

0

R1

0

R4 R1

0

R1

1

Unit 2 R1

0

R1

1

R1

0

R1

1

R1

0

R1

1

R1

1

R1

1

Unit 3 R9 R8 R1

0

This problem became a wider concern when highlighted by NRC Information 

notice No. 89-02, Malfunction of Borg Warner pressure seal bonnet check valves 

caused by vertical misalignment of disk (Reference 1) which described the risk of 

the top of the disk getting caught under the top of the seat (Figure 4). BW/IP 

CFRN-9301 10 CFR Part 21 report concerning 3-in. and 4-in described the 

potential for the disc of specific model valves (which Palo Verde did not have) to 

over-articulate and become wedged against the seat, preventing a closure

(Reference 2). Such disc cocking and wedging under the seat could result from 

an excessive gap between the swing arm and the disc stud washer caused by 

excessive weld buildup at the disc to stud weld.
54

Figure 4: Depiction of the top of the disk getting caught under the top of the seat 

and a photograph of the bonnet hung disk assembly

During normal operation, these valves remain closed throughout the entire fuel 

cycle. This increases the likelihood for magnetite released by the system to 

deposit in the nooks and crannies and over time make the sliding and rotating 

joints stiff and arthritic. The added requirement for these valves to meet LLRT 

requirements in Operating Mode 3 during startup means that each failure 

automatically delays startup and often results in the plant returning to a cold shut 

down to allow for a valve inspection and repair.
55

Cost of Unreliability

The ongoing valve unreliability is reflected in high O&M costs driven by a number 

of contributing reasons including:

• High cost of some replacement spare parts which rival the cost of a new 

valve. 

• Extended outages and lost generation resulting from delaying startup to 

inspect valves that fail in Mode 3 and require returning to Cold shutdown 

(Mode 6).

• The resource intensive nature of routine maintenance (90 page valve 

inspection and assembly procedure)

• Given that the RCS/SI valves are in high dose areas, ALARA-intensive insitu valve body seat repairs.

• Burden to control room operators to continually depressurize systems 

affected by a leaking valve.

In addition to the above tangible costs, there exist intangible costs of future 

unreliability to this large population of obsolete valves in the ECCS systems of all 

three units. A common cause problem found in any one of the larger obsolete 

safety valves that requires a valve replacement poses the risk of extended 

unavailability at one or more units. This extended unavailability allows time for 

the engineering required to identify suitable replacement alternatives and the 

long lead time for delivery of replacement valves. At the high cost of lost 

generation, such a delay of even a few weeks would grow to a substantial sum. 

Other lesser but perhaps more likely intangible costs would be driven by:

• Loss of specialized valve fit up expertise through retirements and 

competition for suitable outage crews to rework valves,

• Maintenance induced errors generated by complex procedures and 

shorter outages, and

• Added management and regulatory oversight generated by the perception 

of unresolved reliability issues.

Table 3 attempts to capture the direct and indirect operation and maintenance 

costs related to hypothetical repairs.
56

Table 3: Pro forma operation and maintenance cost of hypothetical repairs 

estimated by plant staff

Maintenance type Shifts Hours No. of

men

Man 

Hrs

Direct Cost 

$35/hr.(est.)

ROUTINE PREVENTIVE (PM)/CORRECTIVE MAINTENANCE (CM)

1 Valve disassembly and inspect – including 

recording of critical dimensions

Larger valves require rigging (12–14 inch)

- Small valves under 10-inch

1 12 2 24 $840

45,000

25,000

2 Valve Replacement (plug and play), assuming 

availability of replacement assembly

- Larger valves require rigging (10–14 inch) 

1-2 12-24 2 48 $1,680

3 Seat Work to repair seal areas

Larger valves require scaffolding/rigging

(≥12 in.)

- Small valves ≤ 12 inch

2

1

24

12

3

2

72

24

$2,520

$840

4 Decontamination 2 24 2 48 $1,680

5 Reworking bonnet assembly 1 12 2 24 $840

6 Reworking spherical bearing

Cut nut at welded stud, code weld, inspect,

Re-lap seat and reassemble

3-4 36 - 48 2 96 $3,360

7 Other – regardless of size – Radiation 

Physics Coverage (2hrs), Engineering (2 hrs), 

Welders (4hrs), Planning(4hrs) @ $40/hr

12 1 12 $480

8 Spares and cost of carrying inventory

ESTIMATED COST OF PM (1)

Larger valves require rigging (12 – 14 inch) $45,000 

- Small valves under 10-inch $25,000 

ESTIMATED COST OF CM (1+2+3+4+5+6+7) 

Larger valves require rigging (12 – 14 inch) $55,000+ spares

- Small valves under 10 in. $30,000+ spares

COST OF APPARENT-CAUSE ANALYSIS/ROOT-CAUSE ANALYSIS

9 ERCA/CRDR @ $40/hr 40 10 400 16,000

COST OF ALARA 

10 AALARA

High dose (inside shield wall)

e.g., loop checks 160–180 mRem/person/

8-hr shift

Medium dose (inside containment outside 

shield wall) – 20–30 mRem/person/

8-hr shift
57

Low Dose (outside containment) 

e.g., CVCS checks – 10 mRem/person/

8-hr shift

COST OF LOST PRODUCTION

11 Lost generation during seat work /occurrence 

spare $1,000,000

12 Time to power down after an UNSAT

IST leakage test in Mode 3 or 4 and 

subsequent power up

$1,000,000

Plant Response

In the recent past, Palo Verde has conducted a number of corrective-action 

reviews to study this sporadic unreliability and identify common causal effects. 

As part of its component programs (References 3-8) Palo Verde investigated 

included:

1. Bonnet-hung disc hinge assembly prevents a visual verification of proper 

disc alignment on the body seat once the bonnet is installed in the valve 

body. 

2. Spherical bearing introduced to provide extra play of the disc/hinge 

connection (to ensure self-alignment).

3. Weld at the disc stud to disc—that can interfere with the spherical 

bearing.

4. Weld on disc stud threads.

5. A 5° seat angle and axial location of the valve seat relative to the opening 

at the top of the valve.

6. Metal-to-metal seats—more difficult to seal at low pressures.

7. Pressure seal requires a hot torque that can result in stresses on hinge 

arm stretched between a pressurized disc and a rising bonnet (i.e., 

uneven lifting of bonnet under line pressure can result in a loading of the 

hinge arm).

8. Materials of construction:

a. Washer 315 CRES

b. Nut ASTM A194, grade 8M

c. Ball (spherical bearing) Stellite #6B

d. Swing arm 17-4 PH material (AMS 5398)

e. Stud ASTM A276, Type 316A

f. Disc ASTM SA182, Type 316

These studies pointed toward two key common factors: (i) improper reassembly 

related to internal dimensional relationships and design features, and (ii) 

accumulation of magnetite deposits in narrow clearances and loss of articulation. 

These studies, when narrowed to individual valves or subsets of valves, also 

attributed the failures to various other potential contributory causes, some of 

which were validated by physical evidence and robust technical basis, while 
58

others were not. Table 2 lists the range of potential contributory factors identified 

by plant staff over the years.

Palo Verde maintenance engineers launched an effort to understand the 

correlation between variances in various internal dimensions and proper valve fit 

up. This effort has culminated in a 90-page valve inspection and assembly 

procedure [3] and a number of specialized assembly tools to improve the 

reliability of this population of valves. Palo Verde also launched a dimensional 

optimization program to “tighten up clearances.” For this, the plant procured 

optimal dimensions and geometric relationship data for key components (Figure 

5). These dimensional changes were applied programmatically to the entire 

population to reduce internal clearances based on “optimized” data. 

Figure 5: Examples of variable dimensions that significantly influence assembly

New disassembly practices require qualified check-valve inspectors to verify 

freedom of movement of the disc hinge-arm assembly (Figure 6), by checking for 

(i) rotation at the spherical bearing (disc yaw), (ii) gimbal or articulation at the 

spherical bearing (disc pitch and roll), and (iii) rotation at the hinge pin (ability of 

hinge arm to swing open or close). Excessive disc gimbal can cause the disc to 

cock to an extent that it catches under the seat during closure. Disc rotational or 

articulation stiffness, caused by the accumulation of deposits or mechanical 

binding, can prevent the disc from being properly positioned on the valve seat 

when the disc closes from an open position. For proper reassembly, personnel 

must therefore carefully maintain and verify a number of dimensions, such as the 

radial gap between the hinge arm and the disc stud, the axial gap between the 

hinge arm and the disc, and the hinge arm and the washer for any given axial 
59

position of the hinge arm, height of the disc stud to disc weld, height of the 

shoulder in the disc stud relative to the height of the spherical bearing, OD of the 

disc washer relative to the hinge-arm bore, and perpendicularity and eccentricity 

of concentric dimensions. It is this level of attention to detail that makes valve 

reassembly cumbersome and specialized. The time required to perform such 

intricate steps and checks does affect ALARA, given that the RCS/SI valves are 

in high dose areas.

Figure 6: A reduced clearance between the disc and the hinge arm impairs the 

disc’s ability to articulate freely to seal against the body seat.

The newly developed geometric relationships, elaborate procedures, specialized 

tooling, and the new vendor-developed acceptance criteria were expected to 

solve the problem. But the tight clearances actually may have resulted in valves 

becoming arthritic faster in the presence of the magnetite deposits. Despite the 

noteworthy efforts and expense, this population of valves continues to exhibit 

sporadic unreliability.

Disc rotation & gimbal relative to arm constrained 

spherical by clearance between spherical bearing & arm

bearing
60

Table 2: Sampling of potential contributory factors suggested in CRDRs

Test Procedures Application

Insufficient DP during IST testing High dose area (1 or 2 man-rem; 10 

days to get parts out of shop)

Manufacturing Defects Infrequent usage (except for valves in 

charging system)

Spherical bearings installed upside 

down

Loose parts concerns

Large disc-to-stud weld Maintenance Induced

Bonnet bore out of round—Grafoil 

seals

Uneven lifting of bonnet under line 

pressure—loading the hanger

Valve seat angle out of plane 5° vs. 12° Excessive seat lapping—seat cocked 

sideways

Axial projection of seat Limited interchangeability of disk 

assembly

Seat cocked sideways Vendor Guidance Induced

Hanger arm-disc post holes bored off 

center 

Lack of consistency on tolerance and 

dimensions

Hanger arm casting voids Generalized vendor inspection 

guidance insufficient

Tack weld 

Technical Approach

Given the plethora of contributory factors suggested, the range of valve sizes and 

styles, the wide variance in internal geometry, the standby safety function of 

these valves, and the ongoing high O&M costs involved, the present evaluation 

focused on a broad strategic approach instead of a narrow, piecemeal approach 

of modeling individual valves. Furthermore, it was recognized that, more than 

just being a challenging technical problem, the ongoing operational uncertainty 

made this equally a production risk management and economic problem. The 

substantial direct and indirect costs of replacing the 204 valves en masse also 

underscored the need for a rigorous holistic review. 

The first phase of this study consolidated the best available information and plant 

experience on the population that had been gleaned over the years. This effort 

consisted of compiling valve operating history, maintenance records, root-cause 

analyses, and reliability improvement initiatives, as well as a discussion with 

plant domain experts involved with maintaining this valve population. The next 

phase of the study critically reviewed previous root-cause evaluations and 

categorized the findings based on the supporting physical evidence and rigor of 

evaluation. This involved a review of selected plant Component Repair and 

Disposition Reports (CRDRs) and an examination of which corrective actions and 

programs had worked and which had not.
61

This study was able to compartmentalize the role of various contributory factors 

stemming from system, valve design, and maintenance constraints, as well as 

from the unintended consequences of improvement initiatives.

Solution Strategy

The above findings helped reframe the problem into three groups. 

• Group A — Valve problems that were well understood and for which the 

underlying sources of unreliability were demonstrably eliminated based on 

a well-defined technical solution

• Group B — Valve problems that were well understood but could be not be 

eliminated and had to be managed

• Group C — Problems that are not completely understood based on 

available information and studies.

Recommendations, Solutions, Path Forward 

To implement the above solution strategy, one must first determine whether a 

specific problem is well understood or not; therefore, it is essential to determine 

the root cause and assess the reliability of this determination. Once this is done, 

the solution that best fits each target group can be implemented. 

• Group A — For issues that are being eliminated: 

o Stay the course while continuing to validate solutions 

o Where possible, streamline valve procedures to simplify 

maintenance and optimize inspection frequencies. 

• Group B — For issues that cannot be eliminated, the options that should 

be evaluated include:

o Where possible, streamline valve procedures to simplify 

maintenance and optimize inspection frequencies. 

o Selectively maintain spare sets of internals for each problem valve 

body (e.g., where replacement valves will be equally susceptible to 

system-induced unreliability).

o Prepare design engineering packages to order replacement valves 

for targeted applications, judiciously selected using a probabilistic 

analysis. 

o Procure and maintain a supply of ready-to-install replacement 

“parachute” valves to prevent an extended outage at one or more 

units. This would include valve applications that have required 

repeated seat rework, or identified by in-service inspections as 

requiring a body replacement, or valves with long procurement lead 

times. 

• Group C — Rigorously evaluate valves whose failure modes are not 

completely understood, to place them in Group A or B and to guide 

expensive replacement decisions.
62

Conclusions

While the case study presented in this paper focused entirely on a population of 

Borg Warner swing checks, the underlying concepts for ensuring continued 

future reliability with aging, obsolete equipment has broader applicability. With 

the vast majority of units securing operating-life extensions, it will become 

increasingly important to examine sustainable strategies to manage aging,

obsolete equipment to ensure plant safety and economic viability. The significant 

financial impact of equipment replacement decisions underscores the need for a 

rigorous technical evaluation and proactive procurement of strategically selected 

“parachute” components. This will provide an approach that balances the call to 

maintain aging equipment using technically defensible and proven solutions 

against the need to replace known bad actors with improved technology without 

introducing any new problems.

References

1. NRC Information Notice IN 89-62, "Malfunction of Borg-Warner Pressure 

Seal Bonnet Check Valves Caused by Vertical Misalignment of Disk," dated 

August 31, 1989 (NUDOCS Accession Number 8908240375)

2. 10CFR, Part 21 Notification (Ref. No. CFRN-9301) Nonconforming condition 

with Borg-Warner 4” 150# bolted bonnet swing check valves.

3. Study No. 13-MS-A24, Check Valve Evaluation Program for Palo Verde 

Nuclear Generating Station, October 1989.

4. Nuclear Administrative and Technical Manual 73DP-9XI01 Pump and Valve 

Inservice Testing Program – Component Tables.

5. Nuclear Administrative and Technical Manual 73DP-0XI03 Check valve 

predictive maintenance and monitoring program.

6. Nuclear Administrative and Technical Manual 73DP-9XI05 Check Valve 

Condition Monitoring Program.

7. Nuclear Administrative and Technical Manual 73ST-9ZZ25 Check valve 

disassembly, inspection and manual exercise.

8. Nuclear Administrative and Technical Manual 31MT-9ZZ17 Borg-Warner 

Check Valve Disassembly and Assembly.
63

Practical Approaches to Gain Operability Margin of 

Safety Related Gate and Globe Valves 

L. Ike Ezekoye

Westinghouse Electric Company LLC

Pittsburgh, Pennsylvania, USA

ezekoyli@westinghouse.com

Jeffrey J. Taylor

Westinghouse Electric Company LLC

Pittsburgh, Pennsylvania, USA

taylorjj@westinghouse.com

Terrence J. Matty

Westinghouse Electric Company LLC

Pittsburgh, Pennsylvania, USA

mattytj@westinghouse.com

Colin P. Arnold

Westinghouse Electric Company LLC

Pittsburgh, Pennsylvania, USA

arnoldcp@westinghouse.com

Abstract

Generic Letter (GL) 96-05 required licensees to develop a program to 

demonstrate that safety related motor operated valves (MOVs) are capable of 

performing their design basis functions [3]. The Joint Owners Group (JOG) 

consisting of Boiling Water Reactor (BWR) and Pressurized Water Reactor 

(PWR) Owners Groups undertook a comprehensive testing program lasting 

approximately 6 years to characterize age-related degradation in safety related 

MOVs. To address GL 96-05, the JOG had plants perform differential pressure 

testing on various motor operated valve designs as part of the periodic 

verification program to determine any evidence of age-related degradations on 

safety related MOVs. At the end of the testing, the JOG produced a topical 

report, MPR-2524-A, documenting the results of the tests that covers the 

following: classification basis of industry safety related valves depending on the 

potential for age-related degradation, the threshold coefficient of friction of valve 

materials, and margin determination [4]. The JOG topical report proposed an 

implementation schedule of 6 year for plants to comply with the JOG program. 

The Nuclear Regulatory Commission (NRC) issued a Safety Evaluation that 

states that the topical report is an acceptable industry response to GL 96-05 for 

valve age-related degradation [6]. Since the issuance of the NRC safety 

evaluation, plants that committed to the JOG program have established 

programs to implement the JOG document. Among the elements of the program 

implementation are valve categorization, design basis calculations to confirm 

operability, and design changes and modifications, if required. In implementing 

the JOG program document, the primary goal is ensuring that the valves are 

operable and will perform their safety related functions. A secondary and 

equally important goal of plant evaluations is striving to get sufficient operability 

margin to reduce the periodic test frequency of the valves. Westinghouse, as a 

valve manufacturer and a Nuclear Steam System Supplier (NSSS), has provided 

support to a number of plants in their JOG implementation process. While the 
64

majority of the work we do has been on Westinghouse designed valves, we have 

supported other non-Westinghouse valve evaluations. In doing so, several 

technical approaches have been used to gain margin for our customers ranging 

from purely analytical approaches to valve modifications or a mixture of the two. 

In this paper these approaches will be discussed. Practical, cost effective, 

approaches based on experience gained from plant support on gate and globe 

valve evaluations are presented.

Introduction

For years the valve industry was not challenged by design standards to meet 

performance requirements. Vendor experience with the specification and 

application often guided design acceptance. In the author’s opinion, the Three 

Mile Island Unit 2 (TMI-2) accident in 1979 initiated industry-wide interest in valve 

operability assessment to address the operability of safety related valves in the 

nuclear industry after the TMI-2 accident. Following that event, the nuclear 

industry, with regulatory oversight, embarked on understanding what it takes to 

have good, reliable, valves for safety related applications. In nuclear power 

plants, the majority of power operated safety related valves provide either open 

or flow isolation functions during plant operation including postulated accident 

scenarios. Figures 1, 2, and 3 illustrate the three main valve groups typically 

used. As shown in Figure 1, gate valves use gates to affect flow isolation, the 

globe valves use a plug to provide flow isolation, and butterfly valves use 

symmetric discs to do the same. Over the years the NRC has used regulatory 

mechanisms to ensure that safety related valves perform their safety related 

functions. In Bulletin 85-03 the NRC required licensees to ensure that MOV 

switch settings are properly set and maintained so that valves can operate under 

all design basis conditions [1]. In GL 89-10 the NRC required licensees establish 

a program to demonstrate that motor operated valves are capable of performing 

their safety related functions during accident conditions. At the closure of GL 89-

10, GL 96-05 was issued which required licensees to develop a program to 

demonstrate that safety related MOVs are not susceptible to age-related 

degradation and are capable of performing their design basis functions. The JOG 

consisting of BWR and PWR Owners Groups undertook a comprehensive testing 

program lasting approximately 6 years to characterize age-related degradation in 

safety related MOVs. To address GL 96-05, the JOG had 98 participating plants 

perform differential pressure testing on 176 motor operated valve designs from 

many vendors as part of the periodic verification program to determine if there is

any evidence of age-related degradations on safety related MOVs. The focus 

was on the determining the thrust and torque values required by the valves and 

not on the actuators. The tested valves covered many suppliers and 

Westinghouse gate valves were one of the designs dynamically tested in the 

JOG program. At the end of the testing, the JOG produced a topical report, MPR2524-A, documenting the results of the tests. Two of the principal parameters 

identified in the report that govern valve thrust and torque are the coefficient of 
65

friction of the sliding or rotating surfaces in the case of gate valves and butterfly 

valves, and area factor in the case of globe valves. In this paper, we concentrate 

primarily on gate and globe valves because margin determination and how 

margin can be recovered is most commonly affected by the JOG report. While 

this paper focuses on gate and globe valves, some of the issues discussed can 

be extended to butterfly valves.

Valve Operability

A valve is operable when the actuator thrust or torque exceeds the opening and 

closing thrust or torque at the design basis conditions taking into account the 

structural integrity of the valve and the actuator and any associated uncertainties. 

For gate valves, the JOG established the threshold disk-to-seat coefficients of 

friction (COFs) for plants to use for different material pairs and operating 

conditions. The JOG prescribed threshold coefficients for gate valves are 

significantly higher than the traditional values recommended by the valve 

suppliers and which were used to size the valve actuators in operating plants. 

The higher threshold coefficient of friction has been a source of consternation to 

the valve suppliers because they do not believe that their actuators were 

improperly sized and to the end users (i.e., the utilities) because that requires 

resizing the plant actuators and reconfirming whether or not the valves are still 

operable.

In addition to the increase in valve COF, there are other factors noted in the JOG 

report that affect valve operability which include uncertainties associated with 

both actuators and valve design covering such areas as; switch repeatability, 

actuator spring pack relaxation, rate of loading, etc. The increase in valve COF 

combined with the increase in uncertainties considered by the JOG report results 

in reduced margin on MOVs, which is functionally defined as:

Divide the right hand numerator term by the Adjusted Required Thrust in the 

denominator.

 
66

Equation 2 can be simplified to:

The adjusted actuator output includes uncertainties which cover:

• Test equipment accuracy

• Torque switch repeatability

• Rate-of-loading

• Spring pack relaxation

• Stem lubrication degradation

The uncertainty inputs come from various sources. Test equipment accuracy 

comes from the test equipment supplier. Torque switch repeatability data comes 

from the actuator manufacturer (e.g., Limitorque). The rate of loading comes 

from the plant or another industry source based on performing multiple static and 

dynamic tests on the same valve to isolate the rate of loading. The spring pack 

relaxation comes from the actuator manufacturer. The stem lubrication 

degradation is based on plant experience.

Rewriting the Adjusted Required Thrust in its component parts:

 

Because All Uncertainties are taken into account in the Required Thrust:

 

Substituting Equation 6 and 7 into Equation 5:

 

Equation 1 and Equation 6, though written differently, are equivalent. The JOG 

document MPR-2524-A, recognizes that individual plants could apply the 

uncertainties either to the required thrust or to the actuator output or the 

combination of the two, as long as there is no double counting. 
67

For a gate valve the required thrust is 

 (7)

Where: 

VF = Valve Factor 

ΔP = Pressure Drop Across the Valve

A = Effective Disc Area

FPacking = Packing Force

FSE = Stem Ejection Load (can be neglected in the opening direction for 

conservatism)

The valve Factor (VF) is defined as

VFClosing = (COF)/[cos(T)-(COF)*sin(T)] (8)

VFOpening = (COF)/[cos(T)+(COF)*sin(T)] (9)

Therefore, it is clear from the JOG document that the word “Adjusted” denotes 

the inclusion of uncertainties such as; rate-of-loading, test equipment inaccuracy, 

torque switch repeatability and, spring pack relaxation to both Actuator Output 

Thrust and Required Thrust. In order to make the calculation clearer this paper 

applies all of the Uncertainties to the Required Thrust Value; this way the 

Actuator Output Torque is unmodified. Either approach, Equation 1 or 2 yields 

the same results.

Why Margin?

Margin confirms not only operability and no concern for age-related degradation 

but also provides a matrix for static testing of the valves in accordance with MPR2524-A. Table 1 illustrates the risk-margin matrix showing the distribution of 

static test frequency based on risk margin values [4]. For example, a high risk 

valve with high margin can be statically tested every 6 years and one with low 

margin must be tested every 2 years. Similarly, a low risk valve with high margin 

can be tested every 10 years and one with low margin must be tested every 6 

years. Table 1 shows that the higher the margin for any valve the more years the 

static test frequency can be extended, which translates to more savings for the 

plant by reducing maintenance costs and personnel dose.
68

Table 1: MOV Static Test Frequency Criteria

Risk 

Ranking1

PV Test Interval (years) for...

Low Margin

(≤ 5%)

Medium 

Margin

(5% < 10%)

High Margin

(≥ 10%)

High Risk 2 4 6

Medium Risk 4 8 10

Low Risk 6 10 10

1 – Based on Plant Risk Ranking

Margin Improvements

As shown in the above equations (Equations 1, 2, 3 and 6), margin is not only 

governed by the required thrust or torque but also by the uncertainties. Both 

margin and uncertainties are additive and therefore minimizing their respective 

contributions increases margin. As a valve designer, Westinghouse was faced 

with providing supporting evaluations to plants that have Westinghouse designed 

MOVs in their safety systems. Customers have made many different types of 

requests covering structural integrity, weak link analysis and margin 

improvements. Over the years of supporting plants in design basis calculations 

and margin assessment improvements, a number of practical options to gain 

margin have emerged. Table 2 summarizes practical approaches that have 

evolved over the years of our support including MOV evaluations. The goal of 

margin improvement is to make necessary analytical and design improvements 

to arrive at an acceptable overall margin to serve the needs of the plant. This 

may require hardware changes in some cases.
69

Table 2: Approaches to Gain Margin

Area of 

Improvement

How it affects 

margin Basis/Justification Expected Margin

Sliding Surface 

Coefficient of 

Friction

The COF is the 

main factor that 

affects the required 

thrust or torque. 

See equations.

Reduction of COF is 

permitted when there 

is a qualifying basis 

for the reduction in 

accordance with 

MPR 2524-A.

COF reduction by 

20% results in a 

margin 

improvement of 

10.5%.

Stem to Stem Nut 

Coefficient of 

Friction

The stem to stem 

nut friction affects 

the translation of 

motor torque to 

thrust.

The reduction can 

occur if the plant data 

support the 

reduction.

A reduction in stem 

to stem nut COF 

from 0.2 to 0.15 

increases margin 

by 25%.

Actuator Rerating

Actuator capability 

provides the basis 

for margin 

assessment.

A number of 

Limitorque actuators 

have been rerated for 

higher capability by 

Kalsi and 

Westinghouse 

(See Note 1).

Depending on the 

rating program 

used, the gain can 

be up to 60%.

Degraded Voltage

Degraded voltage 

affects the actuator 

capability as the 

output varies 

proportionately to 

voltage squared

(AC Motors).

For conservatism, 

some analysts 

assume that the 

valve is subject to 

degraded voltage. 

Sometimes it is not. 

Need to verify 

susceptibility to 

degraded voltage.

Deletion of

degraded voltage 

improves margin by 

36%.

Valve setting from 

torque limiting to 

position limiting

Valves can be set 

either by torque 

limiting or position 

limiting. Position 

seating reduces 

uncertainties 

significantly.

The vendor must 

have the capability to 

provide the position 

seating guidance.

Position seating 

margin 

improvement can 

be in the range of 

20%

Use of the actual 

Differential 

Pressure

A conservative 

differential pressure 

across the valve 

that does not reflect 

the actual

differential pressure 

reduces margin.

Performing system 

calculation that 

confirms the actual 

differential pressure

across the valve 

reduces the 

conservatism.

Using the actual 

pump pressure for 

example; 2500 psi 

instead of the dead 

head of 2700 psi 

improves margin by 

10%.

Spring Pack 

Limits

In some cases the 

margin or lack of it 

is driven by the 

limits of the installed 

spring pack.

Evaluate if the 

actuator can have a 

higher spring pack

load limit.

An increase in 

spring pack load 

improves margin.
70

Gear ratio Change

Thrust output of the 

actuator is directly 

proportional to gear 

ratio. The higher 

the gear ratio the 

higher margin 

potential.

Provided that the 

reduced speed of 

operation is 

acceptable and the 

structural limit is 

acceptable.

Increased margin 

depends on the 

ratio of the gear 

ratios.

Temperature 

Effect (AC)

High temperature 

affects motor 

actuator output. See 

Limitorque 

Technical Update 

93-03

Evaluate and use the 

actual environmental 

temperatures of the 

MOV.

The margin 

improvement 

between 104°F and 

356°F can be as 

high as 30%.

Temperature 

Effect (DC)

High temperature 

affects motor 

actuator output

Evaluate and use the 

actual environmental 

temperatures of the 

MOV.

The margin 

improvement

between 150°F and 

340°F for 100 ft-lb 

at 250 volts DC is 

24% using 

Limitorque 

guidelines [5].

Structural Weak 

Link Analysis

In some cases the 

structure may limit

the set-up window 

and the overall 

margin.

Review conservative 

criteria or even 

change material to 

increase structural 

limit.

The amount of 

margin depends on 

the extent of 

improvement in 

material properties 

gained by the 

change.

Direction of Flow 

of globe valves

Typically, the 

maximum thrust is 

assumed in the 

calculation of globe 

valve thrust 

requirements 

because it is not of 

clear how the 

valves are installed 

(i.e., over the seat 

or under the seat).

If the actual flow 

direction is known 

the actual equations 

governing the valve 

operation can be 

modeled.

The margin 

improvement can 

be substantial.

Packing Load

Typically, the rule of 

thumb packing load 

is 1000 lbs per inch 

of stem is used.

Determine actual 

packing load from 

diagnostic testing 

and apply it.

The margin 

improvement in low 

differential pressure 

applications can be 

substantial.

Note 1: To request more information on Limitorque actuator re-rating programs please 

contact:

Westinghouse Electric Company; Nuclear Engineering Marketing, 1000 Westinghouse Drive, Cranberry 

Twp., PA 16066

or

Kalsi Engineering, Sugarland, Texas
71

Conclusion

This paper has discussed how MPR-2524-A defines margin and why margin is 

important for operability assessment and static test frequency to demonstrate 

operational readiness. The paper has also presented various approaches the 

authors have used to gain margin on MOVs. It is noteworthy to point out that, of 

the all the approaches presented, the use of COFs lower than the threshold 

values is the most challenging in that it relies completely on the availability of 

substantial differential pressure tests, which most suppliers do not have. To use 

a lower COF, a qualifying basis evaluation in accordance with MPR-2524-A is 

required. It is recommended that the utility MOV engineer that is considering this 

approach should check with their valve suppliers to determine if such data exists 

to support the GL 96-05 evaluations.

References

1. NRC Bulletin IEB 85-03, "Motor-Operated Valve Common Mode Failures 

During Plant Transients due to Improper Switch Settings,” November 15, 

1985.

2. NRC Generic Letter GL 89-10, “Safety Related Motor-Operated Valve 

Testing and Surveillance,” June 28, 1989.

3. NRC Generic Letter GL 96-05, “Periodic Verification of Design-Basis 

Capability of Safety-Related Motor-Operated Valves,” September 18, 

1996.

4. MPR-2524-A, “Joint Owners Group (JOG) Motor Operated Valve Periodic 

Verification Summary,” November 2010.

5. Limitorque (Flowserve), 5114 Woodall Road, Lynchburg, VA 24502 

(Contact: Technical Service).

6. Final Safety Evaluation of the Joint Owners’ Group Program on Periodic 

Verification on Design-Basis Capability of Safety–Related Motor-Operated 

Valves (2-page letter with 24-page enclosure) – ADAMS Accession 

Number ML082480638.
72

Figure 1 – Typical Manual Gate Valve

Figure 2 – Typical Manual Globe Valve
73

Figure 3 – Typical Manual Butterfly Valve
74

Online Valve Monitoring Helps Shell Achieve Goals at 

the Ormen Lange Gas Plant in Norway

Stan Hale 

Score Atlanta, Inc.

Abstract

Located on Nyhamna Island on the west coast of Norway, the Ormen Lange Gas 

Plant is the source of 20% of the natural gas imported into the United Kingdom. 

The gas is transported via the Langeled subsea pipeline across the North Sea 

from Nyhamna to the Easington Gas Terminal near the mouth of the River 

Humber on the UK’s East coast. A/S Norske Shell operates and maintains the 

Ormen Lange plant. 

Ormen Lange is one of the world’s most advanced gas processing plants but is 

operated by a skeleton crew. In fact, Shell’s goal for the facility is to operate and 

maintain the plant with as few people as possible. In order to accomplish this, 

online condition monitoring systems are employed to monitor virtually everything 

that moves in the plant including pumps and compressors, control valves, certain 

structures, and critical shutdown isolation valves. A stated goal for the plant is 

that 70% of the maintenance budget and maintenance spending should be based 

on the results of condition monitoring. This lofty goal carries some element of 

risk since critical components cannot be allowed to run to failure. Any disruption 

in supply from Ormen Lange during the winter months causes significant 

perturbations in the gas markets and affects prices across Europe. Therefore, 

equipment condition must be accurately reflected by the monitoring systems and 

maintenance performed at the moment it is needed.

This paper shall discuss the condition monitoring approach for the 41 most 

critical shutdown isolation valves at Ormen Lange. The population of critical 

valves includes a mix of single and double acting pneumatic and hydraulic gate, 

ball, and flow control valves. These valves are instrumented with strain gages, 

pressure transducers, and acoustic leakage sensors. The sensor data is 

continually streamed to a data acquisition system that combines other important 

data pulled from the plant’s distributed control system (DCS) such as command 

signals, limit switch signals, and upstream and downstream system pressures to 

create a complete picture of what is occurring at the valve during operation.

Acceptance criteria for key parameters such as thrust or torque output at various 
75

points in the cycle, stroke time, leakage, and other critical measures are 

automatically evaluated by the valve monitoring system after each cycle and 

icons in the system display software provide a visual indication of current valve 

condition. 

The monitoring approach is essentially the same as having a motor-operated 

valve (MOV) or air operated control valve (AOV) diagnostic system continually 

attached to these valves at all times. In our nuclear plant world, the analysis is 

akin to evaluating Generic Letter (GL) 89-10 data every time a valve cycles, in 

effect, allowing the valve to test itself and call someone when something changes 

for the worse. Score Atlanta has been assisting Shell in evaluating the on-line 

results and performance of these critical valves for the past 3 years. The data is 

accessed with the right permissions from computers on the Shell network or 

remotely through the internet and the normal valve signature analysis process is 

used where needed to evaluate condition. The approach taken at Ormen Lange 

illustrates how industries around the globe are leveraging the lessons learned 

from over 25years of valve testing in the nuclear power industry by adopting 

systems that make valve diagnostics and condition monitoring a permanent and 

critical element of safe operations and effective plant maintenance.

Background

Following the introduction of the early MOV and AOV diagnostic systems in the 

mid-1980s, the effectiveness and benefits of valve condition monitoring and 

signature analysis were widely discussed in industry forums such as the 

American Society of Mechanical Engineers (ASME)/Nuclear Regulatory 

Commission (NRC) Pump and Valve Symposium, various Electric Power 

Research Institue Valve Symposiums, MOV and AOV Users Group meetings, 

and at other nuclear industry conferences. The early success of diagnostic 

systems for valves has also been well chronicled in numerous industry 

publications and a wealth of information is available on the internet for those 

seeking information on valve diagnostics and condition monitoring. The ASME 

code committees have also made adjustments to the various codes and code 

cases to get the most out of valve diagnostic and signature analysis techniques 

used as alternative methods for in-service testing of valves in nuclear power 

plants.

The leading valve diagnostic system and service suppliers have also marketed 

every process industry in every corner of the globe where improved valve 

performance is desirable. Because of the high cost and absence of regulatory 
76

pressure, adoption of valve diagnostics has not been as wide spread in other 

industries when compared to nuclear. However, that trend is changing at a fast 

pace. The move toward valve diagnostics and condition monitoring has moved 

fastest in the offshore oil & gas industry on the Norwegian side of the North Sea.

The initial adoption of valve diagnostics for the most critical valves on offshore 

platforms by Norwegian oil companies was not initially encouraged by the 

Norwegian Petroleum Directorate which is responsible for offshore regulatory 

compliance. However, after several years of experience with on line data 

acquisition and analysis, the current expectation among operators is that critical 

valves must be monitored at some level.

By 2003, at least a dozen Norwegian offshore platforms were monitoring critical 

isolation valves with on-line monitoring systems. Strain gages, hydraulic and 

pneumatic pressure transducers, and acoustic leakage detection sensors were 

producing a new level of confidence in valve performance. About this same time, 

engineers designing systems and components and planning maintenance and 

operating strategies for the Ormen Lange gas plant were searching for industry 

best practices related to valves. 

In addition to valves, Ormen Lange has become synonymous with best practices 

in all areas of offshore oil and gas production. The gas field itself lies offshore 

and approximately 75 miles northwest of Kristiansund where the seabed is 

approximately 3,300 feet below the surface. There is no platform or other vessel 

on the surface above the wells as would normally be expected. The wells are 

completed subsea and the gas is piped through two 30” pipelines to the Ormen 

Lange plant on the remote Nyhamna Island. On the island, the gas is processed, 

compressed, and then piped 750 miles across the North Sea to the UK. 

Approximately mid way to the UK the pipeline crosses the Sleipner platform. 

Shell took over operation of the plant on December 1, 2007.

One over-riding strategy that helped guide the design and planning process was 

the need to minimize the number of people required at the plant for maintenance 

and testing activities. As a result, heavy use of condition monitoring systems for 

as many components and process systems as possible would be employed. The 

strategy was clear and detailed specifications were developed for the valve 

condition monitoring system and multiple suppliers competed in the bidding 

process. 
77

The V-MAP on line valve monitoring system was one of the systems selected to 

meet the condition monitoring goals of the Project. 

One required feature of instrumentation used in the hazardous oil and gas 

environment involves assurances that electrical faults or instrument failures will 

not create enough energy to ignite a potentially explosive atmosphere in the 

immediate environment. Various strategies are used around the world to protect 

against potential ignition but the breakthrough for condition monitoring was the 

development, certification, and use of intrinsically safe circuits and devices. 

Intrinsically safe electrical circuits require very little power to operate and are 

designed such that normal operation, faults, and shorts cannot release enough 

energy or heat to ignite an explosive atmosphere. 

A critical requirement of the Ormen Lange valve monitoring system was the 

ability to detect through-valve leakage after the valve closes. Through-valve 

leakage is one of the most important test parameters for the oil and gas industry 

and certain valves must be tested periodically to verify they will not leak when 

needed in an emergency. Broadband acoustic emission sensors are employed 

by V-MAP to detect the high frequency noise caused by very small leaks at high 

pressure. The leakage noise elevates the broad band emission output of the 

sensor and also creates an initial peak above 100 KHz that spreads in both 

directions from the peak when the amplitude increases as a result of increasing 

leak size.

The sensors and amplifiers used in the field provide the conditioned data in a 

format needed for automated recording in a safe area away from the valves. 

Much like the portable systems routinely used for periodic MOV and AOV testing 

in nuclear plants, the data acquisition units (DAUs) capture multiple channels of 

sensor data streaming from the acoustic emission sensors, the strain gages, and 

pressure transducers in the field. The DAUs stream the captured data in digital 

format from the sensors to a server in a remote location. Data from the plant 

control system is linked to the field data in the server via an OPC link. The plant 

data includes time stamps for initiation of the valve cycle, limit switch actuations, 

system pressure at the valve, and differential pressure across the valve when the 

valve is closed.

The V-MAP application running on the server provides automated analysis of the 

incoming data based on user defined limits in the software. When acceptance 

criteria are not met, the V-MAP user is alerted at his workstation when viewing 

the main V-MAP dashboard. The visual icons representing each valve change 
78

from green to red or yellow based on automated analysis of the data. During the 

early phases of operation the alarms were allowed to trigger with every cycle 

such that baseline performance could be established over a range of operating 

conditions. After 3 years of monitoring, the acceptance criteria for force or 

torque, cycle time, response time, and leakage have been adjusted to reflect the 

baseline performance at various operating conditions and to help evaluate 

changes over time. 

Condition Monitoring Approach

As discussed above, the critical isolation valves at Ormen Lange include a mix of 

single and double acting pneumatic and hydraulic gate, ball, and flow control 

valves similar to globe valves.

Strain gages are attached to the valves to detect changes in actuator output or 

loads in the valve that may affect performance. The precise location of each 

gage was determined by finite element analysis (FEA). The FEA identified the 

best location for the gage and the appropriate conversion factors for converting 

strain to torque or thrust.

Since the actuators are hydraulic or pneumatic, pressure transducers are 

installed in the supply lines between the hydraulic control solenoids and the 

actuator cylinder. It is important to point out that the actuators and valves used 

at Ormen Lange are much larger than the typical nuclear plant valve. The 

isolation valves at the landfall accommodate the 30” pipeline from the subsea 

wells. The critical shutdown valves on the export side of the plant are 42” in 

diameter with a maximum gas pressure at the valve of 3,600 PSI. The hydraulic 

actuators for these large gate valves can easily apply greater than 250,000 

pounds of force to the valve at the maximum hydraulic system pressure of 4,700 

PSI.

The leakage criteria for each valve vary by valve and application but the typical 

acceptance criterion is .02 kilograms per second (Kg/sec) and .05 Kg/sec. The 

leakage criteria seem tight, but when converted to flow it would be over 100 liters 

per minute depending on the gas density. The acoustic sensors and signal 

processing used will detect a leak as low as .1 liters per minute.

The Ormen Lange plant was designed and built to the highest safety standards 

consistent with International Electrotechnical Commission (IEC) 61508 and 

61511. IEC 61508 is applied during the design of safety critical systems to 
79

ensure that electrical, electronic, and programmable equipment are analyzed 

such that the risks caused by failure of systems or components to perform 

intended safety functions are minimized. IEC 61511 establishes requirements for 

the specification, design, installation, operation, and maintenance of a safety 

instrumented system, so that it can be confidently entrusted to place and/or 

maintain the process in a safe state. 

To reach the desired level of safety at Ormen Lange, features such as partial 

stroke controllers for valves were installed in addition to the condition monitoring 

system. Partial stroke systems facilitate periodic exercising of valves that cannot 

be closed during operations. As a result, valves that must remain open for 

extended periods of time, such as those at Ormen Lange, can be partially cycled 

and monitored at some frequency. Both valve and actuator condition are 

monitored and evaluated after every full cycle and valves that remain open for 

production reasons can be partially closed in order to evaluate potential changes 

in performance. Since these valves may be cycled at any moment and multiple 

valves close at the same instant during shutdowns, it is not practical to capture 

the periodic test data with portable systems. Automated on-line data acquisition 

takes the human element completely out of the testing process and cycles/test 

opportunities cannot escape the continuous monitoring process. Even after the 

valve reaches the closed position, the acoustic sensors continue to stream data 

to the server where it is combined with system pressure information to assess 

the potential of a developing leak.

Strain gage devices and hydraulic transducers wait for the next cycle and the 

command signals from the control room trigger the software to look for activity at 

the valve. The automated analysis system looks at each parameter and decides 

when to alert the user.

Data Analysis and Results

The typical valve actuator at Ormen Lange is spring to close single acting 

hydraulic. However, there are also several double acting hydraulic and some 

pneumatic actuators. The hydraulic system operates at 4,700 PSI and solenoid 

valves route hydraulic pressure to the actuator to open the valve and they also 

release the pressure to allow spring closure.

The gate valves and actuators are both reverse acting, which means the valve 

stem is pulled upward or out to close the valve. When the stem is pulled upward 

or out of the valve, it lifts the gate (obtuator) to cover the orifice and shut off flow. 
80

The gate is pushed down by the actuator to open. This creates a temporary 

orientation issue for an analyst familiar with the operation and signature 

characteristics of a typical gate valve used in a nuclear plant environment.

The backward looking signatures are easier to keep straight for a single acting 

spring close actuator because hydraulic pressure opens the valve and the 

release of hydraulic pressure allows it to close as the spring extends. One of the 

early analysis issues uncovered by the monitoring and signature analysis 

process was related to how fast a valve can close as it exhausts hydraulic 

pressure. The signature data revealed that for the typical actuator the hydraulic 

pressure required to start spring compression, which also starts moving the valve 

in the open direction, is 1,200 PSI. The springs reach full compression, which 

puts the valve in the full open position at approximately 1,750 PSI. However the 

hydraulic system pressure continues to increase to 4,700 PSI after the valve 

reaches the full open position. In order for the valve to close, the hydraulic 

cylinder must release sufficient volume to reduce the pressure from 4,700 PSI to 

1,750 PSI before the spring can overcome the pressure force and start to extend 

which closes the valve. Flow restrictions were found which delayed the start of 

the closure process and extended the closure time for valves required to stroke 

within certain limits required by the safety analysis.

There were several different issues that caused the response time problem. In 

some valves, the size of the exhaust side tubing was increased so the volume 

could escape the actuator cylinder faster. In other cases, the hydraulic control 

blocks that contain the solenoid valves were replaced.

The strain sensor data is used to evaluate changes in running force on gate 

valves or torque on quarter-turn valves that would affect the available margin to 

operate the valve. Some minor changes in torque have been observed over the 

first 3 years but not to a level that would challenge the ability of these robust 

actuators. By evaluating the relationship between hydraulic pressure and 

force/torque from the strain gage, the analyst can assess changes in the valve 

and actuator and determine the location of the observed degradation.

The acoustic emission sensors used to monitor the valve for leakage after it 

closes are sensitive to very low level leakage down to .1 liter per minute. 

Because of the designs used, it is very rare that one of these valves will develop 

a significant leak and to date there have not been leaks that would challenge the 

acceptance limits discussed above. However, it is clear that some of these 

valves do develop very low level leaks from time-to-time that are self correcting. 
81

These leaks which are detected by the system are typically a few liters per 

minute and can be corrected by simply cycling the valve. Debris might normally 

be expected but the gas is very clean by the time it reaches these particular 

valves. At this point they are simply monitored because when the valves close 

the plant or system will typically be headed toward shutdown and lower 

differential pressure across the valve. The cause of these low level intermittent 

leaks is not known but suspected to be related to how well the seats mate during 

closure under different operating conditions.

The valves with partial stroke control systems are exercised regularly and the 

data is automatically captured and evaluated by the system. Since the valves do 

not fully close, there is little diagnostic information about the condition of the 

valve gained from a partial stroke test. However, the partial stroke limit switches 

play an important role relative to stroke time. The amount of time required 

between the close command, the release of the solenoid, the valve starting to 

move, and then reaching the partial close limit is recorded and trended. 

Changes in these times could be indicative of changes in the hydraulic system, 

changes within the actuator or changes within the valve. The simultaneous 

recording of the strain and hydraulic pressure sensor data helps to isolate 

whether the change was due to changes within the valve or actuator. 

All of the data is captured automatically without user intervention. The data is 

processed and analyzed and the results made available through the site network, 

the wider Shell network, and outside of the Shell network through the internet. 

The end result is continuous real time confidence in the condition of critical 

valves versus the unknown and often changing condition not detectable by 

periodic testing programs.

Growing Adoption in Oil & Gas

The growing adoption of on-line valve condition monitoring in oil and gas closely 

mirrors what occurred in the nuclear power industry when portable valve 

diagnostic systems were first introduced. In the early days of adoption by 

nuclear plants, the targets were problem valves known to directly affect safety or 

plant operations. In the Ormen Lange case, it is about getting the most out of the 

plant at the highest level of safety. This strategy has spread throughout the 

Norwegian oil and gas community and into other parts of the world as well.

V-MAP valve monitoring systems have been installed on offshore platforms in the 

North Sea and in the US Gulf of Mexico to monitor critical valves and known 
82

problem valves. Similar systems have also been installed on offshore platforms 

in the Malaysian waters of the South China Sea and most recently in the Tar 

Sands of Northern Alberta. 

In the Tar Sands case, the initial targets are the 3 position coke shuttle valves 

operated by Rotork motor operators. These large ball valves create multiple flow 

paths which allow bitumen to flow into the coking tower from one pipe and out of 

the coking tower through another pipe. These valves are notorious problems that 

eventually lead to extended maintenance outages when they seize due to 

excessive build up of hydrocarbon products within the valve. The monitoring 

approach is to trend increases in the torque required to operate the valve over 

time and schedule maintenance before the actuator can no longer change the 

position of the valve. If the valve seizes with the tower full of bitumen it will 

harden and require extensive manual effort to remove so payback is achieved by 

avoiding the high cost of losing a coking tower in this fashion.

Considerations for Nuclear Plant Valve Testing

On line valve monitoring is not completely foreign to nuclear power plants in the 

United States. On line data acquisition was implemented for a small population 

of MOVs at the Pilgrim Nuclear Plant in the mid-90s as part of the GL 96-05 

program. The data acquisition units are not linked to the outside world through 

the plant IT network as in the Ormen Lange example, but they contain sufficient 

memory to record the required data which is accessed locally by plant personnel. 

The data acquisition units are connected to strain sensors on the valve stem and 

current probes necessary to detect switch actuations are installed in the actuator 

switch compartment.

Unfortunately, on line valve condition monitoring did not gain traction as nuclear 

plants developed and implemented GL 89-10 or 96-05 MOV programs or the 

AOV programs that followed. As a consequence, plants have revisited valves at 

regular intervals to perform the periodic testing required by the MOV and AOV 

programs. The continual at-the-valve testing requires consideration in the outage 

planning process and additional testing resources are often required to install 

equipment and sensors on the valve in order to obtain the required data during 

the outage. 

The many simultaneous outages across the nuclear industry during spring and 

fall refueling seasons continues to tax the various suppliers and demand for 

qualified testing resources often exceeds supply. Valves fail the test acceptance 
83

criteria from time-to-time and an unplanned corrective action is added to the 

outage workload which may also demand additional resources. The process of 

finding the appropriate qualified resources to perform the testing, performing the

tests during the outage, adjusting the outage workload to accommodate 

emerging corrective actions, and risking extending the outage schedule due to 

availability of parts may not always represent the most efficient approach. These 

are the very issues that Shell wanted to avoid at Ormen Lange. 

In the Ormen Lange case, the valves test themselves during each operation and 

the Shell engineer responsible for valve condition monitoring is not even located 

at the site. Valve testing is not a part of the outage and personnel qualified to 

perform valve testing are not required. Maintenance is instead a precise 

orchestra based on the data observed during operation.

Because of GL 89-10 and GL 96-05, strain gage sensors of some type are 

already installed on many nuclear plant MOVs and some AOVs. The addition of 

data acquisition devices that can connect field sensors to the plant network and 

to the outside world can be easily adopted at a lower cost than once expected. 

At-the-valve data acquisition units can communicate data using a dedicated 

valve condition monitoring network or the existing plant network directly to the 

valve program engineer’s desk near real time. As a consequence, valves test 

themselves and all program testing requirements are completed as the valves 

cycle during normal operation or during the shutdown process. Like Ormen 

Lange, this online approach makes outages without at-the-valve MOV or AOV 

testing a reality.

One hurdle to nuclear plant adoption may be how to overcome the real-time 

stream of accurate information on valve condition while the plant is operating. In 

keeping with the highest standards of safety this is desirable. However, it can 

also give operators too much information and lead to unnecessary actions. This 

issue is also a concern in the oil and gas facilities where on line systems are 

currently used. Operations and maintenance personnel must be conscious of not 

blurring the line between the systems required to operate the plant and the 

condition monitoring systems required to maintain components such as valves. It 

must remain clear that an alarm in the condition monitoring system does not 

necessarily mean the component is not operable and this type of alarm should 

remain invisible to operators. However, an alarm in the condition monitoring 

system does alert maintenance and engineering that something is changing and 

it should be evaluated. Occasionally, there may be alarms in the system that 

after complete evaluation require immediate action.
84

Use of on line approaches with ASME Appendix 3 (OMN-1)

The ASME working group responsible for the OM codes related to the operation 

and maintenance of nuclear power plants and specifically the MOV working 

group continue to process inquiries related to implementation of Mandatory 

Appendix III of ASME OM-2009 (also known as OMN-1). Several formal and 

informal inquiries related to Appendix III relate to test frequency and grace for 

missed periodic tests.

Appendix III represents a change from the prescribed test intervals of GL 89-10 

toward empirically derived frequencies based on test data from each valve or 

from groups of similar valves. The “every 2 years” of GL 89-10 and the variable 

intervals of GL 96-05 and the Joint Owners Group Program are relics of the past 

under Appendix III rules. The new approach of Appendix III requires nuclear plant 

licensees to consider margin, risk significance, performance trends, preventative 

maintenance schedules, and other factors that could affect performance when 

setting test frequencies for program valves. It is a highly data dependent and 

analytical process not too dissimilar from the IEC EN 61508 processes used to 

establish failure rates and diagnostic coverage of components that effect safety 

in oil and gas installations.

As plants adopt Appendix III, they will analyze existing data and set test 

frequencies based on the above discussion and factor those tests into future 

outage schedules. Since the average number of MOVs affected by Appendix III 

and GL 89-10 is approximately 100 per nuclear reactor and each MOV on 

potentially different schedules for testing or other program activities, the chances 

that one or more may be overlooked or a scheduled test requirement missed is a 

real concern which has already occurred for at least one plant.

Both of these issues and others are resolved by continuous monitoring of 

program valves and automated data analysis. However, since the software 

driven analysis can only be used to assess certain hard coded criteria such as 

running loads, available thrust or torque, total thrust or torque, and other key 

events, manual analysis by a skilled person or program engineer is still required 

at some frequency. As suggested by the overriding theme of Appendix III the 

manual, visual review of data would be based on the abundance of data 

generated by each operation over the life of the valve.
85

Disclaimer

The views discussed in this paper are those of the author and do not necessarily 

reflect those of any of the organizations discussed herein. The conclusions, 

interpretations, recommendations, or any opinion expressed above may or may 

not be completely the same as those of Score Group, Shell, the ASME MOV 

working group, or any other organization referenced in this paper but are based 

solely on the experience of the author relative to valve condition monitoring over 

the past 25 years in a range of industries.

References

Statoil, Facts about Ormen Lange, www.statoil.com, Copyright 2007

American Society of Mechanical Engineers, Operation and Maintenance of 

Nuclear Power Plants, ASME OM-2009

Score Atlanta, Inc. V-MAP System Description, Copyright 2009

Score Europe, Ltd. V-MAP Generic Functional Description, Copyright 2006

International Electrotechnical Commission, Functional Safety of 

Electrical/Electronic/Programmable Electronic Safety-related Systems, IEC 

61508 Edition 2, Copyright 1998-2010

International Electrotechnical Commission, Functional Safety - Safety 

Instrumented Systems for the Process Industry Sector, IEC 61511, Copyright 

1998-2010
86

FIGURE 1

Ormen Lange Location

FIGURE 2

The Ormen Lange Plant on Nyhamna Island, Norway
87

FIGURE 3

V-MAP Dashboard

FIGURE 4

V-MAP Functional Diagram

Process

Lin

Leak Detection 

Sensors

Strain Gauge

Actuator Pressure 

Transmitter

D

A

U

Computer

Safe Plan

To Plant 

Network
88

FIGURE 5

FEA of Ball Valve Mounting Stool

FIGURE 6

Installed Strain Gages
89

FIGURE 7

Single Acting Gate Valve Model and Example Signatures

<115

Close Direction

<87 >115

Open Direction

91

Session 2(b): Valves II

Session Chair: Dr. Claude L. Thibault, Consultant Wyle Laboratories

93

OM Code Requirements for MOVs – OMN-1 and Appendix III

Kevin G DeWall*

Idaho National Laboratory

Idaho Falls, ID 83415

Kevin.Dewall@inl.gov

* This paper was prepared by the staff of the Department of Energy Idaho National 

Laboratory. It may present information that does not currently represent an agreed 

upon Department of Energy or U.S. Nuclear Regulatory Commission staff position. The 

Department of Energy or U.S Nuclear Regulatory Commission has neither approved nor 

disapproved the technical content.

Abstract

The purpose or scope of the American Society of Mechanical Engineers (ASME) Code 

for Operations and Maintenance of Nuclear Power Plants (OM Code) is to establish the 

requirements for pre-service and in-service testing of nuclear power plant components 

to assess their operational readiness. For Motor-operated valves (MOVs) this includes 

those that perform a specific function in shutting down a reactor to the safe shutdown 

condition, maintaining the safe shutdown condition, and mitigating the consequences of 

an accident. This paper will present a brief history of industry and regulatory activities 

related to MOVs and the development of Code requirements to address weaknesses in 

earlier versions of the OM Code. The paper will discuss the MOV requirements 

contained in the 2009 version of ASME OM Code, specifically Mandatory Appendix III 

and OMN-1, Revision 1. 

Introduction

The requirements for pre-service and in-service testing of nuclear power plant 

components to assess their operational readiness, are found in the ASME OM Code. It 

identifies the components that are subject to test and Owner’s responsibilities under the 

OM Code. The OM Code addresses test methods and intervals, defines the 

parameters to be measured, and provides criteria for evaluating the results. It also 

provides requirements for corrective actions. Its jurisdiction covers components that 

have met the requirements of the construction codes and commences as soon as those 

requirements have been met. The MOVs covered include those required to perform a 

specific function in shutting down a reactor to the safe shutdown condition, maintaining 

the safe shutdown condition, and mitigating the consequences of an accident.

There are several approaches that can be used for component operation, testing, and 

maintenance. One is to simply operate the component until its performance degrades 
94

to unacceptable levels or it fails and then fix or repair the component. This run-to-failure 

approach has never been acceptable for safety-related components. Another method is 

to take a deterministic approach where components are placed in categories based 

upon design and function. Specific test requirements are defined for each category. 

Newer operations and maintenance strategies include risk-informed and performancebased testing, where tests and intervals are based on the impact to plant safety and the 

performance characteristics of the component.

The ASME OM Code was developed in the 1970’s and early 1980’s, and prior to the 

development of diagnostic testing. At that time, deterministic based testing and 

maintenance was considered to be the best available approach. This deterministic 

approach was implemented in the ASME OM Code, Subsection ISTC, “Inservice 

Testing of Valves in Light-Water Reactor Nuclear Power Plants.” Stroke-time testing 

was the best the industry had at the time and was considered adequate for assessing 

MOV operational readiness. ISTC included requirements for position verification, 

quarterly exercising, stroke-time criteria for the quarterly testing, and leak rate testing (if 

required).

Industry Experience and Regulatory Actions

In the early 1980’s, the nuclear industry began to develop an awareness of problems 

with MOVs. The United States Nuclear Regulatory Commission (NRC) issued 

numerous concerns and cautions, and issued a series of documents that resulted in 

utilities developing MOV programs. 

Inspection & Enforcement Bulletin 85-03, Motor-Operated Valve Common Mode 

Failures During Plant Transients Due to Improper Switch Settings. In response to MOV 

events the US nuclear utilities were directed to reevaluate the control switch setting on 

selected safety-related MOVs. The torque switch settings were to be high enough to 

ensure valve operation at design-basis differential pressure conditions. This introduced 

the use of MOV diagnostic testing.

Generic Letter 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance. 

This Generic Letter (GL) expanded the scope of Bulletin 85-03 to all safety-related 

MOVs and led to utility MOV program development. These programs included:

• Review of design-basis conditions

• Development of switch setting calculations

• Use of static testing to set torque switches

• Performance of dynamic testing to demonstrate MOV operability

• Establishment of methods to maintain proper settings for the life of the plant

• Proper post-maintenance activities

Generic Letter 96-05, Periodic Verification of Design-Basis Capability of Safety-Related 

Motor-Operated Valves. Recommendation “d” of GL 89-10 requested that licensees 

prepare procedures to ensure that correct MOV switch settings are maintained 

throughout the life of the plant. GL 96-05 provided more complete guidance regarding 
95

periodic verification of safety-related MOVs and superseded GL 89-10 and its 

supplements with regard to MOV periodic verification. 

A significant concern to the ASME OM committee was the fact that MOVs successfully 

passed the OM Code requirements, yet required additional testing, analysis, and 

upgrades to function at design basis. The ASME OM Code requirements for MOVs 

were inadequate and lagged well behind industry and regulatory activities. NRC 

expressed their concerns in the September 1999 Federal Register, 10CFR50, Section 

2.3.2.5

“...since 1989, it has been recognized that the quarterly stroke-time testing 

requirements for MOVs in the Code are not sufficient to provide assurance of 

MOV operability under design-basis conditions.”

Development of OMN-1

The ASME OM Subgroup on MOVs (formerly the OM-8 Working Group on MOVs) effort 

to update the Code requirements for MOV testing began in 1989. The goal was to 

create consensus-based in-service test requirements that would assess operational 

readiness and eliminate the need for regulatory-based MOV programs. The new 

requirements would eventually replace the MOV related requirements in ISTC. The 

ISTC leakage rate testing would not be affected. In the early 1990’s, the Subgroup on 

MOVs developed new test requirements and selected the ASME Code Case format for 

initial use. The Code Case format provided the quickest path for producing a 

consensus document. Code Cases are voluntary alternatives to Code requirements but 

they allow requirements to use and feedback obtained prior to becoming mandatory 

Code requirements. Code Case OMN-1, Alternative Rules for Preservice and Inservice 

Testing of Active Electric Motor-Operated Valve Assemblies in Light-Water Reactor 

Power Plants, was published with the 1999 Addenda to the OM Code.

OMN-1 is performance based, where testing requirements and frequencies are 

determined using MOV classification (similar to ISTC), design and capabilities, 

operational use and environment, and maintenance programs. It provides test 

requirements for the design basis verification test, preservice test, inservice test, and 

post-maintenance test. OMN-1 encourages the use of engineering evaluations when 

determining the testing strategy and frequency for each MOV or for groupings of MOVs. 

Testing frequency is based on MOV design, capability margin, and what the Owner 

knows about MOV degradation rates (history). OMN-1 replaces the ISTC requirements 

for quarterly stroke-time testing, position verification, and provides exercising 

requirements in lieu of the ISTC requirements. It is also the first ASME Code document 

to allow risk-informed techniques.

Prior to the approval of OMN-1, utilities had to maintain dual test programs, one to meet 

the requirements of the ASME Code and one to meet NRC concerns (GL 89-10, GL 96-

05). OMN-1 programs satisfy the concerns and requirements in both. GL 96-05 

identified the OMN-1 Code Case as one approach for meeting the requirement of that 
96

GL. Based on the 2000 modification to 10 CFR 50.55a and later in Regulatory Guide 

1.192, OMN-1 was approved for use.

Code Case OMN-11 – Risk Informed Testing

As the ASME risk informed initiatives progressed in the 1990’s, the Subgroup on MOVs 

submitted another Code Case to expand the existing risk initiative section of OMN-1. 

This became known as Code Case OMN-11, Risk-Informed Testing for Motor-Operated 

Valves. In order to apply OMN-11 the Owner must first be using OMN-1. OMN-11 

allows the Owner to relax the grouping criteria found in OMN-1, Section 3.5 for Low 

Safety Significant Component (LSSC) MOVs. Existing groups of MOVs can have LSSC 

MOVs associated with them for the purpose of reducing the overall test burden.

ASME OM-2009 and OMN-1, Revision 1

While the development of Code Case OMN-1 was a significant accomplishment, it was 

only the first step toward updating the OM Code. The Subgroup on MOVs has 

continued to address industry feedback to improve OMN-1 and develop a change to the 

mandatory requirements in the OM Code. The goal has recently been completed in the

latest edition of the OM Code. The 2009 OM Code no longer includes the stroke time 

and exercising requirements for MOVs in Subsection ISTC. Instead, ISTC refers MOVs 

to Mandatory Appendix III, Preservice and Inservice Testing of Active Electric Motor 

Operated Valve Assemblies in Light-Water Reactor Power Plants. The 2009 OM Code 

also includes Code Case OMN-1, Revision 1, Alternative Rules For Preservice and 

Inservice Testing of Active Electric Motor Operated Valve Assemblies in Light-Water 

Reactor Power Plants.

The text of Appendix III and OMN-1, Revision 1, is identical. Appendix III becomes the 

required IST for MOVs for users under the jurisdiction of the 2009 OM Code. OMN-1, 

Revision 1, allows voluntary use of Appendix III requirements for users under the 

jurisdiction of earlier versions of the OM Code. The scope of Appendix III/OMN-1, 

Revision 1, is an IST scope which differs from the scope of MOVs mandated by the 

NRC in GL 89-10 and GL 96-05. The scope impact has been minimized by being 

applicable to Active MOVs required for safe shutdown of the plant. The revision 

continues to stress the importance of engineering evaluations and justifications in the 

determination of testing methods and frequencies. Some prescriptive elements found in 

the earlier OMN-1, including confusing diagrams, have been removed. The use of 

torque versus thrust for determining margin has been clarified and Code Case OMN-11 

addressing risk-based initiatives has been fully incorporated. Considerations for new 

testing strategies, such as Motor Control Center (MCC) diagnostic testing, have been 

added. Finally, quarter-turn plug and ball valves have been specifically addressed.

The 2009 OM Code was published in March 2010 and is now being reviewed by NRC 

for endorsement. The endorsement process is expected to take approximately 2 years.
97

Ongoing Efforts

Code Case OMN-1 is being implemented at numerous sites across the US. Other sites 

have stated a desire to implement Appendix III when it is endorsed by NRC. Table 1 

provides a list of these sites and is based on our best feedback to date. The OM 

Subgroup on MOVs continues to address questions presented by industry and 

regulators. Feedback from users is appreciated and used in the effort to continuously 

improve Codes and Standards. Recent questions received by the Subgroup and status 

of these efforts include the following:

Implementation Guide. The Subgroup on MOVs has considered the need for an 

Implementation Guide for Appendix III and Code Case OMN-1. The Subgroup is not 

currently working on this guide since other industry groups are actively working to 

provide this. The IST Owners Group has a draft implementation guide which the 

Subgroup on MOVs will review and provide comments.

Scheduling Allowance (Grace Period). The ASME OM Code establishes the IST 

frequency for all components within the scope of the Code. The frequencies (e.g., 

quarterly) have always been interpreted as “nominal” frequencies and Owners have 

routinely applied the surveillance extension time period (grace period) contained in the 

plant Technical Specifications. However, instances have occurred where regulatory 

issues have been raised as to the applicability of the Technical Specification “Grace 

Period” to OM Code required IST frequencies. A Code Case and Code revision is 

being developed to address scheduling allowance. Current thoughts include a ≤ 25% 

extension for test frequencies of ≤ 2 years, with a maximum 6 month extension for test 

frequencies > 2 years. The allowance cannot be cumulative.

Missed Inservice Test. The ASME OM Code provides corrective actions for IST where 

the acceptance criteria are not satisfied. However, the Code does not consider the 

scenario where an Owner fails to perform an IST. The plant Technical Specifications 

typically contain required actions for a missed surveillance; however, instances have 

occurred where regulatory issues have been raised as to the applicability of the 

Technical Specification for a Code required IST that is not performed. A Code Case 

was suggested to resolve these issues and incorporate requirements when an Owner 

identified that a Code required IST has not been performed. The OM Committee is not 

pursuing this Code Case. The general opinion is that the Code provides requirements 

and should not provide an “out” for those who break the requirements.

Technical Inquiries. The ASME OM Committees meet regularly to conduct standards 

development business. This includes consideration of written requests for 

interpretations, Code Cases, and revisions to the code. ASME OM meetings are open 

to the public and we encourage feedback, questions, and suggestions for improvements 

to the Code. Instructions for the preparation of technical inquiries are contained in the 

front pages of the OM Code. 
98

Conclusion

The ASME OM Code, Mandatory Appendix III and Code Case OMN-1, Revision 1 

provide the requirements for design-basis verification, pre-service, and in-service testing 

of MOVs to assess their operational readiness, These requirements have evolved from 

industry experience and regulatory actions that have produced significant improvement 

in the state of the art in MOV technology and diagnostic testing. Implementation of the 

OM Code and Code Cases should improve the reliability of MOVs, assure their 

performance at design basis, and eliminate the need to regulatory-based MOV 

programs.

Table 1. Implementation of OMN-1 and Appendix III

Sites using or implementing OMN-1 Sites planning to implement Appendix 

III

Beaver Valley Exelon (9 sites)

Calvert Cliffs Southern Nuclear (6 units)

Clinton Duke Power (3 sites, 7 units)

Comanche Peak TVA (3 sites, 7 units)

DC Cook

Diablo Canyon

Ginna

LaSalle

Nine Mile

Palo Verde

Peach Bottom

Perry

Salem

San Onofre

South Texas

Wolf Creek
99

Palo Verde Implementation of ASME OM Mandatory 

Appendix III

Domingo A. Cruz

Component Programs Engineer

Palo Verde Nuclear Generating Station

Abstract

This is paper is a complement to the overview presentation on American Society of 

Mechanical Engineers (ASME) Code for Operation and Maintenance of Nuclear Power 

Plants (OM Code) Mandatory Appendix III, Alternative Rules for Preservice and 

Inservice Testing of Certain Motor-Operated Valve Assemblies in Light Water Reactor 

Power Plants. The paper will discuss how Palo Verde Nuclear Generation Station (Palo 

Verde) is implementing Mandatory Appendix III to determine the operational readiness 

of motor-operated valves (MOVs) and the inservice testing (IST) requirements for 

quarterly-stroke-time and position verification for certain MOVs.

Introduction

Arizona Public Service (APS) - Palo Verde elected to adopt the ASME OM Code

Mandatory Appendix III as part of its IST Program. This election was submitted to the 

Nuclear Regulatory Commission (NRC) as part of the periodic 10-year IST update 

required by Title 10 of the Code of Federal Regulations (10 CFR) part 50.55a. Included 

with the IST submittal was a valve relief request which specifically adopted ASME OM

Code Mandatory Appendix III. Mandatory Appendix III allows the IST program to 

remove stroke time testing and valve position verification for MOVs. It has been long 

recognized in the nuclear industry that stroke time testing does not provide assurance 

of valve / actuator capability. The stroke time testing essentially served to exercise the 

valve. 

ASME Mandatory Appendix III allows the reduction in IST testing based on 

implementation of a more rigorous MOV diagnostic testing program. The primary 

concept imbedded in the Mandatory Appendix III was that credit would be taken for the 

MOV program developed under NRC Generic Letters (GL) 89-10 and 96-05. Although 

there are a number of technical requirement differences between the testing program 

development pursuant to NRC Generic Letters and Mandatory Appendix III, the basic 

concept is still valid.
100

Historically, IST testing has been performed under the auspices of surveillance testing 

in accordance with Plant Technical Specifications. IST test conducted was originally 

required by Technical Specifications (TS) Section 3.0. Testing is now required per TS 

5.5.8 and Technical Requirements Manual (TRM) 5.0.500.8.

Based on the election of ASME OM Code Mandatory Appendix III, it is not clear if MOV 

diagnostic tests need to be performed as a surveillance test or simply the 

implementation of a required test program. 

This paper presents the results of research into the requirements associated with MOV 

testing. The regulatory and administrative aspects of the requirements were 

researched.

Regulatory Requirements

The basis for regulatory requirements originated in 10 CFR 50.36 as implemented via 

TS.

• Review of 10 CFR 50.36:

10 CFR 50.36 defines the requirements for Surveillance Testing and 

Administrative Controls. It is clear that if the NRC intended the IST program (and 

via Mandatory Appendix III) to be included in the surveillance test program that it 

would have included these test programs specifically in Section 3.0 of Improved 

Technical Specifications (ITS) or would have invoked surveillance requirements 

in Section ITS 5.5.8 and TRM 5.0.500.8. However, the NRC elected to include 

IST under Administrative Controls Section (5.0) of ITS.

It should be noted that there are surveillance testing requirements contained in 

selected sections of ITS 5.0.

• Review of Palo Verde Technical Specifications:

The requirements for surveillance testing originated in the plant’s TS. For the 

most part, surveillance requirements (SR) are contained in Sections 3.0, 3.1, 3.2, 

et. al of TS. The SR’s are specifically tied to the accompanying Limited 

Conditions of Operations (LCO’s). The definition of SR’s is not contained in TS 

Section 1.0, but the meaning and requirement of SR’s are clear from the context 

in Sections 1.0, 3.0, and 5.0 of the TS.

Most surveillance requirements are contained in TS Section 3. However, during 

the transition from 1980 and 1990 vintage TS to standardize ITS, many 

programmatic and SR were removed from Section 3.0 of TS and moved either to 

Section 5.0 of TS or to TRM, e.g., radioactive effluent monitoring program, 
101

tendoning testing, etc. The surveillance requirements called out in the TS Section 

5.0 and TRM need to be performed under the auspices of TS and the site 

surveillance test program.

The basic requirements associated with Inservice Inspections (ISI) and IST are

contained in TS 5.5.8 and TRM 5.0.500.8. It should be specifically noted that no 

surveillance test verbiage is contained in these specific sections of TS or TRM.

Administrative Requirements

Palo Verde procedures PD-0AP01, Charter 6.0, 73DP-9ZZ14 and INPO Guideline 83-

031, Rev 2 were reviewed.

• PD-0AP01 

o Charter 6.0 of PD0AP01 provides overall administrative requirements 

associated with testing and inspections performed at Palo Verde. It should 

be noted that while PD-0AP01 includes the IST program under the 

surveillance program, this is not a requirement of either TS or the TRM. It 

appears that either this was a specific election of APS/Palo Verde or it is 

based on historical methodology for implementing the IST program.

• 73DP-9ZZ14

o 73DP-9ZZ14 specifically is scoped to include only surveillance testing 

requirements. Implementation of engineering or other test program is not 

included in 73DP-9ZZ14.

• INPO 86-031, Rev 2

o INPO Guideline 85-031 specifically includes IST programs under the 

auspices of surveillance testing. However, 85-031 was last revised in 

March 1992. During that time frame, IST was included as a surveillance 

test per TS 3.0. This is no longer the case under ITS. 

Evaluation of Requirements

It is clear that IST testing was previously required to be performed as a surveillance 

test. IST testing does not need to be performed as a surveillance test based solely on 

the verbiage contained in ITS. However, Palo Verde as elected to include the IST 

program as part of its surveillance test program per PD-0AP01.

There are no bases in Mandatory Appendix III, GL 96-05, ITS, TRM, INPO Guideline 

85-031, PD-0AP01 or 73DP-9ZZ14 which specifically requires that the MOV program be 

performed as a surveillance requirement. This review includes technical, regulatory or 

administrative perspectives.
102

The only logic which lends itself to pre-suppose that the MOV program needs to be 

included in the surveillance program is if it is constructed to be a direct part of the IST 

program. This latter logic is not deemed viable since the original concept was for IST to 

take credit for the MOV program as opposed to incorporating the MOV program into the 

IST program.

Supplementary Information

The existing MOV diagnostic testing program is well established and has been 

functioning adequately since issuance of GL 89-10. The imposition of additional 

administrative requirements does not enhance the MOV program nor does it enhance 

nuclear safety. The only portion of the MOV program which interfaces with the IST 

program is the performance of periodic verification testing (PVT), i.e. inservice testing 

per Mandatory Appendix III. There are many MOV tests performed which are not 

performed as a PVT, e.g. CMWO retests. The basic requirements associated with ISI 

and IST are contained in TS 5.5.8 and TRM 5.0.500.8. The ISI program is currently 

conducted without surveillance tests even though the requirements originate from the 

same sections of the ITS and TRM.

Conclusion

It is clear that the method of implementing Mandatory Appendix III requirements is to 

utilize a surveillance test package as an administrative device to take credit for MOV 

diagnostic testing. It is also clear that it is not required to be performed as a surveillance 

test. The current program is functioning adequately.

Based on information noted above, APS/Palo Verde decided not to utilize surveillance 

test packages for MOV diagnostic testing. Implementation of Mandatory Appendix III 

can be performed without using surveillance tests. The MOV program will continue to be 

implemented in conformance with GL 89-10, GL 96-05 and Mandatory Appendix III 

while the IST program will continue to take credit for the testing performed under the 

existing MOV test program as implemented by site’s Routine Task program. 
103

Code Case OMN-1: An Individual’s Perspective

Bret R. Collier

Enercon Services, Inc.

Abstract

American Society of Mechanical Engineers (ASME) Code Case OMN-1 has been 

around for a number of years. Several nuclear power plant sites have implemented the 

original revision version of this Code Case, and at least one having received approval to 

implement the 2006 version. The requirements of Code Case OMN-1 have recently 

been incorporated into the 2009 Edition of the ASME Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code) as Mandatory Appendix III, which 

means that once this edition of the OM Code has been approved by reference in the 

Code of Federal Regulations, all sites will be required to adopt these testing 

requirement/methods upon their next inservice testing (IST) interval update.

I was first introduced to OMN-1 at Wolf Creek in 2000, which was one of the first plants 

to implement this Code Case. I have been involved with OMN-1 at LaSalle and I 

recently wrote the first Relief Request used for the implementation of the 1996 version 

of OMN-1 for Peach Bottom Atomic Power Station.

The transition from traditionally utilized quarterly IST stroke timing of Motor Operated 

Valves (MOV) to essentially taking credit for the MOV Program can be a complicated 

undertaking. There are a number of factors that one must consider and address in 

order to undergo a smooth program transition. The purpose of this presentation is to 

provide for those Program Owners who have yet to implement OMN-1, insight into the 

advantages and disadvantages of adopting a risk based MOV Inservice Testing along 

with an experienced view of the implementation process.

Introduction

ASME Code Case OMN-1 was first published with the 1996 Addenda to the 1995 

edition of the OM Code. This version of Code Case OMN-1 has been referred to as 

“revision 0” in the June 2003 release of Regulatory Guide 1.192, “Operation and 

Maintenance Code Case Acceptability, ASME OM Code,” where it was identified as, 

“Conditionally Acceptable”. Since then, Code Case OMN-1 has gone through at least 3 

revisions with its latest version published in the 2009 edition of the OM Code.
104

The 2009 edition of the OM Code, in addition to publishing the current version of Code 

Case OMN-1, added Mandatory Appendix III, “Preservice and Inservice Testing of 

Active Electric Motor Operated Valve Assemblies in Light-Water Power Plants”, 

essentially incorporating the rules and requirements of Code Case OMN-1 into the 

actual OM Code.

This means that once the NRC incorporates the 2009 edition of the OM Code into 10 

CFR 50.55a(b) by reference, all future IST Programs will be required to apply these 

rules in lieu of the standard requirements provided in ISTC when addressing their 

electrically driven, active, motor operated valves. (Note, until the NRC incorporates the 

2009 edition of the ASME Code into 10 CFR 50.55a(b) by reference, it is unknown if the 

NRC will add additional stipulations/requirements to Mandatory Appendix III).

The Revision History of ASME Code Case OMN-1

The following table attempts to explain the revision history of Code Case OMN-1. Over 

the years there have been a number of changes made to this Code Case, but each reissuance of the document has not always been denoted by an indication of revision.

Release Publication 

Circumstance

ASME 

Denoted 

Revision 

Level

NRC 

Denoted 

Revision 

Level

Type of changes 

 (not all inclusive)

1 OM 1996a not 

denoted

2 OM 1999a not 

denoted

 0 Note 1 No Change, only reaffirming 

the 1996a version

3 OM 2004 not 

denoted

unknown Revised to address up to the 

2000 Addenda of the ASME 

Code along with nontechnical format/verbiage 

changes.

4 OM 2006a

(also republished in 

OM 2009 

along with 

Rev. 1 listed 

below)

not 

denoted

Note 2 Technical changes, mainly to 

address the Conditional 

Acceptance Limits initially 

imposed by Regulatory Guide 

1.192. Also added a 

statement to recognize Motor 

Control Center (MCC) testing.
105

5 OM 2009 1 unknown Non-technical verbiage 

changes along with the 

removal of all figures which 

should have been removed in 

the 2006 edition but were not 

due to a publishing error.

1 – Regulatory Guide 1.192 (2003)

2 – In initial discussions with the NRC in preparation for submitting a Relief Request to 

use the 2006 published edition of Code Case OMN-1, we were first requested to 

identify this version of the Code Case as, “Revision 1”, however through the Request 

for Additional Information (RAI) process, we were later requested to make reference 

to this issuance of the Code Case as, “Code Case OMN-1 from the ASME OMb 

Code, 2006 Addenda”

What is Code Case OMN-1/Mandatory Appendix III

In short, the testing methodology utilized by Code Case OMN-1/Mandatory Appendix III 

(henceforth to be referred to as “OMN-1”) provide enhanced methods to both determine 

the operability of an active MOV and provide better/more accurate criteria to be used for 

trending the continued operability of the MOV.

In editions of the OM Code prior to 2009, an active MOV would be stroked timed in its 

active direction with those results compared to stroke time limits derived either directly 

from OM Code requirements or from the plants Design Basis Requirements. These 

stroke time results were also “trended” by the IST Engineer so that they may 

subjectively recognize a detrimental operational trend and apply corrective actions prior 

to the valve being unable to perform as required. Testing normally took place during 

plant conditions that allowed for the ease of testing, thus resulting in these MOVs being 

stroked during static conditions, i.e. zero flow. While these stroke time test were easily 

repeatable (a criteria vital to produce trendable results), the information provided by this 

style of testing is not as suitable for detecting component degradation as is the MOV 

Program where testing takes into account the dynamic operational performance of the 

valve (i.e. under design basis accident flow conditions).

What OMN-1 does is essentially take credit for the MOV testing currently being 

performed to comply with NRC Generic Letter (GL) 89-10 and GL 96-05 in lieu of the 

quarterly stroke time testing previously prescribed by ASME ISTC.
106

As with most IST, there are advantages and disadvantages with adopting new testing 

methods. In my opinion, the advantages far outweigh the disadvantages with the 

adoption of OMN-1. In the remainder of this discussion I will review, based upon my 

experience working with and implementing OMN-1 programs, some the advantages,

disadvantages, and pitfalls that a utility may face with the adoption of an OMN-1 

program. 

Advantages

Reduce the Amount of Testing

Prior to the 2009 edition of the OM Code, ISTC required that active MOV be stroke 

timed quarterly, if not on a cold shutdown or refueling basis, based upon plant 

parameters. To comply with these requirements, many man hours must be spent by 

Operations, Engineering, Health Physics staff, in addition to a number of other support 

departments in preparing for and performing these test. The adoption of OMN-1, 

essentially takes credit for testing which is already being performed through the MOV 

Program. As a result, the majority of the man hours previously expended in the 

preparing for conduction of these quarterly testing will no longer be necessary, saving 

tens of thousands of dollars per year.

Reduction in Radiation Exposure

Not having to perform quarterly stroke time testing will reduce the amount of time 

personnel need to be in radioactive areas, thus reducing the sites collective dose.

Better Test Results

The purpose of IST is not to simply comply with regulatory requirements but to 

determine component operational readiness and to provide assurance that pumps and 

valves which perform a specific function in shutting down a reactor to the safe shutdown 

condition, maintain the safe shutdown condition, and mitigate the consequences of an 

accident, will perform as required. In order to make the most accurate determination of 

the ability of active MOVs to perform these functions, the most effective and efficient 

tools should be applied. MOV Program testing based upon GL 89-10 and GL 96-05 

takes into account the valves operation under dynamic accident conditions and provides 

results from which the valves “margin” under these conditions can be more accurately 

determined than through the standard IST static stroke time testing practice. With these 

more accurate diagnostic tools/methods, a more efficient and effective preventative 
107

maintenance approach can be applied to the valves, resulting in a cost savings in both 

manpower and component availability.

Reduce Valve Wear

With the adoption of OMN-1, IST will only require that the valve be operated once per 

refueling cycle, for which credit can be taken for via normal plant operation, in addition 

to the MOV Testing frequency instead of quarterly. This reduction of valve 

manipulations should reduce wear not only on the valve seating surfaces but wear on 

the motor operator.

Disadvantages

Change to the Process

The adoption of an OMN-1 Program requires that an extensive procedure revision 

process be undertaken which will necessitate a review of the plants design and 

licensing documents along with training the plant staff on the new 

requirements/procedures. This conversion process will take some up front time and 

funding, but cost will be repaid many times over as a result of reducing the number of 

future MOV tests.

Up until now, nuclear plants may have put off adopting OMN-1 due to the initial funding 

and manpower cost, but as a result of the issuance of Mandatory Appendix III, delaying 

the adoption of OMN-1 will no longer be optional.

Operability Test / Post Maintenance Testing

Before OMN-1, if maintenance was performed on the valve (not the operator) of an 

MOV, operability might have simply been determined by the performed of an IST Stroke 

Time Test. If the measured time met the acceptance criteria, the valve could be rapidly 

declared operable. Once OMN-1 is adopted there is no longer an IST Stroke Time test 

which can simply be applied as the Post Maintenance Test (PMT) when work has been 

performed on the valve itself. (Work performed on the valve operator would necessitate 

as before the assignment of an MOV test for PMT). The performance of the MOV test 

is a more complicated process than cycling the valve with a stop watch. It involves the 

attachment of diagnostic equipment which captures not only the stroke time but 

torque/thrust generated. The full evaluation of those results could take the MOV 

engineer hours, if not days, to perform, depending upon the application. Waiting hours 

or days is normally not an acceptable option when trying to bring a plant back to power. 
108

In my experience when an MOV test is necessary to prove operability, the MOV 

engineer will supply an additional set of acceptance criteria, which if passed, will provide 

reasonable assurance that the MOV will still meet test requirements upon a full 

evaluation of the data. There are a number of ways this can be implemented, but it 

requires some forethought and concurrence with all applicable departments prior to the 

implementation of OMN-1. Making sure that the necessary procedures are in place and 

that all departments are in concurrence with any changes to procedures and policies 

can be the most difficult part associated with implementing OMN-1.

An alternative to the assignment of the IST OMN-1 test as a PMT for when work has 

been performed on the valve (and not the operator) is to create separate, stand alone 

PMT instructions for each individual valve.

Reduced Valve Actuations

While reduced valve operation will reduce wear on the valve seating surfaces and valve 

operator, reduced valve actuation may “bring to light” MOV grease issues. Some 

greases are prone to separate faster over time than others where stroking the valve 

allows for the operator to “mix” the grease. OMN-1 states that the maximum test 

interval is 10 years and that each MOV shall be full cycle exercised at least once per 

refueling cycle, not to exceed 24 months. This exercise frequency should be sufficient 

to maintain the grease in a mixed state however some utilities are still identifying MOV 

grease issues. 

What You Need to Watch Out For

Strength of your MOV Program

Peach Bottom Atomic Power Station, for whom I wrote the first Relief Request to 

implement the version of Code Case OMN-1 that is published in the 2006 Addenda of 

the Code, were within days of implementing OMN-1 when an MOV Program test 

discovered that a valve did not stroke due to grease issues. At that time, a decision 

was made to not implement OMN-1 until the root cause for the MOV issues was 

determined and the issues corrected. As of the time of this paper’s writing, OMN-1 has 

yet to be implemented at the Peach Bottom Atomic Power Station, but is expected to 

take place in 2012.

Let me remind us all again that your site may not have the option to postpone OMN-1 

based testing methods once you are required to perform an interval update to an OM 

Code edition containing Mandatory Appendix III.
109

Coordination of your IST and MOV Programs

When implementing an OMN-1 program, one of the first steps to perform is a 

comparison of the valves currently being tested by the sites MOV Program and the 

Active MOV’s being tested within the IST Program. There may be instances when your 

MOV 89-10/96-05 Program scope differs from your IST Active MOV scope. These 

differences will need to be reconciled.

Licensing Commitments

These documents need to be reviewed to see if any periodic stroke timing commitments 

have been made to the NRC for which credit was given to the IST Program. If found, 

these commitments will need to be modified or the individual stroke timing of the subject 

valve(s) may need to be continued to meet the commitment.

Response Time Testing

Your plant may be utilizing the quarterly stroke time values measured in their response 

time testing results. If so, either the Response Time Testing procedure will need to be 

revised to point to the MOV Testing procedure for its data or other arrangements will 

need to be considered. 

Conclusion

Remember that the purpose of your Inservice Testing Program is not to simply comply 

with the regulation, but to provide reasonable assurance that the components in your 

plant will be able to function as required when called upon. It is your job as an IST 

Engineer to utilize the most “Accurate” and “Cost Effective” methods available in order 

to assure the readiness of your plant. The adoption of Code Case OMN-1/Mandatory 

Appendix III works both towards meeting the regulatory required “Accuracy” and plant 

owner(s) “Cost Effectiveness” requirements. 
110

* This paper is the draft Mandatory Appendix IV of the American Society of Mechanical 

Engineers Code for Operation and Maintenance of Nuclear Power Plants (OM Code). 

This Appendix is currently in the course of preparation to be added to the OM Code at 

the time of this NUREG publication. The presentation of Draft Mandatory Appendix IV 

will be given by Fred Setzer.

Draft Mandatory Appendix IV

Preservice and Inservice Testing of Active Pneumatically Operated 

Valve Assemblies in Light-Water Reactor Power Plants 

(This Appendix is mandatory and contains requirements to augment the rules of 

Subsection ISTC, Inservice Testing of Valves in Light-Water Reactor Nuclear Power 

Plants.)

IV-1000 Introduction

IV-1100 Applicability

This Appendix establishes the requirements for preservice and inservice testing to 

assess the operational readiness of active pneumatically operated valves in light water 

reactor (LWR) power plants in addition to the requirements of ISTC - 5130.

 

IV-1200 Scope

 

See ISTC -1200

IV-2000 Supplemental Definitions

Pneumatically operated valve (AOV) -- a valve and its associated actuator that uses 

air/gas as the motive force, including all sub-components required for the valve 

assembly to perform its intended function. For simplicity, this type of valve is referred to 

as an AOV throughout this document.

AOV functional margin -- the increment or percentage by which an AOV's available 

capability exceeds the required load to operate the AOV under design basis conditions.

Design Basis Review - A design basis review (DBR) is an engineering analysis used to 

verify and document the adequacy of AOV sizing, establishing conditions for verification 
111

and establishing acceptance criteria for Inservice Diagnostic Testing. Specifically, the 

DBR consists of both a system level and a component level review. The system review 

determines the AOVs design basis system conditions. The component level review 

establishes the AOVs required design basis loads, actuator output capability and 

available actuator capability margin.

Limited Design Basis Review - A limited design basis review is an engineering analysis 

used to verify and document the adequacy of AOV sizing and in establishing conditions 

for verification and establishing acceptance criteria for Inservice Diagnostic Testing. 

Specifically, the limited DBR consists of a component level review. The component 

level review establishes the AOVs required design basis loads using the best available 

information from existing design, testing and vendor documentation.

Inservice Functional Test - A stroke time test that exercises the AOV and verifies fail 

safe capability in accordance ISTC-3500.

Inservice Diagnostic Test - An Inservice Diagnostic Test consists of measurements of 

parameters required to assess the AOV functional margin and position verification test.

High Margin - AOV functional margin that is greater than or equal to 25 % when 

corrected for uncertainties.

Low Margin - AOV functional margin that is less than or equal to 25 % when corrected 

for uncertainties.

Position Verification Test - AOV Inservice Diagnostic Testing meets the intent of 

position verification testing as defined in ISTC-3700. See Section IV-3700 for risk 

informed insights.

IV-3000 General Testing Requirements

IV-3100 Design Basis Verification Test

A onetime test shall be conducted to verify the capability of each AOV to meet its 

safety-related design basis requirements. The test shall be conducted at conditions as 

close to design basis conditions as practicable. A design basis verification that meets 

the requirements of this Appendix but conducted before implementation of this 

Appendix may be used.
112

(a) Design basis verification test data shall be used in conjunction with preservice test 

data as the basis for inservice test criteria.

(b) Where sufficient test data exists, a DBR can be performed in lieu of a design basis 

verification test. The basis and conclusions of the design basis review shall be 

documented.

(c) Design basis verification testing shall be conducted in situ or in a prototype test 

facility that duplicates applicable design basis conditions. If a test facility is used, an 

analysis shall be documented that supports applicability to the in situ conditions.

(d) Justification for testing at conditions other than design basis conditions and for 

grouping like AOVs shall be documented by an evaluation, alternate testing techniques, 

or both. Where design basis testing of the specific AOV being evaluated is 

impracticable, or not meaningful (provides no additional useful data); data from similar 

valves may be used if justified by evaluation. Sources for the data include other plant 

valves or test data published in industry testing programs. Where analytical techniques 

are used to verify design basis capability, those techniques shall be justified by an 

evaluation.

(e) For certain valve types (i.e., ball, plug, and diaphragm valves) where the need for 

design basis verification testing has not been previously identified, an evaluation of 

operating experience may be used to verify design basis capability.

(f) The design basis verification test shall be repeated if an AOV application is changed, 

the AOV is physically modified, or the system is modified in a manner that invalidates its 

current design basis verification test results or data. A determination that a design basis 

verification test is still valid shall be justified by an evaluation, alternative testing 

techniques, or both.

(g) Where existing site programs and normal plant operation provide adequate 

demonstration of AOV capability via periodic cycling, credit can be taken for this 

demonstration provided that the periodic cycling conditions meet or exceed the design 

basis conditions. Assurance should be provided that the component and accessories 

are operating within allowable limits. The basis shall be documented by an evaluation.

IV-3110 Design Basis Review

A Design Basis Review (DBR) shall be performed and documented per evaluation.
113

IV-3200 Preservice Test

Each AOV shall be tested during the preservice test period or before implementing 

Inservice Testing. These tests shall be conducted under conditions as near as 

practicable to those expected during subsequent inservice testing. Testing that meets 

the requirements of this Appendix but conducted before implementation of this 

Appendix may be used. Only one preservice test of each AOV is required unless, as 

described in Section IV-3400, the AOV has undergone maintenance that could affect its 

performance.

IV-3300 Inservice Test

Inservice Testing, shall commence when the AOV is required to be operable to fulfill its 

required function(s), as described in Section IV-1100, and shall be sufficient to assess 

changes in AOV functional margin consistent with Section IV-6400.

(a) A Inservice Diagnostic Test shall be performed

(b) A Inservice Functional Test shall be performed.

(c) AOVs may be grouped for inservice testing as described in Section IV-3500.

(d) Inservice tests shall be conducted such that they do not invalidate the 

inservice test results. If maintenance is needed between the inservice tests, see 

Section IV-3400. If maintenance activities are scheduled concurrent with or prior 

to an AOV’s inservice test, then the inservice test shall be conducted in the asfound condition, prior to the maintenance activity. See Section IV-3700 for risk 

informed discussion. Inservice Functional Testing should be performed prior to 

diagnostic testing when these tests are schedule concurrently.

(e) Where existing site programs and normal plant operation provide adequate 

demonstration of AOV capability via periodic cycling, Inservice Diagnostic 

Testing is not required and credit can be taken for this demonstration provided 

that the periodic cycling conditions meet or exceed the design basis conditions. 

In these cases a component level review as part of the DBR as defined in 

Section IV-2000, is not required. The basis shall be documented by evaluation.

(f) Valve seat leakage testing shall be performed in accordance with ISTC-3600.
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IV-3310 Inservice Test Interval

IV-3311 Diagnostic Testing

 The diagnostic inservice test interval determination shall include:

(a) All AOVs with the scope of this Appendix, shall have a Inservice Diagnostic 

Test conducted every 2 refueling cycles, not to exceed 4 years (can be extended 

up to 6 months to coincide with refueling cycle) until sufficient data exists, from 

an applicable AOV or AOV group, to justify a longer Inservice Diagnostic Test 

interval. 

(b) The maximum Inservice Diagnostic Test interval shall not exceed 10 years 

(can be extended up to 6 months to coincide with refueling cycle).

IV-3312 Functional Testing

All AOVs, within the scope of this Appendix, shall have a Inservice Functional Test 

performed at least once per refueling cycle, not to exceed 24 months (can be extended 

up to 6 months to coincide with refueling cycles). If Inservice Functional Testing of an 

AOV is not practical during plant operation or cold shutdown, Inservice Functional 

Testing shall be performed during the plant’s refueling outage.

The Owner shall consider more frequent Inservice Functional Testing for AOVs in any of 

the following categories: 

(a) AOVs with high risk significance; 

(b) AOVs with severe service conditions (temperature, radiation, fluid process)

(c) AOVs with any abnormal characteristics (operational, design or maintenance 

conditions).

(d) AOVs with less than 10 % margin

IV-3312 Inservice Test Frequency Extension

(a) Components are required to be tested at the frequencies specified in the applicable 

Subsections.

(b) The test frequency specified in the applicable Subsections is a nominal time period 

that may be extended less than or equal to 25% of the specified time period, not to 

exceed 6 months and is applicable to all test frequencies.
115

(c) The allowable less than or equal to 25% extension is applicable to only an individual 

test and is not cumulative. (e.g., the 2nd occurrence of a quarterly test must be 

performed within 115 (i.e., 92 + 23) days of the 1st occurrence, the 3rd occurrence of 

a quarterly test must be performed within 207 (i.e., 92 + 92 + 23) days of the 1st

occurrence, the 4th occurrence of a quarterly test must be performed within 299 (i.e., 

92 + 92 + 92 + 23) days of the 1st occurrence, and so on).

IV-3400 Effect of AOV Replacement, Repair, Modification or Mainteance 

When an AOV is replaced, repaired, modified or undergoes maintenance that could

affect the valve's performance, new inservice test values shall be determined or the 

previously established inservice test values shall be confirmed before the AOV is 

returned to service. If the AOV was not removed from service, inservice test values 

shall be immediately determined or confirmed. This testing is intended to demonstrate 

that performance parameters, which could be affected by the replacement, repair or 

maintenance, are within acceptable limits. The Owner's program shall define the level 

of testing required prior to and after replacement, repair, modification or maintenance. 

Deviations between the previous and new inservice test values shall be identified and 

analyzed. Verification that the new values represent acceptable operation shall be 

documented as described in Section IV-9000 and ISTC-3500.

IV-3500 Grouping of AOVs for Inservice Diagnostic Testing 

Grouping AOVs for inservice testing is permissible. Grouping AOVs shall be justified by 

an engineering evaluation, alternative testing techniques, or both. The following shall 

be satisfied when grouping AOVs:

(a) AOVs with identical or similar actuators and valves and with similar plant 

service conditions may be grouped together based on the results of design basis 

verification and preservice tests. Functionality of all groups of AOVs shall be 

validated by appropriate inservice testing of one or more representative valves.

(b) Test results shall be evaluated and justified for all AOVs in the group.

IV-3700 Risk Informed AOV Inservice Testing

Risk informed AOV inservice testing that incorporates risk insights in conjunction with 

performance margin to establish AOV grouping, acceptance criteria, exercising 

requirements and testing interval may be implemented.
116

IV-3710 Risk Informed Considerations

The Owner shall consider the following when incorporating risk insights in the 

inservice testing of AOVs: 

(a) develop an acceptable risk basis for AOV risk determination,

(b) develop AOV screening criteria to determine each AOV’s contribution to risk, 

and

(c) finalize risk category by a documented evaluation from a plant expert panel.

IV-3720 Risk Informed Criteria

Each AOV shall be evaluated and categorized using a documented risk ranking 

methodology. This Appendix provides test requirements for High and Low Safety 

Significant Component (HSSC/LSSC) categories. If an Owner established more than 

two risk categories, then the Owner shall evaluate the intermediate SSCs and select 

HSSC or LSSC test requirements for those intermediate SSCs.

IV-3721 HSSC AOVs

HSSC AOVs shall be tested in accordance with Section IV-3300. HSSC AOVs that 

can be operated during plant operation shall be inservice functionally tested 

quarterly, unless the potential increase in core damage frequency (CDF) and large 

early release (LER) associated with a longer inservice functional test interval is 

small.
117

IV-3722 LSSC AOVs

Risk insights shall be applied to inservice testing of LSSC AOVs by the following:

(a) A limited design basis review can be performed in lieu of a design 

basis for review for LSSC AOVs in order to establish required design 

basis loads.

(b) Inservice Diagnostic Test shall be performed at least one time to 

assess valve AOV functional margin.

(c) Inservice Functional Test shall be performed in accordance with IV3300.

(d) Requirements of Section IV-3400 apply for AOV replacement, repair, 

modification or maintenance.

(e) AOV Inservice Diagnostic Testing shall be conducted every 3 refueling 

cycles, not to exceed 6 years (can be extended up to 6 months to 

coincide with refueling cycle) until sufficient data exists, from an 

applicable AOV or AOV group, to justify a longer Inservice Diagnostic 

Test interval.

(f) Periodic inservice diagnostic testing is not required for high margin 

LSSC AOVs. However, position verification test is required to be 

performed once per refueling cycle per ISTC3700 and may be 

performed in conjunction with Inservice Functional Test.

IV-4000 Reserved

IV-5000 Test Methods

IV-5100 Test Prerequisites 

All testing shall be conducted in accordance with plant-specific technical specifications, 

installation details, acceptance criteria, and maintenance, surveillance, operation or 

other applicable procedures.

IV-5200 Inservice Diagnostic Test Conditions 

Inservice Diagnostic Test conditions shall be sufficient to determine the AOV's 

functional margin per Section IV-6400. Test conditions shall be recorded for each test 

per Section IV-9000.
118

IV-5300 Limits and Precautions

Diagnostic Testing limits and precautions include:

(a) Manufacturer or vendor limits and precautions associated with the AOV and 

with the test equipment shall be considered.

(b) Plant-specific operational and design precautions and limits shall be 

followed. Items to be considered shall include, but are not limited to, water 

hammer and intersystem relationships.

(c) The benefits of performing a particular test should be balanced against the 

potential increase in risk for damage caused to the AOV by the particular testing 

performed.

IV-5400 Test Documents 

Approved plant documents shall be established for all tests specified in this Appendix 

and shall provide for:

(a) methodical, repeatable, and consistent performance testing; and 

(b) collection of diagnostic data required to analyze and evaluate the AOV 

functional margin in accordance with Section IV-6400.

IV-5500 Diagnostic Test Parameters 

Sufficient diagnostic test parameters shall be selected for measurement to meet the 

requirements of Section IV-6000 in determining the AOV functional margin. Examples 

of diagnostic test parameters are: valve travel, actuator pressure and stem 

thrust/torque.

IV-6000 Analysis and Evaluation of Diagnostic Data

IV-6100 Acceptance Criteria 

The Owner shall establish methods to determine acceptance criteria for the operational 

readiness of each AOV within the scope of this Appendix. Acceptance criteria shall be 

based upon the minimum amount by which available actuator output capability must 

exceed the required design basis loads. Thrust, torque, or other measured parameters 
119

may be used to establish the acceptance criteria. When determining the acceptance 

criteria, consider the following sources of uncertainty:

(a) test measurement and equipment accuracy

(b) actuator spring preload with consideration of spring preload relaxation

(c) actuator spring displacement and force used to derive spring rate

(d) actuator supply air/gas with consideration of regulator or positioner drift

(e) effective diaphragm area (valve and actuator)

(f) analysis, evaluation, and extrapolation method

(g) grouping method.

IV-6110 Parameter Measurements

Stem force or other parameters may be used to determine AOV margins, if those 

parameters are consistent with Sections IV-5500 through IV-6430.

IV-6200 Analysis of Data 

Data obtained from a test required by this Appendix, shall be analyzed to determine if 

the AOV performance is acceptable. The Owner shall determine which methods are 

suitable for analyzing necessary parameters for each AOV and application.

Whenever data are analyzed, all relevant operating and test conditions shall be 

considered.

The Owner shall compare performance test data to the acceptance criteria. If the 

functional margin, determined per Section IV-6430, does not meet the acceptance 

criteria, the AOV shall be declared inoperable, in accordance with the Owner's 

requirements.

Data analysis shall include a qualitative review to identify anomalous behavior. If 

indications of anomalous behavior are identified, the cause of the behavior shall be 

analyzed and corrective actions completed, if required.
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IV-6300 Evaluation of Data 

The Owner shall determine which methods are suitable for evaluating test data for each 

AOV and application.

The Owner shall have procedural guidelines to establish the methods and timing for 

evaluating AOV test data. Evaluations shall determine the amount of degradation in 

functional margin that occurred over time. Evaluations shall consider the influence of 

past maintenance and test activities to establish appropriate time intervals for future test 

activities.

The evaluations shall apply changes in functional margin to other applicable AOVs to 

establish appropriate time intervals for future test activities.

IV-6400 Determination of AOV Functional Margin 

The Owner shall demonstrate that adequate margin exists between required design 

basis loads and the available actuator output capability to satisfy the acceptance criteria 

for AOV operational readiness. In addition to meeting the acceptance criteria, adequate 

margin shall exist to ensure that changes in AOV operating characteristics over time do 

not result in reaching a point at which the acceptance criteria are not satisfied before the 

next scheduled test activity. 

IV-6410 Determination of Actuator Output Capability 

IV-6411 Available Output Based on Actuator Capabilities 

Available actuator output shall be determined based on the actuator’s capabilities at 

design basis conditions. Considerations shall include:

a) actuator effective area

b) actuator efficiency

c) other appropriate factors

 
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IV-6500 Corrective Action 

If the AOV performance is unacceptable, as established in Section IV-6200, corrective 

action shall be taken in accordance with Owner's corrective action requirements.

IV-6510 Record Of Corrective Action

The Owner shall maintain records of corrective action that shall include a summary of 

the corrections made, the subsequent inservice tests, confirmation of operational 

adequacy, and the signature of the individual responsible for corrective action and 

verification of results.

IV-7000 Reserved

IV-8000 Reserved

IV-9000 Diagnostic Test Records and Reports

IV-9100 Diagnostic Test Information

Pertinent test information shall be recorded or verified for AOV testing, described in 

Section IV-3000. The following information shall be considered:

(a) AOV plant-specific unique identification number.

(b) Test equipment unique identification numbers and equipment calibration 

dates.

(c) Test method and conditions, described in Section IV-5000, including 

description of valve lineups, process equipment, and type of test. Descriptions 

shall include valve body, valve stem, actuator, and piping configuration near the 

AOV.

(d) AOV performance test procedure and other approved plant documents 

containing acceptance criteria.

(e) Name of test performer and date of test.
122

(f) System flow, system pressure, differential pressure, system fluid temperature, 

system fluid phase, and ambient temperature.

(g) Significant observations -- any comments pertinent to the test results which 

otherwise may not be readily identified by other recorded test data shall be 

recorded. Observations shall include any remarks regarding abnormal or erratic 

AOV action noted either during or preceding performance testing and any other 

pertinent design information which can be verified at the AOV.

IV-9200 Documentation of Analysis and Evaluation of Diagnostic Data

The documentation of acceptable AOV performance, which has been analyzed and 

evaluated in accordance with Section IV-6000, shall include, as a minimum:

(a) values of test data, test parameters, and test information established by 

Sections IV-5500 and IV-9100;

(b) summary of analysis and evaluation required per Sections IV-6200 and IV6300;

(c) statement(s), by an individual qualified to make such a statement through the 

Owner's qualification requirements, confirming that the AOV is capable of 

performing its intended safety function; and 

(d) test results and analysis shall be evaluated by qualified individuals and 

documented to include signature and date. Independent verification shall be by 

individuals qualified to verify those specific analyses and evaluations through the 

Owner's qualification requirements.
123

Technical Review of Recent Packing/Gasket Failures 

(Operating Experience OE)

Kenneth A. Hart

Senior Technical Consultant

AP Services, LLC.

203 Armstrong Drive

Northpointe Industrial Park

Freeport, PA 16229

Abstract

Year after year, nuclear power plants experience significant gasket and packing leaks. 

Although the American Society of Mechanical Engineers (ASME) code neglects this 

area, the failure and leakage of sealing components is imperative to nuclear power plant 

operation. Areas such as motor-operated valve (MOV) operability, boric acid corrosion, 

containment leakage, and even overall station reliability are greatly impacted by packing 

and gasket leakage. This paper will review the gasket and packing operating 

experience from the last several years and will provide understanding of the generic 

drivers of these issues. Actual causes, similarity between events and causes, and 

lessons learned will all be examined. With the current fluid sealing knowledge and 

availability of materials, many of these situations could be prevented, especially if this 

common information could be captured and incorporated into training and engineering 

practices. The conclusions of this paper will provide overall generic recommendations

to improve fluid sealing and specific focused solutions where identified. 

Introduction

This paper was prepared using data evaluated by the Fluid Leak Management User’s 

Group (FLMUG), which facilitates improvements in all areas of fluid sealing. The 

nuclear industry’s reporting system for collection and evaluation of data at this level is 

limited. The general trend over recent years for leakage from packing and gaskets has 

been trending down. This favorable trend recognizes the significant improvement steps

which have been expended over the past years both in material improvement, training 

and process. However, even though the total number of these leaks is decreasing, 

significant station impacts from leaks continue to occur such as plant shutdowns, 

downpowers, and loss of safety system availability. 

The steps taken by the industry are improving performance in the fluid sealing area. To 

ensure the continuation of this positive trend, these steps need to be solidified and 

engrained into the station processes and this success needs to be embraced at the 

remaining stations.
124

The belief that “all packing, gasket and pressure leaks are preventable” needs to be 

fostered throughout the nuclear industry. All involved parties need to maintain or

sharpen their focus on minimizing leakage. The implementation of simple root cause 

investigations on known leaks versus the assumption that sealing material will always 

wear-out, age, and leak is a crucial concept to continue to foster. We cannot assume 

that leaks are inherent and will happen regardless of our actions, for if we do we begin 

to accept them as a way of life.

Information regarding known fluid sealing solutions needs to be distributed across the 

nuclear industry. For spiral wound gaskets, this includes the requirement for inner rings 

in raised face and male/female flange designs. For valve packing, this means the 

monitoring of adequate gland load, proper consolidation, use of improved materials, and 

carbon bushing for stem support. In almost all fluid sealing applications, a fundamental 

concept of good bolting practice must be maintained.

Although faced with challenges such as an aging work force, issues with knowledge 

retention, and older equipment, the nuclear industry must continue to move forward. 

Identifying Issues and Trends

It is important to first identify issues and trends with gasket and packing sealing to see if 

the trend is increasing or decreasing to understand the impact of our current actions. 

Industry data is not reported directly in a useful format and must be processed before its 

use. Limitations exist on the information which is reported, such as only significant 

leaks are reported and included in the data sets. The reporting level for less significant 

leaks between stations will vary. If the engineer understands the limitations of the 

available data, however, an appropriate trend of fluid leaks can still be extracted.

The first data review focuses specifically on valves, looking at failures of either the 

packing or the o-rings/gaskets of a valve. The data presented in Figure 1 shows a 

significant declining trend for the last 4 year period. It should further be noted that 

partial data for 2011 shows this a continuation of this trend. Figure 1 shows the total of 

all reported number(s) of leaks per year.
125

Figure 1 Failures of Valve Packing or O-ring/Gaskets

The second data review focuses specifically on “external leaks” reported on valves, 

pumps, heat changers and piping/fittings. Figure 2 represents the data for the last 4 

years period and shows a decreasing trend. It should further be noted that partial data 

for 2011 shows a continuation of this trend.

Figure 2 External Leakage by Component Type

Because of limitations on data collection and the reporting system, further detailed 

analysis of the data as a means to identify generic issues or trends is difficult. 

Regardless of these limitations, it is clear that the current trend of fluid seal leaks is 

decreasing. However, when leaks occur, they still have significant consequences, 

including plant shutdowns, large unit downpowers, impacts on safety system availability,

0

5

10

15

20

25

30

35

40

2007 2008 2009 2010

Number of Leaks

Valve Leakage

Packing

Oring/Gasket

Total

0

20

40

60

80

100

120

140

2007 2008 2009 2010

# of External Leaks

Packing & Gasket - External Leakage

Valves

Ht Exch

Flange/Fittings

Pump

TOTAL
126

and significant boric acid corrosion. From a review of the specific events, no significant 

single dominant cause was discernible. There was no single “silver bullet” solution 

which could be found from the data. When all of the information is taken at face value

and viewed by an engineer experienced with power plant operation, it is possible to 

identify insights, key points, and lessons learned which can be applied to, maintain, and 

further this decreasing trend of fluid sealing leaks.

After careful consideration of the data available, some themes begin to surface: preexisting conditions, age of material, missed opportunities, gaps in application of already 

understood technology, a culture which accepts some leakage as inherent, and 

prospects of simple material improvements. When considering the key factors 

necessary to continue decreasing seal leakage, it becomes evident that knowledge and 

organization are key. There is a pressing need for refined data management systems 

which will enable more efficient ways to investigate leaks, review history, and produce 

solutions to move forward. Such refined data management tools are also fundamental 

to knowledge retention.

Design and Material Issues

The impact of pre-existing conditions and aging of material are difficult to completely 

discern, as it is unrealistic and cost effective to rebuild all fluid connections periodically. 

Since rebuilds are impractical, there are some specific areas which engineers should be 

aware of and should try to incorporate into plant processes:

Gaskets can receive insufficient bolt load for the specific gasket design. In the 

advancement from asbestos to graphite, it was determined that graphite spiral wound 

gaskets require higher loads to reach design crush and new gasket constants require 

higher stresses to seal.

When spiral wound gaskets are installed in vertical joints, there is always the possibility 

of the gasket to fall out while the joint is being pulled together. Significant leaks to main 

turbine steam flanges have occurred from this issue. A simple adhesive can be applied 

to the gasket to ensure it remains in the proper position. 

Flange designs have not always properly contained the gasket. Radial buckling of 

spiral wound gaskets, which have been upgraded to graphite or PTFE filler, continues to 

occur. The use of inner ring or a kamprofile gasket can address this issue. Even in a 

grooved flange design, a graphite filled spiral wound gaskets will extrude to the side 

walls when tolerances are too large, resulting in loss of gasket load. 
127

Figure 3 Radial Buckling of a Sprial Wound Gasket

With age, thermal cycles, and maintenance, flange faces are no longer square or 

properly aligned. This is particularly true with partition plates, heat exchangers and 

hydrogen cooler end plates.

Additionally, inspection of new valves should be given consideration. By disassembly 

and repacking of new valves, not only can all the packing dimensions be obtained, but 

an opportunity is provided to insure the condition of sealing surfaces and clearances 

prior to installation to prevent any future problems.

Packing and Gasket Maintenance 

The application of proper bolting stress techniques is crucial to all fluid joints. In most 

situations, we apply the correct torque to achieve the desired gasket load, but we fail to 

follow through to insure the load actually reaches the gasket. Adequate attention may 

not be paid to proper lubrication (ie consistent with the temperature), the replacement of 

old bolting, or the use of “hardened” washers. Not using hardened washers will reduce 

the applied gasket stress by as much as 50%. For each gasket type and thickness, a 

target gasket stress should be used to achieve adequate sealing and proper gasket 

crush. 
128

Figure 4 Comparison of typical supplied washer to hardened washer after 

service

The retorquing of bolted packing and gasket connections after the initial installation 

affords the opportunity to second check the joint. During re-torque, the engineers can 

discover crucial information, such as that the gasket creep was more than expected, the 

bolting was loose, or other related issues. For valve packing, a re-torque during the first 

refuel outage after a repack ensures that inservice consolidation is adequately 

addressed and packing stress can remain adequate for long-term, leak-free service.

Quality inert gasket materials should be selected to provide low creep and system 

media compatibility so in-service load is not lost and expected performance is achieved. 

Gasket material must be capable of withstanding the service temperature of the 

application with sufficient margin. Proper clearances for the gasket used must be 

confirmed on installation, and not just assumed.

Valve packing needs to be installed with adequate margin in order to achieve leak free 

service. Guaranteeing that this margin is established and maintained addresses many 

of the issues discussed, such as aging equipment, less than perfect stem/box finishes, 

slight misalignments, and manufacturer’s clearances. When valve operability stroking 

requirements require that packing stress be lowered, the margin to leak free service will 

be reduced, but compensatory actions can be taken. These valves can be live-loaded, 

packing loads can be periodically monitored via diagnostic equipment, or periodic 

packing retorque tasks can be applied. 
129

Figure 5 Concept of Packing Consolidation & Margin to Leak Free service

Achieving proper packing consolidation remains an issue, as evidenced by several 

events. Packing consolidation is the simple act of reforming the packing to the actual

size of the stuffing box and ensuring the application of adequate packing stress. 

Packing consolidation is accomplished by continued stroking of the valve stem and 

torquing of the valve packing until no additional nut movement on the packing gland nut 

is achieved. Due to issues such as lack of training, concern for motor overheating, 

scheduling issues, or ALARA, packing consolidation is not always fully achieved.

Material Improvements

At times we focus only on the more complex issues and miss the importance and 

criticality of simple material improvements. Some stations processes are so rigid that 

the implementation of such simple material improvements are delayed or postponed. 

Over the past decade, we have seen an increase in the application of graphite pressure 

seals versus metal. This change is a major step forward because the graphite pressure 

seal provides improved fluid sealing, accommodates for inherent minor damage in the 

sealing area, and allows for ease of valve disassembly. Several events were related to 

graphite pressure seals, either from bonnet misalignment or from lack of adequate 

containment of the graphite. Maintenance workers who have experience with working 

on valves with metal pressure seals need to understand that it will be more difficult to 

maintain bonnet alignment with graphite. The graphite pressure seal does not provide 

the rigid support of the metal pressure seal. The graphite is superior in its ability to flow 

and seal, but this same ability to flow requires extra attention to ensure that the graphite 

is properly contained. This containment can be accomplished by the addition of metal 

caps on both the top and bottom of the graphite pressure seal. Clearances between the 

body and bonnet must be closely maintained, and if caps are not used, these 

clearances become even more critical. As previously discussed in this paper, retorquing of the graphite pressure seal is necessary after being placed in service.
130

Figure 6 Typical Graphite Pressure Seal with top and bottom caps

To make certain that all of the calculated sealing stress is delivered from the torquing of 

the bolts to the sealing material (ie gasket, packing, pressure seal), “hardened” washers 

need to be installed under all bolting. Without “hardened” washers, 25-50% of the bolt 

load is lost, but many equipment manufacturers do not provide these washers with their 

equipment.

Valve packing is focused on providing a flexible seal for a moving valve stem. When 

added challenges arise, such as accommodating high vibration, stem misalignment, 

side loading from a single AOV spring, or stem loading in the horizontal position, 

packing leaks develop. In the past we attributed these leaks to the packing (i.e., its 

limited life causes it to wear out). The use of hardened carbon bushing for stem support 

in these situations can relieve this burden from the valve packing. With the carbon 

bushing handling these loads, the valve packing is capable of reliably providing long 

term sealing of the stem/stuffing box.

On many lower pressure joints, soft iron gaskets are originally provided by the 

manufacturer. The soft iron gasket does not provide a reliable seal long term and is not 

accommodating of the expected degradation of sealing surfaces which inevitably 

occurs. Graphite gasket sheet material or kamprofile gaskets provide a more reliable, 

robust sealing solution to these joints.

Spiral wound gaskets are the standard solution to many joint applications. Spiral wound 

gaskets can be purchased with “extruded” graphite. The graphite filler of the gasket 

simply extends (i.e., protrudes) past the metal winding. The additional graphite, though 

it remains captured by the gasket, provides additional sealing ability to accommodate 

minor surface imperfections of the metal sealing faces.
131

Promoting the Correct Valve Packing Attitudes

Although a number of minor leaks may exist at a station, sites do not typically attempt to 

determine the cause of leaks unless they have a major impact. A culture which believes 

that leaks are inevitable can easily develop. “All packing, gasket, and pressure seal 

leaks are preventable” must become our message. Once we believe that all leaks are 

preventable, it drives us to determine their causes when they occur.

Processes and procedures should incorporate simple “root cause” tools to facilitate the 

evaluation of leaks when they occur. The basics questions asked for any leak should 

be:

• Am I using the correct material for the application?

• Am I loading the packing/gasket correctly?

• Is the sealing material properly contained?

• Has it been properly consolidated (packing) or re-torqued (gaskets and pressure 

seals-if required)?

• Apply a simple root cause investigation to cover other areas such as dimensional 

clearances, available bolt load, flange design, etc...

• Review internal and external OE for similar applications

• Review work history for component and sister component data

Develop a good rapport with your manufactures and suppliers and don’t be afraid to ask 

contacts at other sites. There is a good chance someone has already fixed the same

problem elsewhere. 

An example of how this information could be incorporated into a valve packing 

procedure form for leak investigation is provided below:

Figure 7 Suggestion for Packing Failure Investigation Sheet
132

Data Management

Many of the items discussed within this paper are neither new nor innovative, but the 

review of our operating experience continues to point out similar issues. An oft 

overlooked area in fluid sealing is that of data management.

Refined data management system needs to have the ability to track historical material 

changes, document actual installed situations, and capture recommended material for 

the next repack/disassembly. The system should provide required torque information 

and track leaks to allow for ease in determining similar events, potential areas for similar 

events, and apply generic material upgrades when identified.

When such a data management system is installed, some of the inherent issues, such 

as knowledge transfer, can be addressed because one knows where to go to look for 

answers. The experiences of the past would be readily retrievable.

A refined fluid sealing data management system goes hand in hand with the simple 

analysis of leaks. Without easily accessible data and search capabilities, these root 

causes are not completed due to the lack of time and resources.

Conclusion

Significant gains have occurred in packing technology and leak prevention, but we can 

not rest on our laurels because nuclear power plants are getting older and their 

experienced personnel are retiring. With proper understanding and analysis, the 

engineer can address aging equipment and pre-existing conditions, fill the gaps in the

application of already understood technology, and promote simple material 

improvements. Current plant personnel must remain vigilant, utilize knowledge capture 

techniques, establish a simple root cause process to every fluid leak, and support 

knowledge transfer via organizations such as ASME and FLMUG. Valve engineers 

must embrace the concept that “all packing, gasket and pressure leaks are 

preventable.”
133

Figure 8 “Getting to Leak Free Operation”

135

Session 2(c): Valves III

Session Chair: Dr. Claude L. Thibault, Consultant Wyle Laboratories

137

Case Study of Valve Differential Pressure Calculation Under 

the Condition of Valve Degradation

Zhilin Dong, Mike Whitehead, Mike Brenner

Callaway Plant, Ameren Missouri

Fulton, Missouri, USA

Abstract

In the nuclear electric power industry, engineers often face challenges of making 

decision with limited technical information. It is not uncommon that typical technical 

information for a certain problem, which is required for solving the problem in the 

method described in textbooks, is not available in the real world. This paper introduces 

a case study on how to solve technical problem with limited technical information in the 

nuclear power industry. In this case, a Pump Supply Isolation Valve has degradation 

(only 80% open). The differential pressure across the partially opened valve is needed 

for the engineering evaluation of this issue. However the value of flow coefficient (Cv) for 

this Pump Supply Isolation Valve was not known and the valve’s equivalent length of a 

resistance to flow (L/D) is available. By utilizing L/D and other available technical data 

the valve’s differential pressure is calculated and the engineering evaluation on the 

valve degradation was made.

Introduction

One of the challenges the nuclear power industry engineers facing is that they need to 

make technical decision with currently available technical information/data within limited 

time to meet the regulation/procedure requirements. It is not uncommon that typical 

technical information for a certain problem, which is required for solving the problem in 

the method described in textbooks, is not available in the real world. The engineers 

need to think about alternative way, with the utilization of available data/information, to 

solve the problem. This paper introduces a case study of how to use available technical 

information to solve problem an alternative way.

In this case, Operations observed that a Motor Operated Valve (MOV) did not fully open 

during the scheduled inservice test. It only opened 80% of its full stroke. This MOV is a 

Pump Supply Isolation Valve. To evaluate the influence of the degraded MOV to the 

system or the Past Operability Determination (POD), the differential pressure across the 

MOV is needed. 

Under the worst possible scenario, the degraded MOV, or the partially opened MOV, 

causes the decrease of the cross sectional area of the flow path. Consequently, the 

differential pressure across the MOV increases. To calculate the differential pressure 

across a valve, its flow coefficient (Cv) is typically needed. However in this case, the Cv
138

of the MOV is not available. An alternative method for calculating the differential 

pressure across the MOV is needed. The alternative method can only use the existing 

data which is available from the plant technical documents or vendor technical 

documents. 

Available Data and Calculation Assumptions

By searching the technical documents and contacting the vender, the following technical 

data on this MOV was collected and selected for the calculation:

• This MOV is an 8 inch flex wedge gate valve equipped with Limitorque SB-00 

actuator. The MOV is limit-controlled. The MOV has been set up to open against 

251 psid as required for its active safety function.

• When this MOV fully opened, the differential pressure (DP) across it is 0.145452 

psid.

• L/D at full open is a maximum of 13. 

• The valve disc would clear the seat at about 9% of travel from full closed based 

on the seat ring and the disc nominal dimensions. 

• The disc would clear the flow passage at about 98% of travel. 

• The L/D between the valve clearing the seat and the valve clearing the flow 

passage would be considered linear.

• The valve fully stroke is 7.3 inches. 80% of full stroke is 5.84 inches.

The calculation also is based on the following assumptions:

• Based on the system analysis, the flow rates through this MOV, under the 

condition of it fully opens (condition 1) and the condition of it 80% opens 

(condition 2), are the same.

• When this MOV opens to 9% of the stroke (or 0.657 inch), the differential 

pressure across the valve is 251 psid.

• When this MOV opens to 98% of the stroke its L/D value is 13.

The Calculation

Per Reference 1, we have the following equations:

Equation (1) the DP across valve:

2 ( ) 62.4 Cv

Q P ρ ∆ = (1)
139

Equation (2) the relationship between Cv and K:

K

d Cv

2 29.9 = (2)

Equation (3) the relationship between K and L/D:





 



 = D

L K f (3)

Where:

∆P : DP across valve (psid)

ρ : Fluid weight density ( 3 lb / ft ). The value does not change under condition 1 and 2

d: internal diameter (inch)

Q: flow rate through the valve (gpm). The value does not change under condition 1 and 

2

f: friction factor

Cv: Valve flow coefficient 

K: resistance coefficient

L/D: equivalent length of a resistance to flow, in pipe diameters

Based on the three equations, we can have the relationship between valve DP change 

and valve L/D change when the valve is at different stroke positions (from condition 1, 

valve fully open, to condition 2, valve 80% open).

2

1

2

1

( / )

( / )

L D

L D

DP

DP = (4)

Values known when the valve fully opens: (L/D) or 1 (L / D) is 13 and DP or DP1 is 0.145 

psid.

Also, this MOV’s valve disc would clear the seat at about 9% of travel from full closed 

(9% of the 7.3 inch stroke is 0.657 inch). At this position, the DP across this MOV ( DP0 ) 

is 251 psid. 
140

The (L/D) value 0 (L / D) when valve travels to 9% of stroke is:

*13 22433.5

0.145452

251 ( / ) ( / )1

1

0

0 = L D = = DP

DP

L D

The valve disc would clear the flow passage at about 98% of travel. When valve travels 

to 7.15 inches (98% of 7.3 inches), its L/D is 13.

Based on the above two valve position data and the information that the L/D between 

the valve clearing the seat and the valve clearing the flow passage would be considered 

linear, we can have the following equation to calculate L/D from valve stroke δ (in 

inches).

(L / D) = −3453δ + 24701.95 (5)

From Equation (5) we can calculate (L/D) number when EJHV8804A is at 5.84 inches 

open:

( / ) 3453*5.84 24701.95 4536.55 L D 2 = − + =

The DP across this MOV when it fully opened is known to be:

DP 0.145452 psid 1 =

From Equation 4, we can have the DP across EJHV8804A when it is at 5.84 inches 

open:

DP psid L D

L D DP *0.145452 50.75

13

4536.55 * ( / )

( / ) 1

1

2

2 = = =

The calculation indicates that when this MOV changed from fully open to 80% open, the 

DP across the valve changed from 0.145 psid to 50.75 psid. Based on the calculated 

DP result, the Past Operability Determination can be made accordingly.

References

1. Flow of fluids Through Valves, Fittings, and Pipe, CRANE Technical Paper No. 

410
141

Advances in the Design and Qualification of Main Steam and 

Main Feedwater Isolation Valves (MSIV & MFIV) with Gas 

Hydraulic Actuators

Richard J. Gradle, PE

Flowserve Corp., Flow Control Division

Engineering, Product Development Manager

Raleigh, North Carolina, USA

919-831-3396

RGradle@Flowserve.com

Floyd A. Bensinger, PE

Flowserve Corp., Flow Control Division

Business and Product Development, Product Portfolio Manager-Nuclear

Raleigh, North Carolina, USA

919-831-3200

FBensinger@Flowserve.com

Abstract

Flowserve has supplied valves for many of the critical applications within commercial 

nuclear power plants since the beginning of commercial nuclear power. The supplied 

valves include two of the more highly critical applications: Main Steam Isolation Valves 

(MSIVs) and Main Feedwater Isolation Valves (MFIVs). As the requirements of these 

two applications have evolved, so have the applicable valve and actuator designs and 

their qualifications.

Main Steam Isolation Valves (MSIVs) and Main Feedwater Isolation Valves (MFIVs) 

perform critical functions within commercial nuclear power plants. As a result, the valve 

and actuator design and qualification for the MSIVs and MFIVs must be effective in 

demonstrating the functional capability of these valves. The MSIVs and MFIVs must 

also satisfy qualification requirements addressing end of life aging and radiation 

exposure, seismic qualifications, and Design Basis Event Accident Environmental 

Qualification testing in accordance with the requirements of IEEE 323, 344 and 382. 

ASME has prepared ASME Standard QME-1-2007 that updates the functional 

qualification standard for active mechanical equipment in nuclear power plants. 

This paper discusses:

• The history of MSIV and MFIV applications within nuclear power plants;
142

• MSIV and MFIV design history;

• MSIV and MFIV qualification methodology that satisfies ASME QME-1-2007; and 

• Actuator environmental qualification to IEEE 323, 344 and 382.

Introduction

Main Steam Isolation Valves (MSIV) and Main Feedwater Isolation Valves (MFIV) are 

critical safety equipment in nuclear plants. The sole function of the MSIV and MFIV are 

to isolate the steam supply system and the feedwater supply system of the steam 

generators in the unlikely event of a steam or feedwater pipe break. This action 

prevents the blowdown of the steam generator and supports the heat removal from the 

nuclear-fueled reactor.

Today, for Pressurized Water Reactor (PWRs) and Boiling Water Reactors (BWRs), 

these valves must close quickly, typically within three to five seconds, and must operate 

successfully under all plant conditions including normal, emergency and accident 

situations, even if all normal power supplies fail. 

History of Application

These critical valve applications have evolved since the start of commercial nuclear 

power generation. Initially, MSIVs were check valves and Y-pattern globe valves in 

Pressurized Water Reactors (PWRs) and Boiling Water Reactors (BWRs), respectively. 

Later PWRs utilized Y-pattern globe valves to better control the closure speed of the 

MSIVs.

Eventually newer plant designs took advantage of the more efficient flow characteristics 

of gate valves in place of Y-pattern globe valves. This created the need to use 

gas/hydraulic actuators to actuate the gate valves due to their longer stem travel and 

higher closure thrust requirements.

Quickly and reliably closing MSIVs, which can stand more than 16 feet tall (6.1m) and 

weigh more than 20 tons (20.3 metric tons), is no easy task. It requires several hundredthousand pounds (900 kilo newton) of force to be delivered instantaneously. Refer to 

Figure 1 for a picture of a typical MSIV (gate valve) with the Flowserve Edward Type A, 

gas/ hydraulic actuator as currently designed and manufactured.

MFIVs have only been used in PWRs, not BWRs. Initial MFIVs were motor operated 

gate valves.
143

As plant technical design criteria became more demanding and required operational 

times to be reduced, electric motor operators could no longer close the MFIVs within the 

reduced operational times and pneumatic actuators with mechanical or compressed air 

springs were used in their place. 

Today’s MFIV configuration is essentially the same as that of the MSIV depicted in 

Figure 1 but with a smaller gate valve and actuator.

MSIVs and MFIVs rely on low-pressure sensors on the steam and feedwater lines to 

trigger the MSIV and MFIV closure signals (control signal to the type A, gas/hydraulic 

actuator solenoid valves). This electrical signal causes the release of hydraulic fluid in 

the rod end of the actuator, allowing the high-pressure stored energy of the compressed 

type A, gas to drive the MSIV or MFIV closed.

For more than 30 years, gate valves equipped with gas/hydraulic actuators have been 

the safest, most reliable and cost-effective way to close MSIVs and MFIVs without 

depending on an external energy source. Their small size—compared to other available 

designs with comparable thrust and travel properties — translates into lower installation, 

operation, and energy costs. 

In addition, industry tests have shown gas/hydraulic actuators are capable of performing 

safety-related functions under harsh conditions, such as high-radiation exposure, 

earthquakes, and potential plant accident environmental conditions, resulting from a 

loss of coolant (LOCA) or a main steam line break (MSLB) accidents.

The Flowserve – Edward Gas/Hydraulic Concept

Gas/hydraulic actuators rely on high pressure to open and close the valve. The actuator 

cylinder rod end is pressurized to open the MSIV and depressurized to close it. The 

depressurization of the rod end is controlled by the hydraulic circuit to regulate the rate 

or speed of MSIV closure. 

The cap end of the cylinder contains a high-pressure gas accumulator. On the most 

recent designs, this accumulator is integral with the cylinder and when filled with 

gaseous nitrogen, provides the stored energy to drive the MSIV closed when required. 

Refer to Figure 2 for a general actuator cylinder and accumulator cutaway view.

To close the valve, a quick-release hydraulic circuit discharges the fluid from the 

cylinder rod end to a reservoir, permitting the stored energy of the pressurized gas of 

the cylinder cap end to extend the actuator. To open the valve, a hydraulic power unit 
144

pumps fluid to the rod end of the cylinder to drive the MSIV open and fully pressurize 

the nitrogen in the cap end accumulator.

While the concept is simple, the principle has to be delivered in a way that satisfies the 

reliability and redundancy requirements of a nuclear power plant. 

The first requirement is that stored energy must always be available. Gas stored in 

remotely mounted accumulators could be unavailable when needed, especially if 

leakage occurs in the flexible connections between the accumulators and the valve. 

Even if accumulators are mounted on the valve, connections between accumulators and 

the actuator cylinder could be vulnerable to leaks or failures. 

As a result, the most efficient and reliable actuators have a built-in stored-gas volume. 

In this instance, gas is stored in an accumulator coupled with the cap end of the 

actuator cylinder. Besides eliminating potential leaks, this design eliminates pressure

losses during the stroking of the valve, which ensures quick closure. Whenever the 

MSIV is open, the stored energy to close the MSIV is always available.

Small Size Reduces Cost, Increases Safety

In the past, some nuclear plants used large, low-pressure actuators to close the equally 

large valves (typically size 16 to 32). These large actuators were expensive to 

purchase, install and maintain. In contrast, using smaller, high-pressure stored-energy 

systems to actuate valves minimizes costs. The actuators have a price advantage and 

are more energy efficient and reliable than earlier MSIV actuators. 

Actuator performance during an earthquake is paramount to ensuring plant safety. 

Previous actuator designs were challenged to meet stringent seismic requirements due 

to their large size and piping connections. The small size and integral design of modern 

gas/hydraulic stored-energy actuators allow for reliable performance even during a 

seismic event, without sacrificing the power needed to reliably close the MSIV. 

Safety-Related, Active Valve Qualifications

Since the MSIVs and MFIVs must be able to function during a seismic event and / or a 

nuclear plant accident in order to support the safe shutdown of the nuclear reactor, they 

are classified as active, safety-related components. As such, the MSIVs and MFIVs 

must complete functional and environmental qualifications tests in accordance with 

ASME QME-1 and IEEE 323, 344 and 382. These standards are defined as follows:
145

• ASME QME-1-2007, Qualification of Active Mechanical Equipment Used in 

Nuclear Power Plants;

• IEEE 323-1974-1983, IEEE Standard for Qualifying Class 1E Equipment for 

Nuclear Power Generating Stations;

• IEEE 344-1987, IEEE Recommended Practice for Seismic Qualification of Class 

1E Equipment for Nuclear Power Generating Stations;

• IEEE 382-1996, IEEE Standard for Qualification of Safety-Related Actuators for 

Nuclear Power Generating Stations

Flowserve MSIV and MFIV ASME QME-1 Qualification

ASME QME-1 functional qualification testing is utilized to verify that the safety-related, 

active valves will function during their postulated normal and accident events. MSIV 

and MFIV functional qualification tests include:

• Functional tests with maximum and minimum motive force;

• Hot and cold cycle tests;

• Sealing capability tests to confirm the valve seat and stem sealing capabilities;

• Fundamental frequency determination;

• Seismic tests to confirm the valve will function during a seismic (earthquake 

event);

• End load tests to confirm valve function and seal with applicable pipe loads 

inducted on the valve body nozzles;

• Flow interruption and functional capability test

Testing was performed in accordance with the 1994 edition of the test standard. 

However, the test program also meets the requirements of the 2007 edition of the 

standard.
146

Valves included in the testing are listed in Table 1.

Table 1, List of Test Valves

Size

Pressure 

Class 

Rating

Actuator 

Size

Power 

Plant 

Service

26x24x26 900 A-290 Main 

Steam 

Isolation

4 900 A-100 Main 

Steam 

Isolation

20x16x20 900 A-260 Feedwater 

Isolation

8x6x8 900 A-100 Feedwater 

Isolation

Typical valve design conditions are listed in Table 2.

Table 2, Valve Design Conditions

Valve 

Size

Pressure 

(psig)

Temperature 

(

o

F)

26 x 24 x 

26

Saturated 

Steam 564

4 1390 564

20 x 16 x 

20 2100 564

8 x 6 x 8 2100 564

The ultimate goal of the test program was to provide a test data base that could be used 

to extend the qualification to valves that were not tested.

Consequently, analytical models were developed to calculate critical parameters, 

including natural frequency, static deflection, and required valve closing force. The data 

from the test program was used to verify and validate these analytical models. This 

provides the basis for extending the qualification to valve which were not tested.
147

A closed form mathematical model was used to determine required valve closing force 

during the flow interruption test. The model includes the valve stem ejection load, 

packing friction and the internal friction load resulting from the gate sliding on the 

internal valve body guides.

Three-dimensional finite element models, in addition to a closed form approach, were 

used to calculate valve assembly natural frequencies and deflection resulting from the 

application of the simulated seismic load on the valve upper structure. The 3D finite 

element models allow a more exact representation of the weight distribution of the valve 

assembly.

Baseline testing was performed between each phase of the test program for each valve. 

During the baseline testing, main seat and valve stem packing leakage were tested and 

measured.

Following completion of the test program, the valves were disassembled and inspected 

for damage resulting from the test program.

Most Recent Gas/Hydraulic Actuator Design Advances

Due to its many plant installations and many years of installed life, the Flowserve 

gas/hydraulic stored-energy actuator provides a sound basis for customer operational 

feedback. This feedback provides the knowledge source for continuous design 

improvements. With this knowledge and the drive to enhance the actuator design to 

gain longer maintenance intervals and the use of environmentally friendly hydraulic 

fluids, the Flowserve gas / hydraulic actuator design was updated to include:

• Longer-life solenoid coils;

• Longer-life seals;

• Polyol-ester hydraulic fluid;

• Pressure transmitters for monitoring actuator gas/hydraulic pressures;

• Quick disconnects for actuator wiring;

• Redundant electric motor driven hydraulic pumps.

The change in soft materials (seals, solenoid coils) increases the qualified thermal 

lifetime (maintenance interval) of the actuator from 5 years (122°F) to 12 years (130°F). 

The change in hydraulic fluid reduces the disposal efforts and costs plus is much easier 

for maintenance personnel to work with. The addition of the pressure transmitters 

allows diagnostic monitoring of the actuator while in service. The quick disconnects 

simplify maintenance by simplifying removal of the wiring connections. The redundant 

hydraulic pumps improve reliability.
148

Flowserve Environmental Qualification of the Gas/Hydraulic Actuator

Along with the design changes that have been made to the actuator, the effects on the 

actuators’ operation and environmental qualification were evaluated. A prototype 

actuator was fitted with the new seals, solenoid valves, and hydraulic fluid and 

functionally verified to meet all of the requirements.

However, as several of the actuator safety-related components changed, the enhanced

gas / hydraulic actuator required environmental requalification to the above IEEE 

seismic and environmental standards. These standards require that the actuator be 

aged to an equivalent “end of life” condition and then demonstrate the ability to reliably

perform the safety-related function.

Flowserve has qualified the actuator twice previously in accordance with the relevant 

IEEE test standards. However, changing the seal material, changing the hydraulic fluid, 

and adding the pressure transmitters and quick disconnects required that the enhanced 

gas / hydraulic actuator be environmentally re-qualified in accordance with the above 

IEEE seismic and environmental standards.

The qualification test program included the following test phases:

• Thermal aging;

• Mechanical wear aging;

• Radiation aging;

• Vibration aging;

• Multi-frequency SSE/OBE testing in accordance with IEEE-382;

• Resonance search testing (1-100 Hz);

• Single frequency SSE/OBE RIM testing (3.3 g OBE, 5.0 g SSE);

• Design Basis Even (DBE) simulation with peak transient temperature of 

approximately 500°F.

During DBE testing, the Actuator was actuated to “close the MSIV” at the time of the 

peak temperature of the DBE test. After the actuation was completed, the rupture disk 

on the environmental chamber burst, stopping the test. The Actuator was retracted and 

extended to demonstrate functionality. The rupture disk was repaired and the test 

resumed. After 2 weeks at 150°F, the test was completed. Following very minor 

maintenance to non-safety related components, the actuator was retracted and 

extended as a demonstration of functionality.
149

Conclusion

As a result of the above efforts to develop an enhanced actuator design and satisfy the 

functional qualification requirements in accordance with ASME QME-1 and the 

environmental qualification requirements in accordance with IEEE 323, 344 and 382 for 

the MSIV and MFIV applications, Flowserve now has the most advanced and qualified 

MSIV and MFIV design (valve and actuator) available to the global commercial nuclear 

power generation market. The MSIV and MFIV designs and qualifications support 

installation in current operating nuclear plants as well as the new globally available 

Generation 3 and 3+ nuclear power plants.

Figure 1, A Typical MSIV (Gate Valve) with a Flowserve Edward Type A, Gas / 

Hydraulic Actuator as Currently Designed and Manufactured Today.
150

Figure 2, Cutaway View of the Flowserve Edward Type A, Gas / Hydraulic Actuator 

Cylinder Assembly.

Figure 3, Flowserve MSIV (Equiwedge Gate Valve With Type A Gas / Hydraulic 

Actuator) Setup During the Static Seismic Tests and the Pipe End Loads Tests.
151

Figure 4, Flowserve Edward Type A, Gas / Hydraulic Actuator During the Dynamic 

Seismic Tests, Triaxial – Random Multi-Frequency Input.

Figure 5, Flowserve Edward Type A, Gas / Hydraulic Actuator During the Dynamic 

Seismic Tests, Single Axis – Vertical Input.
152

Figure 6, Flowserve Edward Type A, Gas / Hydraulic Actuator After the Design Basis 

Accident (DBA) Tests.
153

A Practical Method to Baseline Check Valve UT

Shawn Comstock

True North Consulting, LLC

341 Linda St, New Strawn, KS 66839

Abstract

With the updates of the Pump and Valve Inservice Testing programs, a new 

requirement is being implemented to verify check valves in both the open and closed 

positions. Implementers of the new ASME Code for Operation and Maintenance of 

Nuclear Power Plants (ASME OM Code) have found out during this transition that many 

systems were not designed to use traditional methods for check valve close 

verification. This has led to the increased reliance on nonintrusive examinations as 

opposed to the more expensive option of disassembly and inspection.

In many of these cases, the check valves are not in a system application that lends itself 

to the successful implementation of the traditional acoustic method in combination with 

magnetic or eddy current verification. Other options in use include boroscopic 

inspections, radiography, or the most expensive option of disassembly and inspection.

In recent years, a new method has been successfully used as an alternative. The use 

of Ultrasonic Testing (UT) techniques can be used to verify check valve position. This 

method of nonintrusive examination has been used for several years now and is 

established as a low cost, very convenient means of verifying check valve position.

Introduction

With the updates of the Pump and Valve Inservice Testing programs, a new 

requirement is being implemented to verify check valves in both the open and closed 

positions. Implementers of the new ASME Code for Operation and Maintenance of 

Nuclear Power Plants (ASME OM Code) have found out during this transition that many 

systems were not designed to use traditional methods for check valve close verification. 

This has led to the increased reliance on nonintrusive examinations as opposed to the 

more expensive option of disassembly and inspection. 

In many of these cases, the check valves are not in a system application that lends itself 

to the successful implementation of the traditional acoustic method in combination with 

magnetic or eddy current verification. Other options in use include boroscopic 
154

inspections, radiography, or the most expensive option of disassembly and inspection. 

In recent years, a new method has been successfully used as an alternative. The use 

of Ultrasonic Testing (UT) techniques can be used to verify check valve position. This 

method of nonintrusive examination has been used for several years now and is 

established as a low cost, very convenient means of verifying check valve position. 

Check Valve UT Baseline

As with any form of nonintrusive examination, getting started with the valve in a known 

good condition is the key to success for future measurements. This is known as 

establishing a baseline, or a result that sets the standard for comparison with future 

measurements for the purposes of verifying the component is operating acceptably. 

The UT baseline is best established after verifying the valve is in good condition, or after 

the valve has been restored to a good condition. This paper will describe a practical 

method to effectively establish a baseline condition for future UT measurement.

The check valve shown in Figure 1 is an 18” bonnet hung check valve manufactured by 

Borg Warner. 
155

Figure 1 – 18” Borg Warner Bonnet Hung Swing Check
156

Some information can be obtained from the valve nameplate as shown in Figure 2. 

Most importantly, this can be used to confirm the right valve drawing is used for the 

valve of interest.

Figure 2

Information on the nameplate in Figure 2 includes the valve serial number, 

manufacturer’s part number, design pressure, size, weight and material of construction. 
157

Figure 3 shows the inside of the valve body while it is being completely drained of 

water. 

Figure 3 – Inside the Check Valve Body

Figures 4 and 5 show the bonnet hung assembly itself. Notice the nut on the stud 

holding the disc on the swing arm. This is the target area for the UT signal when the 

valve is assembled. If the nut flat is perpendicular to the valve body at the time UT is 

conducted, a nice strong return signal will show up on the UT meter. If it is at an angle 

with respect to the surface of the valve body, this return signal will not be as strong. 

This is normally the case, which means it is very important to know the distance range 

of interest for inspection when shooting through the valve’s body.
158

Figure 4 – Valve Bonnet Hung Assembly Upper

Figure 5 – Valve Bonnet Hung Assembly Lower
159

The physical inspection of the valve concluded that the disc and seat were in good 

shape, but rework was needed to optimize the distance between the disc nut and the 

disc arm. This can be seen in Figure 5. Operating experience with this particular type 

of valve has shown that this area needs to be carefully controlled within specific 

parameters to ensure the valve’s reliability over a long period of time. After this 

maintenance is complete, the valve is ready to be re-assembled. The valve is now 

considered to be in as good or better condition than when it was originally received from 

the factory. 

The process of physically disassembling and inspecting a check valve is the only means 

available to truly assess a check valve’s condition. An important note – it is a process 

that includes disassembly to the degree necessary to measure the wear surfaces of 

mating parts. When this process is complete, record some dimensions in preparation 

for establishing the baseline measurement. Measure the bottom of the valve bonnet to 

the bottom of the disc nut. The measurement does not have to be exact, i.e. estimation 

with a tape measure using the thickness of the valve body and the distance from the 

valve nut to the bottom of the valve body that is perpendicular to the flow stream is 

sufficient. This measurement will establish a target range that should correlate 

approximately with the drawing provided by the manufacturer.

Another set of dimensions can also be useful - the distance from the bottom of the valve 

body bottom to the top of the valve at the bottom of the valve bonnet. A measurement 

through the valve with UT can be used to show there are no obstacles impeding the 

sound path, which may be used as an indication the valve is not stuck open. The 

geometry of the check valve with respect to the ability of the disc to get stuck under the 

top of the valve seat opening should be used with this method. The measurement will 

typically be able to determine if the check valve is in the full open position. The 

detection of a valve in the partial open position using UT, such as when the valve disc 

has dropped on the valve seat far enough to stick under the top of the valve seat 

opening, will depend upon where the measurement can be taken and where the edge of 

the bottom of the valve disc resides when the valve becomes stuck open.

When the valve has been returned to service and the system is filled and vented, a 

baseline reading should be obtained. Do not be disappointed if the distance from the 

bottom of the valve body to the top of the valve at the bottom of the valve bonnet cannot 

be obtained at this point. Any amount of air left in the top of the valve will impede the 

UT sound path. The baseline dimension is from the bottom of the valve body to the disc 

nut. Remember there will be some refraction through the valve metal body and again 

when the system fluid is encountered by the UT sound beam. The optimum 
160

measurement location will typically be slightly downstream from the area directly under 

the disc nut.

The baseline reading from the bottom of the valve body to the bottom of the valve nut 

will correlate to the physical reading taken with the valve disassembled. If your UT 

scope is properly calibrated between successive measurements, the same result can be 

used to demonstrate the valve wear surfaces, such as the hinge pins and bushings, are 

not degrading when the same results are obtained. Obtaining the exact same results 

every time is unlikely, however, and a determination will have to be made when 

successive measurements are trended. If the distance gets shorter in successive 

measurements for example, increased monitoring may be called for to confirm a trend 

towards failure. This will obviously be easier to detect and confirm in time for larger 

valves before a performance problem potentially occurs than for smaller valves.

Other methods can be used for establishing a UT baseline, but disassembly and 

inspection is the most superior method as the only means available to determine the 

check valve’s physical condition. The measurements conducted during the physical 

inspection of the check valve concluded there was about 27” from the bottom of the 

valve body to the top of the valve at the bottom of the valve bonnet. A good vent was 

obtained when this valve was put back into service, which enabled a through valve 

measurement as shown in Figure 6 to demonstrate the valve disc was not stuck open 

impeding the sound path.
161

Figure 6 – UT Test Result From Valve Body Bottom to Bonnet

Measurement of the valve body bottom to disc nut resulted in an average distance of 

12” between the bottom of the valve body and the disc nut with a difference of about ± 

0.375” depending on the orientation of the disc nut as a reflective surface. Figure 7 

shows the results obtained when measurement was conducted.
162

Figure 7 – Valve Body to Disc Nut UT Measurement

The combination of disassembly and inspection with UT for obtaining a baseline 

measurement provides for a confident measurement. The valve drawing in this case 

was found to be to scale with respect to the distance from the bottom of the valve body 

to the disc nut. This is not always the case and experience has shown it is advisable to 

use a physical measurement, even if it is only an external measurement to approximate 

the distances expected using a tape measure. Experience has also shown the 

centerline of valve drawings have typically been representative of the actual. This 

knowledge can be helpful when a baseline method other than disassembly and 

inspection must be utilized.

Conclusion

A UT baseline is a low cost, very convenient means of verifying check valve position. 

Before determining valve position, establishing a baseline that sets the standard for 

comparison with future measurements is a requirement for verifying the component is 

operating acceptably. The valve should be in a known good condition to assure an 

appropriate baseline and success in future measurements.
163

Addressing MOVs in Transition to NFPA 805

Bob Rhodes

Progress Energy-Shearon Harris

New Hill, NC, USA

Mark Bailey

Progress Energy-Shearon Harris

New Hill, NC, USA

Paul Knittle

MPR Associates, Inc.

Alexandria, VA, USA

Abstract

As of December 2010, more than 45 U.S. nuclear plants have submitted letters of intent 

to transition their existing Fire Protection Program to a risk-informed, performancebased program based on National Fire Protection Association Standard 805 (NFPA 

805), “Performance-Based Standard for Fire Protection for Light Water Reactor Electric 

Generating Plants.” NFPA 805 allows the use of performance-based methods, such as 

fire modeling and fire risk evaluations, to demonstrate compliance with the nuclear 

safety performance criteria. The transition to NFPA 805 requires a methodical 

evaluation of safe shutdown scenarios based on fire risks. This process includes 

evaluations of numerous motor operated valves (MOVs) that could potentially be 

impacted due to fire-induced “hot-shorts” (e.g., spurious actuation, motor stall). 

Although the MOV “hot-short” issue is similar to that identified already in generic 

Nuclear Regulatory Commission (NRC) Information Notice (IN) 92-18, “Potential for 

Loss of Remote Shutdown Capability During a Control Room Fire,” the potential scope 

of MOVs impacted may be different based on fire locations and system interfaces. 

As one of the lead plants, Shearon Harris has completed a significant number of 

evaluations of MOVs to support the transition to NFPA 805. This required defining and 

developing a thorough process and establishing appropriate methods and criteria for the 

evaluations. The process applied included a re-evaluation of the safe shutdown list to 

identify susceptible MOVs, applying MOV screening criteria, and performing detailed 

MOV evaluations for motor-stall analyses. 

However, for the NFPA 805 risk evaluations, these evaluations took on a different 

perspective relative to the methods and criteria applied previously. In particular, the 

NFPA 805 evaluations for the safe shutdown equipment included reviews of systems 

not needed for safe shutdown but could impact required systems in ways not previously 

considered. The evaluations had to consider any MOVs (and other energized valves) in 

the non-required systems that, if spuriously operated and challenge the pressure 

boundary, could have an adverse impact such as flow diversion from the credited path, 

loss of water from supply tanks, etc. For example, while Containment Spray is not 

credited for Safe Shutdown, a loss of pressure boundary of certain valves would result 

in a loss of inventory from a tank that was credited in Safe Shutdown (i.e., the Refueling 
164

Water Storage Tank). As a result, the evaluations had to address the pressure 

boundary integrity for a significant number of valves, including many non-active MOVs 

not already addressed in the Plant MOV Program. In many of these cases, additional 

analyses were required to address the pressure boundary integrity issue, including 

establishing analysis criteria. 

The purpose of this paper is to describe the process used, highlight key methods and 

criteria applied, and identify important lessons learned in evaluating MOVs to support 

the transition to an NFPA 805 based Fire Protection Program. 

Introduction

Purpose

Progress Energy’s Shearon Harris Nuclear Plant (HNP) is one of the lead U.S. nuclear 

plants transitioning their existing Fire Protection Program to a risk-informed, 

performance-based program based on National Fire Protection Association Standard 

805 (NFPA 805), “Performance-Based Standard for Fire Protection for Light Water 

Reactor Electric Generating Plants.” To support this transition, HNP has performed a 

significant number of evaluations of motor operated valves (MOVs) that required 

defining and developing a thorough process and establishing appropriate methods and 

criteria for the evaluations. The purpose of this paper is to describe the process used, 

highlight key methods and criteria applied, and identify important lessons learned in 

evaluating MOVs to support the transition to an NFPA 805 based Fire Protection 

Program.

Background

On June 16, 2004, the U.S. Nuclear Regulatory Commission (NRC or the Commission) 

revised Title 10 of the Code of Federal Regulations (10 CFR), Part 50, "Domestic 

Licensing of Production and Utilization Facilities," to include Paragraph 50.48(c). 

Section 48, "Fire Protection," Paragraph 50.48(c), "National Fire Protection Association 

Standard NFPA 805," incorporates by reference NFPA 805, "Performance Based 

Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 2001 

Edition (Reference 1), hereafter referred to as NFPA 805. This change to the NRC's fire 

protection regulations provides licensees with the opportunity to adopt a performancebased fire protection program (FPP) as an alternative to the existing prescriptive, 

deterministic fire protection regulations. Specifically, NFPA 805 allows the use of 

performance-based methods, such as fire modeling and fire risk evaluations, to 

demonstrate compliance with the nuclear safety performance criteria.

As of December 2010, more than 45 U.S. nuclear plants (see Table 1) have submitted 

letters of intent to transition their existing Fire Protection Program to a risk-informed, 

performance-based program based on NFPA 805. As one of the lead plants, HNP has 

implemented a transition from the existing deterministic fire protection licensing basis 

established in accordance with Section 9.5.1 of NUREG-0800, "Standard Review Plan 
165

for the Review of Safety Analysis Reports for Nuclear Power Plants: Light Water 

Reactor Edition" (Reference 2), to a performance-based fire protection program in 

accordance with 10 CFR 50.48(c) that uses risk information, in part, to demonstrate 

compliance with the fire protection and nuclear safety goals, objectives, and 

performance criteria of NFPA 805. 

Before transitioning to NFPA 805, 10 CFR 50.48(c)(3)(ii) states that "the licensee shall 

complete its implementation of the methodology in Chapter 2 of NFPA 805 (including all 

required evaluations and analyses)”. The evaluations and analyses process in Chapter 

2 of NFPA 805 provide for the establishment of the fundamental fire protection program, 

identification of fire area boundaries and fire hazards, determination by analysis that the 

plant design satisfies the performance criteria, identification of the structures, systems 

and components (SSCs) required to achieve the performance criteria, conduct of plant 

change evaluations, establishment of a monitoring program, development of 

documentation, and configuration control. 

The HNP transition to NFPA 805 required a methodical evaluation of safe shutdown 

scenarios based on fire risks. This process included identification and evaluations of 

numerous motor operated valves (MOVs) that could potentially be impacted due to fireinduced “hot-shorts”. Although the MOV “hot-short” issue is similar to that identified 

already in generic NRC Information Notice (IN) 92-18, “Potential for Loss of Remote 

Shutdown Capability During a Control Room Fire,” the potential scope of MOVs 

impacted was different based on fire locations and system interfaces, especially relative 

to potential impact on the valve pressure boundaries. As such, for a successful 

transition to NFPA 805, the potential effect of the fires on the plant MOVs and the 

subsequent consequences (e.g., spurious actuation, motor stall) had to be addressed.

NFPA 805 Requirements and Approach for MOVs

Basic Requirements

NFPA 805 Chapter 1 defines the Nuclear Safety and Radioactive Release performance 

criteria that the fire protection program must meet in order to be in accordance with 

NFPA 805. It states that the fire protection features shall be capable of providing 

reasonable assurance that, in the event of a fire, the plant is not placed in an 

unrecoverable condition. The plant must demonstrate the criteria are met in areas such 

as reactivity control, inventory and pressure control, and decay heat, etc. Chapter 2 of 

NFPA 805 identifies the following steps to be performed:

1. Selection of systems and equipment and their interrelationships necessary to 

achieve the nuclear safety performance criteria above

2. Selection of cables necessary to achieve the nuclear safety performance criteria 

in Chapter 1

3. Identification of the location of nuclear safety equipment and cables

4. Assessment of the ability to achieve the nuclear safety performance criteria given 

a fire in each fire area 
166

In essence, transitioning to an NFPA 805 fire protection program required HNP to 

perform a re-validation of the post-fire Safe Shutdown Analysis (SSA). However, for the 

NFPA 805 risk evaluations, the SSA required an assessment of interconnected systems 

as well that were not credited for safe shutdown, but whose components could still 

affect the shutdown when impacted by a fire. 

In particular, the NFPA 805 includes requirements for assessment of multiple spurious 

operations. NFPA 805 states that the circuits required for the nuclear safety functions 

shall be identified, and that this includes circuits that are required for operation, that 

could prevent the operation, or that result in the mal-operation of the equipment 

identified in the Nuclear Safety Capability Systems and Equipment selection. This 

evaluation is required to consider fire-induced failure modes such as hot shorts 

(external and internal), open circuits, shorts to ground, and to identify circuits that are 

required to support the proper operation of components required to achieve the nuclear 

safety performance criteria, including spurious operation and signals. 

As a result, the HNP NFPA 805 evaluations for the safe shutdown equipment were 

different than that applied in the original safe shutdown equipment selection in that 

systems not needed for safe shutdown could still impact required systems. For 

example, spurious opening of non-active cross-tied system valves could result in 

diversion of flow or inadequate cooling flow. Similarly, these valves could have directed 

flow downstream to another valve that may or may not have been evaluated in the 

existing safe shutdown analysis because its mal-operation had no impact on the 

system. However, a breach of the pressure boundary of that downstream valve could 

then have an impact on the system.

Key Requirements for HNP MOVs

For the HNP MOVs, a re-evaluation of the Safe Shutdown Analysis (SSA) Safe 

Shutdown Equipment List (SSEL)1

In each of these cases, the evaluations had to consider any MOVs (and other energized 

valves) that, if spuriously operated and break the pressure boundary, could have an 

adverse impact such as flow diversion from the credited path, loss of water from supply 

tanks, loss of pressure or net positive suction head (NPSH), etc. As such, the 

evaluations had to consider potential for impacts on the pressure boundary integrity of a 

significant number of valves, including many non-active MOVs which were not 

was required that included the assumption that the 

valves will be subjected to a “hot short” motor stall event as described by Information 

Notice (IN) 92-18 "Potential for Loss of Remote Shutdown Capability During a Control 

Room Fire" (Reference 3). However, the scope of the MOVs that had to be considered 

included system interface valves within all the postulated fire areas, i.e., beyond the 

control room fire scenario identified in IN 92-18. In addition to evaluating the electrical 

susceptibility of these valves to a hot-short as described in IN-92-18, the potential 

impact of a subsequent motor stall on the valve pressure boundary also required 

evaluation.

 1 The SSA SSEL is equivalent to the NFPA 805 Nuclear Safety Capability Systems and Equipment List.
167

previously addressed in the MOV Program for NRC Generic Letter (GL) 89-10 

(Reference 4). 

For compliance with the NFPA 805 requirements, the HNP MOV IN 92-18 analyses 

supporting the SSA re-evaluation had to demonstrate that either of the following 

functions were satisfied when the MOV was subjected to a “hot short”:

• MOV can maintain position, or

• MOV maintains pressure boundary integrity (“passive MOVs”). 

For these MOV IN 92-18 “hot-short” evaluations, it was assumed that the inherent 

protective components (i.e. overload switches, etc) did not function properly and a 

motor stall event was caused. Also it was assumed that the MOV is not protected 

against mechanical overload. 

[Note: Although not covered in this paper, other actions could also be taken to minimize 

fire-induced spurious actuations of the MOVs. In some cases, for example, this can be 

accomplished through procedural changes to de-energize the motors for those MOVs 

not required for normal operation or credited during accidents.]

HNP Approach to Identify Susceptible MOVs

At HNP, the specific steps applied in the re-evaluation of the SSEL to identify 

susceptible MOVs were as follows: 

1. Performed Safe Shutdown Equipment Selection – The potential valves requiring 

evaluation were initially identified based on a systematic review of each system 

required for safe shutdown. This included consideration of the system functional 

and performance requirements, operational alignments, and the following specific 

activities:

a. Reviewed System Flow Diagrams – The flow paths required to satisfy the 

safe shutdown criteria were identified.

b. Identified Active and Boundary valves – For each required flow path, the 

specific valves that could be actuated and their functions were identified, 

including the potential impact of a fire induced spurious actuation on the flow 

path. 

2. Re-Validated Safe Shutdown Analysis to identify success paths – Each flow path 

was either verified as not being impacted by the fire or any spurious valve 

actuations, or potential alternate flow paths were identified and evaluated. For 

active MOVs, this included reviews of circuitry and controls to determine 

mitigating features, if any.

3. Identified any Required (Manual) Action – Based on the potential alternate flow 

paths, reviews were performed to identify potential operational workarounds for 

selected MOVs, especially where the valves had a significant impact in the risk 
168

based evaluations for satisfying the shutdown criteria but were subjected to a 

“hot-short” motor stall. This step included the following activities:

a. Identified any Required (Manual) Action that requires usage of Motor 

operated valves – This evaluation assessed the need to demonstrate the 

capability of a valve to continue functioning and be repositioned with manual 

action assuming either the valve was de-energized or the motor-operator was 

no longer functional. 

b. Perform classical IN 92-18 evaluation to insure that the valve can be manually 

operated - Where needed, this evaluation was performed to demonstrate that 

the valve function with a manual actuation was or was not impacted by the 

occurrence of a “hot-short”, even if the motor actuator portions became unfunctional.

4. Evaluated Valves to Ensure Pressure Boundary is Intact – For each of the MOVs 

identified within the flow paths and at the boundaries, an evaluation of the valve 

capability to maintain pressure boundary integrity was performed assuming the 

fire induced “hot-short” resulted in a motor stall. This process included 

identification of other potential valves not previously required for Safe Shutdown 

and re-consideration of selected boundary isolations. 

NOTE: The following evaluation is different than the original Safe Shutdown 

Equipment Selection, in that systems not needed for Safe Shutdown can 

still impact required systems.

a. Re-Reviewed System Flow Diagrams – Similar to step 1a above, a review 

was performed with a specific purpose to identify Motor Operated, or other 

valves that, if spuriously operated and break the pressure boundary, could 

have an adverse impact such as:

• Flow diversion from the credited path

• Loss of water from supply tanks

• Loss of system pressure (pump NPSH)

• Blockage of Credited Safe Shutdown Walk Paths

• Obscuration of Credited Safe Shutdown Lights.

In these cases, the review extends beyond standard safe shutdown boundary 

until the next isolation point was reached (i.e., closed manual valve, check 

valve, e.g., a non-MOV).

b. Screened Out Non-Susceptible Motor Operated Valves - From the population 

of valves identified in sub step 4a, several screening criteria were applied to 

eliminate consideration of valve designs where the pressure boundary 

integrity would not be challenged by a “hot-short” motor stall. This included 

elimination of the following design types: 
169

• Valves with Hydromotor Actuators

• Butterfly valves

• Other quarter-turn and rotary valves where continued rotation will not 

impact the valve pressure boundary.

In addition, valves with the following characteristics were also determined to 

not require further evaluation and were removed from the scope:

• Valves in “pre-fire rackout” (not normally energized during plant operation)

• Valves in lines sizes where it can be shown that diversion loss does not 

affect flow for credited path (e.g., equal to or less than 3⁄4” in size).

c. Performed stall evaluation of the MOV pressure boundary integrity – An 

evaluation of the MOV valve pressure boundary integrity assuming a IN 92-18 

“hot-short” motor stall was performed as discussed further below. 

HNP MOVs Identified for IN 92-18 Evaluation

Based on the assessment of the MOVS under the NFPA 805 program, HNP identified 

over 190 MOVs that are subject to a motor stall event during safe shut down. As 

identified above, the SSA defines the functional requirements for MOVs subjected to a 

motor stall as:

• the valves must maintain position (i.e., protected from a “hot-short”), or

• the valves only need to maintain pressure boundary integrity under a motor stall 

event. 

Based on the application of the criteria above, HNP concluded that 71 valves required 

further evaluation with regard to demonstrating their capability to maintain pressure 

boundary integrity following an IN 92-18 postulated “hot-short” motor stall condition. 

These valves were all classified as “passive MOVs” that must maintain pressure 

boundary integrity but were not required to remain operable during or following a stall 

event.

The paragraphs below include selected examples demonstrating how of several of the 

MOVs were identified during the SSEL Re-evaluations process.

Example 1: For HNP, the Containment Spray System is not credited for Safe 

Shutdown. However, this system is connected to the Refueling Water Storage Tank 

(RWST) which is required for Safe Shutdown as it supplies water to other systems 

including to the Residual Heat Removal (RHR) and/or Charging System. If certain 

valves in the Containment Spray system experienced a loss of their pressure boundary, 

this could drain water from the RWST. A detailed review of the Containment Spray 

System piping and instrument diagram (P&ID) flow paths identified valves 1CT-25 and 

1CT-26 as potential MOVs whose pressure boundary failure could drain the required 

RWST. The applicable P&ID piping section is shown in Figure 1. Consequently, these 
170

valves were selected for further evaluation to ensure they would maintain pressure 

boundary integrity if subjected to an IN 92-18 postulated “hot-short” motor stall event. 

Example 2: Based on the HNP Safe Shutdown analysis, the Auxiliary Feedwater (AFW) 

System is credited for feedwater flow to a credited Steam Generator. Should the 

Pressure Boundary be breached in an area of the AFW system that is supplying another 

Steam Generator, the flow to the credited steam generator would be reduced, i.e. a 

breach of the pressure boundary will allow the water going to the credited path to be 

diverted to the breached path. The impact would depend on the extent of the breach. 

For example, if sufficient water is still directed to the credited Steam Generator, the 

available volume needed to cool the plant will be reduced, by leaking out of the system. 

However, if the leak is large enough, the needed flow to the credited Steam Generator 

will not be available to supply an adequate Heat Sink for the Reactor Coolant System. 

Six different AFW System MOVs were identified in the P&ID flow paths shown in Figure 

2 whose pressure boundary failure could impact the AFW flows. These valves were 

also selected for further evaluation to ensure pressure boundary integrity would be 

maintained if subjected to a motor stall condition.

Example 3: The HNP Turbine Driven Auxiliary Feedwater (TD AFW) pump is supplied 

steam through a trip and throttle valve (1MS-T). Valve 1MS-T has a motor operator that 

could be subjected to a IN 92-18 “hot-short” motor stall. The concern with this valve is if 

the pressure boundary fails, the area around the TDAFW pump (i.e., in the Reactor 

Auxiliary Building) can become filled with steam and manual actions are not feasible. 

However, this area is designated as a primary walk path on that elevation and is a 

credited walk path for Required Actions (Manual Operator Actions). Consequently, a 

loss of pressure boundary of valve 1MS-T and subsequent steam leaks could block the 

credited walk path and operators might not be able to perform an action, or the action 

may be delayed. As a result, this valve was selected for further evaluation to confirm 

the pressure boundary integrity would be maintained if subjected to a motor stall 

condition. 

MOV Stall Pressure Boundary Evaluations

Approach

For the 71 valves identified as “Passive MOV’s” requiring further evaluation to 

determine the pressure boundary integrity under stall conditions, a three step approach 

was applied. 

STEP 1: Existing HNP documents associated with each valve were reviewed to 

identify valve design information. The design information was used to 

establish common valve groups.
171

STEP 2: The design information and applicable valve evaluations were reviewed to 

identify limiting component capacities for the motor stall events. When 

component capacities were not identified in existing documents, additional 

information was obtained from the valve vendors or supplemented by new 

analyses using plant specific data. The valve component capacities were 

used to evaluate the valve pressure boundary integrity and the potential for 

a non-pressure boundary component (referred to as a “mechanical fuse”)

failure during a motor stall event. In particular, the HNP documents were 

reviewed for each valve to identify the following conditions:

• The motor stall torque and thrust load, 

• The valve weakest link capacities for both the opening and closing 

strokes 

• The pressure boundary capacity for both the opening and closing 

strokes, and

• The mechanical fuse limiting load for both the opening and closing 

strokes, if necessary

STEP 3: The capacity of the pressure boundary component relative to either the 

motor stall load or the mechanical fuse capacity was quantified by 

calculating a margin. The following margin calculations were defined 

relative to the valve capacity: 

1. Stall Margin: The weakest pressure boundary component capacity is 

greater than the maximum stall load. In this case, the margin is 

calculated as: 

2. Mechanical Fuse Margin: The maximum stall load exceeds weak link 

and pressure boundary limiting component capacities, but the weakest 

pressure boundary component capacity is greater than the load at 

which the mechanical fuse component will fail. In this case, the margin 

is calculated as: 

Additionally, the potential for stem failure and subsequent ejection through 

the packing was evaluated for each valve. 

Figure 3 shows the general evaluation logic applied.

PB Load Limit

(PB Load Limit MaxStallLoad) Margin − =

PB Limit

(PB Limit Mech Fuse Load) Margin LoadLoad − =
172

Criteria

Overall, an MOVs’ pressure boundary integrity following a motor stall event was 

considered to be acceptable when: 

• The capacity of the pressure boundary component based on ASME Code 

allowable stress exceeded the maximum stall thrust of the valve, or 

• The capacity of the pressure boundary component based on ASME Code 

allowable stress exceeded the maximum load at which a non-pressure boundary 

component (“mechanical fuse”) failed. 

The criteria defined as applicable to the HNP motor stall events included the following:

• The functional limit and torque switches are postulated to fail during a motor stall 

event and cannot be credited to protect valve components from overload.

• The pressure boundary component capacity is based on the allowable tensile 

stress limit defined as the lesser of the minimum of yield strength or 0.7 times 

the ultimate strength at the process temperature. 

• The non-pressure boundary component capacity is based on the primary stress 

limits defined as the lesser of 1.2 times yield strength or 0.7 times the ultimate 

strength. For shear, the allowable stress is the lesser of 0.72 times yield 

strength or 0.42 time ultimate strength.

• For evaluation of stall conditions, ASME Appendix F can be applied for both 

pressure boundary and non-pressure boundary limits, allowing for an increase in 

the stress from those listed above.

• Motor stall events are outside of the Design Basis of the plant and therefore 

exclude seismic loads.

In addition, “mechanical fuse” criteria were developed and applied. For HNP, a 

“mechanical fuse” was defined as the failure of a non-pressure boundary valve 

component that will eliminate transmission of the actuator load through the valve load 

path. This concept is based on fact that load limiting components (mounting bolts, valve 

stems, etc) can provide inherent protection under motor stall conditions. In the event 

that the stall thrust exceeds the weakest pressure boundary component capacity, an 

evaluation of a mechanical fuse is considered. 

Weak Link and Motor Stall Results

Based on similarities in the valves characteristics, the 71 valves were categorized into 

19 distinct valve groups. This included the following breakdown by valve vendor:

• Anchor/Darling Gate Valves (14 valves in 4 groups)

• Kerotest Globe Valves (4 valves in 1 group)

• Velan Gate and Globe Valves (18 valves in 4 groups)

• Westinghouse Gate Valves (30 valves in 8 groups)
173

• Yarway Globe Valves (4 valves in 1 group)

• Gimpel Globe Valve (1 valve in1 group)

For each valve group, an analysis of the load path during a motor stall condition was 

defined for both the open and close stroke directions based on review of the valve 

configuration and available weak link analyses. At HNP, additional efforts and 

procurement activities were required to obtain complete weak link analyses for the 

Kerotest, Yarway, and Gimpel valves. In particular, the valves in these groups were not 

active safety related valves in the HNP GL 89-10 MOV program, and so weak link 

calculations were not originally procured or required to be prepared by HNP. For some 

of these, the original valve design documents had to be re-constituted by the vendor. 

For others, a combination of vendor provided data and plant walkdown information was 

required to fully evaluate the valve loading conditions and weak link capacities.

In addition, HNP also needed to procure or prepare supplemental analyses for some of 

the Westinghouse, Anchor Darling, and Velan valves. In some of these cases, the 

approach applied in the original vendor supplied weak link analysis focused on load 

limits in only one direction, and/or limited the scope of component capacities evaluated 

based on conservative and worst case load conditions. These conditions, however, did 

not always represent the maximum load condition for the pressure boundary 

components when subjected to a spurious actuation with motor stall. As an example, 

the original vendor weak link analyses for some flex wedge gate valves only limited the 

analysis of the open stroke direction to valve internal components, where the load path 

evaluation assumed the valve disk remains wedged in the valve seats (i.e., the original 

weak link evaluations focused on the connection between the stem and disk). As such, 

they did not evaluate the potential valve bonnet pressure boundary loads assuming the 

stem/disk successfully unwedged and subsequently stroked until the stem reacted 

against the bonnet backseats. 

In general, the existing weak link analyses calculated conservative capacity limits for 

valve components for use in limiting the MOV controlled outputs. However, for the 

NFPA 805 IN 92-18 evaluations, an analysis of all possible load paths in both stroke 

directions was needed with an initial assumption that the non-pressure boundary

components did not fail. Further, many of the existing weak link analyses included 

additional design basis load conditions such as seismic loads and accident temperature 

and pressure conditions. In these cases, the component stress limits were also defined 

based on the Design Basis accident temperature conditions. For the NFPA 805 motor 

stall evaluations, the seismic loads were excluded and in several cases, the pressures 

and temperatures were adjusted to reflect the normal plant operating conditions (as 

allowed by the HNP procedures for the IN 92-18 motor stall conditions). 
174

Maximum possible motor stall load values used in the NFPA analyses were calculated 

based on existing HNP procedural methodology. In particular, the maximum motor stall 

loads were based on the maximum motor torques calculated using maximum voltage 

conditions, vendor motor torque curves, and neglecting temperature heat losses. 

Further, the motor torque was converted to thrust using conservative stem friction 

coefficients (COFs) that either bound the test data available for the valve, or was based 

on a site defined conservative value. In many cases, the maximum stall load that was 

greater than the Limitorque actuator ratings.

For several valves where the motor stall load exceeded the pressure boundary load 

capacity, a “mechanical fuse” evaluation was performed. Some mechanical fuse 

capacity calculations existed in the weak link calculations. However, these analyses 

determined a limiting capacity for the component based on an allowable stress typically 

intended to preclude plastic deformation, as opposed to determining the load at which 

the component will fail completely with a high degree of certainty. Therefore, these 

mechanical fuse capacities were adjusted to use an ultimate strength of a material to 

allow determination of load at which the component is likely to fail and prevent further 

load transmission to the pressure boundary, referred to as the mechanical fuse load.

Margin Evaluation Results

The effect of the stall event on the valve was quantified by calculating margin. For initial 

screening purposes, the pressure boundary integrity was considered adequate when 

the stall margin was greater than 10% or the mechanical fuse margin was greater than 

20%. Margins lower than these threshold values were evaluated further on an 

individual valve basis to determine if the level of conservatism included in the evaluation 

is adequate. The following conservatisms were considered when determining if low 

margin was acceptable: 

• The capacity of the pressure boundary component is based on ASME Code 

allowable strengths and Code acceptance criteria that include inherent 

conservatisms and margin. A comparison of actual material data and Code 

prescribed strengths is used to illustrate the conservatisms associated with the 

ASME Code. 

• For the mechanical fuse concept, the failure capacity of the mechanical fuse is 

calculated using the highest reported ultimate material strength identified in open 

literature. This failure point is compared to the pressure boundary component 

capacity based on ASME Code allowable strength. Therefore, when the 

mechanical fuse failure capacity is less than the pressure boundary capacity, it is 

reasonable to conclude that the mechanical fuse component will fail before the 

pressure boundary component. Note that the larger margin of 20% is bounding 

when reported standard deviations in tensile properties are considered for the 

mechanical fuse capacity. 
175

The HNP evaluations of the 71 Passive MOVs subjected to motor stall determined that 

all the valves had positive margin, and therefore, did not require modifications. Of 

these, 13 valves had margin based on use of the mechanical fuse concept. The results 

included the following:

• 56 valves had acceptable pressure boundary stress margin for maximum stall 

thrust in both valve stroke directions (i.e., in excess of the initial screening 

criteria).

• Eleven (11) valves had low margin for maximum stall thrust based on pressure 

boundary capacity.

• Four (4) valves had low margin for mechanical fuse failure based on capscrew 

shear failure.

The valves with the low margins were evaluated further to confirm sufficient 

conservatism existed in the pressure boundary capacity analysis and the ASME Code 

requirements applied. In a couple cases, the analysis concluded that although the valve 

may experience bonnet leakage under the stall conditions, it was not considered a 

compromise of the pressure boundary (i.e., ASME Code Section III Appendix F limits 

applied as allowed by HNP procedures).

The evaluations also addressed the potential for stem failure and full extraction from the 

valve (i.e., beyond the packing). These evaluations determined that full stem extraction 

would not occur with any of the 71 valves. 

Summary and Lessons Learned

To support the NFPA 805 transition, the SSA re-evaluation approach was developed 

and applied by HNP as presented in this paper. This approach identified 71 “passive” 

MOVs at HNP that required pressure boundary evaluations to demonstrate integrity 

when subjected to IN 92-18 “hot-short” motor stall conditions. HNP also developed a 

pressure boundary analysis approach and criteria and applied it to the 71 passive 

MOVs. The results of the pressure boundary analyses confirmed that there is positive 

margin between the limiting pressure boundary based on the allowable stress limits and 

either the maximum stall thrust or the capacity at which some other non-pressure 

boundary component in the load path will fail (referred to as a “mechanical fuse”). The 

latter case was only considered when the maximum stall thrust exceeded the capacity 

of the weakest pressure boundary component. Although some valves had lower 

margins than desired (i.e., below the initial screening limits), the available margins were 

determined to be acceptable based on inherent conservatism in the pressure boundary 

capacities and the applicable ASME Code requirements.

Based on the lead effort at HNP in transitioning to NFPA 805, important lessons have 

been presented regarding the process for identifying MOVs potentially susceptible to 
176

“hot-shorts” per IN 92-18, and for evaluating the MOV pressure boundaries when 

subjected to the motor stall. The key lessons are:

• The NFPA 805 transition requires a different evaluation approach in selecting the 

system boundaries and equipment for evaluation to support the SSA. The main 

difference is the need to consider the potential impact of an IN 92-18 type “hotshort” motor stall on the pressure boundary of non-credited MOVs at the system 

interfaces/boundaries.

• The transition may require detailed evaluation of some MOVs that previously 

were not required for SSA. Some of these valves have limited design basis 

information available to do a complete IN 92-18 motor stall analysis of the 

pressure boundary integrity. Accordingly, new analyses may be required to 

address pressure boundary integrity.

• Some of the existing weak link calculations prepared for MOVs in the GL 89-10 

MOV Program do not cover the analysis load path components and conditions 

required to fully assess the pressure boundary integrity for the IN 92-18 motor 

stall analysis. As a result, interactions with the valve vendor may be required to 

obtain the necessary information or analyses.

• In some cases, the valve vendors may need to reconstitute the design basis 

information, or plant walkdowns may be required to obtain necessary valve 

information to complete the IN 92-18 motor stall evaluation. 

• The “mechanical fuse” capacity calculation requires re-defining the limiting 

capacity for the component based on determining the load at which the 

component will fail completely with a high degree of certainty that it will prevent 

further load transmission. 

References

1. National Fire Protection Association (NFPA) Standard 805, "Performance Based 

Standard for Fire Protection for Light Water Reactor Electric Generating Plants," 

2001 Edition.

2. NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants: Light Water Reactor Edition."

3. NRC Information Notice (IN) 92-18 "Potential for Loss of Remote Shutdown 

Capability During a Control Room Fire."

4. NRC Generic Letter (GL) 89-10, "Safety-Related Motor-Operated Valve Testing 

and Surveillance."
177

Annex A

Tables and Figures

Table 1: Plants with letters of intent to adopt NFPA 805

Plant Name Date submitted Reactor type Owner/ Operator

Arkansas Nuclear 1/2 11/2/2005 PWR Entergy Nuclear

Beaver Valley 1/2 12/22/2005 PWR First Energy Co.

Browns Ferry 1/2/3 3/4/2009 BWR Tennesse Valley Authority

Brunswick 1/2 6/10/2005 BWR Progress Energy 

Callaway 12/2/2005 PWR Ameren UE 

Calvert Cliffs 1/2 4/17/2006 PWR Constellation Energy

Catawba 1/2 2/28/2005 PWR Duke Energy

Cooper 12/22/2005 BWR Nebraska Public Power District 

Crystal River 3 6/10/2005 PWR Progress Energy 

Davis Besse 1 12/22/2005 PWR First Energy Co.

D. C. Cook 1/2 12/28/2005 PWR Indiana/Michigan Power

Diablo Canyon 1/2 12/29/2005 PWR Pacific Gas & Electric 

Duane Arnold 11/30/2005 BWR Florida Power & Light

Fort Calhoun 6/9/2008 PWR Omaha Public Power District 

Ginna 12/19/2005 PWR Constellation Energy

Kewaunee 7/21/2008 PWR Dominion Generation 

McGuire 1/2 2/28/2005 PWR Duke Energy

Nine Mile Point 1/2 4/17/2006 BWR Constellation Energy

Oconee 1/2/3 (Note 1) 2/28/2005 PWR Duke Energy

Palisades 11/30/2005 PWR Entergy Nuclear

Point Beach 1/2 11/30/2005 PWR Florida Power & Light

Prairie Island 1/2 11/30/2005 PWR Nuclear Management Co.

Robinson 2 6/10/2005 PWR Progress Energy 

Saint Lucie 1/2 12/22/2005 PWR Florida Power & Light

San Onofre 2/3 3/28/2008 PWR PSE&G Nuclear 

Shearon Harris 1 (Note 1) 6/10/2005 PWR Progress Energy 

Summer 10/19/2006 PWR South Carolina Electric & Gas

Turkey Point 3/4 11/15/2005 PWR Florida Power & Light

Waterford 3 12/21/2005 PWR Entergy Nuclear

Note 1: Shearon Harris and Oconee implementing transition as lead/pilot 

plants.
178

Figure 1 - Containment Spray Valves 1CT-25 and 1-CT26 Selected for IN 92-18 

Evaluation
179

Figure 2 - AFW System MOVs Selected for IN 92-18 Evaluation
180

Figure 3 – MOV Motor Stall Event Evaluation Logic


183

Session 3: New Reactors

Session Chair: Michael Norato, U.S. NRC

185

New Reactors OM Code Pump and Valve Testing Overview

Thomas Ruggiero, PE

Exelon Energy Corporation

Ron Lippy

True North Consulting

Abstract

This abstract describes and discusses a path forward with regard to preparation of an 

American Society of Mechanical Engineers (ASME) Code for Operations and 

Maintenance of Nuclear Power Plants (OM Code) applicable for new reactor plants. 

There have been discussions within the industry regarding the expansion of the 

commercial nuclear power fleet and the ongoing work in new reactor plant design and 

construction. As a result of these discussions, the ASME is evaluating the OM Code for 

completeness, clarity, compatibility, and correctness with regards to the testing of new 

reactor systems and components. Since 2005, the ASME OM Code Committee has 

been evaluating the necessity of revising the OM Code to ensure that adequate 

guidance is provided for the development of testing scope, requirements, methods, and 

acceptance criteria for pumps, valves, and dynamic restraints (snubbers) to ensure that 

the "operational readiness" of these components is adequately provided.

The ASME OM Code considered the lessons learned from operating experience at 

current and past operating nuclear power plants and from research conducted by the 

nuclear industry and regulatory authority to provide for effective Inservice Testing (IST) 

programs to be developed and implemented at new nuclear power plants. These 

lessons learned include the following:

1. Design and qualification of pumps, valves, and dynamic restraints to allow IST 

activities (including sufficient flow testing) to assess the operational readiness of those 

components, and the development of ASME QME-1-2007, “Qualification of Active 

Mechanical Equipment Used in Nuclear Power Plants,” to incorporate lessons learned 

in the qualification of mechanical equipment for nuclear power plants.

2. Insights obtained from the operational performance and testing of Motor-Operated 

Valves (MOVs) that indicate the need for improved activities, such as importance of 

adequate design and qualification, sufficient flow during testing to assess valve 

performance, etc. 
186

3. Application of MOV lessons learned to other Power-Operated Valves (POVs).

4. Provisions for bi-directional testing of all safety-related check valves.

5. Implementation of pre-service and comprehensive pump testing (PST and CPT) 

provisions without the need for Code relief.

6. Consideration of potential adverse flow effects on plant components from flowinduced vibration resulting from hydrodynamic loads and acoustic resonance.

In addition to lessons learned from nuclear power plant operating experience and 

research programs, the ASME OM Code Committee addressed new reactor issues in 

its provisions for IST programs. These new reactor issues included the following:

1. Development of IST program descriptions by Combined Operating License (COL) 

applicants in accordance with Title 10 of the Code of Federal Regulations (10 CFR) Part 

52 with implementation of Design Certification provisions for design, qualification, and 

IST activities.

2. Coordination of PST and Inspections, Tests Analysis, and Acceptance Criteria 

(ITAAC) tests so that testing is performed once for both purposes. 

3. Design, qualification, IST, and inspection activities for squib valves that are much 

larger and represent more significant engineering challenges for new reactors than for 

currently operating plants.

4. Design of plant systems and development of IST programs to minimize the need for 

relief from the ASME OM Code requirements.

5. Design, qualification, PST, and IST activities of non-safety related components within 

the scope of Regulatory Treatment of Non-Safety Systems (RTNSS) that perform 

important to-safety functions.

6. Development and implementation of risk-informed IST programs, including 10 CFR 

50.69 programs, for new reactors.
187

7. Consideration of appropriate Code and standards modifications for design, 

qualification, PST, and IST activities in response to application of software-based digital 

technology in mechanical components (e.g., pumps and valves).

Introduction

This white paper describes and discusses a path forward for the preparation of an 

ASME OM Code applicable for new reactor plants. Advanced reactor designs are not 

currently included in this effort.

As a result of discussions within the nuclear industry on the expansion of the 

commercial nuclear power fleet and ongoing work in new reactor plant design and 

construction, the ASME is evaluating the OM Code for completeness, clarity, 

compatibility and correctness for the testing of new reactor systems and components. 

Since 2005, the ASME OM Code Committee has been evaluating the necessity of 

revising the OM Code to ensure that adequate guidance is provided for the 

development of testing scope, requirements, methods, and acceptance criteria for 

pumps, valves and dynamic restraints (snubbers) to ensure that the "operational 

readiness" of these components is adequately provided.

Lessons learned from nuclear power plant operating experience and research

The ASME OM Code considered the operational experiences from current and past 

operating nuclear power plants and research conducted by the nuclear industry and 

regulatory authority to develop effective IST programs for new nuclear power plants. 

These lessons learned include the following:

1. Design and qualification of pumps, valves, and dynamic restraints to allow IST 

activities (including sufficient flow testing) to assess the operational readiness of 

those components, and development of ASME QME-1-2007 to incorporate 

lessons learned in the qualification of mechanical equipment for nuclear power 

plants.

2. Insights obtained from the operational performance and testing of MOVs that 

indicate the need for improved activities, such as importance of adequate design 

and qualification, sufficient flow during testing to assess valve performance, 

consideration of performance parameters (including valve disc and stem friction 

coefficients, reduced voltage, elevated temperature, and load sensitive behavior), 

use of adequate diagnostic instrumentation to allow proper evaluation and setup, 

improved maintenance and personnel training, monitoring of potential motor 

magnesium rotor degradation, and justification for motor control center testing.
188

3. Application of MOV lessons learned to other POVs.

4. Provisions for bi-directional testing of all safety-related check valves.

5. Implementation of PST and CPT provisions without the need for Code relief.

6. Consideration of potential adverse flow effects on plant components from flowinduced vibration resulting from hydrodynamic loads and acoustic resonance

New Reactor Issues

In addition to lessons learned from nuclear power plant operating experience and 

research programs, the ASME OM Code Committee addressed new reactor issues in 

its provisions for IST programs. These new reactor issues included the following:

1. Development of IST program descriptions by combined operating license (COL) 

applicants in accordance with 10 CFR Part 52 with implementation of design 

certification provisions for design, qualification, and IST activities.

2. Coordination of PST and Inspections, Tests Analysis and Acceptance Criteria 

(ITAAC) tests so that testing is performed once for both purposes. For example, 

how do PST requirements fit into the new Part 52 ITAAC closure and 

maintenance process? Under the new Part 52 process, an applicant is required 

to meet OM Code requirements after the 52.103(g) finding is made although it 

would be preferable to complete the PST requirements earlier.

3. Design, qualification, IST, and inspection activities for squib valves that are much 

larger and represent more significant engineering challenges for new reactors 

than for currently operating plants.

4. Design of plant systems and development of IST programs to minimize the need 

for relief from the ASME OM Code requirements.

5. Design, qualification, PST, and IST activities of non-safety related components 

within the scope of Regulatory Treatment of Non-Safety Systems (RTNSS) that 

perform important to-safety functions.

6. Development and implementation of risk-informed IST programs, including 10 

CFR 50.69 programs, for new reactors.

7. Consideration of appropriate Code and standards modifications for design, 

qualification, PST, and IST activities in response to application of software-based 

digital technology in mechanical components (e.g., pumps and valves).
189

Deliverables

The OM Code Standards Committee determined that two deliverables are needed for 

new nuclear plants, a Design Guide and a New Reactor OM Code (NROMC).

The Design Guide will provide guidance for implementing the NROMC and performing 

preoperational and startup testing and periodic IST throughout the new plant life.

The NROMC will update/supplement/replace the existing OM Code so that both the new 

plant designers and the regulators have a more clear vision of IST requirements for new 

reactors.

The NROMC has been developed to remove the code provisions specifically for 

components that were not provided with provisions to permit IST from the OM Code. 

The NROMC requires that all components within IST scope must have provisions to 

permit full IST with no exceptions.

The method of producing the NROMC has been discussed with the following options 

considered:

1. Develop and issue a new OM Code, removing the provisions specifically for 

components that were not provided with provisions to permit IST from the current 

OM Code. This would be the most straightforward method; however, it would 

involve the maintenance of two separate Codes and might require extensive 

ongoing Code committee efforts.

The use of a Code Case would allow the new reactors to incorporate 

"alternatives" to the Code.

2. Develop a mandatory appendix. This may be the quickest method to develop 

Code requirements specific to new reactors. The use of a Mandatory Appendix 

may be acceptable, but would involve significant duplication of the existing Code

sections and subsections.

3. Create a new division within the OM Code similar to the existing divisions of 

several of the ASME Boiler and Pressure Vessel Code Sections. As in 

recommendation #1 above, this would also involve the maintenance of two 

somewhat identical or similar Codes.

4. The fourth option is to revise OM Code Subsection ISTA to include the general 

requirements for both new and existing reactors and to create new Subsections, 

as necessary, to identify specific testing requirements for new reactors. For 

example, Subsections ISTF, ISTG, ISTH and ISTI might be created to identify 
190

pump, valve, snubber and risk-informed testing requirements for the new 

reactors in lieu of Subsections ISTB, ISTC, ISTD and ISTE. This method would 

require minimal change to the existing Code, and does not require that a 

separate Code, Appendix or division be maintained. This is the option that is 

recommended by the Task Group.

Overview of the Changes in the Code for New Plants

Definitions

Pre – 2000 Plant: A nuclear power plant that was issued its construction permit by the 

applicable regulatory authority prior to January 1, 2000.

Post – 2000 Plant: A nuclear power plant that was issued (or will be issued) its 

construction permit, or combined license for construction and operation, by the 

applicable regulatory authority on or following January 1, 2000. 

Changes to Subsection ISTA

Defined Preservice Test Period

The test plan for the preservice test period shall comply with the latest edition and 

addenda of this Section that has been adopted by the regulatory authority 36 months 

prior to the docket date of the Unit’s construction permit, or the edition and addenda of 

the OM Code referenced in the Unit’s COL, as applicable. Alternately, the test plan for 

the preservice test period shall comply with subsequent editions and addenda that have 

been adopted by the regulatory authority. Specific portions of such subsequent editions 

and addenda may be used, provided all related requirements are met. 

Initial Inservice Test Interval

The test plan for the initial inservice test interval shall comply with the latest edition and 

addenda of the Section that have been adopted by the regulatory authority 12 months 

prior to the issuance of the operating license, or 12 months before the date scheduled 

for initial loading of fuel under a Combined License, if applicable. Alternately, the test 

plan for the initial inservice test interval shall comply with subsequent editions and 

addenda that have been adopted by the regulatory authority. Specific portions of such 

subsequent editions and addenda may be used, provided all related requirements are 

met. 
191

Changes to Subsection ISTB

ISTB is now applicable solely to Pre – 2000 Plants

Changes to Subsection ISTC

ISTC 5223 Series Valves in pairs is applicable to pre-2000 or earlier plants

Changes to Subsection ISTE

Table ISTE-5120-1 LSSC Pump Testing Pump groups are applicable to pre-2000 plants 

only

New Subsection ISTF for post-2000 Plants

No Pump Groupings

All Pumps must have full flow test loops, including instrumentation and valves that can 

be throttled

Conclusion

This ASME New Build Effort was viewed to be within the current OM Code Scope as 

listed in ISTA. Option 4 is the preferred option with a Design Guide to assist in the 

implementation.

The location of these products will be determined at a future date, but a structure similar 

to the current documents is desired, e.g. duplication of requirements will be eliminated 

to the extent practical.

1. The Project Team will prepare the Design Guide to address the additional 

design provisions that are needed to help convert New Plant Design Control 

Documents (DCDs) into detailed design documents. 

2. The Project Team will update the OM Code to address operating experience 

and new reactor issues, and also will have a Code Cleanup effort to remove 

the “as practical issues” from the code.

3. RTNSS [Regulatory Treatment of Non-Safety Systems] issues will be 

addressed after these first documents are completed.
192

Comparison of Existing 2009 Edition of OM Code to New Reactor Code

AS PUBLISHED AS PROPOSED

PREFACE PREFACE

Division 1: Section IST — Light-Water Reactor Nuclear 

Power Plants

Subsection ISTA General Requirements

Subsection ISTB Inservice Testing of Pumps

Subsection ISTC Inservice Testing of Valves

Subsection ISTD Preservice and Inservice Examination and 

Testing of Dynamic Restraints (Snubbers)

Subsection ISTE Risk-Informed Inservice Testing of Components

Division 1: Section IST — Light-Water Reactor Nuclear 

Power Plants

Subsection ISTA General Requirements

Subsection ISTB Inservice Testing of Pumps – Pre-2000 Plants1

Subsection ISTC Inservice Testing of Valves

Subsection ISTD Preservice and Inservice Examination and 

Testing of Dynamic Restraints

(Snubbers)

Subsection ISTE Risk-Informed Inservice Testing of 

Components

Subsection ISTF Inservice Testing of Pumps – Post – 2000 

Plants2

1 Pre – 2000 Plant: A nuclear power plant that was issued its’ 

construction permit by the applicable regulatory authority prior to 

January 1, 2000.

2 Post – 2000 Plant: A nuclear power plant that was issued (or 

will be issued) its’ construction permit, or combined license for 

construction and operation, by the applicable regulatory authority 

on or following January 1, 2000.

Subsection ISTA Subsection ISTA

ISTA-1500 Owner’s Responsibilities

The responsibilities of the Owner of the nuclear power plant shall 

include the following:

(a) determination of the appropriate Code Class for each 

component of the plant, identification of the system boundaries for 

each class of components subject to test or examination, and the 

components exempt from testing or examination requirements

(b) design and arrangement of system components to include 

allowance for adequate access and clearances for conduct of the 

tests and examinations

(c) preparation of plans and schedules

ISTA-1500 Owner’s Responsibilities

The responsibilities of the Owner of the nuclear power plant shall 

include the following:

(a) determination of the appropriate Code Class for each 

component of the plant, identification of the system boundaries 

for each class of components subject to test

or examination, and the components exempt from testing or 

examination requirements

(b) design and arrangement of system components to include 

allowance for adequate access and clearances for conduct of the 

tests and examinations. Refer to Nonmandatory Appendix M of 

this Division for guidance.

(c) preparation of plans and schedules

ISTA-3200 Administrative Requirements

(a) IST Plans shall be filed with the regulatory authorities having 

jurisdiction at the plant site.

(b) The selection of components included in the test plan is subject 

to review by the regulatory authorities having jurisdiction at the 

plant site.

(c) Application of the requirements of this Section shall be 

governed by group classification criteria of the regulatory authority 

having jurisdiction at the plant site.

(d) The use of any Code Case is subject to acceptance by the 

regulatory authorities having jurisdiction at the plant site.

ISTA-3200 Administrative Requirements

(a) IST Plans shall be filed with the regulatory authorities having 

jurisdiction at the plant site.

(b) The selection of components included in the test plan is 

subject to review by the regulatory authorities having jurisdiction 

at the plant site.

(c) Application of the requirements of this Section shall be 

governed by group classification criteria of the regulatory 

authority having jurisdiction at the plant site.

(d) The use of any Code Case is subject to acceptance by the 

regulatory authorities having jurisdiction at the plant site.
193

(e) Revisions to a previously approved Code Case may be 

substituted for that Code Case with the acceptance of the 

regulatory authorities having jurisdiction at the plant site.

(f) Tests and examinations shall meet the requirements of the 

edition and addenda of this Section specified in the following 

paragraphs:

(1) Preservice Test Period. The test plan for the preservice test 

period shall comply with the edition and addenda of this Section 

that has been adopted by the

regulatory authority 36 mo prior to the docket date of the unit’s 

construction permit, or subsequent editions and addenda that have 

been adopted by the regulatory authority. Specific portions of such 

subsequent editions and addenda may be used, provided all 

related requirements are met.

(2) Initial Inservice Test Interval. The test plan for the initial 

Inservice test interval shall comply with the edition and addenda of 

the Section that have been adopted by the regulatory authority 12 

mo prior to the issuance of the operating license, or subsequent 

editions and addenda that have been adopted by the regulatory 

authority. Specific portions of such subsequent editions or addenda 

may be used, provided all related requirements are met.

(e) Revisions to a previously approved Code Case may be 

substituted for that Code Case with the acceptance of the 

regulatory authorities having jurisdiction at the plant site.

(f) Tests and examinations shall meet the requirements of the 

edition and addenda of this Section specified in the following 

paragraphs:

 (1) Preservice Test Period – The test plan for the preservice 

test period shall comply with the latest edition and addenda of 

this Section that has been adopted by the regulatory authority 36 

months prior to the docket date of the Unit’s construction permit, 

or the edition and addenda of the OM Code referenced in the 

Unit’s Combined License, as applicable. Alternately, the test plan 

for the preservice test period shall comply with subsequent 

editions and addenda that have been adopted by the regulatory 

authority. Specific portions of such subsequent editions and 

addenda may be used, provided all related requirements are 

met.

 (2) Initial Inservice Test Interval – The test plan for the initial 

Inservice test interval shall comply with the latest edition and 

addenda of the Section that have been adopted by the regulatory 

authority 12 months prior to the issuance of the operating 

license, or 12 months before the date scheduled for initial 

loading of fuel under a Combined License, applicable. 

Alternately, the test plan for the initial Inservice test interval shall 

comply with subsequent editions and addenda that have been 

adopted by the regulatory authority. Specific portions of such 

subsequent editions and addenda may be used, provided all 

related requirements are met.

Subsection ISTB Subsection ISTB

Subsection ISTB

Inservice Testing of Pumps in Light-Water Reactor 

Nuclear

Power Plants

Subsection ISTB

Inservice Testing of Pumps in Light-Water 

Reactor Nuclear

Power Plants – Pre – 2000 Plants1

1 Pre – 2000 Plant: A nuclear power plant that was issued its’ 

construction permit by the applicable regulatory prior to 

January 1, 2000.

Subsection ISTC Subsection ISTC

ISTC-5223 Series Valves in Pairs. If two check valves are in a 

series configuration without provisions to verify individual reverse 

flow closure (e.g., keepfill pressurization valves) and the plant 

safety analysis assumes closure of either valve (but not both), the 

valve pair may be operationally tested closed as a unit. If the plant 

safety analysis assumes that a specific valve or both valves of the 

pair close to perform the safety function(s), the required valve(s) 

shall be tested to demonstrate individual valve closure.

ISTC-5223 Series Valves in Pairs.10 If two check valves are 

in a series configuration without provisions to verify individual 

reverse flow closure (e.g., keepfill pressurization valves) and the 

plant safety analysis assumes closure of either valve (but not 

both), the valve pair may be operationally tested closed as a unit. 

If the plant safety analysis assumes that a specific valve or both 

valves of the pair close to perform the safety function(s), the 

required valve(s) shall be tested to demonstrate individual valve 

closure.

10ISTC – 5223 only applicable to Pre – 2000 Plants whose 

construction permit was issued January 1, 2000 or earlier.
194

Subsection ISTE Subsection ISTE

ISTE-5110 High Safety Significant Pump Testing.

Group A and Group B pumps categorized as HSSCs shall meet all 

requirements of Subsections ISTA and ISTB.

ISTE-5110 High Safety Significant Pump Testing.

Pumps categorized as HSSCs shall meet all requirements of 

Subsections ISTA and ISTB or ISTF.

Subsection ISTE

Table ISTE-5120-1 LSSC Pump Testing

Subsection ISTE

Table ISTE-5120-1 LSSC Pump Testing

Pump Group Group A

Test

Group B

Test

Comprehensive

Test

Group A (routinely 

or continuously 

operated pumps)

6 mo

[Note (1)]

Not 

required

Not required

Group B

(standby pumps)

2 Yr 6 mo

[Note (1)]

Not required

NOTE:

(1) To meet vendor recommendations, pump operation may be 

required more frequently than the specified test frequency.

Pump Group Group A

Test

Group B

Test

Comprehensive

Test

Group A (routinely 

or continuously 

operated pumps)

6 mo

[Note (1)]

Not 

required

Not required

Group B

(standby pumps)

2 Yr 6 mo

[Note (1)]

Not required

NOTE:

(1) To meet vendor recommendations, pump operation 

may be required more frequently than the specified test 

frequency.

(2) This column also applies if using ISTF.

ISTE-5120 Low Safety Significant Pump Testing

(a) Group A and Group B pumps categorized as LSSCs shall meet 

all the requirements of Subsections ISTA and ISTB, except that the 

testing requirements

identified in this paragraph and in Table ISTE 5120-1 may be 

substituted for those in para. ISTB-3400 (Table ISTB-3400-1).

(b) All Group A and Group B LSSC pumps shall receive an initial 

Group A test conducted within ±20% of pump design flow rate as 

soon as practical and no later than the first refueling outage 

following implementation of the RI-IST Program.

(c) Thereafter, all Group A and Group B LSSC pumps shall be 

Group A tested within ±20% of pump design flow rate at least once 

every 5 yr or three refueling outages, whichever is longer.

ISTE-5120 Low Safety Significant Pump Testing

ISTE-5121 Low Safety Significant Pump Testing – Pre – 2000 

Plants1

(a) Group A and Group B pumps categorized as LSSCs shall 

meet all the requirements of Subsections ISTA and ISTB, except 

that the testing requirements identified in this paragraph and in 

Table ISTE 5121-1 may be substituted for those in para. ISTB3400 (Table ISTB-3400-1)

(b) All Group A and Group B LSSC pumps shall receive an initial 

Group A test conducted within +/-20% of pump design flow rate 

as soon as practical and no later than the first refueling outage 

following implementation of the RI-IST Program.

(c) Thereafter, all Group A and Group B LSSC pumps shall be 

Group A tested within +/-20% of pump design flow rate at least 

once every 5 yr or three refueling outages, whichever is longer.

ISTE-5122 Low Safety Significant Pump Testing – Post –

2000 Plants2

(a) Pumps categorized as LSSCs shall meet all the requirements 

of Subsections ISTA and ISTF, except that the testing 

requirements identified in this paragraph and in Table ISTE 

5120-1 may be substituted for those in para. ISTF-3400.

(b) All LSSC pumps shall receive an initial test conducted within 

+/-20% of pump design flow rate as soon as practical and no 

later than the first refueling outage following implementation of 

the RI-IST Program.

(c) Thereafter, LSSC pumps shall be tested every 6 months in 

accordance with ISTF and within +/-20% of pump design flow 

rate at least once every 5 yr or three refueling outages, 

whichever is longer.

1

Pre – 2000 Plant: A nuclear power plant that was issued its’ 
195

construction permit by the applicable regulatory authority prior to 

January 1, 2000.

2

Post – 2000 Plant: A nuclear power plant that was issued (or 

will be issued) its’ construction permit, or combined license for 

construction and operation, by the applicable regulatory authority 

on or following January 1, 2000.

ISTE-5130 Maximum Test Interval. ISTE-5130 Maximum Test Interval – Pre – 2000 Plant

Subsection ISTF Subsection ISTF

Subsection ISTB

Inservice Testing of Pumps in Light-Water Reactor 

Nuclear

Power Plants

Subsection ISTF

Inservice Testing of Pumps in Light-Water 

Reactor Nuclear

Power Plants– Post – 2000 Plants1

1

Post – 2000 Plant: A nuclear power plant that was issued (or 

will be issued) its’ construction permit, or combined license for 

construction and operation, by the applicable regulatory on or 

following January 1, 2000.

ISTB-1000 INTRODUCTION

ISTB-1100 Applicability

The requirements of this Subsection apply to certain centrifugal 

and positive displacement pumps that have an emergency power 

source.

ISTF-1000 INTRODUCTION

ISTF-1100 Applicability

The requirements of this Subsection apply to certain centrifugal 

and positive displacement pumps that have an emergency power 

source.

ISTB-1200 Exclusions ISTF-1200 Exclusions

ISTB-1300 Pump Categories

All pumps within the scope of paras. ISTA-1100 and ISTB-1100 

shall be categorized as either a Group A or Group B pump.

ISTF -1300 Owner’s Responsibility

In addition to the requirements of para. ISTA-1500, it is the 

Owner’s responsibility to

(a) include in both the pumps and plant design all necessary 

valving, instrumentation, test loops, required fluid inventory, or 

other provisions that are required to fully comply with the 

requirements of this Subsection. Testing capability shall be 

possible irrespective of plant mode.

(b) identify each pump to be tested in accordance with the rules 

of this Subsection. 

ISTB-2000 SUPPLEMENTAL DEFINITIONS

The following are provided to ensure a uniform understanding of 

selected terms used in this Subsection.

Group A pumps: pumps that are operated continuously or routinely 

during normal operation, cold shutdown, or refueling operations.

Group B pumps: pumps in standby systems that are not operated 

routinely except for testing.

vertical line shaft pump: a vertically suspended pump where the 

pump driver and pump element are connected by a line shaft within 

an enclosed column.

ISTF-2000 SUPPLEMENTAL DEFINITIONS

The following is provided to ensure a uniform understanding of 

selected terms used in this Subsection.

vertical line shaft pump: a vertically suspended pump where the 

pump driver and pump element are connected by a line shaft 

within an enclosed column.

ISTB-3000 GENERAL TESTING REQUIREMENTS

The hydraulic and mechanical condition of a pump relative to a 

previous condition can be determined by attempting to duplicate by 

test a set of reference values. Deviations detected are symptoms of 

changes and, depending upon the degree of deviation, indicate 

need for further tests or corrective action.

 The parameters to be measured during preservice and Inservice 

ISTF-3000 GENERAL TESTING REQUIREMENTS

The hydraulic and mechanical condition of a pump relative to a 

previous condition can be determined by attempting to duplicate 

by test a set of reference values. Deviations detected are 

symptoms of changes and, depending upon the degree of 

deviation, indicate need for further tests or corrective action.

 The parameters to be measured during preservice and 
196

testing are specified in Table ISTB-3000-1. Inservice testing are specified in Table ISTF-3000-1.

NOTE:

(1) For positive displacement pumps, flow rate shall be measured 

or determined, for all other pumps, differential pressure or flow rate 

shall be measured or determined.

Note deleted.

ISTB-3100 Preservice Testing

During the preservice test period or before implementing Inservice 

testing, an initial set of reference values shall be established for 

each pump. These tests shall be conducted under conditions as 

near as practicable to those expected during subsequent Inservice 

testing. Except as specified in para. ISTB-3310, only one 

preservice test is required for each pump. A set of reference values 

shall be established in accordance with para.

ISTB-3300 for each pump required to be tested by this Subsection. 

Preservice testing shall be performed in accordance with the 

requirements of the following paragraphs:

(a) centrifugal pump tests (except vertical line shaft centrifugal 

pumps) in accordance with para. ISTB-5110

(b) vertical line shaft centrifugal pump tests in accordance with 

para. ISTB-5210

(c) positive displacement pump (except reciprocating) tests in 

accordance with para. ISTB-5310

(d) reciprocating positive displacement pump tests in accordance 

with para. ISTB-5310

ISTF-3100 Preservice Testing

During the preservice test period or before implementing 

Inservice testing, an initial set of reference values shall be 

established for each pump. These tests shall be conducted 

under conditions as near as practicable to those expected during 

subsequent Inservice testing. Except as specified in para. ISTF3310, only one preservice test is required for each pump. A set 

of reference values shall be established in accordance with para.

ISTF-3300 for each pump required to be tested by this 

Subsection. Preservice testing shall be performed in accordance 

with the requirements of the following paragraphs:

(a) centrifugal pump tests (except vertical line shaft centrifugal 

pumps) in accordance with para. ISTF-5110

(b) vertical line shaft centrifugal pump tests in accordance with 

para. ISTF-5210

(c) positive displacement pump (except reciprocating) tests in 

accordance with para. ISTF-5310

(d) reciprocating positive displacement pump tests in accordance 

with para. ISTF-5310

ISTB-3200 Inservice Testing

Inservice testing of a pump in accordance with this Subsection 

shall commence when the pump is required to be operable (see 

para. ISTB-1100). Inservice testing shall be performed in 

accordance with the requirements of the following paragraphs:

(a) centrifugal pump tests (except vertical line shaft centrifugal 

pumps) in accordance with para. ISTB-5120

(b) vertical line shaft centrifugal pump tests in accordance with 

para. ISTB-5220

(c) positive displacement pump (except reciprocating) tests in 

accordance with para. ISTB-5320

(d) reciprocating positive displacement pump tests in accordance 

with para. ISTB-5320

ISTF-3200 Inservice Testing

Inservice testing of a pump in accordance with this Subsection 

shall commence when the pump is required to be operable (see 

para. ISTF-1100). Inservice testing shall be performed in 

accordance with the requirements of the following paragraphs:

(a) centrifugal pump tests (except vertical line shaft centrifugal 

pumps) in accordance with para. ISTF-5120

(b) vertical line shaft centrifugal pump tests in accordance with 

para. ISTF-5220

(c) positive displacement pump (except reciprocating) tests in 

accordance with para. ISTF-5320

(d) reciprocating positive displacement pump tests in accordance 

with para. ISTF-5320

ISTB-3300 Reference Values

Reference values shall be obtained as follows:

(a) Initial reference values shall be determined from the results of 

testing meeting the requirements of para.

ISTB-3100, Preservice Testing, or from the results of the first 

Inservice test.

(b) New or additional reference values shall be established as 

required by para. ISTB-3310 or ISTB-3320, or subpara. ISTB6200(c).

ISTF-3300 Reference Values

Reference values shall be obtained as follows:

(a) Initial reference values shall be determined from the results of 

testing meeting the requirements of para.

ISTF-3100, Preservice Testing, or from the results of the first 

Inservice test.

(b) New or additional reference values shall be established as 

required by para. ISTF-3310 or ISTF-3320, or subpara. ISTF6200(c).
197

(c) Reference values shall be established only when the pump is 

known to be operating acceptably.

(d) Reference values shall be established at a point(s) of operation 

(reference point) readily duplicated during subsequent tests.

(e) Reference values shall be established in a region(s) of relatively 

stable pump flow.

(1) Reference values shall be established within ±20% of pump 

design flow rate for the comprehensive test.

(2) Reference values shall be established within ±20% of pump 

design flow for the Group A and Group B tests, if practicable. If not 

practicable, the reference point flow rate shall be established at the 

highest practical flow rate.

(f) All subsequent test results shall be compared to these initial 

reference values or to new reference values established in 

accordance with para. ISTB-3310 or ISTB-3320, or subpara. ISTB6200(c).

(g) Related conditions that can significantly influence the 

measurement or determination of the reference value shall be 

analyzed in accordance with para. ISTB-6400.

(c) Reference values shall be established only when the pump is 

known to be operating acceptably.

(d) Reference values shall be established at a point(s) of 

operation (reference point) readily duplicated during subsequent 

tests.

(e) Reference values shall be established in a region(s) of 

relatively stable pump flow.

(1) Reference values shall be established within ±20% of pump 

design flow rate for the Inservice test.

(2) Reference values shall be established within ±20% of pump 

design flow.

(f) All subsequent test results shall be compared to these initial 

reference values or to new reference values established in 

accordance with para. ISTF-3310 or ISTF-3320, or subpara. 

ISTF-6200(c).

(g) Related conditions that can significantly influence the 

measurement or determination of the reference value shall be 

analyzed in accordance with para. ISTF-6400.

ISTB-3310 Effect of Pump Replacement, Repair, and 

Maintenance on Reference Values. When a reference value or 

set of values may have been affected by repair,

replacement, or routine servicing of a pump, a new reference value 

or set of values shall be determined in accordance with para. ISTB3300, or the previous value reconfirmed by a comprehensive or 

Group A test run before declaring the pump operable. The Owner 

shall determine whether the requirements of para. ISTB-3100, to 

reestablish reference values, apply. Deviations between the 

previous and new set of reference values shall be evaluated, and 

verification that the new values represent acceptable pump 

operation shall be placed in the record of tests (see section ISTB9000).

ISTF-3310 Effect of Pump Replacement, Repair, and 

Maintenance on Reference Values. When a reference value or 

set of values may have been affected by repair,

replacement, or routine servicing of a pump, a new reference 

value or set of values shall be determined in accordance with 

para. ISTF-3300, or the previous value reconfirmed by an 

Inservice test run before declaring the pump operable. The 

Owner shall determine whether the requirements of para. ISTF3100, to reestablish reference values, apply. Deviations between 

the previous and new set of reference values shall be evaluated, 

and verification that the new values represent acceptable pump 

operation shall be placed in the record of tests (see section 

ISTF-9000).

ISTB-3320 Establishment of Additional Set of Reference 

Values. If it is necessary or desirable, for some reason other than 

stated in para. ISTB-3310, to establish an additional set of 

reference values, a Group A or comprehensive test shall be run at 

the conditions of an existing set of reference values and the results 

analyzed. If operation is acceptable per para. ISTB-6200, an 

additional set of reference values may be established as follows:

(a) For centrifugal and vertical line shaft pumps, the additional set 

of reference values shall be determined from the pump curve 

established in para. ISTB-5110 or ISTB-5210, as applicable. 

Vibration acceptance criteria shall be established by a Group A or 

comprehensive test at the new reference point. If vibration data 

was taken at all points used in determining the pump curve, an 

interpolation of the new vibration reference value is acceptable.

(b) For positive displacement pumps, the additional set of reference 

values shall be established per para. ISTB-5310.

A test shall be run to verify the new reference values before their 

implementation. Whenever an additional set of reference values is 

established, the reasons for so doing shall be justified and 

documented in the record of tests (see section ISTB-9000). The 

requirements of para. ISTB-3300 apply.

ISTF-3320 Establishment of Additional Set of Reference 

Values. If it is necessary or desirable, for some reason other 

than stated in para. ISTF-3310, to establish an additional set of 

reference values, a Group A or comprehensive test shall be run 

at the conditions of an existing set of reference values and the 

results analyzed. If operation is acceptable per para. ISTF-6200, 

an additional set of reference values may be established as

follows:

(a) For centrifugal and vertical line shaft pumps, the additional 

set of reference values shall be determined from the pump curve 

established in para. ISTF-5110 or ISTF-5210, as applicable. 

Vibration acceptance criteria shall be established by an Inservice

test at the new reference point. If vibration data was taken at all 

points used in determining the pump curve, an interpolation of 

the new vibration reference value is acceptable.

(b) For positive displacement pumps, the additional set of 

reference values shall be established per para. ISTF-5310.

A test shall be run to verify the new reference values before their 

implementation. Whenever an additional set of reference values 

is established, the reasons for so doing shall be justified and 

documented in the record of tests (see section ISTF-9000). The 

requirements of para. ISTF-3300 apply.
198

Table deleted.

ISTB-3400 Frequency of Inservice Tests

An Inservice test shall be run on each pump as specified in Table 

ISTB-3400-1.

ISTF-3400 Frequency of Inservice Tests

An Inservice test shall be run on each pump quarterly.

ISTB-3410 Pumps in Regular Use. Group A pumps that are 

operated more frequently than every 3 mo need not be run or 

stopped for a special test, provided the plant records show the 

pump was operated at least once every 3 mo at the reference 

conditions, and the quantities specified were determined, recorded, 

and analyzed per

section ISTB-6000.

ISTF-3410 Pumps in Regular Use. Pumps that are operated 

more frequently than every 3 mo need not be run or stopped for 

a special test, provided the plant records show the pump was 

operated at least once every 3 months at the reference 

conditions, and the quantities specified were determined, 

recorded, and analyzed per section ISTF-6000.

ISTB-3420 Pumps in Systems Out of Service. For a pump in a 

system declared inoperable or not required to be operable, the test 

schedule need not be followed.

Within 3 months before the system is placed in an operable status, 

the pump shall be tested and the test schedule followed in 

accordance with the requirements of this Subsection. Pumps that 

can only be tested during plant operation shall be tested within 1 

week following plant startup.

ISTF-3420 Pumps in Systems Out of Service. For a pump in a 

system declared inoperable or not required to be operable, the 

test schedule need not be followed.

Within 3 months before the system is placed in an operable 

status, the pump shall be tested and the test schedule followed 

in accordance with the requirements of this Subsection. 

ISTB-3430 Pumps Lacking Required Fluid Inventory. Section deleted.

ISTB-3500 Data Collection ISTF-3500 Data Collection

ISTB-3510 General

(a) Accuracy. Instrument accuracy shall be within the limits of Table 

ISTB-3510-1. If a parameter is determined by analytical methods 

instead of measurement, then the

determination shall meet the parameter accuracy requirement of 

Table ISTB-3510-1 (e.g., flow rate determination shall be accurate 

to within ±2% of actual). For

individual analog instruments, the required accuracy is percent of 

full-scale. For digital instruments, the required accuracy is over the 

calibrated range. For a combination of instruments, the required 

accuracy is loop accuracy.

ISTF-3510 General

(a) Accuracy. Instrument accuracy shall be within the limits of 

Table ISTF-3510-1. If a parameter is determined by analytical 

methods instead of measurement, then the

determination shall meet the parameter accuracy requirement of 

Table ISTF -3510-1 (e.g., flow rate determination shall be 

accurate to within ±2% of actual). For

individual analog instruments, the required accuracy is percent 

of full-scale. For digital instruments, the required accuracy is 

over the calibrated range. For a combination of instruments, the 

required accuracy is loop accuracy.
199

(b) Range

(1) The full-scale range of each analog instrument shall be not 

greater than three times the reference value.

(2) Digital instruments shall be selected such that the reference 

value does not exceed 90% of the calibrated range of the 

instrument.

(3) Vibration instruments are excluded from the range requirements 

of subparas. ISTB-3510(b)(1) and ISTB-3510(b)(2).

(c) Instrument Location. The sensor location shall be established 

by the Owner, documented in the plant records (see section ISTB9000), and shall be appropriate for the parameter being measured. 

The same location shall be used for subsequent tests. Instruments 

that are position sensitive shall be either permanently mounted, or 

provision shall be made to duplicate their position during each test.

(d) Fluctuations. Symmetrical damping devices or averaging 

techniques may be used to reduce instrument fluctuations. 

Hydraulic instruments may be damped by using gage snubbers or 

by throttling small valves in instrument lines.

(e) Frequency Response Range. The frequency response range of 

the vibration measuring transducers and their readout system shall 

be from one-third minimum pump

shaft rotational speed to at least 1,000 Hz.

(b) Range

(1) The full-scale range of each analog instrument shall be not 

greater than three times the reference value.

(2) Digital instruments shall be selected such that the reference 

value does not exceed 90% of the calibrated range of the 

instrument.

(3) Vibration instruments are excluded from the range 

requirements of subparas. ISTF -3510(b)(1) and ISTF -

3510(b)(2).

(c) Instrument Location. The sensor location shall be established 

by the Owner, documented in the plant records (see section 

ISTF -9000), and shall be appropriate for the parameter being 

measured. The same location shall be used for subsequent 

tests. Instruments that are position sensitive shall be either 

permanently mounted, or provision shall be made to duplicate 

their position during each test.

(d) Fluctuations. Symmetrical damping devices or averaging 

techniques may be used to reduce instrument fluctuations. 

Hydraulic instruments may be damped by using gage snubbers 

or by throttling small valves in instrument lines.

(e) Frequency Response Range. The frequency response range 

of the vibration measuring transducers and their readout system 

shall be from one-third minimum pump

shaft rotational speed to at least 1,000 Hz.

ISTB-3520 Pressure ISTF-3520 Pressure

ISTB-3530 Rotational Speed. Rotational speed measurements of 

variable speed pumps shall be taken by a method that meets the 

requirements of para. ISTB-3510.

ISTF-3530 Rotational Speed. Rotational speed measurements 

of variable speed pumps shall be taken by a method that meets 

the requirements of para. ISTF-3510.

ISTB-3540 Vibration ISTF-3540 Vibration

ISTB-3550 Flow Rate. When measuring flow rate, a rate or 

quantity meter shall be installed in the pump test circuit. If a meter 

does not indicate the flow rate directly, the record shall include the 

method used to reduce the data. Internal recirculated flow is not 

required to be measured. External recirculated flow is not required 

to be measured if it is not practical to isolate, has a fixed 

resistance, and has been evaluated by the Owner to not have a 

substantial effect on the results of the test.

ISTF-3550 Flow Rate. When measuring flow rate, a rate or 

quantity meter shall be installed in the pump test circuit. If a 

meter does not indicate the flow rate directly, the record shall 

include the method used to reduce the data. Internal recirculated 

flow is not required to be measured. External recirculated flow is 

required to be measured if such flow is present during the design 

function of the pump.

ISTB-4000 TO BE PROVIDED AT A LATER DATE ISTF-4000 TO BE PROVIDED AT A LATER DATE

ISTB-5000 SPECIFIC TESTING REQUIREMENTS

This Subsection defines requirements for Group A, Group B, and 

comprehensive tests. When a Group A test is required, a 

comprehensive test may be substituted. When a Group B test is 

required, a Group A or comprehensive test may be substituted. A 

preservice test may be substituted for any Inservice test.

ISTF-5000 SPECIFIC TESTING REQUIREMENTS

A preservice test may be substituted for any Inservice test.

ISTB-5100 Centrifugal Pumps (Except Vertical Line Shaft 

Centrifugal Pumps)

(a) Duration of Tests

(1) For the Group A test and the comprehensive test, after pump 

conditions are as stable as the system permits, each pump shall be 

run at least 2 min. At the end of this time at least one measurement 

or determination of each of the quantities required by Table ISTB3000-1 shall be made and recorded.

(2) For the Group B test, after pump conditions are stable, at least 

one measurement or determination of the quantity required by 

ISTF-5100 Centrifugal Pumps (Except Vertical Line Shaft 

Centrifugal Pumps)

(a) Duration of Tests

(1) For the Inservice test, after pump conditions are as stable as 

the system permits, each pump shall be run at least 2 min. At the 

end of this time at least one measurement or determination of 

each of the quantities required by Table ISTF-3000-1 shall be 

made and recorded.

(b) Bypass Loops

(1) A bypass test loop may be used for an Inservice test, 
200

Table ISTB-3000-1 shall be made and recorded.

(b) Bypass Loops

(1) A bypass test loop may be used for a Group A test or 

comprehensive test, provided the flow rate through the loop meets 

the requirements as specified in para. ISTB-3300.

(2) A bypass test loop may be used for Group B tests if it is 

designed to meet the pump manufacturer’s operating specifications 

(e.g., flow rate, time limitations) for minimum flow operation.

provided the flow rate through the loop meets the requirements 

as specified in para. ISTF -3300.

ISTB-5110 Preservice Testing. The parameters to be measured 

are specified in Table ISTB-3000-1.

(a) In systems where resistance can be varied, flow rate and 

differential pressure shall be measured at a minimum of five points. 

If practicable, these points shall be from pump minimum flow to at 

least pump design flow. A pump curve shall be established based 

on the measured points. At least one point shall be designated as 

the reference point(s). Data taken at the reference point will be 

used to compare the results of Inservice tests. A pump curve need 

not be established for pumps in systems where resistance cannot 

be varied.

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTF-5110 Preservice Testing. The parameters to be measured 

are specified in Table ISTF-3000-1.

(a)Flow rate and differential pressure shall be measured at a 

minimum of five points. If practicable, these points shall be from 

pump minimum flow to at least pump design flow. A pump curve 

shall be established based on the measured points. At least one 

point shall be designated as the reference point(s). Data taken at 

the reference point will be used to compare the results of 

Inservice tests.

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTB-5120 Inservice Testing ISTF-5120 Inservice Testing

ISTB-5121 Group A Test Procedure. ISTB-5122 Group B 

Test Procedure. 

These Sections deleted.

ISTB-5123 Comprehensive Test Procedure

Comprehensive tests shall be conducted with the pump operating 

at a specified reference point. The test parameters shown in Table 

ISTB-3000-1 shall be determined and recorded as required by this 

paragraph. The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference point 

(±1%) for variable speed drives.

(b) For centrifugal and vertical line shaft pumps, the resistance of 

the system shall be varied until the flow rate equals the reference 

point. The differential pressure shall then be determined and 

compared to its reference value. Alternatively, the flow rate shall be 

varied until the differential pressure equals the reference point and 

the flow rate determined and compared to the reference flow rate 

value.

(c) Where it is not practical to vary system resistance, flow rate and 

pressure shall be determined and compared to their respective 

reference values.

(d) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band (unfiltered). If velocity 

measurements are used, they shall be peak. If displacement 

amplitudes are used, they shall be peak-to-peak.

(e) All deviations from the reference values shall be compared with 

the ranges of Table ISTB-5121-1 and corrective action taken as 

specified in para. ISTB-6200. The vibration measurements shall be 

compared to both the relative and absolute criteria shown in the 

alert and required action ranges of Table ISTB-5121-1. For 

example, if vibration exceeds either 6Vr or 0.7 in./sec (1.7 cm/s), 

the pump is in the required action range.

Inservice tests shall be conducted with the pump operating at a 

specified reference point. The test parameters shown in Table 

ISTF-3000-1 shall be determined and recorded as required by 

this paragraph. The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference 

point (±1%) for variable speed drives.

(b) For centrifugal and vertical line shaft pumps, the resistance of 

the system shall be varied until the flow rate equals the reference 

point. The differential pressure shall then be determined and 

compared to its reference value. Alternatively, the flow rate shall 

be varied until the differential pressure equals the reference point 

and the flow rate determined and compared to the reference flow 

rate value.

(c) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band (unfiltered). If velocity 

measurements are used, they shall be peak. If displacement 

amplitudes are used, they shall be peak-to-peak.

(d) All deviations from the reference values shall be compared 

with the ranges of Table ISTF-5121-1 and corrective action taken 

as specified in para. ISTF -6200. The vibration measurements 

shall be compared to both the relative and absolute criteria 

shown in the alert and required action ranges of Table ISTF -

5121-1. For example, if vibration exceeds either 6Vr or 0.7 

in./sec (1.7 cm/s), the pump is in the required action range.
201

ISTB-5200 Vertical Line Shaft Centrifugal Pumps

(a) Duration of Tests

(1) For the Group A test and the comprehensive test, after pump 

conditions are as stable as the system permits, each pump shall be 

run at least 2 min. At the end of this time at least one measurement 

or determination of each of the quantities required by Table ISTB3000-1 shall be made and recorded.

(2) For the Group B test, after pump conditions are stable, at least 

one measurement or determination of the quantity required by 

Table ISTB-3000-1 shall be made and recorded.

(b) Bypass Loops

(1) A bypass test loop may be used for a Group A test or 

comprehensive test, provided the flow rate through the loop meets 

the requirements as specified in para. ISTB-3300.

(2) A bypass test loop may be used for Group B tests if it is 

designed to meet the pump manufacturer’s operating specifications 

(e.g., flow rate, time limitations) for minimum flow operation.

ISTF-5200 Vertical Line Shaft Centrifugal Pumps

(a) Duration of Tests

For the Inservice test, after pump conditions are as stable as the 

system permits, each pump shall be run at least 2 min. At the 

end of this time at least one measurement or determination of 

each of the quantities required by Table ISTF-3000-1 shall be 

made and recorded.

(b) Bypass Loops

A bypass test loop may be used for an Inservice test, provided 

the flow rate through the loop meets the requirements as 

specified in para. ISTF-3300.

ISTB-5210 Preservice Testing. The parameters to be measured 

are specified in Table ISTB-3000-1.

(a) In systems where resistance can be varied, flow rate and 

differential pressure shall be measured at a minimum of five points. 

If practicable, these points shall be from pump minimum flow to at 

least pump design flow. A pump curve shall be established based 

on the measured points. At least one point shall be designated as 

the reference point(s). Data taken at the reference point will be 

used to compare the results of Inservice tests. A pump curve need 

not be established for pumps in systems where resistance cannot 

be varied.

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTF-5210 Preservice Testing. The parameters to be measured 

are specified in Table ISTF-3000-1.

(a) Flow rate and differential pressure shall be measured at a 

minimum of five points. If practicable, these points shall be from 

pump minimum flow to at least pump design flow. A pump curve 

shall be established based on the measured points. At least one 

point shall be designated as the reference point(s). Data taken at 

the reference point will be used to compare the results of 

Inservice tests. 

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTB-5220 Inservice Testing ISTF-5220 Inservice Testing

ISTB-5221 Group A Test Procedure. ISTB-5222 Group B 

Test Procedure. 

These Sections deleted.
202

ISTB-5223 Comprehensive Test Procedure. Comprehensive 

tests shall be conducted with the pump operating at a specified 

reference point. The test parameters shown in Table ISTB-3000-1 

shall be determined and recorded as required by this paragraph. 

The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference point 

(±1%) for variable speed drives.

(b) The resistance of the system shall be varied until the flow rate 

equals the reference point. The differential pressure shall then be 

determined and compared to its reference value. Alternatively, the 

flow rate shall be varied until the differential pressure equals the 

reference point and the flow rate determined and compared to the 

reference flow rate value.

(c) Where system resistance cannot be varied, flow rate and 

pressure shall be determined and compared to their respective 

reference values.

(d) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band (unfiltered). If velocity 

measurements are used, they shall be peak. If displacement 

amplitudes are used, they shall be peak-to-peak. (See Fig. ISTB5223-1.)

(e) All deviations from the reference values shall be compared with 

the ranges of Table ISTB-5221-1 and corrective action taken as 

specified in para. ISTB-6200. The vibration measurements shall be 

compared to both the relative and absolute criteria shown in the 

alert and required action ranges of Table ISTB-5221-1. For 

example, if vibration exceeds either 6Vr or 0.7 in./sec (1.7 cm/s), 

the pump is in the required action range.

Tests shall be conducted with the pump operating at a specified 

reference point. The test parameters shown in Table ISTF-3000-

1 shall be determined and recorded as required by this 

paragraph. The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference 

point (±1%) for variable speed drives.

(b) The resistance of the system shall be varied until the flow 

rate equals the reference point. The differential pressure shall 

then be determined and compared to its reference value. 

Alternatively, the flow rate shall be varied until the differential 

pressure equals the reference point and the flow rate determined 

and compared to the reference flow rate value.

(c) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band (unfiltered). If velocity 

measurements are used, they shall be peak. If displacement 

amplitudes are used, they shall be peak-to-peak. (See Fig. ISTF5223-1.)

(d) All deviations from the reference values shall be compared 

with the ranges of Table ISTF-5221-1 and corrective action taken 

as specified in para. ISTB-6200. The vibration measurements 

shall be compared to both the relative and absolute criteria 

shown in the alert and required action ranges of Table ISTF -

5221-1. For example, if vibration exceeds either 6Vr or 0.7 

in./sec (1.7 cm/s), the pump is in the required action range.

ISTB-5300 Positive Displacement Pumps

(a) Duration of Tests

(1) For the Group A test and the comprehensive test, after pump 

conditions are as stable as the system permits, each pump shall be 

run at least 2 min. At the end of this time at least one measurement 

ISTF-5300 Positive Displacement Pumps

(a) Duration of Tests

For the Inservice test, after pump conditions are as stable as the 

system permits, each pump shall be run at least 2 min. At the 

end of this time at least one measurement or determination of 
203

or determination of each of the quantities required by Table ISTB3000-1 shall be made and recorded.

(2) For the Group B test, after pump conditions are stable, at least 

one measurement or determination of the quantity required by 

Table ISTB-3000-1 shall be made and recorded.

(b) Bypass Loops. A bypass test loop may be used for a Group A 

test or comprehensive test, provided the flow rate through the loop 

meets the requirements as

specified in para. ISTB-3300. A bypass test loop may be used for 

Group B tests if it is designed to meet the pump manufacturer’s 

operating specifications (e.g., flow rate, time limitations) for 

minimum flow operation.

each of the quantities required by Table ISTF-3000-1 shall be 

made and recorded.

(b) Bypass Loops. A bypass test loop may be used for an 

Inservice test, provided the flow rate through the loop meets the 

requirements as specified in para. ISTF-3300. 

ISTB-5310 Preservice Testing. The parameters to be measured 

are specified in Table ISTB-3000-1.

(a) For positive displacement pumps, reference values shall be 

taken at or near pump design pressure for the parameters specified 

in Table ISTB-3000-1.

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTF-5310 Preservice Testing. The parameters to be measured 

are specified in Table ISTF-3000-1.

(a) For positive displacement pumps, reference values shall be 

taken at or near pump design pressure for the parameters 

specified in Table ISTF-3000-1.

(b) Vibration measurements are only required to be taken at the 

reference point(s).

ISTB-5320 Inservice Testing ISTF-5320 Inservice Testing

ISTB-5321 Group A Test Procedure. ISTB-5322 Group B 

Test Procedure. 

These Sections deleted.

ISTB-5323 Comprehensive Test Procedure. Comprehensive 

tests shall be conducted with the pump operating at a specified 

reference point. The test parameters shown in Table ISTB-3000-1 

shall be determined and recorded as required by this paragraph. 

The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference point 

(±1%) for variable speed drives.

(b) The resistance of the system shall be varied until the discharge 

pressure equals the reference point. The flow rate shall then be 

determined and compared to its reference value.

(c) Where system resistance cannot be varied, flow rate and 

pressure shall be determined and compared to their respective 

reference values.

(d) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band

(unfiltered). If velocity measurements are used, they shall be peak. 

If displacement amplitudes are used, they shall be peak-to-peak.

(e) All deviations from the reference values shall be compared with 

the ranges of Table ISTB-5321-1 or Table ISTB-5321-2, as 

applicable, and corrective action taken as specified in para. ISTB6200. For reciprocating positive displacement pumps, vibration 

measurements shall be compared to the relative criteria shown in 

the alert and required action ranges of Table ISTB-5321-1. For all 

other positive displacement pumps, vibration measurements shall 

be compared to both the relative and absolute criteria shown in the 

alert and required action ranges of Table ISTB-5321-2. For 

example, if vibration exceeds either 6Vr or 0.7 in./sec (1.7 cm/s), 

the pump is in the required action range.

Tests shall be conducted with the pump operating at a specified 

reference point. The test parameters shown in Table ISTF-3000-

1 shall be determined and recorded as required by this 

paragraph. The test shall be conducted as follows:

(a) The pump shall be operated at nominal motor speed for 

constant speed drives or at a speed adjusted to the reference 

point (±1%) for variable speed drives.

(b) The resistance of the system shall be varied until the 

discharge pressure equals the reference point. The flow rate 

shall then be determined and compared to its reference value.

(c) Vibration (displacement or velocity) shall be determined and 

compared with corresponding reference values. Vibration 

measurements are to be broad band

(unfiltered). If velocity measurements are used, they shall be 

peak. If displacement amplitudes are used, they shall be peakto-peak.

(d) All deviations from the reference values shall be compared 

with the ranges of Table ISTF -5321-1 or Table ISTF -5321-2, as 

applicable, and corrective action taken as specified in para. ISTF

-6200. For reciprocating positive displacement pumps, vibration 

measurements shall be compared to the relative criteria shown 

in the alert and required action ranges of Table ISTF -5321-1. 

For all other positive displacement pumps, vibration 

measurements shall be compared to both the relative and 

absolute criteria shown in the alert and required action ranges of 

Table ISTF -5321-2. For example, if vibration exceeds either 6Vr 

or 0.7 in./sec (1.7 cm/s), the pump is in the required action 

range.
204
205

ISTB-6000 MONITORING, ANALYSIS, AND EVALUATION ISTF-6000 MONITORING, ANALYSIS, AND EVALUATION

ISTB-6100 Trending

Test parameters shown in Table ISTB-3000-1, except for fixed 

values, shall be trended.

ISTF-6100 Trending

Test parameters shown in Table ISTF-3000-1, except for fixed 

values, shall be trended.

ISTB-6200 Corrective Action

(a) Alert Range. If the measured test parameter values fall within 

the alert range of Table ISTB-5121-1, Table ISTB-5221-1, Table 

ISTB-5321-1, or Table ISTB-5321-2, as

applicable, the frequency of testing specified in para. ISTB-3400 

shall be doubled until the cause of the deviation is determined and 

the condition is corrected.

(b) Action Range. If the measured test parameter values fall within 

the required action range of Table ISTB-5121-1, Table ISTB-5221-

1, Table ISTB-5321-1, or Table ISTB-5321-2, as applicable, the 

pump shall be declared inoperable until either the cause of the 

deviation has been determined and the condition is corrected, or an 

analysis of the pump is performed and new reference values are 

established in accordance with subpara. ISTB-6200(c).

(c) New Reference Values. In cases where the pump’s test 

parameters are within either the alert or required action ranges of 

Table ISTB-5121-1, Table ISTB-5221-1, Table ISTB-5321-1, or 

Table ISTB-5321-2, as applicable, and the pump’s continued use at 

the changed values is supported by an analysis, a new set of 

reference values may be established. This analysis shall include 

verification of the pump’s operational readiness. The analysis shall 

include both a pump level and a system level evaluation of 

operational readiness, the cause of the change in pump 

performance, and an evaluation of all trends indicated by available 

data. The results of this analysis shall be documented in the record 

of tests (see section ISTB-9000).

ISTF-6200 Corrective Action

(a) Alert Range. If the measured test parameter values fall within 

the alert range of Table ISTF-5121-1, Table ISTF-5221-1, Table 

ISTF-5321-1, or Table ISTF-5321-2, as applicable, the frequency 

of testing specified in para. ISTF-3400 shall be doubled until the 

cause of the deviation is determined and the condition is 

corrected.

(b) Action Range. If the measured test parameter values fall 

within the required action range of Table ISTF-5121-1, Table 

ISTF-5221-1, Table ISTF-5321-1, or Table ISTF-5321-2, as 

applicable, the pump shall be declared inoperable until either the 

cause of the deviation has been determined and the condition is 

corrected, or an analysis of the pump is performed and new 

reference values are established in accordance with subpara. 

ISTF-6200(c).

(c) New Reference Values. In cases where the pump’s test 

parameters are within either the alert or required action ranges of 

Table ISTF-5121-1, Table ISTF-5221-1, Table ISTF-5321-1, or 

Table ISTF-5321-2, as applicable, and the pump’s continued use 

at the changed values is supported by an analysis, a new set of 

reference values may be established. This analysis shall include 

verification of the pump’s operational readiness. The analysis 

shall include both a pump level and a system level evaluation of 

operational readiness, the cause of the change in pump 

performance, and an evaluation of all trends indicated by 

available data. The results of this analysis shall be documented 

in the record of tests (see section ISTF-9000).

ISTB-6300 Systematic Error

When a test shows measured parameter values that fall outside of 

the acceptable range of Table ISTB-5121-1, Table ISTB-5221-1, 

Table ISTB-5321-1, or Table ISTB-5321-2, as applicable, that have 

resulted from an identified systematic error, such as improper 

system lineup or inaccurate instrumentation, the test shall be rerun 

after correcting the error.

ISTF-6300 Systematic Error

When a test shows measured parameter values that fall outside 

of the acceptable range of Table ISTF-5121-1, Table ISTF-5221-

1, Table ISTF-5321-1, or Table ISTF-5321-2, as applicable, that 

have resulted from an identified systematic error, such as 

improper system lineup or inaccurate instrumentation, the test 

shall be rerun after correcting the error.

ISTB-6400 Analysis of Related Conditions

If the reference value of a particular parameter being measured or 

determined can be significantly influenced by other related 

conditions, then these conditions shall be analyzed1 and 

documented in the record of tests (see section ISTB-9000).

ISTF-6400 Analysis of Related Conditions

If the reference value of a particular parameter being measured 

or determined can be significantly influenced by other related 

conditions, then these conditions shall be analyzed1 and 

documented in the record of tests (see section ISTF-9000).
206

ISTB-7000 TO BE PROVIDED AT A LATER DATE ISTF-7000 Reserved

ISTB-8000 TO BE PROVIDED AT A LATER DATE ISTF-8000 Reserved

ISTB-9000 RECORDS AND REPORTS ISTF-9000 RECORDS AND REPORTS

ISTB-9100 Pump Records

The Owner shall maintain a record that shall include the following 

for each pump covered by this Subsection:

(a) the manufacturer and the manufacturer’s model and serial or 

other identification number

(b) a copy or summary of the manufacturer’s acceptance test report 

if available

(c) a copy of the pump manufacturer’s operating limits

ISTF-9100 Pump Records

The Owner shall maintain a record that shall include the 

following for each pump covered by this Subsection:

(a) the manufacturer and the manufacturer’s model and serial or 

other identification number

(b) a copy or summary of the manufacturer’s acceptance test 

report if available

(c) a copy of the pump manufacturer’s operating limits

ISTB-9200 Test Plans

In addition to the requirements of paras. ISTA-3110 and ISTA3160, the test plans and procedures shall include the following:

(a) category of each pump

(b) the hydraulic circuit to be used

(c) the location and type of measurement for the required test 

parameters

(d) the method of determining test parameter values that are not 

directly measured by instrumentation

ISTF-9200 Test Plans

In addition to the requirements of paras. ISTF-3110 and ISTF3160, the test plans and procedures shall include the following:

(a) type of each pump

(b) the hydraulic circuit to be used

(c) the location and type of measurement for the required test 

parameters

(d) the method of determining test parameter values that are not 

directly measured by instrumentation

ISTB-9300 Record of Tests

See para. ISTA-9230.

ISTF-9300 Record of Tests

See para. ISTA-9230.

ISTB-9400 Record of Corrective Action

See para. ISTA-9240.

ISTF-9400 Record of Corrective Action

See para. ISTA-9240.
207

Inservice Testing Program Improvements for New Reactors

Thomas G. Scarbrough*

Component Integrity, Performance, and Testing Branch 2

Division of Engineering

Office of New Reactors

U.S. Nuclear Regulatory Commission

* This paper was prepared by staff of the U.S. Nuclear Regulatory Commission. It may 

present information that does not currently represent an agreed-upon NRC staff 

position. The NRC has neither approved nor disapproved the technical content.

Abstract

The nuclear industry is preparing for the licensing and construction of new nuclear 

power plants in the United States. The U.S. Nuclear Regulatory Commission (NRC) 

reviews information provided by applicants related to inservice testing (IST) programs 

for Design Certifications and Combined Licenses (COLs) under Part 52, “Licenses, 

Certifications, and Approvals for Nuclear Power Plants,” in Title 10 of the Code of 

Federal Regulations (10 CFR Part 52). The NRC discusses the development of IST 

programs for new reactors in Commission papers (including SECY 90-016, 93-087, and 

95-132, and their Staff Requirements Memoranda), and Regulatory Guide 1.206 (June 

2007), “Combined License Applications for Nuclear Power Plants (LWR Edition).” The 

American Society of Mechanical Engineers (ASME) has a program underway to 

develop improved IST provisions for new reactors in the ASME Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code). As part of its review of COL 

applications, the NRC staff is evaluating the descriptions of IST programs provided by 

COL applicants in their Final Safety Analysis Reports, including the incorporation by 

reference of information provided by reactor vendors in support of the NRC review of 

applicable certified designs. In its review, the NRC staff evaluates compliance of the 

IST program description with the ASME OM Code as incorporated by reference in the 

NRC regulations. The staff also evaluates the IST program description for 

consideration of Commission policy on IST programs for new reactors; and lessons 

learned from nuclear power plant operating experience, NRC and industry valve testing 

programs, and design of new nuclear power plant systems and components. This 

paper discusses the NRC staff review of IST program descriptions for new reactors; and 

improvements in IST surveillance activities for new reactors based on industry operating 

experience, testing programs, and new reactor system and component design.

Introduction

The nuclear industry is preparing for the licensing and construction of new nuclear 

power plants in the United States. The U.S. Nuclear Regulatory Commission (NRC) 

reviews information provided by applicants related to inservice testing (IST) programs 
208

for Design Certifications and Combined Licenses (COLs) under Part 52, “Licenses, 

Certifications, and Approvals for Nuclear Power Plants,” in Title 10 of the Code of 

Federal Regulations (10 CFR Part 52). The NRC discusses the development of IST 

programs for new reactors in several Commission papers and a regulatory guide. The 

American Society of Mechanical Engineers (ASME) has a program underway to 

develop improved IST provisions for new reactors in the ASME Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code). As part of its review of COL 

applications, the NRC staff is evaluating the descriptions of IST programs provided by 

COL applicants in their Final Safety Analysis Reports (FSARs), including the 

incorporation by reference of information provided by reactor vendors in support of the 

NRC review of applicable certified designs. 

NRC Regulations

The NRC regulations in 10 CFR Part 52 provide a process for licensing of new nuclear 

power plants in the United States as an alternative to the process described in 10 CFR 

Part 50 “Domestic Licensing of Production and Utilization Facilities.” Part 52 specifies 

rules for (1) Early Site Permits (ESPs), (2) Standard Design Certifications, (3) COLs, (4) 

Standard Design Approvals, and (5) Manufacturing Licenses. It is anticipated that most 

applicants for the construction and licensing of new nuclear power plants will follow the 

process established in 10 CFR Part 52.

The NRC regulations in 10 CFR 52.79(a)(11) require a COL applicant to provide in its 

safety analysis report, at a level sufficient to enable the NRC to reach a final conclusion 

on all safety matters that must be resolved before COL issuance, a description of the 

programs and their implementation necessary to ensure that the systems and 

components meet the requirements of the ASME Boiler & Pressure Vessel Code (BPV 

Code) and the ASME OM Code in accordance with 10 CFR 50.55a. The NRC 

regulations in 10 CFR 52.79(a)(41) require that COL applications include an evaluation 

of the standard plant design against the revision of the NRC NUREG-0800 Standard 

Review Plan (SRP) in effect 6 months before the docket date of the application. In 

addition, the NRC regulations in 10 CFR 52.79(a)(37) require that COL applications 

include information necessary to demonstrate how operating experience insights have 

been incorporated into the plant design. 

The NRC regulations in 10 CFR 50.55a(f)(4)(i) state that inservice tests to verify 

operational readiness of pumps and valves, whose function is required for safety, 

conducted during the initial 120-month interval must comply with the requirements in the 

latest edition and addenda of the ASME OM Code incorporated by reference in 10 CFR 

50.55a(b) on the date 12 months before the date scheduled for initial fuel loading under 

a COL issued per 10 CFR Part 52 or the optional ASME Code cases listed in NRC 

Regulatory Guide (RG) 1.192, “Operation and Maintenance Code Case Acceptability, 

ASME OM Code,” subject to the limitations and modifications listed in Section 50.55a. 
209

Commission Guidance for New Reactor Designs

Commission Papers SECY-90-016, “Evolutionary Light Water Reactor (LWR) 

Certification Issues and Their Relationship to Current Regulatory Requirements,” 

SECY-93-087, “Policy, Technical, and Licensing Issues Pertaining to Evolutionary and 

Advanced Light-Water Reactor (ALWR) Designs,” SECY-94-084, “Policy and Technical 

Issues Associated with the Regulatory Treatment of Non-Safety Systems (RTNSS) in 

Passive Plant Designs,” and SECY-95-132, “Policy and Technical Issues Associated 

with the Regulatory Treatment of Non-Safety Systems (RTNSS) in Passive Plant 

Designs (SECY-94-084),” and their Staff Requirements Memoranda (SRM), discuss 

design aspects related to IST programs for new reactors. In a public memorandum to 

file dated July 24, 1995, the NRC staff consolidated the guidance in Commission 

Papers SECY-94-084 and 95-132, and their respective SRMs. The guidance in these 

Commission papers and the NRC staff memorandum are summarized in the following 

paragraphs.

In SECY-90-016, the NRC staff recommended that the Commission approve four IST 

provisions for safety-related pumps and valves in evolutionary light water reactors:

1. Piping design should incorporate provisions for full flow testing (maximum design 

flow) of pumps and check valves.

2. Designs should incorporate provisions to test motor-operated valves (MOVs) under 

design-basis differential pressure.

3. Check valve testing should incorporate the use of advanced, nonintrusive techniques 

to address degradation and performance characteristics.

4. A program should be established to determine the frequency necessary to 

disassemble and inspect pumps and valves to detect unacceptable degradation that 

cannot be detected through the use of advanced, nonintrusive techniques.

The NRC staff considered these provisions to be necessary to provide adequate 

assurance of the operability of the components.

In the SRM dated June 26, 1990, on SECY-90-016, the Commission approved the 

staff’s position as supplemented in the staff’s response dated April 27, 1990, to the 

Advisory Committee on Reactor Safeguards (ACRS). In that response, the staff agreed 

with the ACRS recommendations to emphasize the provisions of Generic Letter (GL) 

89-10, “Safety-Related Motor-Operated Valve Testing and Surveillance,” for 

evolutionary plants, to resolve check valve testing and surveillance issues, and to 

indicate how these provisions are to be applied to evolutionary plants. The staff also 

agreed that the provisions should permit consideration of proposed alternatives in 

meeting inspection and surveillance requirements. The Commission noted that due 

consideration should be given to the practicality of designing testing capability, 

particularly for large pumps and valves. 
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In SECY-93-087, the NRC staff recommended that the Commission approve the 

position that the recommended IST requirements for evolutionary plants also be 

imposed for passive ALWR plants. The staff noted that additional IST requirements 

may be necessary for certain pumps and valves in passive plant designs. This 

necessity was said to arise because passive safety systems rely heavily on the proper 

operation of certain equipment (such as check valves and depressurization valves) to 

mitigate the effects of accidents and to shut down the reactor. Depressurization valves 

are operated by pyrotechnic (squib) actuators in some new plant designs. In its SRM 

dated July 21, 1993, the Commission did not object to the staff’s position, but noted that 

the staff planned to provide more detail in a future paper.

In SECY-94-084, the NRC staff provided recommendations to the Commission 

pertaining to technical and policy issues related to RTNSS equipment in passive ALWR 

plants, including inservice testing of pumps and valves. In its SRM dated June 30, 

1994, the Commission responded to those recommendations with specific directions to 

the staff. With respect to inservice testing, the Commission directed that the staff clarify 

the recommendations.

In SECY-95-132, the NRC staff provided a revision to the staff recommendations in 

SECY-94-084 based on the Commission’s direction in the SRM dated June 30, 1994. 

With respect to IST activities for passive plant designs, the staff stated in SECY-95-132 

that the “unique passive plant design relies significantly on passive safety systems, but 

also depends on non-safety systems (which are traditionally safety-related systems in 

current light water reactors) to prevent challenges to passive systems. Therefore, the 

reliable performance of individual components is a significant factor in enhancing the 

safety of passive plant designs.” The staff recommended that the following provisions 

be applied to passive ALWR plants to provide assurance of proper component 

performance:

1. Nonsafety-related piping systems with functions that have been identified as important 

by the RTNSS process should be designed to accommodate testing of pumps and 

valves to assure that the components meet their intended functions.

2. To the extent practicable, the passive ALWR piping systems should be designed to 

accommodate the applicable Code requirements for quarterly testing of valves. 

However, design configuration changes to accommodate Code-required quarterly testing 

should be done only if the benefits of the test outweigh the potential risk.

3. The passive system designs should incorporate provisions (a) to permit all critical check 

valves to be tested for performance, to the extent practicable, in both the forward- and 

reverse-flow directions, although the demonstration of a nonsafety direction test need 

not be as rigorous as the corresponding safety direction test; and (b) to verify the 

movement of each check valve’s obturator during inservice testing by observing a direct 

instrumentation indication of the valve position such as a position indicator or by using 

nonintrusive test methods.

4. The passive system designs should incorporate provisions to test safety-related poweroperated valves (POVs) under design-basis differential pressure and flow. Similarly, to 
211

the extent practicable, the design of nonsafety-related piping systems with functions that 

have been identified as important by the RTNSS process should incorporate provisions 

to test POVs in the system to assure that the valves meet their intended functions under 

design-basis conditions.

5. To the extent practicable, provisions should be incorporated in the design to assure that 

MOVs in safety-related systems are capable of recovering from mispositioning.

In its SRM dated June 28, 1995, the Commission approved the recommendations in 

SECY-95-132. With respect to the IST recommendations, the Commission directed that 

the staff clarify the recommendation, and to clearly differentiate the types of testing that 

are to be performed to ensure design-basis capability of safety-related POVs prior to 

installation, prior to initial startup, and during the operational phase (i.e., qualification 

test, preoperational test).

In a public memorandum dated July 24, 1995, the NRC staff provided a consolidated list 

of the approved policy and technical positions associated with RTNSS equipment in 

passive plant designs discussed in SECY- 94-084 and 95-132, and their associated 

SRMs. As directed by the SRM dated June 28, 1995, the staff memorandum clarified 

that the design capability of safety-related POVs should be demonstrated by a 

qualification test prior to installation. Prior to initial startup, the memorandum stated that 

POV capability under design-basis differential pressure and flow should be verified by a 

pre-operational test. During the operational phase, the memorandum stated that POV 

capability under design-basis differential pressure and flow should be verified 

periodically through a program similar to that developed for MOVs in 

GL 89-10. 

IST Operational Program Description

In SECY-02-0067, “Inspections, Tests, Analyses, and Acceptance Criteria for 

Operational Programs (Programmatic ITAAC),” the NRC staff recommended that COL 

applications for nuclear power plants submitted in accordance with the requirements of 

10 CFR Part 52 contain ITAAC for operational programs required by regulations, such 

as training and emergency planning, to the extent that such ITAAC are necessary and 

sufficient to support the finding that the facility has been constructed and will be 

operated in conformity with the license, the provisions of the Atomic Energy Act, and the 

Commission’s rules and regulations. In an SRM dated September 11, 2002, the 

Commission determined that a COL applicant is not required to have ITAAC for an 

operational program for a nuclear power plant licensed under 10 CFR Part 52 with the 

exception of emergency planning. The Commission stated that ITAAC for an 

operational program should not be necessary if the program and its implementation are 

fully described in a COL application and found to be acceptable by the NRC staff at the 

COL stage. The Commission noted that the burden is on the applicant to provide the 

necessary and sufficient programmatic information for approval of the COL without 

ITAAC. 
212

In SECY-04-0032, “Programmatic Information Needed for Approval of a Combined 

License Without Inspections, Tests, Analyses, and Acceptance Criteria,” the NRC staff 

provided recommendations to the Commission regarding the level of programmatic 

information needed for approval of a COL without ITAAC for operational programs. In 

an SRM dated May 14, 2004, the Commission stated that “fully described” for an 

operational program should be understood to mean that the program is clearly and 

sufficiently described in terms for scope and level of detail to allow a reasonable 

assurance finding of acceptability. The Commission noted that required operational 

programs should always be described at a functional level and an increasing level of 

detail where implementation choices could materially and negatively affect the program 

effectiveness and acceptability.

The NRC staff discussed the Commission’s position on operational programs in SECY05-197, “Review of Operational Programs in a Combined License Application and 

General Emergency Planning Inspections, Tests, Analyses, and Acceptance Criteria 

[ITAAC].” In particular, COL applicants should fully describe the IST and MOV testing 

operational programs to avoid the need for ITAAC for the implementation of those 

programs. In SECY-05-0197, the NRC staff defines operational programs for new 

nuclear power plants as programs that are required by regulation, are reviewed by NRC 

staff for acceptability with the results documented in the safety evaluation report, and 

will be verified for implementation by NRC inspectors. The description of the program 

would contain the information necessary for the staff to make a reasonable assurance 

finding on the acceptability of the operational program in the review of a COL 

application. The staff proposed license conditions to provide certainty as to when the 

operational programs are scheduled to be implemented.

With the requirement in 10 CFR 50.55a(f)(4)(i) that the IST program comply with the 

Code edition and addenda incorporated by reference in the NRC regulations 12 months 

before fuel load, a COL applicant may describe the IST and MOV testing operational 

programs based on the ASME Code edition and addenda applicable at the time of 

submittal of the COL application. The COL applicant could then provide milestones for 

development and implementation of the final operational programs. The milestones 

should allow sufficient time for NRC inspections to review development and 

implementation of operational programs prior to relying on equipment to perform their 

safety functions. 

Regulatory Guide 1.206

Regulatory Guide 1.206, “Combined License Applications for Nuclear Power Plants 

(LWR Edition),” provides guidance for COL applicants to use in preparing applications 

to construct and operate their proposed nuclear power plants. As noted in the 

Supplementary Information provided in the Federal Register notice for the revision to 10 

CFR Part 52 (72 FR 49352, 49387), the NRC does not require applicants to evaluate 

their facility against RG 1.206. However, RG 1.206 can provide useful guidance to COL 

applicants in preparing their applications and that use of this guidance will facilitate the 

NRC’s review. Therefore, the staff considers the information in RG 1.206 for 
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operational programs to be addressed in COL applications to be one method of fully 

describing those operational programs consistent with Commission guidance. 

In Section C.I.3.9.6, “Functional Design, Qualification, and Inservice Testing Programs 

for Pumps, Valves, and Dynamic Restraints,” of RG 1.206, the NRC staff provides 

guidance for submittal of COL application information on functional design, qualification, 

and IST programs for pumps, valves, and dynamic restraints in plants not referencing a 

certified design. In Section C.III.3.9.6 of the same title in RG 1.206, the staff provides 

guidance for a COL applicant referencing a certified design. The guidance is intended 

to minimize requests for additional information, streamline the review process, and 

reduce inspection activity. 

In Section C.IV.4, “Operational Programs,” of RG 1.206, the NRC staff summarizes the 

Commission guidance provided in the SECY papers and SRM for the description of 

operational programs by COL applicants. In Section C.IV.9, “Regulatory Treatment of 

Nonsafety Systems,” of RG 1.206, the staff summarizes the Commission guidance 

provided in the SECY papers and SRM on the treatment of RTNSS equipment in new 

reactors.

IST Lessons Learned for New Reactors

Lessons learned from operating experience at operating nuclear power plants and from 

research conducted by the nuclear industry and regulatory authority related to IST 

programs should be applied to new reactors. These IST lessons learned include:

7. Design and qualification of pumps, valves, and dynamic restraints should allow 

IST activities (including sufficient flow testing) to assess the operational 

readiness of those components, and to implement ASME Standard QME-1-2007, 

“Qualification of Active Mechanical Equipment used in Nuclear Power Plants,” 

that incorporates lessons learned for the qualification of mechanical equipment 

for nuclear power plants.

8. Lessons learned from performance and testing of MOVs indicate the need for 

improved activities, such as importance of adequate design and qualification, 

sufficient flow during testing to assess valve performance, consideration of 

performance parameters (including valve disc and stem friction coefficients, 

reduced voltage, elevated temperature, and load sensitive behavior), use of 

adequate diagnostic instrumentation to allow proper evaluation and setup, unique 

direct current motor characteristics, improved maintenance and personnel 

training, monitoring of potential motor magnesium rotor degradation, and 

justification for motor control center testing.

9. MOV lessons learned should be applied in the design, qualification, and testing 

of other POVs. The NRC staff discusses the application of MOV lessons learned 

to other POVs in Regulatory Issue Summary (RIS) 2000-03, “Resolution of 

Generic Safety Issue 158, Performance of Safety-Related Power-Operated 
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Valves Under Design-Basis Conditions,” and Information Notice 96-48, “MotorOperated Valve Performance Issues.” 

10.Provisions for bi-directional testing should be implemented for all safety-related 

check valves. Nuclear power plant operating experience has revealed that 

testing check valves in only the flow direction can result in significant degradation 

(such as a missing valve disc) not being identified by the test.

11.Comprehensive pump testing (CPT) provisions should be implemented for new 

reactors. Pump testing at operating nuclear power plants revealed that current 

plant designs may not provide an effective means to test safety-related pumps 

with sufficient flow to identify potential degradation in pump performance.

12.Potential adverse flow effects on plant components from flow-induced vibration 

resulting from hydrodynamic loads and acoustic resonance should be considered 

in design, qualification, and startup testing of new reactors. Nuclear power plant 

operating experience has revealed that hydrodynamic loads and acoustic 

resonance can damage plant components (including valve actuators) that may 

not be revealed until the component is incapable of performing its design 

function.

IST Improvement Areas

Based on the IST lessons learned from operating reactors and the design of new 

reactors, there are several areas of potential improvement for IST programs for new 

reactors. For example, these IST improvement areas include:

8. Development of effective functional qualification of IST components: The NRC 

staff accepted ASME Standard QME-1-2007 for the functional qualification of 

active mechanical equipment in Revision 3 to RG 1.100, “Seismic Qualification of 

Electric and Active Mechanical Equipment and Functional Qualification of Active 

Mechanical Equipment for Nuclear Power Plants,” with specific provisions. 

Design Certification applicants are addressing functional qualification of IST 

components through applications of ASME QME-1-2007 as accepted in RG 

1.100 (Revision 3) and other similar methods.

9. Performance of full flow testing of pumps: New reactors are being designed to 

allow for sufficient flow testing of pumps to assess their operational readiness in 

response to Commission guidance for new reactors. 

10.Demonstration of MOV design-basis capability and periodic verification: Design 

Certification and COL applicants are addressing MOV design-basis capability 

through application of ASME Standard QME-1-2007 as accepted in RG 1.100 

(Revision 3). COL applicants are addressing periodic verification of MOV designbasis capability to comply with 10 CFR 50.55a(3)(b)(ii) through application of 

ASME OM Code Case OMN-1 (as accepted in RG 1.192) and the Joint Owners 
215

Group (JOG) Program on MOV Periodic Verification (as accepted in an NRC 

safety evaluation report dated September 2006 and its supplement dated 

September 2008).

11.Application of MOV lessons learned to other POVs: COL applicants are applying 

MOV lessons learned to other POVs by the specification of the attributes for 

successful implementation of POV programs provided in RIS 2000-03 in their 

COL FSARs.

12.Performance of bi-directional testing of check valves: New reactors are being 

designed to allow bi-directional testing of check valves in their IST programs in 

response to Commission guidance for new reactors.

13.Design, qualification, IST and inspection activities for pyrotechnic-actuated 

(squib) valves: Design and qualification activities are underway for the AP1000 

squib valves that are much larger and represent more significant engineering 

challenges than the squib valves used at current operating plants. Lessons 

learned from those activities can be applied in developing IST surveillance 

activities to periodically assess the operational readiness of squib valves in new 

reactors.

14.Design of plant systems and development of IST programs to minimize the need 

for relief from the ASME OM Code requirements: Design Certification applicants 

are designing new reactors to minimize the need for relief from the ASME OM 

Code requirements, such as including full flow test lines for safety-related pumps.

15.Surveillance of potential adverse flow effects from flow-induced vibration caused 

by hydrodynamic loads and acoustic resonance: Design Certification applicants 

are addressing potential adverse flow effects from hydrodynamic loads and 

acoustic resonance during the design process with verification through startup 

surveillance programs. COL applicants will address potential adverse effects 

from flow-induced vibration during the preoperational testing programs described 

in the Design Certification and COL supporting documentation.

16.Design, qualification, preservice testing (PST), and IST activities of RTNSS 

components that perform important to-safety functions: New reactors may use 

nonsafety-related components that perform risk-significant functions. 

17.Development and implementation of risk-informed IST programs, including 10 

CFR 50.69 programs, for new reactors: COL applicants may apply risk insights 

in the development and implementation of their IST programs. The ASME has 

developed initial guidance for the treatment of low-risk safety-related components 

in OM Part 29. 
216

18.Consideration of design, qualification, PST, and IST activities for software-based 

digital technology in mechanical components: Component suppliers have 

indicated an interest in applying digital technology in mechanical components. 

ASME Activities

ASME has activities underway to improve the IST programs to be implemented at new 

reactors. Some of these activities include:

ASME Code Case OMN-1, “Alternative Rules for Preservice and Inservice Testing of 

Certain Electric Motor-Operated Valve Assemblies in Light Water Reactor Power 

Plants,” and Code Case OMN-11, “Risk-Informed Testing for Motor-Operated Valves,” 

specify an approach of periodic MOV exercising and diagnostic testing as an alternative 

to the quarterly stroke-time testing provisions in the ASME OM Code editions prior to 

2009. The NRC staff accepted the use of Code Cases OMN-1 and OMN-11 with 

conditions in RG 1.192. The MOV program described in Code Cases OMN-1 and 

OMN-11 can be used to help satisfy the requirement in 10 CFR 50.55a(b)(3)(ii) to 

establish a program to demonstrate the design-basis capability of safety-related MOVs 

on a periodic basis. ASME has incorporated Code Cases OMN-1 and OMN-11 into the 

2009 Edition of the ASME OM Code as Appendix III. 

ASME has prepared a White Paper on its activities to improve the IST provisions for 

new reactors in the ASME OM Code. As part of this effort, ASME is preparing new 

sections in the OM Code to specify IST provisions for new reactors. The first phase of 

this effort will address full flow pump testing for new reactors and specific clarification 

issues. The second phase will address additional lessons learned and new reactor 

issues. When the effort is complete, the NRC staff will consider the ASME OM Code for 

new reactors for incorporation by reference in 10 CFR 50.55a.

ASME is preparing a non-mandatory appendix to the ASME OM Code to provide 

guidance for system and component design to support IST activities for new reactors. 

For example, ASME is considering recommendations for accessibility to perform IST 

activities in the design of new reactors. The proposed non-mandatory appendix also 

addresses recommendations for individual components such as MOVs and other POVs. 

ASME is evaluating the proposed non-mandatory appendix through its ballot process.

NRC Staff Activities

The NRC staff is reviewing IST program descriptions in COL applications and 

referenced Design Certification provisions to determine whether the descriptions satisfy 

the NRC regulations in 10 CFR Part 52 for issuance of a COL for new reactors. The 

NRC staff conducts audits of IST program documentation including valve design and 

procurement specifications as part of the review of COL applications. The NRC staff is 

preparing inspection procedures for ITAAC completion and IST program development 

and implementation.
217

The NRC staff is updating NUREG-1482, “Guidelines for Inservice Testing at Nuclear 

Power Plants,” to provide improved guidance for development and implementation of 

IST programs. The staff plans to incorporate lessons learned from operating 

experience at current nuclear power plants in the updated NUREG. This information 

will also be useful in the development of IST programs at new nuclear power plants.

The NRC staff will continue to participate in ASME activities to update the OM Code for 

new reactors. The staff will evaluate the new OM Code editions and addenda for 

incorporation by reference in 10 CFR 50.55a with any appropriate limitations and 

modifications. The staff is currently working on an update to 10 CFR 50.55a that will 

consider for incorporation by reference the latest ASME Code edition and addenda, 

including sections related to new reactors.

Conclusion

The nuclear industry is preparing for the licensing and construction of new nuclear 

power plants in the United States. ASME has a program underway to develop improved 

IST provisions for new reactors in the ASME OM Code. As part of its review of COL 

applications, the NRC staff is evaluating the descriptions of IST programs provided by 

COL applicants in their FSARs, including the incorporation by reference of applicable 

Design Certification information. In its review, the NRC staff evaluates compliance of 

the IST program description with the ASME OM Code as incorporated by reference in 

the NRC regulations. The staff will evaluate the ASME OM Code editions and addenda 

that include IST provisions for new reactors for incorporation by reference in 10 CFR 

50.55a with any appropriate limitations and modifications. 
218

Design and Baseline Testing of Motor Operated Valves for 

Generation 3+ Nuclear Power Generating Plants

Matthew E. Hobbs

Flowserve Corp., Flow Control Division

Engineering, Product Engineer

Raleigh, North Carolina, USA

919-334-7127

MHobbs@Flowserve.com

Floyd A. Bensinger, PE

Flowserve Corp., Flow Control Division

Business and Product Development, 

Product Portfolio Manager-Nuclear

Raleigh, North Carolina, USA

919-831-3200

FBensinger@Flowserve.com

Richard J. Gradle, PE

Flowserve Corp., Flow Control Division

Engineering, Product Development 

Manager

Raleigh, North Carolina, USA

919-831-3396

RGradle@Flowserve.com

Abstract

Flowserve is currently supplying motor operated valves (MOVs) to Generation 3+ 

nuclear power plants. These valves have been custom designed to meet the design 

and qualification criteria for ASME Section III, Class 1 nuclear service. To support plant 

operations, these valve designs benefit from the lessons learned from US NRC Generic 

Letter (GL) 89-10, “Safety-Related Motor-Operated Valve Testing and Surveillance”, the 

subsequent MOV testing programs, the Joint Owners Group (JOG) MOV Periodic 

Verification Program and ASME QME-1 functional qualifications. 

As a result, some new MOV designs are larger and heavier than typical valves of 

corresponding size and pressure class supplied to existing nuclear power plants.

During the valve functional testing portion of valve manufacturer’s testing, each MOV 

assembly is instrumented to record stem thrust, torque and position, motor operator 

voltage and current draw, and limit switch and torque switch function. The data are 

digitally recorded for further review and acceptance. The baseline data will allow the 

end user to confirm proper MOV installation and setup. The baseline data can also be 
219

compared to future test data to evaluate potential performance degradation during the 

nuclear power plant operation. 

This paper discusses:

• MOV design parameters and design features

• the production testing to establish and record MOV baseline functional data and 

• ASME QME-1-2007 qualification of these MOVs

Introduction

The issuance of the NRC’s GL 89-10, “Safety-Related Motor-Operated Valve Testing 

and Surveillance,” has resulted in substantial changes in the design, manufacture, and 

testing of nuclear valves for suppliers, utilities, and their agents worldwide. As the 

qualification requirements have been refined, the eventual requirements placed much 

emphasis on verification by testing and design validation that safety-related MOVs are 

capable of performing their safety-related functions during all postulated plant 

conditions, throughout the plant life.

Prior to the issuance of GL 89-10, ASME had developed ASME B16.41, “Functional 

Qualification of Power Operated, Safety-Related Valves.” This standard was the first 

standard released to address testing and validation requirements for the power 

operated, safety-related valves under normal and accident conditions. Subsequently, 

ASME developed ASME QME-1-2007 to supersede ASME B16.41. B16.41 based 

functional adequacy on stroke time measurements, an approach that was ultimately 

considered unsatisfactory. The QME-1-2007 standard uses a much more detailed 

approach towards determination of functional adequacy and the extension of 

qualification to valves not tested under design-basis conditions.

As a result of the test methods and data collection methods developed during the 

Electric Power Research Institute (EPRI) and utilities’ GL 89-10 valve testing programs, 

many updates have been incorporated into ASME QME-1-2007. The NRC has 

accepted ASME QME-1-2007 with specific provisions in Revision 3 to Regulatory Guide 

1.100, “Seismic Qualification of Electrical and Active Mechanical Equipment and 

Functional Qualification of Active Mechanical Equipment for Nuclear Power Plants.” 

Today, the testing and validation results of ASME QME-1-2007 provide additional 

assurance of valve functional capabilities when required within the operation of the 

commercial nuclear power plant.

Along with the above, many of the recent valve design specifications for the Generation 

3+ commercial nuclear power plants require baseline testing and baseline data
220

collection of safety-related, power operated valves (POVs) prior to shipment to the new 

power generation plants. These testing and data collections require the addition of 

instrumentation to the valve during testing to measure the operator and valve 

performance characteristics. Additionally, digital recording equipment is utilized to 

record the data and allow its initial review and later comparisons to equivalent data 

collected during plant installation and operation.

US NRC Generic Letter 89-10 Influence on Valve Design

GL 89-10 requested that nuclear power plant licensees verify the design-basis capability 

of their safety-related MOVs through design-basis testing where practicable. The NRC 

issued GL 96-05, “Periodic Verification of Design-Basis Capability of Safety-Related 

Motor-Operated Valves,” to address the long-term testing of MOVs to maintain their 

design-basis capability. The NRC subsequently incorporated a requirement in 10 CFR 

50.55a for the periodic verification of MOV design-basis capability to supplement the 

ASME Code for Operation and Maintenance at Nuclear Power Plants (OM Code). Prior 

to this, valve testing focused on stroke-time testing under static (no load) conditions per 

the ASME Boiler and Pressure Vessel Code and the ASME OM Code.

As a result, high quantities of valve testing and analysis have been performed. Along 

with this, valve performance enhancements and predictability also followed. In order to 

assure the capability of safety-related MOVs (and other POVs) throughout the life of the 

power plant, valve degradation must be better understood and controlled. Design 

enhancements must be validated with testing that takes into account the aging 

parameters such as interaction, corrosion and wear of the sliding surfaces in valves; 

seats, stems, disc guides, etc. If these surfaces and their clearances and edges are not 

design properly or become significantly marred over time, the capability of the valve 

might become unpredictable.

Valve designs have been enhanced and verified to address these concerns. These are 

the designs that are being supplied to the next generation commercial nuclear power 

plants, Generation 3 and 3+.

Design Features to Support Nuclear Island Applications

The Flowserve-Anchor/Darling flex wedge gate valve and Flowserve-Edward T-Pattern 

Globe valve designs have been enhanced for the ASME Section III, class 1, nuclear 

island applications to assure continued predictability and capability. These 

enhancements include:
221

• Flex wedge gate and globe valves with hardfaced disc guide surfaces (see Figures 

2, 3, 4 and 5)

• Controlled hardfaced disc guide slot and body guide clearances to control disc tilt of 

flex wedge gate valve disc (see Figure 2)

• Chamfers on leading edges on the seating and disc guiding surfaces of the disc and 

body seats

• Body/bonnet flanges and gasket seals designed with an option for in-service seal 

weld capabilities 

• Valve “structures” designed to handle the applicable seismic parameters including 

the “hard-rock formations” of some new nuclear power plant locations

• Flowserve-Limitorque motor actuators sized conservatively using a valve seating 

coefficient of friction from the JOG MOV Periodic Verification Test Program data

MOV Design Process

To start, basic dimensions of the valves were used from previous designs such as seat 

and stem diameters. Using this basic information, along with specific closing pressure 

requirements and the JOG recommended friction factors, a required torque and thrust to 

fully seat each valve was developed.

Actuator Control: The electrical control to close each valve was developed based on 

each valve application. Once the gate contacts the seat, if there was sufficient pressure 

in the line to aid in sealing the valve, the control for this assembly would be position 

seated (the electric motor would shut off at a certain stem location). However, if the 

specific application for the valve assembly does not have sufficient line pressure to aid 

in the sealing of the valve, the assembly would need to rely on a calculated amount of 

torque from the actuator to completely seal the valve (the electric motor would shut off 

at a certain torque).

Margin of Uncertainties: The disadvantage of the torque controlled system is the 

uncertainty of the rate of loading that must be added to the required thrust to seat the 

valve. Where a stem friction coefficient based on design-basis conditions (rather than 

static loading conditions) is applied in the MOV sizing calculations, the rate of loading 

for a position controlled system is zero since the actuator will shut off at the same point 

in its travel considering the repeatability of the switch – whereas the rate of loading for a 

torque switch control (based on EPRI testing) is 5.6% bias and 26.4% random. A 

torque switch’s repeatability for this application is an additional 10% while a position 

switch control repeatability is significantly lower at 1%. This amounts to (including 10% 

test equipment accuracy for either control system) a required margin of uncertainty 

when sizing the actuator of an additional 35.5% for torque control and 14% for position 

controlled.
222

Seismic Considerations: Once the actuators were sized appropriately, the enhanced 

features listed above were implemented into the designs. In addition to these features, 

each assembly was designed to simultaneously withstand biaxial seismic accelerations 

of 6 g’s horizontally plus 7 g’s vertically with at least a 10% margin. These seismic 

considerations have an effect on many parts of the valve assembly including flange 

thicknesses, body neck thickness, bolt sizes and circle diameter, gasket and lipseal 

diameter, yoke thickness, and actuator bolting.

Many of the designs are of a higher pressure class and designing for these high seismic 

loads creates a heavier more robust design than the previous lipseal designs.

Materials: The traceability and chemical composition of the raw materials used are also 

a major aspect in the design process. Most of the parts on the valve are treated as a 

safety related item in order to maintain traceability of the product. This includes 

anything from raw material origin to the way in which the part was handled within the 

Flowserve facility. Many of the designs are stainless steel body and bonnets; however, 

any exposed carbon steel parts (such as the yoke and actuator) are coated with a 

sealant to resist corrosion. Packing or gasket materials are mainly made of graphite 

materials with controlled contents of certain elements, such as leachable chloride, 

fluoride, and sulfur.

Additional Features: Furthermore, a unique element to the design is a small undercut in 

the stem located between the packing chamber and actuator. This undercut serves two 

purposes. The first is to provide a location for the mounting of a position indication arm. 

This arm can be used for local visual position indication, or mounted with a magnet for 

the safety related proximity switches for remote valve position indication. The second 

purpose for this undercut is to provide a breaking point in the event of an actuator 

malfunction. In the event of a catastrophic electrical failure and the actuator motor stalls 

(indefinite maximum amount of torque output), the stem will break prior to any other 

piece outside of the packing chamber. Because of the location of the breaking point, 

valve pressure boundary integrity will be maintained since the pressure boundary will 

not be violated, nor will this create any projectiles leaving the valve assembly. 

The remote position indication is a new design from previous generation’s nuclear 

facilities. The previous designs typically used a lever operated limit switch while these 

new designs for the Generation 3+ facilities use a magnetically operated Topworx GO

switch. The advantage to this new design is that it is a completely sealed 303 stainless 

steel switch and target magnet housing with no seals or gaskets to replace over its 

qualified life (60 years). The sensing range can vary, depending on the magnet type, 

from within a 0.250” gap to a 0.100” gap between the magnet and switch. Also, since 
223

there are no arms or levers that are required to move, there is no force required to 

activate the switch. 

Valve Manufacturer Testing Requirements

Typical valve production testing requirements as required by ASME Section III, ASME 

B16.34 and MSS-SP-61 for gate valves include:

• Hydrostatic shell and disc tests

• Packing tests

• Main seat and backseat leakage

Design specifications and manufacturer standards also require valve functional tests to 

verify operational times and proper valve travel under the manufacturer’s test system 

conditions.

The valve design specifications for Generation 3+ nuclear power stations take the 

functional testing requirements further. They require the valve stems be instrumented 

with a strain gauge (see Figure 6, Teledyne Test Services Quick Stem Sensor (QSS)) 

which measures strain in the stem during the functional testing. Flowserve uses a 16 

channel diagnostic computer to measure and record this strain which can then be 

converted to thrust and torque as a function of time. At a frequency of 1000 Hz, the 

computer records the data in addition to:

• Voltage (AC or DC)

• Current

• Torque switch indication

• Actuator control limit switch indication

• Stem position (using a string potentiometer)

• Actuator spring pack displacement (using a Linear Variable Differential 

Transmitter (LVDT))

Using this recorded information, additional parameters can be calculated such as motor 

power, packing thrust/torque, maximum running current, stem thread coefficient, and 

countless other data points of interest. Once both pressurized and non-pressurized 

testing for each individual valve is complete, a report is compiled which contains a 

wealth of baseline data for use in a Generation 3+ nuclear power station.

The baseline data can be used throughout the 60+ year lifespan of the valve for 

comparison to the results of subsequent plant testing evaluating the attributes of the 
224

valve, such as degradation of the wear components. With the ability to understand and 

document these changes to the valve functions, valve capability can be evaluated, and 

maintenance during plant shut-downs can be better planned. 

Refer to Figures 7 and 8 for a typical test setup of functional testing to measure and 

record functional test performance data at Flowserve-Raleigh.

Flowserve ASME QME-1-2007 Qualification of MOVs

ASME QME-1-2007 functional qualification testing is utilized to verify that the safetyrelated, active valves will function during their normal operation and postulated accident 

events. MOV functional qualification tests include:

• Fundamental frequency determination

• Sealing tests to confirm the valve seat and stem sealing capabilities

• Seismic tests to confirm the valve will function during a seismic event (static 

deflection method, see Figure 9)

• Piping End load tests to confirm valve function and seal with applicable pipe loads 

applied to the valve body nozzles

• Flow interruption and functional capability test

In addition to the tests listed above, both pre- and post- test dimensional and visual 

inspections of the wear surfaces will be documented. This information is vitally

important to show the aging effect of the performed tests.

The test valves chosen from the designs in Table 1 are intended to envelope all sizes 

and pressure class ranges. Even where a specific valve design is not tested under 

design-basis conditions, the program will be developed to adequately assure that the 

valve is qualified through analysis combined with reduced qualification testing 

requirements since all the designs within a group are geometrically similar. 

Currently within the MOV assemblies, there are a total of 14 unique designs in the 

qualification program – six of these are intended to be design-basis test qualified valves 

per ASME QME-1-2007. These designs are divided into two geometrically similar 

Groups, A & B, which consist of Flowserve-Anchor/Darling Flexwedge valves and 

Flowserve-Edward Globe valves respectively. The design-basis test qualified valves are 

indicated in Table 1.

The test data will be used to validate and verify the analytical models used to design the 

valve assemblies. The intent is that the data used for the validation and verification will 
225

apply to as wide a range of valve sizes as possible, within the requirements for 

extrapolation of valve qualification provided in the QME-1-2007 standard. This is one 

reason the smallest and largest valves were chosen. The verified and validated 

analytical models are then used to qualify other valves using the provisions in QME-1-

2007. Since Group A contains a large quantity of valve assemblies, an intermediate 

size valve (Size 6 Class 150) was also chosen to be tested to show correlation over a 

larger group of valves.

The three Flowserve-Edward Globe valves are all design-basis test valves, so 

interpolation of test results for these valves is not required.

Table 1: QME-1 Qualification Program

** Indicates test valve

As of this writing, Flowserve had developed the test plan and procedures for the ASME 

QME-1-2007 qualification and was in the initial stages of testing. The symposium 

presentation will provide updates to the Flowserve ASME QME-1-2007 test program. GROUP

A

Size 3 Class 150 Flexwedge manual 

gate

**Size 3 Class 1500 Flexwedge MOV**

Size 4 Class 150 Flexwedge manual 

gate

Size 4 Class 1500 Flexwedge MOV

**Size 6 Class 150 Flexwedge MOV**

Size 6 Class 900 Flexwedge MOV

Size 6 Class 1500 Flexwedge MOV

Size 8 Class 150 Flexwedge MOV

Size 8 Class 1500 Flexwedge MOV

Size 10 Class 1500 Flexwedge MOV

**Size 14 Class 1500 Flexwedge 

MOV**

GROU

PB

**Size 3 Class 1500 Globe MOV**

**Size 4 Class 1500 Globe MOV**

**Size 8 Class 1500 Globe MOV**
226

Conclusion

As a result of the above design enhancement, valve functional tests and functional 

qualifications in accordance with ASME QME-1-2007, the MOVs supplied for the 

nuclear island application of the Generation 3 and 3+ commercial nuclear power plants 

are much better positioned to provide predictable, initial and long-term, validated 

functional reliability than previously supplied MOVs.

Figure 1: Typical Motor Operated Flex Wedge Gate Valve Ready for Shipment to a 

Generation 3+ Nuclear Power Generation Plant.

Figure 2: Flex Wedge Guide Top View with Hardfacing
227

Figure 3: Typical Motor Actuated, Flex Wedge Gate Valve Drawing

Figure 4: Globe Valve Plug Hardfacing
228

Figure 5: Flowserve-Edward Typical Balanced Plug Globe Valve

Figure 6: View of Instrumented Stem with Position Indication Arm
229

Figure 7: Picture of Production Functional Testing of an MOV with Full Instrumentation 

and Test Data Collection.

Figure 8: Additional Picture of Production Functional Testing of MOV
230

Figure 9: Static Deflection Seismic Qualification Setup
231

Nuclear Standards for Small Modular Reactors

James F. Gleason, P.E.

Chairman, IEEE Nuclear Power Engineering Committee, 

Subcommittee 2 Qualification

ARES Corporation

Abstract

Nuclear Standards have been in place for nuclear reactors for almost 40 years. 

Standards Development Organizations (SDOs), including American Nuclear Society 

(ANS), American Society of Mechanical Engineers (ASME), and Institute of Electrical 

and Electronic Engineers (IEEE), work closely together and coordinate over 

international boundaries to ensure current applicability and completeness of nuclear 

standards. For the last five years, IEEE has been collaborating with International 

Electrotechnical Commission (IEC) to harmonize the standards that apply to 

qualification of safety related equipment. This harmonization process recognizes that 

nuclear power plants will be deployed both nationally and internationally and ensures 

that the standards for equipment qualification are universally accepted. The large 

reactor vendors have been key players in the harmonization process to ensure their 

respective designs can be used worldwide. Recently, momentum has increased for 

Small Modular Reactors (SMRs) and the process for equipment qualification will need to 

be incorporated into their designs. This paper discusses some of the standards that will 

likely apply to SMRs and a few of the challenges for the standards organizations and 

reactor suppliers.

Introduction

ANS, ASME, and IEEE, along with other SDOs have been crucial in establishing the 

consensus approach for safety standards used in the construction and operation of 

nuclear power plants. These consensus standards have been in effect for almost 40 

years and the nuclear power industry and nuclear fuel facilities regularly utilize these 

standards during operations. Many of these standards have been endorsed by 

regulators worldwide as applicable to nuclear power plants and nuclear fuel facilities. 

Traditional nuclear suppliers and their regulators are very familiar with these standards 

and regularly participate on the standards committees. A new type of nuclear power 

plant, the SMR, is receiving a lot of attention and has created new opportunities and 

challenges for the nuclear industry. In most cases, industry articles focus on the 

attributes of SMRs, few articles discuss the standards that will likely apply to SMRs, and 
232

even fewer articles discuss the challenges for the standards organizations and reactor 

suppliers. This paper adds to the discussion of standards and challenges for SMRs.

Industry Acceptance of SMRs

Significant design aspects of a nuclear plant are independent of the type of reactor. For 

example, the mechanical, structural, electrical, and Instrumentation and Control (I&C) 

characteristics of all Nuclear Power Plants (NPPs) are similar, as are the treatment of 

quality assurance, environmental qualification, seismic qualification, mechanical design 

and qualification, and the site hazards designs. The most challenging regulatory issues 

for a new reactor design tend to center on core and reactor coolant design, materials 

applications, system configuration, accident analysis, and containment.

The recent earthquake and tsunami in Japan demonstrated the need for NPPs to not 

only survive an earthquake, but to remain safe after a subsequent tsunami. These 

events suggest that the efforts of the standards development organizations are crucial 

to the use of nuclear power because safety standards provide confidence of the 

performance of safety systems and safety equipment. Safety standards consider 

conditions, natural events, performance requirements, acceptance methods, and 

acceptance criteria and ensure safety for the public and workers. The earthquake, 

tsunami, and following accidents illustrate an interdependency among structural, 

electrical, mechanical, instrumentation and control features, and human interface to 

ensure operation of safety systems that needs to be considered for light water reactors 

(LWRs) and SMRs. Standards will need to evaluate the flooding potential following an 

earthquake and re-evaluate the hydrogen explosion scenario since preliminary 

indications signal that hydrogen explosions occurred at Fukushima. Additionally, other 

gases and their explosive and deleterious consequences will have to be addressed at 

SMRs through standards.

The current fleet of light water NPP designs differs from SMRs in important ways. 

SMRs generally incorporate innovative approaches to achieve simplicity, improved 

operational performance, and enhanced safety. Gas‐cooled and liquid metal–cooled 

reactors represent an even greater departure from current designs and consequently 

greater challenges to the application of current regulatory guidance and the consensus 

standards to which they are designed and comply. Light water NPP requirements 

provide assurance of safety system quality, capability, reliability, and redundancy 

commensurate with the safety characteristics of current designs. Since SMR designs 

incorporate passive safety features, enhanced safety margins, slower accident 

response, and improved severe accident performance in comparison to non-SMR 
233

designs, opportunities to simplify and streamline the regulatory process and 

requirements should be considered.

Some aspects of non‐LWR SMR designs could present hazards that need additional 

review to ensure compliance with regulatory requirements. An example of a hazard is 

sodium fires postulated at liquid metal–cooled plants. Theoretically, some non‐LWR

designs are postulated to be unsusceptible to Loss of Coolant Accidents (LOCA) and 

might not require an emergency core cooling system (ECCS).

In 2010, the nuclear community discussed opportunities for SMRs and regulatory 

aspects (Reference 1). A general theme presented was that SMRs were different from 

existing licensed large NPPs and their inherent safety features would result in a less 

difficult licensing process with the applicable regulator. 

The general theme from the community was that the SMR community should provide a 

consensus approach. 

Since much of the design of a nuclear plant is independent of the type of reactor, the 

mechanical, structural, electrical, and I&C characteristics of all NPPs are similar, and 

the treatment of quality assurance, environmental qualification, and design for site 

hazards are addressed in industry standards, the existing consensus approach is 

applicable to SMRs. 

It is widely anticipated that the SMR designs will have a much lower calculated 

probability of core damage and radioactive release than current‐generation plants. 

Smaller core inventory, simpler design with fewer systems, and the inclusion of 

advanced design features such as passive safety systems contribute to this anticipation. 

Attached to these advanced features are requirements from standards as to their 

construction and performance. For instance, in order for some passive features to 

perform as designed, instrumentation, controls, valves, and actuators will need to 

perform safety functions under adverse conditions. The ASME and IEEE qualification 

standards thus are applicable to these features; therefore, it is apparent that ASME and 

IEEE qualification committees will have to ensure that the standards adequately test 

and evaluate passive safety system performance and properly qualify the equipment for 

the expected environments.

External events

SMRs are being proposed for remote locations generally not chosen for large nuclear 

reactors, such as the proposed Galena Nuclear Power Plant to be constructed in the 
234

Yukon River village of Galena in the U.S. state of Alaska. These remote sites introduce 

the possibility that certain external events may be the dominant accident initiators and 

would have to be addressed through standards and regulations. Additionally, 

earthquake risk, less reliance on offsite power, and additional external events might be 

higher at remote sites. 

Additional external events that would be of particular concern for SMRs include the 

following:

• Flood: Some SMR designs have the reactor located underground, and 

groundwater intrusion or flooding of the buildings would be a design and 

qualification consideration. 

• External fire: For sites near wooded areas, an off‐site forest fire could challenge 

plant operation and features such as dampers and internal circulation might be 

necessary. 

• Extreme cold: For sites with very cold temperatures, such as ‐60°F, and very 

high temperatures, such as + 115 °F, extreme temperatures represent unique 

challenges to equipment and would have to be accounted for in the design and 

qualification. 

• Extreme snow and/or ice: Extreme snow and/or ice conditions could limit access 

to the plant and would necessitate additional human factors considerations. 

• Volcanic ash conditions: Volcanic ash effects on equipment, dampers, and 

limited access to the plant would have human factors, design and qualification 

impacts.

The design of some SMRs could accommodate these challenges due to their ability to 

provide core cooling with natural circulation in the absence of off‐site power or operator 

intervention. The affected standards might require modifications to account for these 

newly anticipated occurrences. Fortunately, passive safety features have been 

designed into advanced LWRs, such as Westinghouse’s AP1000 and General Electric 

Hitachi’s ESBWR and the applicable ACI, ANS, ASME, and IEEE standards already 

consider risk, performance, and qualification for passive features. The active 

mechanical and electrical safety equipment necessary to initiate the passive safety 

features are also covered by the consensus standards, such as ASME QME-1-2007, 

“Qualification of Active Mechanical Equipment Used in Nuclear Power Plants,” and 

IEEE 323, “IEEE Standard for Qualifying Class 1E Equipment for Nuclear Power 

Generating Stations.”

Coordination and Concerns

The SDOs are working together with the Nuclear Energy Standards Coordinating 

Council to ensure that SMRs are adequately considered in the standards. Additional 
235

work is needed due to confusion in the licensing process. An example of this confusion 

was a recent announcement of discussions on the use of topical reports in lieu of 

consensus standards to protect proprietary features of SMRs. This proposal is a 

potential concern. The standards committees take pride and passion in ensuring a 

consensus approach to safety. A large effort was made in the last two decades to 

ensure that the standards apply to LWRs and SMRs with international consensus. The 

standards development process is purposely not instantaneous, which allows for careful 

and widespread consideration among the world’s experts before a conclusion is 

reached. The consensus timeline results in several standards generated and approved 

within 2 to 3 years, and processes are in place for swiftly addressing clarifications. The 

misconception that topical reports can be used instead of consensus standards needs 

to be swiftly, visibly, and strongly corrected by the SDOs. The use of topical reports is 

to provide proprietary documents and discussion on how proprietary features meet the 

consensus standards and the applicable regulations. Topical reports are common in 

large LWRs, but topical reports for SMRs should not to be used as an alternate to 

consensus standards.

A process for the design of SMRs must not be allowed outside of the consensus 

standards approach. It is up to each SDO to monitor this situation and correct this 

misconception when noted. The SDOs also need to coordinate through the liaison 

committee process whenever issues such as this come up.

Conclusion

SDOs are ready for SMRs, but as noted, the consideration of recent events, such as the 

March 2011 earthquake and tsunami in Japan and the additional severity of natural 

hazards, demonstrates that standards work is not complete. SDOs, and specifically 

ANS, ASME, and IEEE, need to continue the active liaison process in which members 

of each committee and subcommittee regularly attend and present the status and 

details of standards activities. As SMR safety features and performance requirements 

evolve, the SDOs need to evolve with them to ensure their safety. The ANS, ASME, 

and IEEE standards that address safety equipment performance, qualification, and 

natural hazard mitigation need to be applied to SMRs. It is our collective safety interest 

to ensure safety structures, systems and components perform properly during plant 

operation and in response to plant events. 

References

1. Interim Report of the American Nuclear Society President’s Special Committee 

on Small and Medium Sized reactor (SMR) Generic Licensing Issues, July 2010

237

Session 4: Pumps

Session Chair: Robert Kershaw, Arizona Public Service Company

239

Comprehensive Pump Inservice Testing (IST) Issues -

Seeking Resolution of Two Long Standing Regulatory 

Concerns

Robert I. Parry, NextEra Energy Seabrook LLC

ASME Operations & Maintenance Standards Committee, Vice Chair

Sub-Group ISTB CPT Issues Project Team Member

Thomas Robinson, Nebraska Public Power

ASME Operations & Maintenance Standards Committee Member

Sub-Group ISTB Member and CPT Issues Project Team Member

Abstract

The purpose of this paper is to document the various historical issues associated with 

two long standing pump inservice testing regulatory concerns. The first issue is the 

definition and the testing of the “pump design flow rate” as used in the comprehensive 

pump testing (CPT) requirements. The term “pump design flow rate” was not clearly 

defined in the American Society of Mechanical Engineers (ASME) Operations & 

Maintenance (OM) Code for Operation and Maintenance of Nuclear Power Plants and 

Nuclear Regulatory Commission (NRC) expressed their concerns that pump design 

basis accident capability was not explicitly being addressed by the current CPT 

requirements. The second issue discussed is that the NRC questioned the bases for 

the upper hydraulic acceptance criteria limits and how are the limits related to 

instrumentation issues versus the test technique. The Sub-Group ISTB investigated the 

bases for the 1.03% and OM code changes are currently being developed to address 

these issues. 

Introduction

The American Society of Mechanical Engineers (ASME) Operations & Maintenance 

(OM) Code for Operation and Maintenance of Nuclear Power Plants, ASME OM CODE1996 Addenda, and later editions and addenda have incorporated comprehensive pump 

testing (CPT) requirements. One of the requirements of the CPT is to establish 

reference values within +/- 20% of the pump design flow rate. However these editions 

and subsequent addenda have not defined “pump design flow rate”. The ASME OM 

Committee, and in particular the Sub-Group ISTB who is responsible for the 

requirements of Subsection ISTB, Inservice Testing of Pumps in Light-Water Reactor 

Nuclear Power Plants, have received numerous questions regarding the definition and 

intended use of this term in the IST Code.
240

The second issue discussed in this paper is that the NRC questioned the bases for the 

upper hydraulic acceptance criteria limits and how are the limits related to 

instrumentation issues versus the test technique. The current upper hydraulic 

acceptance criterion is 1.03%. Flow measurements performed at operating nuclear 

power plants often do not achieve this accuracy during routine CPT when the pump is 

not suffering from degradation. Additionally, instrumentation issues with pump testing in 

the field include using 2% Full Scale loop accuracy instrument loops for pressure. 

Because the OM Code also limits the full scale range of the pressure device to three 

times the reference value, it is possible to have almost 6% uncertainty for the test 

reading for pressure without consideration for the flow uncertainty. The Sub-Group 

ISTB is currently developing OM Code changes to alleviate the instrument accuracy 

issues faced by operating plants.

This paper will refer to the various key reference materials as attachments – but the 

actual attachments are not included due to needing to limit the document length for 

publication. (Please contact the authors for copies of the references if interested.)

Unresolved issues 

The 1996 CPT change addressed the testing of pumps using minimum flow lines which 

have limited ability in detecting pump degradation. The 1996 CPT change was meant to 

test each pump at a point at which degradation was more readily detectable. 

During several ASME OM meetings, the Nuclear Regulatory Commission (NRC) 

expressed their concerns that pump design basis accident capability was not explicitly 

being addressed by the current CPT requirements. As a result of several stalled code 

changes, a special joint ASME OM/NRC June 2007 meeting was scheduled, and from a 

detailed review of all the issues, a conceptual agreement was reached. ASME agreed 

to initiate ISTB Code actions to address the conceptual agreement.

ASME was essentially of the opinion that the 1996 Comprehensive Pump Test Code 

change had resolved the original NRC concerns that dealt with the transition from 

ASME Section XI IWP to the 1988 OM Part 6 requirements. Attachment 1 describes, 

thru a review of three papers presented at the First NRC/ASME Pump & Valve 

Symposium, August, 1989, the ASME OM Code Committee pump testing philosophy 

that existed in the 1990 timeframe. Many comments received during the OM Part 6 final 

approval process indicated that further changes to the IST pump testing requirements 

would be needed. The resolution of these final ballot comments integrated with the OM 

Part 6 pump testing concepts, lead to the development of the Comprehensive Pump 

Test. The CPT was approved and published in the 1996 Addenda to the 1995 Edition 

of the OM Code.

There were the normal questions associated with any major code addition as the CPT 

was initially implemented by the Owners starting in the 2000 timeframe. The SubGroup ISTB tried on several occasions to clarify the application and the use of the CPT 

“design flow” for not only the regulators but for the users of the code.
241

The Subgroup ISTB had proposed changes to the ASME OM Code Subsection ISTB, 

2004 Edition through the 2006 addenda, and provided the basis for why the changes 

were being made. The changes attempted to resolve the regulatory issue of what 

exactly is the design flow rate? These changes were not successful and it became 

apparent that ASME and the NRC were at a philosophical impasse.

In April, 2007, ASME requested a special meeting with the NRC to discuss pump testing 

issues. This meeting was separate from the regularly scheduled ASME OM Code 

meetings and was solely focused on the CPT and the code pump testing philosophy. 

The goal of the meeting was to allow each organization time to explain their 

perspectives associated with the Comprehensive Pump Testing issues. From this 

candid discussion, ASME OM Code members hoped to then seek a path to ultimately 

resolve the long standing pump testing issues. Key representatives from the ASME 

Committee including Committee officers, Sub-Group ISTB members, and NRC 

interested parties were asked to attend this meeting. 

Attachment 2 contains a copy of the ASME Request for a Special Meeting in a letter 

dated April 23, 2007.

The meeting was held at the NRC offices in White Flint, Maryland on June 4, 2007. 

Attachment 3 contains the NRC Presentation used to describe their issues with the 

current ISTB requirements. Attachment 4 contains the ASME OM presentation 

materials for this meeting. There was open discussion during both presentations. Both 

the NRC and ASME presentations were filed on the ASME OM Committee Webpage 

under Committee File Sharing.

With regard to the Comprehensive Pump test, the discussions identified there were 

three long standing issues (the first two of which are discussed in this paper), that 

ASME OM needed to be address:

1. Design Flow – What is exactly meant by design flow? Is it accident analysis? 

Is it Best Efficiency Point or BEP? Who defines design flow? Is the slope of 

the pump curve a consideration? Does NRC Information Notice (IN) 97-90, 

“Use of Nonconservative Acceptance Criteria in Safety-Related Pump 

Surveillance Tests,”– being above the minimum address the issue?

2. Instrumentation issues – For plants who can run their quarterly tests at 

“Design Flow”, why do they still need to use better instrumentation? Why do 

high alerts happen? Why are there separate criteria for the Comprehensive 

Pump Test versus the Group A?

3. What is the purpose of the Group B test? “Go or a NoGo” test to validate a 

start demand – no degradation? Only one parameter monitored – Flow or 

differential pressure (DP), not both? No degradation other than it started and 

got into the hydraulic box? No vibration needed?
242

Conceptual Agreement 

As a result of this joint meeting, the ASME OM members in attendance now had a clear 

understanding of the regulatory issues and the basis of their concerns. As this material 

was reviewed and further discussed as the ASME OM Committee Meetings in June 

2007, a conceptual agreement was developed for use by the ISTB CPT Project Team. 

Attachment 5 contains a copy of the Conceptual Agreement that was filed on the ASME 

OM Committee Webpage under Committee File Sharing.

Major portions of this agreement are contained in this paper.

First Issue – Design Flow

The CPT flow needed to be in a relative stable hydraulic region due to the application of 

the vibration acceptance criteria as a major indicator of pump health. Testing at points 

of the accident analysis did not necessarily present hydraulically stable regions. One of 

the NRC‘s concerns was to have a Technical Specification (TS) Program requiring 

certain Emergency Core Cooling System (ECCS) and Emergency Feedwater (EFW) 

pumps to be tested at a specific flow rate i.e., at design accident conditions. This 

concern was identified as being largely associated with the TS Change (processed 

approximately in the 2000 time period). The change deleted testing requirements at 

design accident flow rate conditions by replacing those requirements with references to 

testing in accordance with TS 4.0.5 or the IST Program. The NRC wanted certain 

pumps to be periodically tested at their design accident conditions and they wanted this 

testing to be in a TS Program.

These old TS requirements, for some plants, did not generally require testing at "design 

accident" conditions. Instead of having the specific hydraulic parameters for each pump 

listed in the TS, the TS change simply referenced the IST program. This TS change did 

not realize that IST did not necessarily require specific flow rates to be achieved other 

than the range as specified by the CPT (e.g., 80 to 120% of the design flow rate). 

Some pumps had a specific post maintenance surveillance requirement, like EFW 

pumps that would demonstrate their safety function. The 1996 CPT code change would 

require a five point head curve validation for pumps that were overhauled due to 

maintenance issues, yet there would be no periodic test if maintenance was not done.

The 1996 Comprehensive Pump test was an improvement over the old TS recirculation 

tests as CPT was conducted at a more representative flow rate, depending on how the 

owner defined "design flow rate". Vibration acceptance criteria also was used in a more 

prominent role than it had been during the ASME Section XI, IWP testing.

For some IST pumps, like pressurized water reactor (PWR) ECCS pumps, the design 

accident flow rate hydraulic parameters may be very close to run out conditions. The 

“design” flow used in 1996 CPT was not explicitly defined. The CPT also applied 

vibration criteria where the old TS IST type tests simply had the hydraulic parameters 

listed. This vibration check was specifically required during the CPT to compliment the 
243

hydraulic assessment of the pump health. The establishment of the CPT test point 

involves having a hydraulically stable region, such as the Best Efficiency Point (BEP), 

as the reference value for both the hydraulic and vibration assessments. The BEP may 

be at a much lower flow rate than the design accident condition. The hydraulic stability 

conditions at run out are not always conducive to the application of the ISTB vibration 

criteria (0.325 inches per second (ips) for ALERT and 0.7 ips for REQUIRED ACTION) 

without having specifically having these requirements imposed on the pump 

manufacturer during the original pump procurement process.

It was realized that there are also some pumps that have a design accident condition 

flow rate that is much less than BEP. ASME OM was also concerned that the two 

requirements, the CPT and the design accident condition flow test, could conflict with 

each other, meaning that we would be applying test criteria to a pump that was not 

designed for that condition.

OM Action

ASME OM agreed that a potential additional test point (DP and Flow only) to address 

the design accident flow conditions could be added to the ISTB requirements. The NRC 

indicated that this request would be to recreate the original TS surveillance 

requirements. Essential attributes for this new requirement were:

• FREQUENCY: Two year timeframe like the CPT, and most likely done at the 

same time as the CPT if that was convenient for the Owner. It should be the 

Owner’s decision on how to schedule the new testing activity.

• HYDRAULIC ONLY : No vibration is required to be taken as the pumps, based 

on the site specific safety analysis, may not be in a region that is hydraulically 

stable. As such the application of the vibration criteria is not appropriate. ITSB 

members wanted to minimize the time in this configuration, so not taking 

vibration data helps reduce the overall test duration.

• PREVIOUS TEST BASIS: The original TS requirements did not include explicit 

vibration requirements.

• APPLICABILITY: Generally the applicability is for those certain pumps that were 

listed in the plant TS. For example, PWR ECCS pumps, and other pumps like 

EFW or Containment Building Spray pumps that had design accident flow and 

DP (or maybe discharge pressure) values listed in the plant’s TS.

Resolution of the Design Flow Rate - Pump Periodic Verification Test Code 

Change

The Sub-Group ISTB is resolving the first of the NRC’s long standing issue by defining a 

comprehensive pump test flow rate and by the addition of a new pump periodic 

verification test.

The following information is contained in the White Paper for the OM Code change. 

During one of the many ballots, the white paper was presented as a non-mandatory 
244

appendix to the OM Code in an attempt to capture the information and make it readily 

available to the end users. It was ultimately removed as part of the OM Code change 

as several OM Committee felt that including the white paper as a non-mandatory 

appendix would be the exception. Since the white paper contains some of the basis for 

the code change, it is included as Attachment 6.

To many ASME OM Committee members the pump periodic verification test (PPVT) 

was not an IST test. To highlight that the new pump periodic verification test satisfies a 

different purpose and to separate it from applying other IST requirements, the PPVT 

was added as a separate Mandatory Appendix in the OM Code.

Discussion of Proposed Code Change

Attachment 7 contains the 2011 PPVT proposed code changes.

The change will be to 1) eliminate the “pump design flow” wording, and 2) to replace it 

with the “comprehensive pump test flow rate” and 3) add in a PPVT for those certain 

applicable pumps that have design basis accident flow rates specified in their TS or 

Updated Safety Analysis Report. The PPVT is not expected to be required for all of the 

pumps in the IST Program.

The comprehensive pump test flow rate is defined as the flow rate established by the 

Owner that is effective for detecting mechanical and hydraulic degradation during 

subsequent testing. The best efficiency point, system flow rates, and any other plant 

specific flow rates shall be considered. Under the definition, the owner will be given 

some flexibility in establishing this value by being able to consider pump best efficiency 

point as defined by the pump manufacturer, system flow rate requirements, and any 

other plant specific flow rate requirements. With this allowed flexibility, it is possible that 

the comprehensive pump test flow rate will not encompass the highest required 

accident flow rate (if applicable) as is defined in the owner’s safety analysis (e.g. TS 

and/or Updated Safety Analysis Report). If, in this case, there is a design basis 

accident flow rate in the owner’s safety analysis not bounded by the comprehensive 

pump test or Group A test, then the owner will be required to perform a pump periodic 

verification test. The pump periodic verification test details are located in a separate 

stand alone appendix, Division 1, Mandatory Appendix V, to denote that this is a 

separate test not traditionally considered an IST activity. As indicated above, if 

required, the Owner may elect to combine this pump periodic verification test with the 

comprehensive pump test activity or perform it separately.

The reason for having the pump periodic verification test has been derived from the 

previous TS requirements and the Criterion XI requirement to demonstrate that safety 

related pumps are capable of meeting their design bases accident conditions - flow rate 

and the associated DP (discharge pressure for positive displacement pumps). 

The frequency requirement for the pump periodic verification test will be once every 2 

years. This will allow the test to be performed during a refueling outage, if necessary, 
245

and is consistent with the comprehensive pump test frequency. Instrumentation for flow 

and/or DP will be consistent with the comprehensive pump test since this verification 

could be performed while the gauges are installed, or the instrument inaccuracies shall 

be accounted for in either in the analysis, itself, or in the acceptance criteria of the test. 

The intent of the pump periodic verification test is not to require the owner to develop 

new design basis accident flow and DP (discharge pressure for positive displacement 

pumps) requirements for those pumps in which this does not apply. For example, if 

design basis accident flow rates are not specified in the Owner's TS, Updated Safety 

Analysis Report, or other design basis documentation for specific IST pumps, then 

those pumps would not have to be considered for a pump periodic verification test. 

Similarly, certain IST pumps that have design basis accident flow rates in the Owner's 

credited safety analysis, but the maximum required flow and associated DP (discharge 

pressure for positive displacement pumps) are encompassed within a Group A or 

Comprehensive pump test, then a separate pump periodic verification test would not be 

required. The owner would document that the comprehensive test satisfies both tests in 

the IST Program Plan. The Owner is responsible for capturing the basis for the 

comprehensive pump test flow rate and the pump periodic verification test flow rate and 

associated pressure within the owner’s pump records [ISTB-9100(d) and by Division 1, 

Mandatory Appendix V]. 

Criterion XI

Criterion XI of Appendix B to 10CFR50, Quality Assurance Criteria for Nuclear Power 

Plants and Fuel Reprocessing Plants, requires that each safety-related pump achieves 

its minimum design-required performance. 

Appendix B establishes quality assurance requirements for the design, manufacture, 

construction, and operation of those structures, systems, and components. The 

pertinent requirements of this appendix apply to all activities affecting the safety related 

functions of those structures, systems, and components; these activities include 

designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, 

installing, inspecting, testing, operating, maintaining, repairing, refueling, and modifying.

XI. Test Control

A test program shall be established to assure that all testing required to demonstrate 

that structures, systems, and components will perform satisfactorily in service is 

identified and performed in accordance with written test procedures which incorporate 

the requirements and acceptance limits contained in applicable design documents. The 

test program shall include, as appropriate, proof tests prior to installation, preoperational 

tests, and operational tests during nuclear power plant or fuel reprocessing plant 

operation, of structures, systems, and components. Test procedures shall include 

provisions for assuring that all prerequisites for the given test have been met, that 

adequate test instrumentation is available and used, and that the test is performed 
246

under suitable environmental conditions. Test results shall be documented and 

evaluated to assure that test requirements have been satisfied.

Richardson Letter

Attachment 8 contains a copy of the Richardson Letter.

In the early 1990’s, the NRC requested that ASME OM Committee revise the pump 

testing requirements to ensure the ability of certain pumps to perform their intended 

“hydraulic and mechanical” safety function(s). The NRC indicated that the then current 

pump and valve tests did not: a) include each component that has a hydraulic or 

mechanical safety function; b) accomplish verification of each safety function of such a 

component; or c) require that such verification be accomplished at the design basis 

conditions. The NRC indicated that an amendment to 50.55a might be initiated to 

........ii) require verification of each safety function......; iii) require such verification be 

accomplished at the design basis conditions or where such verification is not possible a 

test, at less than the design basis conditions, combined with an analysis may be 

substituted ...

ASME OM Response to the Richardson Letter

Attachment 9 contains a copy of the ASME response to the Richardson Letter.

ASME OM Committee indicated that new requirements were being prepared that would 

be more related to the design basis for the pump. ASME OM Committee indicated that 

the opinions on what is required to fulfill the request vary widely. The options vary from 

radical redefinition of current pump and valve testing to continuation of the present 

evolutionary changes that are being planned and implemented as part of our revision 

process. Those ASME OM members who met directly with the staff believe that they 

too have difficulty in appreciating all of the implications of the suggested changes. 

Pumps – ASME OM Committee indicated that a major effort was underway (at that time 

it had been underway for 2 years) to add new requirements for pump testing that would 

be more related to the design basis testing for the pumps. The comprehensive pump 

test revisions were then undergoing ballot at the OM Committee. ASME OM Committee 

believed that this effort would be a significant improvement for testing of some pumps, 

and in line with the requested suggestions. Testing was based on degradation with 

respect to the baseline head curve and vibration. 

ASME OM Committee also indicated that.....there is increased recognition that it is 

difficult to establish relatively simple go-no-go acceptance criteria for pumps and valves. 

Changes to add requirements for analysis of the measured parameters in the 

acceptance criteria to ensure that the acceptance criteria are more consistent with the 

design basis conditions are being developed. ASME OM Committee recognizes that 

the evaluation and analysis of data and the results of tests is a very necessary part of 

the program. These requirements are being added as necessary to ensure adequate 
247

engineering is applied to the determination of the acceptability of the results of individual 

inservice tests.

W Standard Technical Specifications

“Periodic surveillance monitoring of Emergency Core Cooling Systems (ECCS) pumps 

to detect gross degradation caused by impeller structural damage or other hydraulic 

component problems is required by Section XI of the ASME Code. This type of testing 

may be accomplished by measuring the pump developed head at only one point of the 

pump characteristic curve. This verifies both that the measured performance is within an 

acceptable tolerance of the original pumps baseline performance and that the 

performance at the test flow is greater than or equal to the performance assumed in the 

plant safety analysis.”

Pumps in a nuclear power plant system may have a variety of requirements or features 

such as making a specific flow rate, operating over a range of flow for various functions, 

making a total developed head, a start time requirement to achieve rated flow, motor 

current usage restrictions, and a multitude of system requirements. 

The purpose of ISTB is not to validate all of these above features but to test the pump to 

detect degradation. Initial program attributes that shaped the IST pump tests were: 

1. Surveillance frequency (i.e., the need for frequent tests at either monthly and 

then later quarterly intervals); 

2. Hydraulic performance with either discharge pressures or DP actually specified in 

plant TS; 

3. Available hydraulic flow paths to conduct the on line at power surveillance 

activities; and,

4. Mechanical performance (vibration) taken as a secondary performance measure. 

Information Notice 97-90

In December 1997, the NRC noted that some licensees had concentrated on IST 

requirements without explicitly ensuring that their pump performance met the specific 

plant safety analysis. The absence of an explicit tie to plant safety analysis could allow 

pumps to degrade over time more than values specified in their analysis. The NRC 

indicated that the ASME Code “does not require that pumps be tested at the designbasis conditions”.

Information Notice 07-05

The NRC indicated that Service Water pump shaft failures events demonstrate that IST 

alone might not be sufficient to ensure pumps meet their accident acceptance criteria. 

Operating experience also shows that pump shaft failures and coupling failures can 

result in sudden total loss of flow before standard performance monitoring techniques 

alert plant staff to the impending failure. Other techniques such as inspection and 
248

refurbishment or more sophisticated vibration analysis techniques may be capable of 

identifying the onset of degradation.

Second Issue – Limits and Instrumentation

The NRC questioned the bases for the upper hydraulic acceptance criteria limits and 

how are the limits related to instrumentation issues versus the test technique.

Where did the 1.03% come from?

The 1.03% is believed to be from an API standard test stand limit where the vendor had 

control of the test flow rate (instrument tap locations, weigh tank, or highly accurate flow 

device) and could minimize its error contribution. Field flow measurements, especially 

on the older plants, cannot match the vendor test facility standards. Test technique 

issues such as waiting an appropriate time for the system to stabilize before making 

further adjustments can also impact high flow readings. 

Instrumentation issues with pump testing in the field include using 2% Full Scale loop 

accuracy instrument loops for pressure (flow accuracy requirements were not changed 

during the Comprehensive Pump Test). The Code also limits the full scale range of the 

pressure device to three times the reference value. Thus, it is possible to have almost 

6% uncertainty for the test reading for pressure alone without consideration for the flow 

uncertainty.

Example 1: Test reference 34 psig, Full Scale 100 psig, 2% Full Scale is 2 psig or 2/34 

psig is about 6% (5.88%) of reading.

Example 2: USNRC Information Notice 97-90 approach to look at why we can exceed 

1.03%

• Reference flow at 10,000 gallons per minute (gpm) with 64.525 pounds per square 

inch differential (psid). (on the pump curve)

• +/- Tolerance on flow for Operations is +/- 100 GPM. (gage scale)

• Flow uncertainty is 240 gpm, so when OPS is at 9900 gpm, they could also really be 

at 9760 gpm.

• At 9760 gpm, DP uncertainty for Comprehensive Pump test is about 0.3 FT X 0.445 

or about 0.134 psid. 

• The CPT Minimum DP is therefore 64.659 psid.

• The Group A minimum DP is 6 FT or 6 FT X .445 or about 2.67 psid.

• The Group A minimum DP is therefore 67.195 psid. This is 1.04% of the reference 

pressure. 

If we assume that the reference was taken at the high end of the uncertainty and was 

really 2.67 psid lower, or 64.525 – 2.67 = 61.855 psid. It is possible then that the Group 

A minimum DP of 67.195/61.855 is 1.086%. All accuracy's are within the OM Code 

allowable values.
249

Even if we use the 0.5% pressure gages (CPT), we are still subject to the slope of the 

curve and the flow uncertainty errors and these combined can easily exceed 1.03%.

OM Action

The Sub-Group ISTB investigated the bases for the 1.03% and considered adding some 

requirements to the analysis section so that Owners understand the reasons for the 

exceeding the 1.03%. Another potential is to increase the Group A acceptance criteria 

for those plants who can test at the CPT flow rate.

Resolution of the Instrumentation Issue - Relaxation of CPT High Required Action

The Sub-Group ISTB is resolving the second of the NRC’s long standing issues by 

providing a relaxation of the high required action range for the Comprehensive Pump 

Test Hydraulic Parameters (1.03 to 1.06). 

This code change will address the instrumentation issues previously proposed under 

record #05-1134, ballot 08-1449. It was independently voted on (e.g., separated from 

the Design Flow issue) under a new record to allow more focus on the particular topic. 

Instrument Code Change:

1. Revise the CPT high required action acceptance criteria from 1.03 times the 

reference to 1.06 times the reference. 

2. This, in turn, results in the same revision to the upper acceptable range.

Background:

Owners are having difficulties with the implementation of the current CPT required 

action range high limit of only 3% above the established reference value for the 

measured hydraulic value of either DP or Flow. Owners have or will be faced with 

declaring pumps inoperable for reasons that do not represent a pump degradation 

issue. Revising the code to allow a high required action limit of 6% above the reference 

value is a more realistic value that should allow any true potential degradation issues to 

be captured and should alleviate unnecessarily declaring pumps inoperable.

This issue was also discussed at the ASME/NRC special meeting on June 4th, 2007. 

The NRC questioned the basis for the upper required action limits. At the June OM 

code meeting, the NRC was receptive to a compromise between the 1.03 value and the 

1.10 value for the comprehensive pump test upper required action limit. The basis for 

this change is discussed below. 
250

Basis for Change: 

There are several factors that may quickly cut into the existing 3% upper limit. Each 

factor is discussed below.

1. Instrument inaccuracies of measured hydraulic value:

 

a. Case A: Set Flow, Measure DP: If flow is set and DP (or pressure) is measured, 

up to 1.5% of the current 3% band may be eliminated based on the code allowed 

pressure instrument inaccuracies, alone. Currently, ISTB-3510(a) and table 

ISTB-3510-1 require analog pressure instrumentation for the CPT to meet +/-

0.5% of full scale. Based on ISTB-3510(b)(1), the full scale range of each analog 

instrument shall not be greater than three times the reference value. Therefore, 

the existing code allows the measured DP (or pressure) reference value to have 

instrument inaccuracies of up to +/-1.5% of the reference value. A similar 

discussion is addressed within NUREG 1482, Revision 1, section 5.5.1. 

 

b. Case B: Set DP, measure Flow: If DP is set and Flow is measured, up to 6%, or 

over twice of the current 3% band may be reached based on the code allowed 

flow instrument inaccuracies, alone. Currently, ISTB-3510(a) and table ISTB3510-1 require analog flow instrumentation for the CPT to meet +/-2.0% of full 

scale. Based on ISTB-3510(b)(1), the full scale range of each analog instrument 

shall not be greater than three times the reference value. Therefore, the existing 

code allows the measured Flow reference value to have instrument inaccuracies 

of up to +/-6% of the reference value. A similar discussion is addressed within 

NUREG 1482, Revision 1, section 5.5.1.

2. Instrument inaccuracies of set value and its affect on measured value: 

a. Case A: Set Flow, Measure DP: If flow is being set, for the same reasons as 

were discussed under item #1, the reference set flow value may have instrument 

inaccuracies of up to +/-6%. This allowed amount of inaccuracy for the set flow 

value for a comprehensive pump test that is performed at a point well out on the 

sloped portion of the pump curve would have a significant impact on the 

measured DP value. The impact would vary from pump to pump, but this factor 

alone may jeopardize or exceed the current upper +/-3% criteria that would be 

applied to the measured DP value. 

b. Case B: Set DP, Measure Flow: If DP is being set, for the same reasons as 

were discussed under item #1, the reference set DP value may have instrument 

inaccuracies of up to +/-1.5%. This allowed amount of inaccuracy for the set DP 

value for a comprehensive pump test that is performed at a point well out on the 

sloped portion of the pump curve would have an impact on the measured flow 

value. The impact would vary from pump to pump, but this factor alone may 

jeopardize the current upper +/-3% criteria that would be applied to the measured 

Flow value.
251

3. Instrument inaccuracies and allowed tolerance for Speed:

For those pumps with variable speed drives, table ISTB-3510-1 and subsection 

ISTB-3510 requires the instrument accuracy for speed to meet +/-2% of full scale for 

analog instruments or over the calibrated range if it is a digital instrument. 

Additionally, the CPT (and Group A and B pump tests) allows speed to be adjusted 

to the reference point with an allowed tolerance of +/-1% around the reference point. 

Therefore, a total variation of up to +/-3% of the reference speed is possible for 

variable speed drive pumps. Variations from the reference point would actually shift 

the entire pump curve up or down. A shift downward would impact the current upper 

3% required action limit for the measured hydraulic value of flow or DP, whichever is 

applicable.

 

4. Human Factors involved with setting and measuring flow, DP, and speed:

As is discussed in NUREG 1482, Revision 1, section 5.3, certain designs do not 

allow for the licensee to set the flow [or potentially DP or speed] at an exact value 

because of limitations in the instruments and controls for maintaining steady flow [or 

potentially DP or speed]. If the owner takes the approach to obtain a steady value at 

approximately the set value for the parameter being measured, there most likely will 

be some minor variations in what is read from test to test and from individual to 

individual. The same would be true if a plant has taken the approach to justify 

various degrees of tolerance around the set value being measured. Therefore, the 

human factors involved with these issues may also reduce the margin to the +3% 

upper limit that is currently in the OM Code for the measured flow or DP, whichever 

is applicable. 

 

5. Readability of Gauges based on the smallest gauge increment:

The OM Code does not address the affects that the readability of test gauges may 

have on the value being measured. Gauges should only be read to 1⁄2 of the 

smallest increment. Following this basic rule may at least have a minor impact on 

the 3% upper limit.

 

6. Misc. Factors: 

The Code does not explicitly require the licensee to consider physical attributes 

(such as orifice plate tolerances), tap locations, environmental effects (such as 

temperature, radiation or humidity), vibration effects (such as seismic) or process 

effects (such as temperature). All of these factors may impact the accuracy of the 

measured flow or DP. 

Comprehensive Pump Test Operating Experience 

Industry Experience associated with the implementation of the upper 1.03 required 

action limit for the comprehensive pump test was gathered through the IST Owner’s 

group (ISTOG) mass email system. Two questions were asked concerning the 

implementation of the comprehensive pump testing. The results support the 

conclusions previously reached that the upper limit of 1.03 is too limiting and should be 

revised. The following is a summary of the information obtained. The plant names 
252

have been withheld to maintain the focus on the information provided and not who it 

was provided from. 

1. Do you have any pumps in which the 1.03 upper required action limit has 

been exceeded? If so, what was the cause and how did you resolve the 

condition? 

Summary of responses: 

Plant A: We had a test failure due to exceeding the 3% flow upper limit. No 

definitive cause could be determined and I was forced to re-baseline at the 

higher flow rate. The pump was declared inoperable when it was clearly capable 

of performing its specified function. Plant resources were unnecessarily 

expended by bringing in personnel in the middle of the night to establish an 

action plan, etc.

Plant B: We have had 2 occasions where the quarterly test [using same 

instrumentation as the comprehensive pump test] exceeded 1.03 and have 

written corrective actions to investigate. In the first case further investigation 

revealed an improper lineup and I declared the test invalid and performed 

another test with acceptable results. The second event is an instrument

readability issue with the 0.5% accuracy gauge. Nothing was wrong with the 

pumps in either case. 

Plant C: We have had one pump failure in which we slightly exceeded the 1.03 

upper acceptance criteria, which was conservatively being applied to the 

quarterly Group A test, since the test setup was identical to the comprehensive 

pump test. The test was reviewed and compared to historical test data. It was 

determined that the data point obtained was within the normal data scatter. 

Therefore, the pump was unnecessarily declared inoperable. One corrective 

action was to utilize the 1.10 criteria for the quarterly test and 1.03 criteria for the 

comprehensive pump test.

2. Do you have any pumps in which you anticipate possibly exceeding the 

1.03 upper required action limit? If so, what is the anticipated reason for 

exceeding the 1.03 upper required action limit? 

Summary of responses: 

Plant D: Approximately 70% of the Group A tests at this plant are mirror images 

of the associated CPT (same test gage, reference flow rate or DP). A quick look 

at previous test data reveals 18 instances (6 DP, 12 flow rate) where flow or 

pressure/DP exceeded the 3% upper acceptance limit since 2002, but was well 

within the test allowable 10% limit. Subsequent test results returned to within the 

allowable CPT values. 

Plant E: At this plant, we are concerned about river water supply pumps due to 

normal data scatter.

Plant F: Some potential failures because data scatter is larger than the 1.03 will 

tolerate. All of our tests are now using the 0.5% pressure gauges as a standard, 

so it is not related to instrument inaccuracies. OM Code testing is not performed 

in a laboratory controlled and instrumented environment so the ability to get 
253

consistent data within +3% will be challenging in some cases. We go from a 

20% window to a 13% window.

Plant G: We don't have any OE yet, but I can see it coming with our SW pumps 

and dye flow testing. We meet the +10% fine, but we have not always been 

within +3%.

Plant H: We are currently in the process of updating to the 2001 Edition through 

2003 addenda, so we have not realized any failures yet. I fully expect there will 

be failures [referenced many of the same reasons presented in this white paper].

Plant I: We are struggling with the CPT of all the ECCS pumps as there is 

very high probability of the pumps being declared inoperable due to exceeding 

the 103% upper limit. It is very difficult to explain to the management that the 

pumps which show no sign of degradation for years of testing and trending have 

to be declared inoperable due to exceeding their performance by 3% during CPT.

Plant J: We are upgrading to the 2001 (2003 Addenda), so the 103% criteria 

hasn't affected our testing yet. However, after reviewing past test data, there are 

several pumps which we anticipate will exceed the 103% criteria periodically. We 

do not believe this is indicative of pump degradation, but rather to the scatter in 

the data.

Plant K: We have established or are working on establishing new reference 

values for most of our comprehensive pump testing due to the installation of 

higher accuracy gauges even though all other aspects of the test in relation to 

the quarterly test is the same. The second time the test is run may be almost 4 

years into the interval. Based on past historical data, the potential exists for 

several of our comprehensive pump tests to begin to fail at that time due to the 

upper 1.03 limit. Due to all the uncertainties, it is not expected that the higher 

accuracy pressure instruments will make that much difference in the readings 

obtained every quarter. This has been validated in several instances with the 

establishment of new comprehensive pump test reference values and comparing 

them to the quarterly reference values. Also, in some cases, our quarterly 

pressure gauge accuracies are not far from the 0.5% accuracy required for the 2-

YR tests, further supporting this information.

Conclusions for Limits and Instrumentation 

Based on what has been presented, the current allowed inaccuracies associated with 

obtaining the Comprehensive pump test hydraulic data may very easily result in the 

measured value to exceed the existing Code allowed upper required action limit of 3%. 

In fact, evidence has been shown that even the proposed upper 6% limit could 

potentially be in jeopardy of being exceeded. However, when compiling all the affects 

of the individual inputs discussed above, most pumps will typically be able to meet the 

newly proposed 6% upper limit. The most likely reason for this is that not all of the 

inputs discussed, above, will impact the measured value to the largest extent possible 

and each input would not act upon the measured value in the same direction (i.e. all 

push the measured value upward or downward). Therefore, the proposed 6% upper 

limit will be a much better indication of potential degradation of the pump (or increased 
254

affect of an input) in the upward direction rather than the current 3% upper limit. This 

new limit should also alleviate owners from unnecessarily declaring pumps inoperable 

and entering unplanned LCOs.

Acknowledgements

Special thanks to Jack McHale, NRC Representative and ASME OM Standards 

Committee Member who helped arrange the June 2007 Special Meeting on Pump 

Inservice Testing Issues.

The final resolution of these pump testing issues is directly related to the substantial 

support provided by Thomas Ruggiero, Sub-Group ISTB Chair, Wavel Justice, SubGroup ISTB Secretary, Dennis Swann, Sub-Committee OM Code Chair and Sub-Group 

ISTB Member, and R. Scott Hartley and David Kanuch, both Sub-Group ISTB 

Members. Also the remaining SG ISTB membership needs to be recognized for their 

technical review and integration of the recent ISTB Code changes. This support 

spanned over many years as the issues were refined and as code deliverables were 

identified. 

Materials used for this paper were from the ballot white papers prepared by the original 

ISTB Task Group of Tom Robinson, Dave Kanuch, and Scott Hartley.

Attachments (contact the authors for copies of #2 - #9)

1. 1990 ASME OM Working Group Pump IST Historical Perspective (included)

2. April 23, 2007 Letter from ASME to the NRC for a Special Meeting to discuss pump 

testing issues.

3. NRC Presentation Materials, June 4, 2007 Meeting with ASME.

4. ASME OM Presentation Materials, June 4, 2007 Meeting with NRC.

5. ASME OM Conceptual Agreement, date June 19, 2007 outlining OM Actions to 

resolve three long standing pump testing issues.

6. Pump Periodic Pump Testing White Paper 

7. Proposed Code Change Pump Periodic Verification Test

8. James E. Richardson, Director Division of Engineering Technology, Office of 

Nuclear Reactor Regulation, Letter 9/9/1991 to Forrest T. Rhodes, Chair ASME 

Operations & Maintenance Committee.

9. Forrest T. Rhodes, Chair ASME Operations & Maintenance Committee.

Response to James E. Richardson, Director Division of Engineering Technology, Office 

of Nuclear Reactor Regulation, Letter 9/6/1992.
255

Attachment 1

1990 ASME OM Working Group Pump IST Historical Perspective

Using published articles and Letters of Correspondence between ASME and the 

Nuclear Regulatory Commission (NRC), a historical perspective on pump testing can be 

determined. These three papers were from key individuals heavily involved in the 

ASME OM Code Committee work, in pump testing, and in pump failure investigations.

These papers reflect the prevalent ASME OM thought process at that time. The main 

elements of these three papers are summarized below in the following eight 

perspectives and in the more detailed capsule summary sections for each paper.

• Vibration was being treated as the prime indicator of pump health more so than it 

was during ASME Section XI testing.

• More stringent hydraulic acceptance criteria were being required for positive 

displacement and vertical line shaft pumps as vibration was judged to be less 

effective in detecting issues with these pumps.

• Although manufactured to exacting tolerances, no two pumps are ever exactly the 

same; therefore, small performance variations should be expected.

• At the design or BEP flow rate, the fluid motion is comparable with the physical 

contours of the hydraulic passages and is therefore well behaved.

• The industry should not rely solely on low-flow testing for operational readiness 

determinations.

• Based on many of the comments received during the final OM Part 6 Code balloting 

process, the OM working group on pump and valve testing began actively 

considering further improvements to these standards.

• Even when operating at these points, performance of the same pump can vary from 

test to test. Performing in the hydraulically stable regions should provide less data 

scatter, and will generally simplify the data interpretation process.

• Pumps should be tested when they are operating at hydraulically stable areas, such 

as the best efficiency point. This is a key consideration as we are also applying the 

vibration acceptance criteria to the hydraulics. Having test results suitable for 

trending was an important part of this change.

1. ASME/NRC Symposium on Inservice Testing of Pumps & Valves, August 

1989, Washington, DC.

1. Article by John Zudans, Introduction to ASME/ANSI OMa-1989a Part 6 – “Inservice 

Testing of Pumps in Light-Water Reactor Power Plants” and Technical Differences 

between Part 6 and ASME Section XI, Subsection IWP.1
256

John Zudans, at that time, was the Vice Chair on the Working Group on Pump & 

Valves. He had also previously served as Chair of this working group. He is 

currently the Chair of the OM Committee.

This article was the introduction article for the new IST pump requirements. The 

then new OM pump and valve standards (Part 6 and Part 10) had just been 

published as the 1988 addendum to the OM-1987 Operation and Maintenance 

Document. 

The purpose of the article was to highlight differences between the new and the old 

IST pump requirements. The article also highlighted some changes in a future 

change section. 

In the future change section, the following statement was made:

“The OM working group on pump and valve testing is actively considering further 

improvements to these standards. The areas for improvement have been 

recommended by industry as well as regulatory bodies. Task groups and action 

plans have been established for the higher priority issues and results should be 

forthcoming. Some of the pump issues being considered include; improvements in 

mini-flow acceptance criteria, hydraulic acceptance criteria, trending, and analysis 

time limits- 96 hour criteria.”

To highlight the differences, Attachment 1 in this article contained a three column 

comparison between the new and the old IST requirements. One column contained 

the IWP paragraph requirement, the second column contained the corresponding 

OM Part 6 requirement, and the third column provided the change and the basis for 

the change.

On Attachment 1, page 8 of 18, the change and basis section contained the 

following:

“Early in the development of this Standard, it was recognized there were many 

problems with detecting change in pump performances based on hydraulic 

parameters. Additionally, there were concerns raised about causing undue wear 

because of excessive testing. This is of particular concern for those pumps tested 

on a mini flow line. As a result, a change in emphasis was made towards using 

vibration as the primary indicator of pump degradation. Vibration testing is more 

indicative of pump mechanical condition that hydraulic testing. It is expected there 

will be fewer pumps requiring increased testing or corrective action based on 

erroneous test results. A careful investigation showed that all pumps could not be 

treated the same. Thus Table 6100-1 differentiates between three types of pumps; 

positive displacement, vertical line shaft, and centrifugal pumps.”

“While vibration is to be relied upon more heavily, it is also recognized that positive 

displacement and vertical line shaft pump degradation could go undetected with 
257

typical instrumentation being used in most plants. Therefore, more stringent 

hydraulic acceptance criteria are still used for these pumps.”

“For all other centrifugal pumps, the hydraulic acceptance criteria have been 

relaxed. The extent of the change is to allow the equipment to be run in a “window” 

hydraulically and to then evaluate pump condition more closely with vibration. The 

purpose of the window is twofold. First, it ensures the pump is performing its 

primary function that is, pumping liquid. Second, that it is operated in a specified 

narrow band where the vibration data will be comparable.”

2. Article by James J. Healy, Enhance Pump Reliability through Improved Inservice 

Testing” 

Mr. Healy, at that time, was the Pump Specialist for Stone & Webster Engineering 

Corporation.

As part of the introduction, an important point is made with regard to the traditional 

IST methodology. “ANSI/ASME OM-6 has taken the place of Subsection IWP, and 

has changed a number of test ranges and shifted the focus of testing for centrifugal 

pumps from hydraulic criteria to an emphasis on changes in mechanical criteria, 

such as vibration levels. EPRI has undertaken a study to assess the effectiveness 

of existing testing programs to accurately monitor and predict performance changes 

before either pump performance degrades of an actual failure occurs. Anticipated 

changes in inservice testing techniques are directed towards enhancing the validity 

of test data, ensuring its repeatability, and avoiding deterioration of the pump 

assembly. There is a new-found interest in the test programs of all types that has 

occurred, in part because of an increase in reported pump degradation and pump 

failure.” He concluded that inservice testing of pumps, which has long been a basis 

of assuring operability, has apparently produced an opposite effect; namely, the 

appearance of a reduction in reliability.

Two of the four pump characteristics are mentioned here:

1. Pumps are hydraulically designed to operate over a wide range of flows 

but perform best at, or near, their best efficiency point of flow.

2. Performance of “identical pumps” varies from pump to pump, even when 

they are built at the same time. Performance of the same pump can vary 

from test to test. Although manufactured to exacting tolerances, no two 

pumps are ever exactly the same; therefore, small performance variations 

should be expected.

One of the recommendations made to enhance pump reliability, was the selection of 

an optimal point where the pump should be tested it characteristic curve. The 

proper selection of this optimal point would result in improved test results. Often 

existing system configurations dictates that safety pumps be tested at or below the 

minimum continuous recirculation flows specified by the pump manufacturer. 
258

Testing flows at or near a minimum flow point specified by the manufacturer may be 

convenient but usually result in an undefined point. Testing at flows below 25% of 

the best efficiency point can result in IST results that are inconsistent and may or 

may not indicate that the pump has degraded.

Furthermore, the author indicates that experience has shown that both new and 

worn pump characteristic curves share the same shutoff head if the impellers (s) 

diameter(s) and speed remain the same. IF IST is done at low flows, the ability to 

differentiate between the new and worn conditions approaches a level below 

instrument accuracy.

3. Article by William L. Greenstreet, Low-Flow Operation and Testing of Pumps in 

Nuclear Plants. Dr. Greenstreet worked for Oak Ridge National Labs, Oak Ridge 

TN and this paper was based on research done for the NRC.

The article discusses the need to test pumps at the best efficiency point, or BEP. 

The author states that pumps are designed for best performance at a specific 

combination of capacity, head, and speed that is the BEP. At the design or BEP 

flow rate, the fluid motion is comparable with the physical contours of the hydraulic 

passages and is therefore well behaved. Hydraulic instability is a term used to 

describe unsteady flow phenomena that become progressively more pronounced as 

a pump is operated farther away from BEP. The hydraulic instability is manifested 

by flow recirculation in both the suction and discharge regions of an impeller stage 

when operating below the design flow.

As part of his conclusion, he indicated that “Head and flow data are not reliable 

indicators for health because head vs. capacity curves, in many instances, exhibit 

very little change at low flows (especially as shut-off is approached) because of 

degradation. He states that.” hydraulic instability can complicate the data 

interpretation process.” He recommended on not placing reliance on low-flow 

testing for operational readiness determinations.

2. ASME/NRC Symposium on Inservice Testing of Pumps & Valves, July 1994, 

Washington, DC.

This paper describes the thought process that existed at that time. The main 

elements of these three papers are summarized below in the more detailed capsule 

summary section but the following five perspectives can be noted:

• Vibration was still being used as the prime indicator of pump health with the major 

difference being that pumps now had a flow requirement that was closer to the 

design conditions.

• The higher pressure instrument requirements helps to obtain more accurate 

reference values and minimize measurement uncertainties during testing.

• The critical performance analysis for pumps was to be done when the pumps are 

operating at hydraulically stable areas, such as the best efficiency point. 
259

• The change in the Group B testing addressed the previous concerns that industry 

should not rely solely on low-flow testing for operational readiness determinations.

• The OM working group on pump and valve testing finally felt that they had 

adequately addressed all of the NRC concerns with regard to pump testing.

1. Article by R. Scott Hartley, Description of Comprehensive Pump Test Change to 

ASME OM Code, Subsection ISTB.

Scott Hartley has been a long time member of the ASME OM Code Committee, and 

is currently a member of the Standards Committee and the Sub Group ISTB.

The article provide this background: “The USNRC was considering adopting Part 6 

in the regulations in 1988 and requested a meeting with the OM Committee. The 

OM Working Group on Pumps & Valves (WGPV) met with the USNRC in March 

1989. The meeting was held to discuss concerns related to the newly approved 

pump and valve testing standards, OM-6 and OM-10, respectively. The OM-6 pump 

testing standard increased the upper action limit for hydraulic test parameters from 

103% (ASME, 1986) to 110%. The reasoning for the increase was that hydraulic 

performance was not expected to improve (Zudans, 1990). However, the higher 

limit could allow significant instrument drift. The USNRC also had raised concerns 

about the potential for damage during low flow testing of pumps in IST programs 

(USNRC, 1988). The USNRC agreed to accept OM-6 as written, if the ASME 

WGPV would consider improvements to the pump testing requirements.”

“Following the discussions, the OM-6 Task Group on NRC Issues, a task group 

under WGPV, began work to develop a better, more comprehensive test for 

assessing pump condition.”

“The OM-6 pump test standard was issued in October 1990 as OM Code-1990, 

Subsection ISTB (ASME, 1990). The comprehensive pump test change was written 

against the 1990 Subsection ISTB.”

From the Development of the Comprehensive Test section the following items are 

highlighted:

1. Pumps were categorized into two categories, Group A, and Group B. Group 

A pumps are defined as pumps that operate continuously ore routinely during 

normal operation, cold shutdown, or refueling outages. Group B pumps are 

defined as pumps in standby systems that are not operating routinely except 

for testing.

2. Pumps that operated more frequently, such as service water or component 

cooling water pumps, are likely to degrade at higher rates than pumps that 

are only operated occasionally, such as standby liquid control pumps.

3. Four test were identified – preservice, comprehensive, Group A and Group B. 

Pumps in dry sumps were exempted from the quarterly tests, with all pumps 

receiving the 2 year test.
260

4. The preservice test would use high precision pressure instruments and 

establish accurate reference values at points of operation that would allow a 

precise assessment of pump performance, or operational readiness. For a 

centrifugal pump in variable resistance systems, the test requires differential 

pressure and flow rate to be taken at five points of operation, from pump 

minimum to near design flow rates, to establish a baseline pump curve.

5. The comprehensive test was developed to help ensure a better evaluation of 

pump performance characteristics at a reduced frequency. The test is 

performed at a single reference value, or near (within 20%), the pump’s 

design flow rate for centrifugal pumps. This area of the curve is considered to 

be most representative of the pump’s hydraulic characteristics (Greenstreet, 

1990). 

6. The difference between the Group A test and the ISTB-1990 test is that the 

test should be performed at as high a flow rate (or discharge pressure for 

positive displacement pumps) as practical. ISTB-1990 did not address the 

flow rate or pressure at which pumps tests were to be preformed.

7. The Group B test, for standby pumps, was intended to be a quick, simple, 

largely qualitative test. The test would roll the pump to keep the bearings 

from taking a set and to lubricate and exercise the moving parts. It was not 

intended to be used to determine hydraulic performance capabilities or to 

detect minor imbalances through vibration measurements. The critical 

performance analysis for Group B pumps were to be done with the less 

frequent comprehensive pump test. The Group B test can allow detection of 

gross mechanical or hydraulic failures of electrical or control systems.
261

Allowable Variance from Reference Value for IST Test Flow

Ed Cavey

Fermi 2 IST Program Manager

Newport, Michigan, USA

Abstract

The American Society of Mechanical Engineers (ASME) Code for Operation and 

Maintenance of Nuclear Power Plants (OM Code) requires during subsequent inservice 

testing (IST), after the establishment of reference values, that the flow rate or differential 

pressure be set to the exact reference value. The OM Code does not acknowledge the 

possibility that there may be limitations in the ability of plant personnel and equipment to 

meet this requirement. This issue is discussed in NUREG-1482, Revision 1, Section 5.3, 

“Allowable Variance from Reference Points and Fixed-Resistance Systems.” Close 

reading of this guidance reveals that the Nuclear Regulatory Commission (NRC) would 

find it acceptable for plants to apply a variance limit of ± 2%, but this 2% must include 

inaccuracy of the flow measurement device. The industry recently discovered that many 

plants were misinterpreting the NUREG-1482 guidance and using procedural flow range 

limits of up to ± 2% without the consideration of flow accuracy. This presentation will 

share lessons learned from recent experience in obtaining approved relief for this issue. 

A primary basis for regulatory approval of this relief was the proven ability to accurately 

trend pump performance using data normalization techniques to overcome the data 

scatter problem. Examples of actual pump degradation data and normalization will be 

provided.

Introduction

IST of pumps has been accomplished in a successful manner for decades. The intent

of the activity is to detect degrading conditions as early as possible, allowing for 

sufficient time to implement corrective actions before loss of the pump’s safety function. 

IST Program Owners establish testing procedures which are intended to produce 

repeatable conditions and measurement methods, allowing them to directly compare 

new test data to component history.

Repeatable pump testing requires operations personnel to establish and adjust system 

conditions to the pump reference value. Typically, this involves throttling on a valve or 

valves until the reference value measurement matches the desired value. Many 

systems do not have throttling control sufficient to achieve a specific repeatable 

reference value. This paper describes the methodologies employed by IST Program 

Managers in order to meet the intent of the testing in those situations.
262

NUREG-1482 Guidance

NUREG-1482, Revision 1, correctly identified that many plant systems did not have the 

throttling control to precisely adjust to reference values test to test. ASME OM Code 

does not address this issue. The NUREG-1482, Rev. 1, guidance allowed for ± 2% 

variance in reference value, however, the exact wording in NUREG-1482, Rev. 1, 

required that this 2% value must be inclusive of instrument accuracy. For most IST 

pumps, the reference parameter is flow and the variable parameter is differential 

pressure (DP). The accuracy of flow indication required by the Code is 2%. Given the 

discussion in NUREG-1482, Rev. 1, if the flow measurement accuracy is 2%, there is no 

remaining variance allowance. IST Engineers are left with the same guidance as the 

OM Code, which is to adjust the flow to exactly the reference value. 

Plant Testing Example

The Residual Heat Removal Service Water system (RHRSW) at Fermi Power Plant, 

Unit 2, has identical divisions, each containing two identical vertical line shaft two-stage 

centrifugal pumps. These pumps can each deliver flow values in the range of 3000 –

7000 gallons per minute (gpm) at a discharge pressure between 30 – 60 pounds per 

square inch (psi). Each pump discharges through a 16 inch pipe before joining to a 24 

inch header. The RHRSW flowpath travels approximately 900 feet horizontally and 

approximately 40 feet vertically into the reactor building and through the RHR heat 

exchangers. On the outlet of the heat exchanger is a motor-operated throttle valve 

(MOV). This is a globe valve with an SMB-3 Limitorque operator. The gearing of the 

MOV is relatively slow to allow for better throttling characteristics, however the valve 

has a safety function to close in order to isolate the residual heat removal system (RHR) 

from RHRSW and prevent any leakage of primary fluid outside of secondary 

containment. This closure function warrants a speed of isolation which limits how slow 

the MOV stroke time can be. During test operations with a single pump running, the 

Operations crew attempts to adjust flow using this MOV to the 5400 gpm reference 

value. Individual, rapid operations of the pushbutton typically yield flow changes of 

between 60-80 gpm. If the test procedure required them to establish exactly 5400 gpm, 

it could take several hours or longer to achieve that condition. Multiple motor starts on 

the MOV are limited to ensure motor temperatures stay within reasonable levels and 

require cooldown periods. Manual throttling of the test MOV is not feasible due to their 

location in High Radiation Areas.

It is simply unreasonable to expect the operations staff to perform testing on a quarterly 

basis in such a manner. An acceptable range for test flow in this scenario is 5400 gpm 

± 100 gpm. This equates to a 1.85% variance. Flow is measured with temporary digital 

equipment with a best accuracy possible of 0.8%. Combination of these two factors, 

even using square root sum of the squares (SRSS), yields a total variance of greater 

than 2%. 

Fermi has 10 safety-related service water pumps located in our RHR / emergency 

diesel generator complex. All of these pumps are deep-draft vertical line shaft pumps 
263

from the same vendor and were initially placed in service in 1984. Analysis of historic 

test data in 2000 showed that all of the pumps had experienced some degree of 

hydraulic degradation. Pump replacement activities were initiated and the sequence / 

prioritization was based on the IST trend data. Because of the degree of scatter in the 

data, a normalization method was established to allow for accurate short term trending. 

The first pump replacement occurred in 2004 and involved the pump with the lowest 

remaining margin and most aggressive degradation trend. Pumps were replaced as 

scheduled in the years following, with the last pump replacement in early 2011. No 

pump ever reached the required action threshold. Some pumps did operate in Alert 

range for periods of time with increased frequency testing. IST trend information was 

used throughout this time to drive the scheduling and selection of the pump 

replacements.

Case for Change

The concern about limiting reference value variance is due to the degree of data scatter. 

The concern about data scatter is the impact on the ability to detect an increasingly 

degraded condition.

The example described above is an actual situation where the reference flow variance 

did produce some degree of data scatter AND the pumps were in fact degrading over 

time. The example proves that analytical methods exist to reduce the data scatter and 

that trending can be performed quite successfully despite the higher reference flow 

variance.

The Inservice Testing Owners Group and ASME OM Code Committees have been 

working to adopt improved guidance on this subject. It is a simple fact that IST testing 

of most pumps cannot be performed such that an exact reference value is achieved in 

every test. The OM Code language needs to include some allowance for variability 

about the reference values.

Recent discussions have promoted the idea of using a -1% / +2% band for the setting of 

reference values. This would be independent of any discussion of instrument accuracy 

(which is already covered explicitly in ASME OM Code Section ISTB). This amounts to 

a total 3% band in which to set flow or pressure, with the desire that effort be made to 

be as close to the actual reference value as possible. This 3% band will accommodate 

almost all situations of throttling and control capability. Any isolated situations where 

repeatable testing within the 3% variance is not possible would likely require special 

relief from the regulatory authority. The limitation of -1% provides additional 

conservatism since the typical scatter would be in the "conservative" direction for the 

variable parameter. IST Engineers should employ data normalization (or equivalent) 

techniques to reduce the data scatter. This will ensure the ability to detect and monitor 

degradation.
264

Acknowledgments

B. Leimkuehler - System Engineering Lead Fermi 2

References

2004 edition ASME OM Code Section ISTB

NUREG-1482 Revision 1

ANNEX B

RHRSW TREND DATA

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

3.00%

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53

Total deviation from reference for each test 

(includes 0.8% Flow ACC)

RHRSW Pump A

RHRSW Pump B
265

5200

5250

5300

5350

5400

5450

5500

5550

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51

Actual RHRSW Flow values (Last 51 tests)

Pump A FLOW

Pump B FLOW
266

50

51

52

53

54

55

56

57

58

6/1/1999

11/1/1999

4/1/20009/1/20002/1/20017/1/2001

12/1/2001

5/1/2002

10/1/2002

3/1/20038/1/20031/1/20046/1/2004

11/1/2004

4/1/20059/1/20052/1/20067/1/2006

12/1/2006

5/1/2007

10/1/2007

3/1/20088/1/20081/1/20096/1/2009

11/1/2009

4/1/20109/1/2010

RHRSW Pump D Long Term DP Trend

DP
267

51

52

53

54

55

56

57

58

6/1/1999

12/1/1999

6/1/2000

12/1/2000

6/1/2001

12/1/2001

6/1/2002

12/1/2002

6/1/2003

12/1/2003

6/1/2004

12/1/2004

6/1/2005

12/1/2005

6/1/2006

12/1/2006

6/1/2007

12/1/2007

6/1/2008

12/1/2008

6/1/2009

12/1/2009

6/1/2010

12/1/2010

6/1/2011

12/1/2011

RHRSW Pump D Performance Analysis

DP test

DP norm
268

51.0

51.5

52.0

52.5

53.0

53.5

54.0

54.5

55.0

55.5

56.0

3/1/20076/1/20079/1/2007

12/1/2007

3/1/20086/1/20089/1/2008

12/1/2008

3/1/20096/1/20099/1/2009

12/1/2009

3/1/20106/1/20109/1/2010

12/1/2010

3/1/20116/1/20119/1/2011

12/1/2011

RHRSW Pump D - Short Term Trend

DP norm

DP test

Alert Criteria - 52.25 psid

Action Criteria - 51.15 psid
269

51.0

51.5

52.0

52.5

53.0

53.5

54.0

54.5

55.0

55.5

56.0

RHRSW Pump D - Short Term Trend

DP norm

Alert Criteria - 52.25 psid

Action Criteria - 51.15 psid
270

51.0

51.5

52.0

52.5

53.0

53.5

54.0

54.5

55.0

55.5

56.0

RHRSW Pump D - Short Term Trend

DP norm

DP test

Alert Criteria - 52.25 psid

Action Criteria - 51.15 psid
271

High Pressure Safety Injection Pump

Mechanical Seal Leakage Cause Analysis

Robert Kershaw

Cause Analysis Engineer

Palo Verde Nuclear Generating Station (PVNGS)

Arizona Public Service Company

Abstract

In February 2010, the PVNGS Unit 2 “B” Train High Pressure Safety Injection (HPSI) 

Pump was found to have a high leak rate from the pump’s outboard mechanical seal 

during a functional test following a bearing oil change. The initial leakage, a pencil size 

stream, decreased during an hour of operation to approximately 250 milliliter per hour 

(ml/hr). Initial observations, made during seal trouble shooting and replacement, 

indicated abnormal wear on the carbon stationary seal ring. Failure cause analysis 

found that the seal carrier springs that hold the rotating tungsten ring against the 

stationary carbon ring had been over stressed by maintenance and engineering 

personnel during pre-installation manipulation. PVNGS had experienced several HPSI 

seal leakage problems over the 2 previous years that led station personnel to measure 

the spring force of spare seal parts in an attempt to install the ‘strongest’ seal available 

in the spare part inventory when replacing HPSI mechanical seals. While measuring 

the spring force, the carrier springs were collapsed to solid which over stressed the 

springs and resulted in a loss of 30-40% of the spring force. The weakened springs 

resulted in excessive seal leakage during pump starts. The carbon ring degradation, 

caused by seal flushing water flowing across the carbon seal face during pump starts 

while the seal faces slowly reseated, contributed to the seal leak rate. It was found that 

the seal manufacturer provided seals designed to operate 24 hours a day for extended 

periods of time – not for a pump used in standby and required to operate for much 

shorter durations. New seal design with stronger springs for the operational 

expectations for these standby pumps are being developed by the seal vendor for the 

PVNGS application.

Introduction

In February 2010, while the Unit 2 PVNGS “B” Train of the Safety Injection (SI) System 

was in a 72 hour Limiting Condition of Operation (LCO) for planned maintenance, 
272

operations personnel observed that the 2B High Pressure Safety Injection (HPSI) Pump 

was leaking excessively from the pump’s outboard mechanical shaft seal during a 

functional run following an oil change. The leakage challenged the pump design 

expectation and impacted the plant’s Technical Specification for leakage from Primary 

Coolant Sources Outside Containment which has a maximum limit of 1500 ml/hr for all 

Emergency Core Cooling System (ECCS) piping outside of containment. 

The 2B HPSI Pump high seal leakage was corrected by replacing the seal. The 2B 

HPSI Pump was returned to service before the end of the 72 hour LCO time period. A 

failure cause analysis was performed to determine causes and take corrective action to 

minimize recurrence.

Equipment Description

The PVNGS HPSI Pumps are Ingersol-Rand, Model 4X11CA-8, 1000 horsepower, 

horizontal, high pressure pumps with a design discharge pressure of 2050 pounds per 

square inch gauge (psig). Pump output flow at 1000 psig is approximately 1040 gallons 

per minute (gpm). These pumps are hydraulically balanced to minimize thrust forces by 

injecting high pressure discharge to the low pressure end bearing housing. The inboard 

bearing is a journal bearing. The outboard bearing is a combination journal and thrust 

bearing. It is an 8 stage pump with a 4 inch discharge. They are basically 1930 vintage 

boiler feed pumps manufactured to nuclear grade requirements.

Event Narrative

On February 17, 2010, the 2B HPSI Pump, exhibited high leakage from the outboard 

pump mechanical shaft seal when the pump was started for a functional run following 

an oil change. When the pump was started at 1600 hours, operations personnel 

noticed a pencil size steady stream of water flowing from the outboard pump seal. After

15 minutes of run time, at 1615, seal leakage had decreased and was determined to be 

500 ml/hr. The leak rate continued to decrease and was determined to be 250 ml/hr at 

1640. The pump was shutdown at 1656, and seal leakage decreased to 1 drop per 20 

seconds at 1700 (based on 10-15 drops per ml, this equates to ~14 ml/hr). 

Immediately prior to this pump run, under static conditions, the seal had been leaking at 

the rate of 1 drop per 7-8 seconds (~40 ml/hr).
273

The design specification (not a Technical Specification) for HPSI Pump seal leakage 

indicates that these seals should leak less than 50 ml/hr. The LCO, Primary Coolant 

Sources Outside Containment, establishes a limit of 1500 ml/hr for all ECCS piping 

outside of containment, which is in contact with recirculation sump inventory during loss 

of coolant (LOCA) conditions. 

The 50 ml/hr was a design value for normal leakage during operational conditions 

developed by the plant’s designer. Significantly more leakage is necessary before the 

pump would become inoperable (unable to deliver the credited safety related flow). A 

plant calculation for HPSI System performance includes a Surveillance Requirement 

Basis that assumes a net flow loss of 20 gpm. The leak rate experienced is far less than 

this amount. In addition, the leak rate would need to exceed the capacity of the 

Engineered Safety Features (ESF) room floor drains (and sump/sump pump) which is 

on the order of several hundred gpm. Therefore, the 2B HPSI Pump leak would have 

been a small contributor to the system requirements of 1500 ml/hr and as such would 

not impact the Title 10 of the Code of Federal Regulations (10 CFR) Part 100 off-site 

dose.

HPSI Pump 2B was isolated and drained for seal replacement. During the seal 

disassembly and inspection of parts the following observations were made:

• Spring preload appeared satisfactory (gap measurement)

• Shaft play was satisfactory (~0.015”, within the acceptable range 0 - 0.030”)

• Rotating face (tungsten) was satisfactory (disassembly caused a small chip)

• Stationary face (carbon) had non-uniform coloration – 90 degrees counter 

clockwise from the locating pin

• Carrier looked good

• Lip was satisfactory (not a repeat of 3R14 issue)

• O-rings were satisfactory

This particular seal was installed in the 2B HPSI Pump during a refueling outage in 

November 2009. It was installed as part of an effort to replace the old non-Q class 

seals with new Q class parts. 

Inspections of the leaking seal parts found a discolored area on the stationary (carbon) 

seal surface. Under optical flat/monochromatic light, the seal area in question had only 

approximately 30% of contact area. This lack of flatness is measured in fractions of a 

mil. The rotating (tungsten) seal surface was found in good condition. New thrust 

bearings and a new mechanical seal were installed. Seal performance was satisfactory 

during retest. See diagram in the analysis section for internal seal details.
274

Inspections, following this 2010 seal replacement, have identified that the new outboard 

seal on the 2B HPSI Pump had again begun to develop a very slow leak under static 

conditions – as evidenced by the formation of boron on the bottom of the seal. The 

leakage had not developed to the point of developing drops falling from the seal 

housing. 

Pictures taken during the seal trouble shooting and replacement:

Leaking seal – note Boron

Seal flushing line

HPSI mechanical 

seal – Boron 

indicates leaking 

seal
275

HPSI mechanical seal being disassembled

Seal carrier 

springs (TYP)
276

Stationary ring – Carbon – note discoloration

Stationary Ring – Carbon - details

Discoloration

Locating Pin
277

The flatness of both the stationary and rotating seal rings was measured using an 

optical flat plus a monochromatic light. The light rings/pattern is an indication or 

measurement of surface flatness.

Leaking carbon seal showing lack of flatness as indicated 

by the wavy lines and low spot at area of discoloration

New carbon seal showing what flat looks like

Low spot

Locating pin
278

A Maintenance Rule Functional Failure (MRFF) evaluation was performed. HPSI pump 

mechanical seal leakage of 250 ml/hr (most conservative assumption even though the 

leak rate was decreasing at the time the pump was secured) is much less than the 20 

gpm limit discussed in Safety Injection (SI) System calculation. This calculation 

indicates that up to 20 gallons per minute of system leakage can be diverted from the 

HPSI pump and it will still continue to operate and provide normal performance. 

Therefore, the U2 B HPSI pump’s capacity (flow and pressure) would not have been 

affected by the 250 ml/hr leakage from its outboard mechanical seal. Therefore, the 

Reactor Heat Removal (HR), Reactivity Control (RXC) and Inventory and Pressure 

Control (IPC) MR Key Safety Functions (KSFs) would have been fully protected and 

met.

With respect to the Indirect Radiation Release (IRR) MR KSF, the 250 ml/hr leakage 

would NOT have exceeded the Technical Specification leakage limit for ECCS Leakage 

Outside of Containment of 1500 ml/hr. This leakage limit is established to ensure that 

ECCS Leakage Outside of Containment, during the Safety Injection System 

recirculation mode of operation following a Loss Of Coolant Accident, does not result in 

dose rates to the public in excess of the 10 CFR 100 limits. For PVNGS Unit 2, the 

approximate ECCS Leakage Outside of Containment at the time of this event was 35 

ml/hr. An additional 250 ml/hr leakage would have resulted in a total of 285 ml/hr, which 

is still considerably less than the 1500 ml/hr limit. Therefore, the IRR MR KSF would 

have been fully protected and met.

Therefore there was no MRFF or MR impact for this seal leakage event. Similarly, there 

was no significant impact to nuclear safety resulting from this seal leakage event.

Industry and plant Operating Experience were reviewed for similar events. Numerous 

previous events were identified that involved leaking HPSI seals – reasons for previous 

leakage were attributed to use of wrong lubricant during assembly, foreign material and 

poor workmanship during installation. In each case the corrective actions involved 

installation of new seals. Seal problems appeared to be handled as a component issue 

and not as an issue related to nuclear power.

Analysis

A Fault Tree and an Equipment Failure Modes and Causal Factors Chart were used in 

the analysis of this event and are included at the end of this paper.
279

The following are the facts and observations gathered by the cause investigation team:

• PVNGS handles the seals very carefully and installs them with great care 

(observation made by pump vendor representative).

• Foreign material contamination was not observed and is not considered an issue 

for this leakage event.

• PVNGS maintenance personnel have noted that the seal kit carrier springs do 

not seem as strong in the Q class parts as they were in the previously used NonQ class parts. 

• PVNGS personnel have measured spring rates and installed those kits with the 

strongest springs by measuring the spring forces versus compression of the 

carrier surfaces.

• The seal vendor measures the spring force by compressing the carrier to 1⁄4 inch 

spacing and records the spring force at that position (50-72 pounds force [lbf]).

• The seal vendor has informed PVNGS that if the carrier springs are compressed 

to solid height, the springs are degraded and will only retain ~70% of their 

original spring force.

o PVNGS has measured spring force of spares considered for installation 

and found 40-47 lbf at 1/4 inch spacing that would have been 57-67 lbf 

force (according to the vendor) before being compressed to solid height.

 Degraded seal removed from 2B HPSI measured 42.5 lbf

 Spare seal S/N ...02 measured 47.7 lbf

 Spare seal S/N ...03 measured 46.9 lbf

 Spare seal S/N ...06 measured 39.9 lbf

o PVNGS regularly compresses the carriers to solid height to ensure the 

guides move freely and to obtain a spring force curve – which the vendor 

has now indicated could have damaged the springs.

o This indicates that PVNGS practices, according to the vendor, could have 

degraded the springs.

• Static leakage is controlled solely by spring force. 

o The new Q class parts have been observed to regularly leak under static 

conditions in the drops per minute range – even before the practice of 

measuring spring force was started.

o Upon pump startup, although the HPSI pump is balanced, the pump shaft 

moves slightly towards the motor which tends to decrease the force that 

the outboard seal rotating face is pressing against the stationary face.

o At pump startup, a spray of leakage has been noted in the outboard seal 

followed by a steady leak rate that slowly decreases over time – usually 

decreasing back to zero leakage.

o When the pump is running, the seal cavity is slowly pressurized by pump 

pressure and the sealing is aided by the hydraulic forces. This pressure 

build up occurs slowly due to the torturous path the pressure takes along 

the pump shaft in the bearing/seal area. 

o Since changing to Q class seals, PVNGS has implemented a 10 hour 

HPSI run for post maintenance to get the mechanical seals to seat and 

seal as expected.
280

o Greater than normal leak static leak rates have been observed on the 

three PVNGS HPSI pumps that have had the new Q class seals installed. 

2B outboard seal is the only seal that has developed a gross leak upon 

pump start that has not decreased to near zero after pump was running. 

This leakage developed after the pump was run for a total of ~44 hours of 

operation since installing this seal.

• During the disassembly of the leaking seal the carbon seal face was found to be 

discolored and not completely flat when measured with an optical flat.

o The low spot was the area of discoloration.

o This area is 90 degrees counter clockwise from the seal locating pin which 

corresponds to the flushing water inlet.

o It is believed, by the vendor, that the flushing water flow impacted the 

carbon sealing face during the time the tungsten face was not firmly 

seated on the carbon – causing a slight erosion of the sealing face. This 

is considered to be collateral damage of weak springs.

o This loss of flatness of the carbon seat is the most likely cause of the 

sustained high leak rate experienced on this seal and over time the 

tungsten rotating seal would have reseated better and better – effectively 

decreasing the leak rate.

• HPSI operation was monitored as normal for pressure, vibration, shaft 

movement/alignment, balancing drum operation, flushing flow, etc.

Maintenance History

During the PVNGS Unit 3 refueling outage in April 2009, the “3A” and “3B” HPSI pump 

seals were replaced as part of planned maintenance with a pump vendor representative 

supervising the pump work. Replacement of the “3B” pump seal required multiple 

evolutions prior to successful pump performance. Following the first replacement, 

excessive leakage was observed during initial pump filling activities. A decision was 

made to replace this seal, based on the leakage likely being due to installation issues. 

A small piece of a carbon-like material was found in the area of the stationary seal oring seating area. The second seal replacement again resulted in excessive leakage 

which was determined to be a result of an installation error which caused a rolled gland 

lip. After the third replacement a successful post-maintenance testing was completed 

with minimal seal leakage that went to zero after about 10 minutes of run time. There 

were no indications, at that time, of a defective seal face.

During PVNGS Unit 2 refueling outage in October 2009, the “2B” HPSI pump seals 

were replaced as part of planned maintenance. The post maintenance testing (PMT) 

revealed seal leakage from both seals – initially 3-4 drops per minute (~18.5 ml/hr) but 

continued pump operation resulted in zero mechanical seal leakage. Including the PMT 
281

and Surveillance Testing, this pump was run 43.9 hours before the pump was started on 

2/17/2010 and experienced the pencil stream high leak rate. 

The new, Q class parts were leaking - both under static and dynamic conditions 

compared to no active leakage with the older non-Q class seals that were replaced in all 

three of these pumps. The new Q class seals, in contrast to the older non-Q class seals, 

often exhibit a spray of leakage when the pump is started or when system valve 

alignments are changed. The new Q class seals sometimes have leaked large amounts 

(200-500 ml/hr) upon startup but over several minutes to hours have settled in and the 

leak rate has decreased to drops per minute. This is now understood to probably be as 

much a function of the development of hydraulic forces in the seal as it is for the seal 

surfaces to seat. The static leakage and leakage upon pump start is caused by 

weakened spring in the seal package not needing time for the seal surfaces to wear in.

The degraded 2B HPSI Pump seal was leaking, under static conditions at the rate of 1 

drop every 7-8 seconds (~37 ml/hr), prior to starting the pump when the gross leakage 

was experienced before the seal was replaced in February 2010. The new seal, just 

installed in the 2B HPSI pump in February 2010, leaked minimally at first but leakage 

stopped after 10 minutes of run time. The vendor representative (a pump specialist, not 

a seal specialist) was present and involved in its installation. He made comments to the 

effect that the PVNGS Mechanics handled the seal very carefully and exhibited great 

skill and care in the way they installed the seal - that it could have not be installed 

better. During walk downs and inspections in March 2010, boron deposits were 

observed be forming on the bottom of the 2B HPSI seal indicating that it is weeping 

under static conditions. The leak rate had not developed to the point of forming droplets 

at that time. This is not a condition PVNGS was used to seeing while operating with the 

non-Q class seal assemblies in the past or on pumps that have not had their seals 

replaced with Q class parts. 

To deal with these leaking seals - the pump vendor representative stated to properly 

break in the seal faces, the pump should be run for 3-4 hours of normal pump pressures 

and temperatures (i.e. no starts and stops). The way PVNGS starts and stops the pump 

could potentially be impacting the seal break-in. So a 10 hour PMT run time was

instituted.
282

Vendor seal Diagram

Summary of Investigation Analysis

The cause of the 2B HPSI seal leak was weak/degraded springs in the Q class parts. If 

the springs supplied in these new Q parts are compressed beyond 1/4 inch gap, the 

seal vendor has indicated they have then been compressed too far. If the carrier is 

compressed completely to 'solid height', the spring force will only return to about 70% of 

its rated amount when the carrier is released. The seal vendor was able to duplicate 

our spring force findings on the 3 spare parts in their inventory (mid 40 lbf range at 1/4 

inch versus the design 50-72 lbf) by compressing the carrier of a new spare part 

completely and then re-measuring the spring force at 1/4 inch spacing. 

PVNGS had developed the practice of compressing the carriers all the way to solid to 

measure spring rates to choose the best carrier during the installation part choice effort, 

as well as exercising the carrier to ensure the guide pins move smoothly and are not 

bound up.
283

The spring force provides sealing during static periods and during pump startup. During 

pump runs, hydraulic forces, pushing against the rotating element, provide the sealing 

force. The hydraulic forces take time to build up and reseat the sealing surfaces if 

spring force is insufficient to keep the seal tight during pump start. 

During the period of startup, if the seal is not tightly sealing, the carbon stationary seal is 

exposed to flushing water flow. There is an area on the degraded carbon seal removed 

from the 2B HPSI Pump that was discolored and not completely flat when measured 

using an optical flat. This was not well understood and further analysis by an off-site 

Laboratory was performed. This location aligns with the flushing water line. There were 

micro mils of 'erosion' caused to the carbon sealing surface while the seating faces 

were not touching tightly during pump start and period of running waiting for the seal to 

reseat - sometimes hours long. Since the carbon seal is stationary, the flushing water 

flow strikes the same area of the seal face until the seal reseats. The ‘erosion’ appears 

to have contributed to the sustained leak flow experienced in this event. The ‘erosion’ is 

considered to be a contributing cause resulting from the effects of the weakened 

springs. 

When the pump is not running or just after being started, it is the seal carrier springs 

that provide the sealing force pressing the rotating seal (tungsten) against the stationary 

seal (carbon). If the springs are not strong enough, the seal will develop slow leaks or 

weeping under static conditions (i.e. the pump not running). Also on pump start, there 

will be a spray of water out of the seal followed by a leak rate that will decrease over 

time. This is what has been observed with the Q class HPSI Pump seals installed to 

date. These seals were installed in the 3A, 3B HPSI Pumps April 2009 and in the 2B 

HPSI Pump October 2009. The 2B pump developed a larger than usual leak rate upon 

the pump start in February 2010. The leak rate began as a pencil stream and 

decreased to 500 ml/hr in 15 minutes. The leak rate continued to decrease and was 

measured as 250 ml/hr 25 minutes later. This is indicative of weak springs allowing a 

large leak rate at pump start and the leak rate decreasing as the hydraulic forces build 

up in the seal area which combine with run time to reseat the rotating seal on the 

stationary seal face.

Our experience with HPSI Pumps has been the longer they run the less they leak. The 

seals need time to reseat themselves and the components need time to heat up and 

come to stable equilibrium for these seals to work optimally. 

Seal vendor representatives, present for the seal installation of the 1B Low Pressure SI 

(LPSI) pump seal (similar seal construction) informed PVNGS personnel that they build 

their seals for pumps that are in use most of the time, not used in standby and only 
284

operated for short periods of time. The seal vendor representative suggested the need 

for stronger springs to maintain no leakage during standby periods and infrequent pump 

starts. The seal faces would wear slightly faster during pump operation but that wear 

would not impact our pump mission times.

Conclusion

The new Q Class mechanical seals currently installed in the 3A, 3B, and 2B HPSI 

Pumps may have been degraded by the way PVNGS maintenance and engineering 

personnel have manipulated these seals and therefore are susceptible to leakage 

during static conditions (i.e. pump not running) and during pump start. If leakage occurs 

during pump start, it is expected to decrease rapidly after the pump is running and 

should decrease to minimal or no leakage. If static leakage occurs, it is expected to 

slowly increase until the pump is run long enough to completely reseat the sealing 

faces. This time is not necessarily constant or precisely quantifiable (depends on the 

particular pump and seal), but it is expected to be a reasonably short time (order of 

hours), after which seal leakage should have decreased to a negligible rate relative to 

the system limits of 1500 ml/hr.

Obviously, if more measureable leakage were to persist over a longer time, the system 

limits of 1500 ml/hr would ultimately govern this leakage. However, at this time, there is 

no evidence that leakage would increase during pump operation over the mission time 

of the pump and therefore reasonable assurance that the 1500 ml/hr total ECCS piping 

leakage limit would continue to be met.

Corrective actions

Have seal vendor representatives support for any future seal replacements until 

corrective actions are in place to preclude seal degradation during installation by 

PVNGS personnel.

Add information to the HPSI Pump rework procedure, with instructions to not compress 

the seal carrier closer than 1/4 inch spacing with a caution about spring damage and 

check for seal flatness. Make similar changes to LPSI and Containment Spray 

procedures also.

Evaluate whether the HPSI pump should be run continuously for 3-4 hours upon initial 

startup following a seal change to properly break in the new seal(s). Make appropriate 
285

changes to the HPSI Pump rework procedure. This would be considered a lessonslearned enhancement action.

Return the 3 degraded HPSI spare seal kits to the vendor to be refurbished.

PVNGS Engineering - work with the seal vendor to obtain springs that still provide 

design force after being compressed tight - return all spare parts for refurbishment if 

springs are changed.

Determine needed changes to ECCS pump maintenance training courses.

Direct Cause 

HPSI 2B seal leakage was caused by weakened springs that allowed the seal faces to 

not be tightly compressed which resulted in a large leak rate.

Apparent Cause 

A lack of vendor information allowed PVNGS personnel to fully compress the HPSI 

Pump seal carrier springs which resulted in weakening these springs.

Supporting Facts

• Vendor information, in their shop drawings, not provided to PVNGS, 

cautions against compressing the new Q class HPSI seal carrier springs 

beyond their ‘working height’ and no cautions were provided about 

potential seal damage if the springs are compressed.

• Static leakage is controlled by seal spring force acting on the seal 

surfaces.

• Initial pump start causes a spray of leakage that is not immediately 

stopped by spring force – indicating weak springs.

• PVNGS spring rate testing methodology versus vendor methodology 

(seals S/N 02, 03, & 06 are now degraded and need to be refurbished).

• PVNGS compressing the carrier to ensure guide pins moved smoothly.

• Spring force measurements performed by PVNGS and vendor verified this 

degradation mechanism.

• Leak rate decreases over time as the pump is being run indicating sealing 

surfaces were wearing in and reseating as the seal was being pressurized 

by pump flow.
286

Contributing Cause 

A lack of surface flatness or sealing surface degradation occurred in the carbon seal 

face which was exposed to flushing water flow when the seal faces were not tightly 

compressed.

Supporting Facts

• Flatness test using light table/light bands.

• Discoloration.

• Possible material issue since the discoloration, area that is not flat, aligns 

with the flushing water flow.

Other Issue 

PVNGS should work with Flowserve to obtain springs that still provide design force after 

being compressed tight.
287

Fault Tree Leaking Mechanical Seal

YES

Leaking under dynamic 

conditions

Leaking under static conditions

YES

Pump Problem

NO

Seal face Problem

YES

Gasket or o-rings damaged 

or improperly installed

NO

Items such as:

Loss of seal flushing 

water flow

Seal flushing lines 

not vented

Excessive shaft 

movement- unloads 

seal

Balance drum 

setting

Constant dripping –

 

Crystallized boron

NO

Defects in sealing face surfaces

YES 

CONTRIBUTING CAUSE

Weak 

spring 

force

YES

Foreign material between seal 

faces

Foreign material 

between seal faces

NO

Seal faces damaged 

during installation

NO

Leak rate decreases over 

time

Cocking sealing surfaces 

during installation

NO

Over tightened 

stationary face

NO – located by pin

Cocking sealing surfaces 

during installation

NO

Seal faces damaged during 

operation

YES – collateral damage

Seal faces damaged during 

installation

NO

Faces wear over time

YES

Installation issue

YES

APPARENT CAUSE

Design issue

YES
288

EQUIPMENT FAILURE MODES and CAUSAL FACTORS CHART

HPSI 2B seal not 

leaking

Seal replaced 

during U2 

10/2009 

outage 

Seal leaked 

initially but 

leakage stopped 

after running the 

pump

Seal leaking under 

static conditions

Seal leakage during 

post maint testing

Non-Q class seal

Q class seal Took 3 attempts to finally get a 

good seal installation – vendor 

supervised

Considered normal for new 

seals – need run time for seal 

surface to seat

Especially true for Q class 

seals – springs not a strong 

as older style non-Q class 

parts – Mechanics 

No leakage following 

post maint testing at 

end of Unit 2 outage

Found to be leaking 1 

drop per 7-8 minutes in 

Feb 2010

Seal leaking – flow decreased 

from steady stream to 500 

ml/hr to 250 ml/hr over 40 

minutes pump run

Leak rate dropped to1 

drop per 20 seconds 

after pump was 

d

Determined to be a 

seal failure – seal 

replaced

During installation – sometimes 

PVNGS testing seal kits compresses 

the springs to solid height – Vendor 

now indicates this damages the 

springs and results in 30% drop in 

spring force of Q class springs 

APPARENT CAUSE

Discoloration found on carbon seal face

CONTRIBUTING CAUSE


291

Session 5: Regulatory Interactive

Session Chair: Anthony C. McMurtray, U.S. NRC

293

Interface Between IST Program and Design Engineering

Ed Cavey

Fermi 2 IST Program Manager

Newport, Michigan, USA

Abstract

Several issues arose in recent years that demonstrate the need for a structured process 

for interface between the Design Engineering group and the Inservice Testing (IST) 

Programs at each power reactor site. A few examples are: 

• Valve stroke time limits - design issues such as the effect of Emergency Diesel 

Generator (EDG) frequency and Limit Switch settings on Motor Operated Valve (MOV) 

stroke times and whether IST criteria is reconciled with those impacts. 

• The effect of actual fluid temperature on indicated pump flow readings due to fluid 

density impact on flow element output. 

• The impacts of design calculation factors such as EDG frequency, suction strainer 

clogging, etc. on IST pump performance limits.

This presentation will examine these and other examples in detail to illustrate the need 

for design engineering to quantify and communicate the appropriate design limits. IST 

engineers need access to this information when they are determining procedural criteria 

for pumps and valves so the acceptance criteria can be truncated as necessary.

Introduction

Individual power plants undergo periodic Nuclear Regulatory Commission (NRC) 

inspections, including Component Design Basis Inspections (CDBI). These inspections 

often involve highly technical issues, including IST and criteria involved with specific 

components. Inspectors often question the IST Program Managers about test 

methodology and the basis for acceptance criteria. When acceptance criteria is based 

on design limits, which are more limiting than Code-based criteria, the IST personnel 

need to be able to engage design engineering personnel in the discussion.
294

Recent CDBI Issues

EDG Low Frequency 

There have been several instances in the past 6 years where inspectors were intent on 

verifying that surveillance test criteria for alternating current (AC) powered pumps was 

truncated appropriately for EDG low frequency conditions. Most plants have EDG 

speed and emergency bus frequency controls with limits of +/- 2% or ± 1.2 hz. It is 

understood that pumping performance of an AC powered pump will be diminished with a 

reduced input power frequency and for pumps with relatively low operating margins this 

2% impact can be significant. In some cases, the IST criteria was adjusted in the 

conservative direction to account for the 2% underfrequency condition. The impacts of 

such conditions need to be embedded into plant design calculations, not parsed one-byone into IST criteria.

Emergency bus frequency can have a slight effect on AC powered valves as well. 

Stroke times of these valves would increase. IST engineers may be prompted to adjust 

their acceptance criteria by the 2% value as a response to inspector concerns. Again, 

these factors need to be evaluated within design calculations.

MOV Limit Switch Settings 

Another recent issue involved the setting of limit switches in MOVs. MOVs are typically 

stroke timed from the control room using the open / close indications. The limit switches 

that actuate the remote indications are set at points of valve travel. For example, the 

limit switch that extinguishes the valve open light at the end of a closing stroke may be 

set at a point approximately 3-5% away from valve hard seat contact. That setting is 

appropriate because the same limit switch rotor may also operate the contact which 

provides for electrical bypass of the open torque switch contact. 

The limit switch which operates the close light may be set at the point of opening valve 

travel well away from the backseat position. The same rotor may operate the limit 

switch that turns off the motor in the opening direction. Many valves with relatively high 

stroke speeds would suffer higher than desired inertial seating forces in the open 

direction if the motor cutoff point is too close to the backseat point. The recorded stroke 

times are based on these limit switch settings, not actual valve position. For valves with 

small operating margins between actual stroke times and design requirements, this 

variation between true and indicated valve position may be a concern.

Design calculations have to reconcile many different design factors and assumptions. 

Design engineers must consider many different accident scenarios and operating 

conditions. The hydraulic calculation for the Fermi 2 Core Spray system (Design 

Calculation 0230 Vol. I) is 399 pages long. Some key aspects of this calculation are:

1) Provides the minimum head / differential pressure limits to satisfy the Technical 

Specifications.
295

2) States the minimum accuracy requirements for flow and pressure indications 

during acceptance testing.

3) Considers the effects of EDG frequency, system frictional losses, suction strainer 

clogging, flow orifice plate degradation, 8 different operating modes, 3 to 4 

specific cases in each mode, system source water temperatures and other 

factors.

This design calculation is very complex and the incorporation of all the design factors 

requires very careful analysis. If IST engineers are employing simple truncations to 

criteria without close cooperation with their design engineering staff, it is likely that 

margins would be reduced unnecessarily. 

When questions involving non-Code impacts on pump and valve criterion come up 

during CDBI inspections, the IST Engineer needs to ensure that design engineers 

become involved. Engineering managers may need to become involved to ensure that 

issues are evaluated in a comprehensive multi-disciplined approach. NRC inspectors 

need to be sensitive to these issues as well. If the question they ask is "Why doesn't 

this IST criteria account for EDG underfrequency?" it may influence the IST and 

Licensing personnel to "fix that problem" without engaging the design personnel.

Emergency Core Cooling Systems (ECCS) Pump Flow Indication Errors Due to 

Temperature Bias 

In July 2009 Operational Experience (OE) 29428 was issued. The following is one 

paragraph from that OE:

On June 25, 2009 NRC CDBI inspectors questioned the Inservice Testing Engineer 

on how various uncertainties, including the pump flow element accuracy, were 

considered in the RHR [Residual Heat Removal] pump, ASME OM Code 

Comprehensive Pump test acceptance criteria. The basis for the question was to 

ensure design requirements were properly considered during testing as identified in 

NRC Information Notice IN 97-90, “Use of Nonconservative Acceptance Criteria in 

Safety-Related Pump Surveillance Tests.” During the response to this question and 

related follow up questions review of the vendor supplied orifice data sheet 

appeared to indicate that the orifice full scale differential pressure was 316.15 inches 

of water at a flow rate of 3000 gpm and a flow temperature of 350 degrees F. 

RHR pump testing is routinely performed at flow temperatures of 80 to 95 degrees F. 

Testing with a fluid temperature considerably less than the assumed fluid 

temperature for the transmitter calibration would result in the indicated flow being 

higher, approximately 5%, than the actual flow.

This OE was reviewed and it was determined that Fermi likely contains the same 

vulnerability. The RHR pump flow indication uses an inline flow orifice as its source. 

Flow passing through this orifice creates a pressure drop which is measured by a 

differential pressure (DP) transmitter. As the fluid temperature varies, the density varies 
296

proportionally. The fluid density affects the amount of pressure drop across the orifice 

and thus influences the indicated value. The instrumentation and control (I&C) 

calibration for the flow loop inserts a known DP at the transmitter and verifies correct 

reading in the control room. The calibration tables correlate the flow and DP readings at 

the assumed accident temperature. According to I&C design engineering personnel, 

the overriding design philosophy is that the instrumentation in the control room be 

accurate under accident conditions. If accuracy could be affected by system conditions, 

it is better that any manual corrections required be done when the plant is in a normal 

steady-state condition. An accident scenario or event, with all of the extraordinary 

demands on the operating crew, is not the time to have to perform manual calculations 

for critical parameter accuracy. See Figure 1 below:

FIGURE 1

The flow orifice design calculations are circa 1983-1984 documents and are likely 

without revision since that period. These design calculations state that the calibrated 

indications will be accurate at the design temperature and if inservice testing is 

performed at a fluid temperature other than the design value, a correction factor must 

be applied. These calculations provide a graph displaying the temperature correction 

factor versus temperature to aid the IST engineers. Initial system acceptance testing in

the early 1980's was completed using the appropriate temperature corrections; 
297

however, the initial surveillance procedures created for RHR and other pump systems 

did not include any temperature correction for flow. 

Fermi corrective action document (CARD) 09-26745 was initiated in early September 

2009 based on this concern and assigned to Design Engineering - I&C. Unfortunately, 

that CARD investigation was less than adequate and the CARD was dispositioned and 

closed in late October with no action taken. That CARD disposition was challenged with 

the help of the Nuclear Quality Assurance group. A series of meetings were held in 

November 2009 to more thoroughly evaluate the impact of the OE on Fermi plant 

systems. It was determined that Fermi contained a similar problem with flow 

measurement accuracy for the RHR pumps. Additionally, this adverse issue applied to 

all divisions of all Fermi ECCS systems, but the RHR impact was the most significant 

because of the higher flow values involved. Investigation identified that flow readings in 

the Main Control Room (MCR) are calibrated for true accuracy when the fluid 

temperature (RHR suction) is 200 deg F. At normal system temperatures of 70° - 75° F, 

the MCR flow indication will indicate approximately 200 GPM HIGHER than actual flow. 

Quarterly testing verifies Technical Specification (TS) surveillance requirement (SR) that 

RHR can deliver ≥ 10,000 GPM. Applying the density correction to past 

surveillance results showed that the majority of the testing had corrected flow 

values < 10,000 GPM. A Level 2 (high safety significance) CARD 09-28815 was 

initiated as a result, requiring immediate operability reviews of all ECCS systems. The 

RHR surveillance procedures were revised immediately and testing was performed 

within days to confirm RHR operability. Further extent of condition analysis was able to 

support initial operability determinations on the other affected systems. Procedure 

revisions for all the other affected systems have been made. Below is an excerpt from 

our current RHR system surveillance procedure which illustrates the change that was 

made to account for the density correction to flow.
298

This is an example of the need for close cooperation between "in plant" engineers such 

as IST and System Engineers and the design engineering staff. 

One example of a "structured process" for interface between design engineering and 

IST at Fermi was a one-time reconciliation of all IST pump testing conditions and 

acceptance criteria against design calculations performed in 2006. That effort produced 

an engineering evaluation to document the effort and did discover a few necessary 

corrections to both design calculations and IST procedures. In one instance, it was 

discovered that a design calculation included an assumption of no more than 5% 

lifetime pump degradation. The IST criteria had been set based on typical ASME OM 

Code 10% allowance. The IST criteria for that pump was adjusted to match the 5% 

assumption in the design document. 

Following that one-time effort, a process change was made that required design 

engineering review and concurrence for any changes to pump testing methods or 
299

criteria. These in-line reviews by the design engineering personnel ensure fidelity to the 

2006 base evaluation.

The purpose of inservice testing is to detect and trend component degradation. It is 

commonly believed that there should be deliberate separation between IST and TS 

operability testing. One philosophical view I have heard is that TS surveillance testing 

proves that a component or system is operable at this moment and that it has remained 

operable since the last test. The IST test then establishes confidence that the system or 

component will remain operable until the next test. In real world application, there is 

often a single test which is meant to satisfy both the TS SR and the IST. This "double 

duty" style of testing is what creates the need for close cooperation between IST 

engineers and design engineers.

Conclusion

This process at Fermi has made the design engineers more aware of the ASME OM 

Code requirements for testing and criteria, which has helped to ensure that subsequent 

revisions to design calculations did not invoke more restrictive limitations unless 

absolutely necessary. The IST and system engineers have likewise become much 

more familiar with the hydraulic design calculations and especially how all the various 

design factors are embedded. This process has strengthened our compliance with 10 

CFR 50.55a as well as 10 CFR 50 Appendix B. 

Acknowledgments

A. Klemptner - PSE I&C Fermi 2

T. Lang - PSE Mechanical & Civil Fermi 2

G. Wojtowitz - PSE Mechanical & Civil Fermi 2

References

OE 29428
300

Inservice Testing Is About Operability 

Kevin Mangan*, Senior Reactor Inspector

Frank Arner*, Senior Reactor Inspector

Engineering Branch 2, Division of Reactor Safety

Region 1, U.S. Nuclear Regulatory Commission

* This paper was prepared by staff of the U.S. Nuclear Regulatory Commission (NRC). 

It may present information that does not currently represent an agreed upon NRC staff 

position. NRC has neither approved nor disapproved the technical content.

Abstract

Title 10 of the Code of Federal Regulations (10 CFR) 50.55a(f) requires that nuclear 

power plants perform inservice testing (IST) of American Society of Mechanical 

Engineers (ASME) Section III Class 1, 2, and 3 components (pumps and valves) in 

accordance with the ASME Code for Operation and Maintenance of Nuclear Power 

Plants (OM Code) to determine component degradation. In addition to the CFR, the 

requirement for testing using the ASME OM Code had historically been found within 

many licensee technical specifications (TSs). This requirement has subsequently been 

removed from many TSs and now resides in the licensee Technical Requirements 

Manual (TRM). In addition to the testing required by the ASME OM Code, licensees are 

required to test safety-related structures, systems, and components (SSCs) to verify 

operability and ensure TS surveillances, and in some cases design requirements, are 

met. Licensees have established test programs to meet the requirements of the ASME 

OM Code, as required by 10 CFR 50.55a, and quarterly TS surveillance requirements, 

as required by their license. Because different component performance criteria are 

required to confirm compliance with the ASME OM Code, TS surveillances, and design 

requirements, test results are sometimes not properly evaluated to ensure the results 

meet all the requirements of the license and ensure the system can perform its design 

function. This paper will compare the various parameters measured during IST and TS 

testing, and show how those parameters are used in design calculation assumptions as 

they relate to the ability of safety-related pumps to respond to a design basis accident or 

event. Additionally, the paper will discuss violations of Nuclear Regulatory Commission 

(NRC) requirements resulting from incorrect pump testing acceptance criteria and 

improper evaluation of pump test results.
301

Introduction

To ensure that pumps are capable of responding to design basis events and accidents, 

licensees are required to comply with Title 10 of the Code of Federal Regulations (10 

CFR), including 10 CFR 50.55a, “Codes and Standards,” and implement programs that 

meet the quality assurance requirements of 10 CFR 50 Appendix B, Criterion III, 

“Design Control”; Criterion V, “Procedures”; and Criterion XI, “Test Control.” 

Additionally, licensees’ TSs include specific requirements for performance of periodic 

surveillance testing of safety-related pumps. The purpose of these programs, in 

combination, is to verify the operability of the pumps and to provide reasonable 

assurance that the pumps will be able to adequately respond to design basis events 

and accidents. 

There are five terms defined below that are used to describe the operating condition of 

the safety related systems. These terms are used to describe component readiness 

and need to be understood and addressed when evaluating pump testing results. 

Fully Qualified: An SSC is fully qualified when it conforms to all aspects of its 

licensing basis, including all applicable codes and standards, design criteria, 

safety analyses assumptions and specifications, and licensing commitments. 

Degraded Condition: A degraded condition is one in which the qualification of an 

SSC or its functional capability is reduced. Examples of degraded conditions are 

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

equipment. Examples of conditions that can reduce the capability of a system 

are aging, erosion, corrosion, improper operation, and maintenance (Reference 

1). 

Nonconforming Condition: A nonconforming condition is a condition of an SSC 

that involves a failure to meet the current licensing basis (CLB) or a situation in 

which quality has been reduced because of factors such as improper design, 

testing, construction, or modification so that an SSC fails to conform to one or 

more applicable codes or standards (Reference 1).

Operability: A system, subsystem, train, component, or device shall be 

OPERABLE or have OPERABILITY when it is capable of performing its specified 

safety functions, and when all necessary attendant instrumentation, controls, 

normal or emergency electrical power, cooling and seal water, lubrication and 

other auxiliary equipment that are required for the system, subsystem, train, 

component, or device to perform its function(s) are also capable of performing 

their related support function(s). (Reference 2)
302

Inoperable: A system, subsystem, train, component, or device is Inoperable 

when it is not capable of performing its specified safety functions.

To inform licensees of the NRC’s expectations for 10 CFR compliance, the NRC has 

published various generic communications. Specifically, the NRC has created several 

generic communications to assist the licensee in determining how to determine the 

operating condition of an SSC. The NRC’s guidance for inservice testing was provided 

in Generic Letter (GL) 89-04(Reference 3) and NUREG -1482, Rev. 1, (Reference 4). 

These two NRC generic communications provide guidance on how to develop and 

implement an acceptable IST program. 

As part of the guidance for implementation of an IST program, NUREG-1482, Rev. 1 

also established expectations in order to conclude that a pump is fully qualified. 

NUREG-1482, Rev. 1, Section 2.1, “Compliance Considerations,” states “This testing is 

intended to assess the operational readiness of the stated component,” and Section 5.6, 

“Operability Limits of Pumps,” describes how operability limits must always meet, or be 

consistent with, licensing based assumptions in the safety analysis for a plant. Section 

5.6 also references an additional NRC GL 91-18 (Reference 5) (replaced by Regulatory 

Issue Summary (RIS) 2005-20 (Reference 6)). With regard to pump testing, GL 91-18 

is referenced to provide guidance on how to assess operability of a system when pump 

testing determines a pump is degraded or not fully qualified.

Subsequent to the issuance of the generic communications listed above, the NRC, 

through the inspection program, continued to identify deficiencies with licensees’ testing 

programs. To inform all licensees of these deficiencies, the NRC issued Information 

Notice (IN) 97-90 (Reference 7). The purpose of the IN was to inform licensees that 

“although licensees have established IST acceptance criteria that meet the 

requirements specified in the ASME OM Code, the criteria at some plants allowed 

safety-related pumps to degrade below the performance assumed in the accident 

analysis.” The discussion in the IN focused on the requirement for licensees to address 

the operational readiness aspect of these pumps when reviewing test results. 

Since the issuance of the IN, NRC inspection teams have continued to find nonconservative acceptance criteria in testing programs. The establishment of pump 

testing requirements and review of pump testing results should not only verify ASME 

OM Code compliance, but verify that design basis functions have been maintained, 

including TS requirements. This paper discusses, in general terms, NRC inspection 

findings related to identified deficiencies between the various testing programs and 

associated requirements that could lead to, or has lead to, incorrectly assessing 

operability of safety-related pumps. Additionally, some of the inspection findings 

identified by NRC inspection teams over the last five years are listed in the attachment 

to this paper.
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ASME OM Code Limits

The ASME OM Code provides testing guidelines and acceptance ranges for pump 

testing. The alert and required action ranges are defined by the ASME OM Code. 

When the pump testing is performed in accordance with the requirements of the ASME 

OM Code and the results are maintained within the limits of the acceptable range, the 

component can be considered in conformance with the ASME OM Code testing 

requirements. If the limits are exceeded, the ASME OM Code requires actions by the 

user to address the degradation. The NRC has also provided guidance on 

requirements for assessing the degraded condition as it relates to operability of pumps 

that enter alert and required action ranges. As previously discussed, RIS 2005-20 

provides guidance for assessing the operability of equipment that is found to be 

degraded or non-conforming. Additionally, Position 8 of Attachment 1 to GL 89-04 

(Reference 3) notes that if performance data fall within the required action range, 

regardless of whether the limit is equal to the TS limit or more restrictive, the pump or 

valve must be declared inoperable immediately and the limiting condition of operation 

(LCO) must be declared not met and the applicable conditions must be entered. The 

failure to meet the acceptance levels in the ASME OM Code is considered a degraded 

and nonconforming condition. 

The 9900 Technical Guidance (Reference 6) clarifies the basis for this position by 

discussing the underlying assumptions as the basis for operability. Reference 6 states, 

in part, that the SSCs that TS require to be operable are designed and operated, as 

described in the CLB [current licensing basis], with design margins and engineering 

margins of safety to ensure, among other things, that some loss of quality does not 

result in immediate failure to meet a specified function. The CLB includes commitments 

to specific codes and standards, design criteria, and some regulations that also dictate 

margins. Therefore, the underlying assumption that there is margin for degradation of a 

pump is no longer valid when the pump enters the ASME OM Code action range absent 

any understanding of the causes of the degradation.

Therefore, the NRC has defined that the required action range for a component is also 

bounded by any design and engineering margins. When a pump parameter required for 

a pump by the TSs falls within the required action limit, it should be considered 

degraded and non-conforming and consequently, licensees must enter the TS Action 

Statement and evaluate the cause of the degradation. A variety of actions exist to 

address a nonconforming condition of pump performance being within this required 

action range. For example, when the required action range is more limiting than its 

corresponding TSs, the corrective action need not be limited to replacement or repair; it 

could involve an analysis to demonstrate that the specific performance degradation 

does not impair operability and that the pump will still fulfill its safety function. The 

analysis should address the capability of the pump to deliver the required flow for the 
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required mission time. This may allow justification for establishing a new required 

action range as allowed by the ASME OM Code. 

Design Flow and Pressure

TS or design basis testing performed on pumps should demonstrate that they can meet 

the design requirements. NRC inspections have determined that, for a variety of 

reasons, ASME OM Code acceptance limits do not always bound the design basis flow 

and pressure requirements for the system. This is acceptable, but licensees should not 

be using the ASME OM Code acceptance limits for a TS or design basis test. The IST 

program engineer, system engineer, and design engineer should all understand and 

concur with the testing methodology so that the operability of the system can be 

properly evaluated. Various program requirements are incorporated into test programs 

and procedures employed by licensees to determine operability, TS surveillance 

compliance, and ASME OM Code compliance. Unfortunately, these requirements come 

from different sources and the test results that are evaluated may not be measuring the 

same flow or pressure attribute.

 

In order to evaluate the operability of a pump, test results should show, to the maximum 

extent practical, that the pump will be capable of responding to design basis accidents 

and events. This should be done through TS or design basis parameter testing. As a 

minimum, the test results should ensure, either directly or in concert with design 

calculations, that the minimum acceptable pump performance will provide flow credited 

in the worst case accident or licensing basis event. The Updated Final Safety Analysis 

Report defines the design basis accidents and what equipment is credited to respond to 

events. Typically, the assumed Core Operating Limit Report (COLR) flow rate 

determines the minimum actual flow requirement for a pump; however, there are other 

licensing basis events (Fire or Station Blackout) that may determine the most limiting 

flow rate for a pump. It should be noted that although the analysis methodology used 

for the COLR has conservatism built into it, the NRC considers the COLR flow rates as 

the minimum requirements and credit for additional conservatisms within the COLR 

cannot be used for additional margin. Because the COLR flow rates do not account for 

inaccuracies, such as measurement error, other analysis must include these 

inaccuracies to determine the minimum acceptable test flow.

Licensees’ TSs also contain minimum flow requirements within the TS surveillance 

requirements and these flow rates are typically greater than those established in the 

COLR. The TS minimum flow rates are part of the plant’s license and must be met to 

maintain system operability. The difference between these two flow rates is a result of 

conservatism accounting for some measurement error within the TS surveillance 

acceptance limits.
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The NRC Inspection Manual, Part 9900 (Reference 1), Technical Guidance, Section 

3.0, “Acceptable Measurement Tolerances for Technical Specification Limits,” states: 

“The TS limits are established with allowance for measurement tolerances 

already incorporated. The limits take into consideration measurement 

uncertainties as necessary to assure safe plant operation. The stated limit 

presupposes that the licensees have tolerances consistent with normal industry 

standards (e.g., ASTM, IEEE, ACI, etc.).”

In general, IST instrumentation inaccuracies are within the limits of the TS surveillance 

requirements. Therefore, IST test results can be readily compared to TS surveillance 

requirements to determine if the surveillance was met, as long as the test is measuring 

the same attribute.

The calculations to determine the design pressure requirements for a pump are typically 

developed by the licensee. The calculations determine the minimum pump discharge 

pressure required to meet the assumed flow conditions stated in the COLR. An 

additional calculation may be needed to determine the discharge pressure required to 

meet TS surveillance requirements. This pressure is based on the verbiage used in the 

TS surveillance and these calculations include the worst case design pressures at the 

pump suction using minimum tank or heat sink level and suction piping head losses at 

design flows. The calculations should also assume the highest backpressure that would 

occur at the discharge point of the system. For pumps that discharge into the primary 

system or steam generators, this should include the safety relief valve pressure plus 

drifting tolerances. Other variables that should be included in the calculations when 

determining the minimum acceptable levels for the IST tests are variations in suction 

sources, maximum assumed vessel pressure, piping and component friction factors, 

and pressure gauge accuracy. 

The ASME OM Code has criteria to establish the flow and differential pressure test 

point(s) for pumps. The reference flow and/or differential pressure are based, in part, 

on the design flow rate and discharge pressure requirements of a pump, but the 

acceptance criteria are based on a percentage increase or decrease in pump 

performance. There is a potential concern with the developed acceptance criteria 

because the allowed degradation of a pump in the ASME OM Code, as defined by the 

“Alert Range” and “Required Action Range,” could result in COLR or design bases 

pump performance assumptions not being met. Additionally, for centrifugal pumps, the 

IST test pressure acceptance limits are stated as differential pressure across the pump, 

while required pressure to ensure adequate flow to the vessel is based on pump 

discharge pressure limits. Finally, unlike required flow rates, which can be found in 

licensing basis documents, discharge pressure requirements are determined through 

design calculations and must include conservative evaluations in the calculation. 
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Speed Control

The ability to control and adjust the speed of the driver can become critical in 

determining the flow and pressure limits for a pump. The testing of turbine driven 

pumps that discharge into the primary system or steam generators is typically not 

performed and is not required to be performed, at design pressures and flow rates. To 

ensure that the design bases of the pump can be achieved, the developed test criteria 

for the quarterly and biennial testing results must be compared to a design calculation to 

determine pump operability. Typically, pump affinity laws are used to extrapolate the 

results to verify the ability of a pump to reach the required flow and pressure. For these 

pumps, it is important to understand the design calculation assumptions and system 

capabilities to assure that the testing program acceptance criteria are bounding. 

One key assumption in the design calculation is the speed of the turbine. NRC 

inspections have identified that, due to the design or setup of the control circuit of the 

flow/speed control circuit, licensees’ calculations sometimes assume an unachievable 

increase in the turbine/pump speed. Typically, reactor core isolation cooling (RCIC) and 

high pressure cooling injection (HPCI) controllers are designed to achieve a preset flow. 

If the flow is below the setpoint, the controller sends a signal to open the throttle valve 

until the preset flow is achieved. This will increase pump discharge pressure as the 

speed of the turbine increases, resulting in additional flow until the design flow is met. 

However, the controller signal is limited in range and an internal speed control loop is 

calibrated to not allow speed to increase above a design speed reference. This has 

resulted in controllers not being able to open the steam admission valve far enough to 

meet the design flow and pressure requirements because the required speed, perhaps 

due to pump degradation, was above the maximum output signal of the controller. In 

this case, the pump IST and TS surveillance tests were met, but the pump, although 

capable of meeting the design requirements, would not have provided the required flow 

because it would have been limited by the controller output. This can occur because 

the existing TSs often only require pump flow rates at normal reactor pressure and not 

the worst case backpressures as afforded by safety relief valve setpoints. 

Because auxiliary feedwater (AFW) turbine system controllers are designed to maintain 

turbine speed, they are not susceptible to the RCIC and HPCI control issues referenced 

above, but control of the speed during the testing is important to maintain design 

assumptions. Typically, these tests are performed by setting the speed manually. 

Licensees have created operability questions when the speed used in the test is higher 

than that assumed in the design calculations. Additionally, the AFW quarterly testing is 

typically performed using minimum flow lines, resulting in flow rates that are much lower 

than design flow rates. Therefore the results are not readily comparable to design 

requirements in order to assess pump operability without reviewing pump differential 

pressure parameters. Understanding the assumptions used to extrapolate pump curves 

and making adjustments using affinity laws can lead to errors in the evaluation of pump 
307

performance. Speed controller errors and measurement errors must also be accounted 

for in either the design calculation or the test procedure. It is critical to understand the 

assumptions in the design calculations in order to set the speed range of the test. For 

ASME OM Code testing, the speed is one of the reference values used for variable 

speed drives. If the acceptance criterion for speed is higher than the speed assumed in 

the design calculation or the speed set per the operating procedures, then the pump 

could be operating outside of its design limits. In this case, the higher speed could 

result in acceptable IST head and flow results, but these results would not be achieved 

during a design basis event.

When testing pumps with electric driven motors, speed is assumed to be consistent 

from test to test and is, therefore, not recorded as part of IST testing. This assumption 

is appropriate since the offsite grid provides a very consistent 60 Hertz (Hz) to the 

motors. The NRC has raised questions as to the validity of the motor speed assumption 

for design calculations because the system shall be operable whether it is supplied from 

the offsite grid or the onsite emergency diesel generators (EDGs). TS surveillances for 

EDG regulators generally have a ± 1.2 Hz allowed frequency variation when being 

tested, which calls into question what speed the motor should be assumed to be 

operating at during a design basis accident or event. Additionally, NRC inspections 

have found that some licensees set their EDGs at a frequency other than 60 Hz. 

Licensees should address the basis for the speed they are using in their design 

calculations as it relates to electric driven motors.

System Flow Balances

For cooling water systems, licensees have taken two approaches to addressing system 

operability. Some licensees have developed system models to determine flow to each 

component. Typically, a licensee will determine the flow and pressure, through actual 

measurement, at some points in the system to validate the model. Another approach is 

to perform a system flow balance, which is typically performed during refueling outages. 

For this method, each component flow must be verified above some predetermined flow 

rate to establish system operability. 

In both approaches, the quarterly IST pump test may be critical to assuring system 

operability. If the system flow balance method is used, then the licensee has 

established system operability based on the current pump curve for the pump used in 

the test. If degradation of the pump is identified, then the basis for operability of the 

system could be called into question. Licensees should know what flow rate margins 

exist for components in the system and what level of pump degradation or increase in 

system dynamic head loss would call into question the previously performed flow 

balance. Measurement of pump degradation based on ASME OM Code limits may not 

be indicative of TS system operability. 
308

For the modeling method, the curve used to establish the validity of the model and the 

curve used to ensure system operability should not be the same curve. The degraded 

curve, assuming a maximum system head loss, should be used in the model to show 

bounding pump and system performance. These limits should be evaluated to 

determine if the ASME OM Code action ranges or the model requirements are the most 

limiting. The more conservative curve should be used as the acceptance limit in the 

testing procedures. 

Conclusion

Testing of pumps in accordance with the limits established by the ASME OM Code may 

not be adequate to ensure operability of SSCs. The limiting acceptable conditions for a 

pump must be understood in order to properly evaluate if the pump is operable and fully 

qualified. The NRC has found that licensees have incorrectly used IST test procedures 

limits, established in accordance with the requirements of the ASME OM Code, in order 

to show compliance with TS surveillance requirements and to demonstrate operability of 

systems. Although the use of these test procedures may be appropriate for 

demonstrating operability of safety-related SSCs, they should only be used when the 

licensee understands the limits of the testing, the assumptions of the associated design 

calculations, and the way the test procedure is actually performed, including measuring 

flow, differential pressure, and equipment speed. The implementing pump test 

procedures should have acceptance limits, which may be different or more limiting than 

ASME OM Code requirements, which can provide reasonable assurance that the SSCs 

will be able to respond to the licensee’s design basis accidents and events. These 

values are often found in TSs or the licensees’ design basis or licensing documents. 

References

1. NRC Inspection Manual, Part 9900, Technical Guidance, “Operability 

Determinations and Functionality Assessments for Resolution of Degraded or 

Nonconforming Conditions Adverse to Quality or Safety.”

2. NUREGs 1430-1434, Standard Technical Specifications- Babcock and Wilcox 

Plants, Westinghouse Plants, Combustion Engineering Plants, General Electric 

Plants (BWR/4) and General Electric Plants (BWR/6)

3. Generic Letter 89-04, “Guidance on Developing Acceptable Inservice Testing 

Programs,” April 3, 1989

4. NUREG-1482, Revision 1, “Guidelines for Inservice Testing at Nuclear Power 

Plants,” Washington, DC, January 2005
309

5. NRC Generic Letter 91-18, “Information to Licensees Regarding Two NRC 

Inspection Manual Sections on Resolution of Degraded and Nonconforming 

Conditions and on Operability,” November 7, 1991

6. Regulatory Issue Summary 2005-20, “Revision to NRC Inspection Manual Part 

9900 Technical Guidance, ‘Operability Determinations & Functionality 

Assessments for Resolution of Degraded or Nonconforming Conditions. Adverse 

to Quality or Safety,’” Revision 1, Washington, DC, April 1, 2008

7. Information Notice 97-90, “Use of Nonconservative Acceptance Criteria in SafetyRelated Pump Surveillance Tests,” December 30, 1997
310

Violations Identified

The following is a list of testing related findings identified by NRC CDBI teams from 

2006 to 2011. Inspection reports can be accessed via: 

http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/listofrpts_body.html

IST Limits Below Accident Analysis

05000461/2007008 Inappropriate SX Pump Test Acceptance Criteria

Green. The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion XI, “Test 

Control,” having very low safety significance, in that, the shutdown service water (SX)

pump tests conducted did not appropriately demonstrate that the SX pumps met design 

basis accident requirements. Specifically, the pump test acceptance criteria allowed the 

pump performance to degrade below the performance assumed by the design analysis. 

Once identified, the licensee completed an evaluation. Follow-up retesting 

demonstrated the pumps’ capacity to perform required safety functions.

05000456/2010007, Non-Conservative Acceptance Criteria for CS Pump Performance 

Testing

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion XI, “Test 

Control,” having very low safety significance for the licensee’s failure to ensure 

adequate acceptance limits were incorporated into test procedures. Specifically, the 

licensee failed to consider instrument loop uncertainties when determining the alert and 

required action values used in the IST procedure for testing of the containment spray 

(CS) pumps. Consequently, the acceptance criteria for both the upper and lower limits 

on total developed head (TDH) were non-conservative. Specifically, the failure to 

consider instrument uncertainties in the development of IST acceptance criteria resulted 

in the creation of acceptance criteria values that did not ensure that the CS pump could 

meet its intended safety function. As a result, the licensee subsequently entered the 

issue into their corrective action program, performed an operability evaluation and 

concluded equipment were operable. Additional corrective actions were assigned to 

investigate and correct the cause of the apparent degradation of the 2B CS pump.

05000302/2007006 Violation of 10 CFR 50, Appendix B, Criterion XI for Failure to 

Account for Instrument Uncertainty During EFP-2 Testing

The inspectors identified a finding of very low safety significance involving a violation of 

10 CFR 50, Appendix B, Criterion XI, “Test Control,” for failure to implement a test 

program which accounted for the effects of instrument uncertainty on surveillance 
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testing of Emergency Feedwater Pump (EFP)-2 in accordance with the approved Inservice Testing (IST) program.

05000321/366/2009006 Failure to Correctly Establish Acceptance Criteria for the 

Standby Diesel Service Water Pump Section

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion XI, “Test 

Control,” for failure to correctly establish acceptance criteria for the Standby Diesel 

Service Water (SDSW) System. The licensee performed a past operability 

determination and initiated a Condition Report to revise the acceptance criteria.

Modeling and Design Basis Calculations

05000424/425/2008002 Capability of Auxiliary Feedwater System to Meet Design and 

Licensing Requirements

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion III, “Design 

Control,” for failure to include the cumulative effects of the replacement of the 1A motor 

driven auxiliary feedwater (AFW) pump rotating element, accuracy of AFW system 

resistance values, safety relief valve setpoint tolerances, and turbine driven AFW pump 

speed settings on evaluation of the performance of the AFW system.

05000382/2006008 Failure to Translate Design Basis Information into Specifications 

and Procedures

The team identified a finding of very low safety significance for a non-cited violation of 

10 CFR Part 50, Appendix B, Criterion III, “Design Control,” for the failure to translate all 

design basis information into specifications and procedures were not adequate to 

assure that instrument uncertainties were correctly accounted for in the development of 

Technical Specification values or in the surveillance test acceptance criteria.

5000498/499/2007007 Failure to Incorporate Instrument Uncertainties into Surveillance 

Requirements for Technical Specification Limiting Condition for Operation 3.5.2

The team identified a non-cited violation of 10 CFR Part 50, Appendix B, Criteria III, 

"Design Control," of very low safety significance for the failure to adequately translate 

design basis information into specifications and procedures. Specifically, measurement 

instrument uncertainties were not included in the determination of minimum allowed 

high head safety injection pump and low head safety injection pump developed head 

values used during periodic technical specification surveillance testing. 
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05000286/2007006 Non-Conservative Calculation for TDAFW Pump Discharge 

Pressure Used for Surveillance Testing

The team identified a finding of very low safety significance involving a non-cited 

violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," in that the 

licensee had not verified the adequacy of design for the turbine driven auxiliary 

feedwater (TDAFW) pump. Specifically, the pump hydraulic analysis was nonconservative, but was used to verify adequacy of surveillance test acceptance criteria 

for pump minimum discharge pressure. The licensee subsequently verified that the 

pump remained operable and entered the finding into their corrective action program to 

revise the system analysis.

05000369/370/2008002 Nuclear Service Water (RN) System Flow Analysis Deficiencies

The inspectors identified a NCV of 10 CFR 50, Appendix B, Criterion III, “Design 

Control,” for failure to establish measures to verify the design capability of the RN 

pumps. Specifically, the licensee did not perform system hydraulic analyses or use 

other means to demonstrate that RN pumps 1A and 1B could perform their safety 

function under the most limiting design basis conditions.

0500305/2007006 Non-Conservative Assumption Used in Service Water Flow Model 

Calculation

The inspectors identified a finding having very low significance and an associated NCV 

of 10 CFR Part 50, Appendix B, Criterion III, “Design Control.” Specifically, the licensee 

failed to appropriately account for service water strainer plugging in the service water 

system flow model. Upon discovery, the licensee placed this issue into their corrective 

action program and planned to formally revise the service water system flow model to 

reflect plugging of both strainers in a train.

EDG Frequency

05000369/370/2006007 Effect of EDG Under-Frequency not Included in ECCS

Pump Test Acceptance Criteria

The team identified a non-cited violation of 10 CFR 50, Appendix B, Criterion III, 

“Design Control.” The licensee did not account for emergency diesel generator under

frequency in test acceptance criterion for ASME Section XI testing of the high head 

safety injection (NV) pumps 1A and 1B. The licensee entered this issue into the 

corrective action program and performed an operability assessment which determined 

that the pumps were operable.
313

Speed Control

05000277/278/2006009 Non-Conservative HPCI and RCIC Pumps Test Acceptance 

Criteria

The team identified a finding of very low safety significance involving a non-cited 

violation of 10 CFR 50, Appendix B, Criterion XI, Test Control. The team determined 

that the licensee had failed to ensure that the high pressure coolant injection (HPCI) 

and reactor core isolation cooling (RCIC) pump hydraulic performance test procedures 

had acceptance criteria that incorporated the limits from applicable design documents. If 

the HPCI pump had degraded to the lower limit of the test acceptance criteria, it would 

not have been able to meet the design basis discharge pressure and flow requirements. 

Following the identification of the issue the licensee entered the issue into the corrective 

action program and verified the operability of the pumps based on actual test results. 

Additionally, the licensee intends to change the test procedures.
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NRC Perspective - Transitioning to ASME OM-2009 Division 

1, Mandatory Appendix III “Preservice and Inservice Testing 

of Active Electric Motor Operated Valve Assemblies in LightWater Reactor Power Plants” (Formerly ASME OM Code Case 

OMN-1)

Michael F. Farnan*

Component Performance & Testing Branch

Division of Component Integrity

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

* This paper was prepared by staff of the U.S. Nuclear Regulatory Commission (NRC). 

It may present information that does not currently represent an agreed upon NRC staff 

position. NRC has neither approved nor disapproved the technical content.

Abstract

The American Society of Mechanical Engineers (ASME) has recently issued the 2009 

Edition of the Code for Operation and Maintenance of Nuclear Power Plants (OM 

Code). (Reference 1) One of the major changes in the 2009 Edition of the OM Code is 

the addition of Mandatory Appendix III “Preservice and Inservice Testing of Active 

Electric Motor Operated Valve Assemblies in Light-Water Reactor Power Plants” 

(formerly ASME OM Code Case OMN-1). This paper provides insights from an NRC 

staff perspective on transitioning to the new ASME OM Code Mandatory Appendix III.

Background

The National Technology Transfer and Advancement Act of 1995 (Public Law 104-113) 

requires that if agencies establish technical standards, they must use technical 

standards developed or adopted by voluntary consensus standards bodies unless the 

use of such standards is inconsistent with applicable law or is otherwise impractical. 

Public Law 104-113 requires Federal agencies to use industry consensus standards to 

the extent practical; however, it does not require Federal agencies to endorse a 

standard in its entirety. The law does not prohibit an agency from generally adopting a 

voluntary consensus standard while taking exception to specific portions of the standard 

if those provisions are deemed to be “inconsistent with applicable law or otherwise 

impractical.”
315

The ASME OM Code establishes requirements for preservice testing (PST) and 

inservice testing (IST) and examination of certain components to assess their 

operational readiness in light-water reactor nuclear power plants. The OM Code was 

developed and is maintained by the ASME Committee on Operation and Maintenance 

of Nuclear Power Plants. This document is periodically updated through new Editions 

and/or Addenda. The ASME OM Code is a national, voluntary consensus standard and 

Public Law 104-113 requires government agencies to consider its use.

The Code of Federal Regulations (CFR) 10 CFR 50.55a, “Codes and Standards,” 

defines the requirements for applying industry codes and standards to boiling or 

pressurized water-cooled nuclear power facilities. The NRC applies voluntary 

consensus standards by approving and mandating the use of Editions and Addenda to 

the ASME OM Code in 10 CFR 50.55a through the rulemaking process. The first 

Edition and Addendum to the OM Code that 10 CFR 50.55a incorporated was the 1995 

Edition and the 1996 Addendum. The requirements of the OM Code became 

regulations once they were incorporated into 10 CFR 50.55a. More specifically,10 CFR 

50.55a(b)(3)(ii) addresses the incorporation of the ASME OM Code provisions for 

testing of motor-operated valves (MOVs).

10 CFR 50.55a(b)(3)(ii) (2011 Edition) states that “Licensees shall comply with the 

provisions for testing motor-operated valves in ASME OM Code ISTC 4.2, 1995 Edition 

with the 1996 and 1997 Addenda, or ISTC-3500, 1998 Edition through the latest edition 

and addenda incorporated by reference in paragraph (b)(3) of this section, and shall 

establish a program to ensure that motor-operated valves continue to be capable of 

performing their design basis safety functions.”

The 10 CFR 50.55a(b)(3)(ii) requirement has two elements:

1. Plant IST programs must meet the ASME OM Code requirements

2. Plants must have an MOV program that provides continued assurance of the 

capability of MOVs to perform their design basis safety functions

The second element was a direct result of Generic Letters (GL) GL 89-10, (Reference 

2), GL 95-07, (Reference 3), and GL 96-05 (Reference 4). GL 89-10 requested 

licensees to verify the design basis capability of their safety-related MOVs by dynamic 

testing where practicable. GL 95-07 requested licensees to address concerns of 

potential pressure locking and thermal binding of power-operated gate valves. GL 96-

05 requested licensees to develop programs to periodically verify MOV design basis 

capability. The provisions in GL 96-05 superseded GL 89-10.
316

The ASME OM Code subgroup committee for MOVs combined these two elements by 

developing ASME OM Code Case OMN-1, “Alternative Rules for Preservice and 

Inservice Testing of Certain Electric Motor-Operated Valve Assemblies in Light Water 

Reactor Power Plants OM Code-1995, Subsection ISTC.” A Case is the official ASME 

method of handling a reply to an inquiry when study indicates that the Code wording 

needs clarification, or grants permission to use alternative methods. Code Cases are 

written as a question and a reply, and are usually intended to be incorporated into the 

Code at a later date. A Code Case is not considered a part of the ASME OM Code or 

its addenda. ASME has agreed to publish Cases issued by the Operation and 

Maintenance Committee concerning the OM Code as part of the updated service to the 

OM Code. The ASME OM Code Case OMN-1 original inquiry and reply was as follows:

Inquiry: What alternative rules, to those of OM Code, Subsection ISTC, may be 

used for preservice and inservice testing to assess the operational readiness of 

certain electric motor-operated valve assemblies in light-water reactor power plants?

Reply: It is the opinion of the Committee that, in lieu of the rules for preservice and 

inservice testing to assess the operational readiness of certain electric motoroperated valve assemblies in light-water reactor power plants in OM Code-1995, 

Subsection ISTC, except for ISTC 4.3, the following alternative requirements may be 

applied. Electric motor-operated valves for which seat leakage is limited to a specific 

maximum amount in the closed position for fulfillment of their required function 

(Category A) must also be seat leakage rate tested in accordance with the 

requirements of ISTC 4.3.

The NRC staff reviews Code Cases and publishes a listing of Code Case acceptability 

in Regulatory Guide (RG) 1.192, “Operation and Maintenance Code Case Acceptability, 

ASME OM Code” (Reference 5). Cases found to be unacceptable are listed in RG 

1.193 “ASME Code Cases Not Approved For Use” (Reference 6). Approved Code 

Cases may be used by licensees without submitting a request to the NRC, provided 

they are used with any identified limitations or modifications. OM Code Cases not yet 

endorsed by the NRC may be implemented through 10 CFR 50.55a(a)(3), which 

permits the use of alternatives to the Code requirements referenced in 10 CFR 50.55a 

provided the proposed alternatives result in an acceptable level of quality and safety 

and provided their use is authorized by the NRC.

ASME OM Code, 2009 Edition, Mandatory Appendix III is the end result of ASME OM 

Code Case OMN-1 which was written in 1995 and first appeared as a supplement to 

ASME OMa Code 1996 Addenda. The supplement was not considered part of the OM 

Code but was included in the 1996 Addenda as a convenience to the end user. The 

NRC staff reviewed and approved, with conditions, the use of ASME OM Code Case 

OMN-1. OMN-1 was revised in the ASME OM Code 2001 Edition. The revision was 
317

very minor in nature and did not change the technical content or methodology. The 

changes included an update to the Code Case expiration date and a few editorial 

language improvements. OMN-1 was revised again in the ASME OMb Code 2006 

Addenda. This time, the revision was a major change which incorporated years of 

feedback and assessments to improve the overall alternative testing approach. The 

NRC staff reviewed the revision made in the 2006 Addenda and concluded that the 

alternative continued to be acceptable with conditions. RG 1.192 is currently being 

revised to update Code Case acceptability for OMN-1 and other ASME Code Cases. In 

the ASME OM Code 2009 Edition, OMN-1 was revised again with a minor change. The 

change was minor in detail in that it removed reference margin flow charts but did not 

alter technical content or methodology. The name of the Code Case was updated to a 

standard ASME format designating a revision change and the resulting name of the 

latest Code Case revision is OMN-1-1. This latest update was published as a 

supplement to the ASME OM Code 2009 Edition. For those end users who desire the 

reference margin flow charts, OMN-1 was also published in the ASME OM Code 2009 

Edition. OMN-1-1 was incorporated into ASME OM Code 2009 Edition as Mandatory 

Appendix III. Appendix III also incorporates ASME OM Code Case OMN-11 that 

addresses risk-informed aspects for implementing Code Case OMN-1.

During the next update to 10 CFR 50.55a, the NRC staff will evaluate the incorporation 

by reference of ASME OM Code 2009 Edition, including Mandatory Appendix III. The 

NRC staff will determine whether to include any modifications or limitations for the 

implementation of ASME OM Code 2009 Edition. As part of this review, the staff will 

determine whether any conditions in RG 1.192 regarding the acceptance of ASME OM 

Code Cases OMN-1 and OMN-11 need to be included in 10 CFR 50.55a for the 

implementation of Mandatory Appendix III to the ASME OM Code 2009 Edition.

NRC Staff Perspective

There have been many industry questions and/or concerns about transitioning to 

Mandatory Appendix III requirements. The following discussion will attempt to answer 

those questions and/or concerns from an NRC staff perspective. The information being 

provided by this perspective must not be confused with interpretation of the ASME OM 

Code requirements. End users with interpretation questions must follow the process of 

submitting their inquiries to the ASME OM Code Committee. The following NRC staff 

perspective analysis reviews each section of Mandatory Appendix III and provides an 

applicable comment.
318

Division 1, Mandatory Appendix III

Preservice and Inservice Testing of Active Electric

Motor Operated Valve Assemblies in Light-Water Reactor

Power Plants

III-1000 INTRODUCTION

III-1100 Applicability

This Mandatory Appendix establishes the requirements for preservice and inservice 

testing to assess the operational readiness of active motor-operated valves (MOVs) in 

light-water reactor (LWR) power plants.

Comment: Per ASME OM Code 2009 Edition Subsection ISTA, (General 

Requirements), paragraph ISTA-1100 (Scope), bullet (a), “These requirements apply 

to pumps and valves that are required to perform a specific function in shutting down 

a reactor to the safe shutdown condition, in maintaining the safe shutdown condition, 

in mitigating the safe shutdown condition, or in mitigating the consequences of an 

accident.” Licensees are cautioned to review the population of MOVs that are 

required to meet this action statement. The IST program scope may not be the 

same scope that was specified for addressing GL 89-10 and GL 96-05 concerns. 

Licensee IST and MOV program engineers should consult their licensing basis.

III-1200 Scope

See para. ISTC-1200.

Comment: Paragraph ISTC-1200 specifies valves that may be exempt from the test 

requirements. Questions or clarification of this section should be forwarded to the 

ASME OM Code Committee for interpretation.

III-2000 SUPPLEMENTAL DEFINITIONS

full cycle exercise: full stroke of the valve from and back to its initial position.

motor-operated valve (MOV): a valve and its associated electric motor driven 

mechanism for positioning the valve, including components that control valve action and 

provide position output signals

MOV functional margin: the increment by which an MOV’s available capability 

exceeds the capability required to operate the MOV under design basis conditions.

stem factor: the ratio of stem torque to stem thrust in rising-stem valves.

Comment: None.
319

III-3000 GENERAL TESTING REQUIREMENTS

III-3100 Design Basis Verification Test

A one-time test shall be conducted to verify the capability of each MOV to meet its 

safety-related design basis requirements. This test shall be conducted at conditions as 

close to design basis conditions as practicable. Requirements for a design basis 

verification test are specified in applicable regulatory documents. Testing that meets 

the requirements of this Mandatory Appendix but conducted before implementation of 

this Mandatory Appendix may be used.

(a) Design basis verification test data shall be used in conjunction with preservice test 

data as the basis for inservice test criteria.

(b) Design basis verification testing shall be conducted in situ or in a prototype test 

facility that duplicates applicable design basis conditions. If a test facility is used, an 

engineering analysis shall be documented that supports applicability to the in situ 

conditions.

(c) Justification for testing at conditions other than design basis conditions and for 

grouping like MOVs shall be documented by an engineering evaluation, alternate testing 

techniques, or both. Where design basis testing of the specific MOV being evaluated is 

impracticable or not meaningful (provides no additional useful data), data from other 

MOVs may be used if justified by engineering evaluation. Sources for the data include 

other plant MOVs or test data published in industry testing programs. Where analytical 

techniques are used to verify design basis capability, those techniques shall be justified 

by an engineering evaluation.

(d) For certain valve types (i.e., ball, plug, and diaphragm valves) where the need for 

design basis verification testing has not been previously identified, an engineering 

evaluation of operating experience may be used to verify design basis capability.

(e) The design basis verification test shall be repeated if an MOV application is 

changed, the MOV is physically modified, or the system is modified in a manner that 

invalidates its current design basis verification test results or data. A determination that 

a design basis verification test is still valid shall be justified by an engineering 

evaluation, alternative testing techniques, or both.

Comment: This Code provision requires the demonstration of design-basis 

capability for each MOV within the IST program. Following the initial demonstration 

of MOV design-basis capability, the IST program will maintain the design-basis 

capability by periodic exercising and diagnostic testing. For those MOVs within the 

scope of the GL 89-10 and GL 96-05 programs, the testing and/or engineering 

analysis performed to close out those generic letter concerns may be used to meet 
320

this requirement. For MOVs that were outside of the scope of GL 89-10 and GL 96-

05 but within the IST program, a one time test and/or engineering analysis is 

required. In both cases, it is expected that licensees will have the design basis 

verification test and/or engineering evaluation analysis formally documented for each 

MOV in the IST program.

III-3200 Preservice Test

Each MOV shall be tested during the preservice test period or before implementing 

inservice testing. These tests shall be conducted under conditions as near as 

practicable to those expected during subsequent inservice testing. Testing that meets 

the requirements of this Mandatory Appendix but conducted before implementation of 

this Mandatory Appendix may be used. Only one preservice test of each MOV is 

required unless, as described in para. II-3400, the MOV has undergone maintenance 

that could affect its performance.

Comment: This paragraph has the same requirements as ISTC-3100. There is no 

impact or change in requirements when transitioning to Mandatory Appendix III.

III-3300 Inservice Test

Inservice testing shall commence when the MOV is required to be operable to fulfill its 

required function(s), as described in para. III-1100, and shall be sufficient to assess 

changes in MOV functional margin consistent with section III-6000.

(a) MOVs may be grouped for inservice testing as described in para. III-3500.

(b) Inservice tests shall be conducted in the as-found condition. Activities shall not be 

conducted if they invalidate the inservice test results. If maintenance is needed 

between the inservice tests, see para. III-3400. As-found testing is not required prior to 

maintenance activities as long as the MOV is not due for an inservice test. If 

maintenance activities are scheduled concurrently with an MOVs inservice test, then the 

inservice test shall be conducted in the as-found condition, prior to the maintenance 

activity.

(c) The inservice testing program will include a mix of static and dynamic MOV 

performance testing. The mix of MOV performance testing may be altered when 

justified by an engineering evaluation of test data.

(d) Dynamic MOV performance testing is not required for certain valve types (i.e., ball, 

plug, and diaphragm valves), with acceptable operating experience.

(e) Remote position indication shall be verified locally during inservice testing or 

maintenance activities.
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Comment: Inservice testing shall commence when the MOV is required to be 

operable. Grouping is allowed as discussed. Inservice testing shall be conducted in 

the as-found condition. This is an important aspect of the MOV test program. The 

gathering of as-found test data helps to validate design assumptions, such as stemto-stem nut coefficient of friction, packing loads, and actuator efficiencies. The test 

program will include a mix of static and dynamic testing. Engineering evaluation of 

static and dynamic test data can justify altering the mix of static and dynamic valve 

testing. For those plants that participated in the Joint Owners Group (JOG) MOV 

Periodic Verification Program, the licensee can rely on the engineering evaluation 

based on the MOV dynamic testing program conducted by the JOG to support its 

mix of static and dynamic testing. The JOG program is described in the JOG final 

program document MPR-2524-A (Reference 7). Participating JOG plants must 

implement the recommendations of the final JOG program document consistent with 

the NRC safety evaluation report dated September 2006 and its supplement dated 

September 2008 (Reference 8). The MPR-2524-A engineering evaluation does not 

eliminate the need for dynamic testing completely. Should a valve be subjected to a 

change in valve service conditions and/or have a modification or repair which would 

disallow the valve’s qualifying basis, dynamic testing would be required to establish 

the new basis for the valve. Further, some MOVs or their service conditions are 

outside the scope of the JOG program. Licensees will be responsible for 

establishing activities that satisfy Mandatory Appendix III for those MOVs or their 

service conditions.

III-3310 Inservice Test Interval.

The inservice test interval determination shall include the following:

(a) The inservice test interval shall be determined in accordance with para. III-6440.

(b) If insufficient data exist to determine the inservice test interval in accordance with 

para. III-6400, then MOV inservice testing shall be conducted every two refueling cycles 

or 3 yr (whichever is longer) until sufficient data exist, from an applicable MOV or MOV 

group, to justify a longer inservice test interval.

(c) The maximum inservice test interval shall not exceed 10 yr. MOV inservice tests 

conducted per para. III-3400 may be used to satisfy this requirement.

Comment: The IST interval for determining static and dynamic tests shall be 

determined in accordance with paragraph III-6440. The specified test interval of 

every two refueling cycles or 3 years (whichever is longer) until sufficient data exists 

to justify a longer test interval for a MOV or MOV group is an acceptable approach. 

The adequacy of the diagnostic test interval for each MOV must be evaluated and 
322

adjusted as necessary, but not later than 5 years or three refueling outages 

(whichever is longer) from initial implementation. The maximum inservice test 

interval shall not exceed 10 years. As of today, industry data cannot support 

extension beyond the current 10 year limit. However, this topic can be revisited and 

the Code updated when sufficient data exists. For applicable licensees, the JOG 

program includes provisions for testing intervals for those MOVs within the scope of 

the program.

III-3400 Effect of MOV Replacement, Repair, or Maintenance

When an MOV or its control system is replaced, repaired, or undergoes maintenance 

that could affect the valve’s performance, new inservice test values shall be determined, 

or the previously established inservice test values shall be confirmed before the MOV is 

returned to service. If the MOV was not removed from service, inservice test values 

shall be immediately determined or confirmed. This testing is intended to demonstrate 

that performance parameters, which could be affected by the replacement, repair, or 

maintenance, are within acceptable limits. The Owner’s program shall define the level 

of testing required after replacement, repair, or maintenance. Deviations between the 

previous and new inservice test values shall be identified and analyzed. Verification 

that the new values represent acceptable operation shall be documented as described 

in section III-9000, Records and Reports.

Comment: This paragraph has the same requirements as ISTC-3310. There is no 

impact or change in requirements when transitioning to Mandatory Appendix III.

III-3500 Grouping of MOVs for Inservice Testing

Grouping MOVs for inservice testing is permissible. Grouping MOVs shall be justified 

by an engineering evaluation, alternative testing techniques, or both. The following 

shall be satisfied when grouping MOVs:

(a) MOVs with identical or similar motor-operators and valves and with similar plant 

service conditions may be grouped together based on the results of design basis 

verification and preservice tests. Functionality of all groups of MOVs shall be validated 

by appropriate inservice testing of one or more representative valves.

(b) Test results shall be evaluated and justified for all MOVs in the group.

Comment: As noted in the comments on Section III-3300, the JOG final program 

document MPR-2524-A (Reference 7) is an example of an engineering evaluation 

where valves are grouped into classifications based on key parameters:

• Type of valve
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• Type of DP stroking the valve undergoes

• Disk-to-seat materials

• Disk-to-body guide materials

• Type of fluid in system

• Valve factor or apparent disk-to-seat coefficient of friction

• Shaft material

• Bearing material

• Presence or absence of a hub seal

• Bearing friction coefficient

These key parameters, coupled with the valve risk and margin, help identify 

applicable test intervals.

III-3600 MOV Exercising Requirements

III-3610 Normal Exercising Requirements. All MOVs, within the scope of this 

Mandatory Appendix, shall be full cycle exercised at least once per refueling cycle with 

the maximum time between exercises to be not greater than 24 mo. Full cycle 

operation of an MOV, as a result of normal plant operations or Code requirements, may 

be considered an exercise of the MOV, if documented. If full stroke exercising of an 

MOV is not practical during plant operation or cold shutdown, full stroke exercising shall 

be performed during the plant’s refueling outage.

III-3620 Additional Exercising Requirements. The Owner shall consider more 

frequent exercising requirements for MOVs in any of the following categories:

(a) MOVs with high risk significance,

(b) MOVs with adverse or harsh environmental conditions, or

(c) MOVs with any abnormal characteristics (operational, design, or maintenance 

conditions).

Comment: These requirements represent a change from the quarterly stroke time 

testing previously required in ASME OM Code section ISTC-3500 and ISTC-3510. 

The licensee must consider the impact on its Probabilistic Risk Analysis regarding 

changes of the exercise interval from quarterly to every 24 months for MOVs with 

high risk significance. The licensee must consider the impact on MOV performance 

when modifying the exercise interval, such as high temperature areas that might 

degrade the stem lubricant or gearbox grease.
324

III-3700 Risk-Informed MOV Inservice Testing

Risk-informed MOV inservice testing that incorporates risk insights in conjunction with 

performance margin to establish MOV grouping, acceptance criteria, exercising 

requirements and testing interval may be implemented.

III-3710 Risk-Informed Considerations. The Owner shall consider the following when 

incorporating risk insights in the inservice testing of MOVs:

(a) develop an acceptable risk basis for MOV risk Determination

(b) develop MOV screening criteria to determine each MOVs contribution to risk

(c) finalize risk category by a documented evaluation from a Plant Expert Panel

III-3720 Risk-Informed Criteria. Each MOV shall be evaluated and categorized using 

a documented risk ranking methodology. This Mandatory Appendix provides test 

requirements for high and low safety significant component (HSSC/LSSC) categories. If 

an Owner established more than two risk categories, then the Owner shall evaluate the 

intermediate SSCs and select HSSC or LSSC test requirements for those intermediate 

SSCs.

III-3721 HSSC MOVs. HSSC MOVs shall be tested in accordance with para. III-3300 

and exercised in accordance with para. III-3600. HSSC MOVs that can be operated 

during plant operation shall be exercised quarterly, unless the potential increase in core 

damage frequency (CDF) and large early release (LER) associated with a longer 

exercise interval is small.

III-3722 LSSC MOVs. In meeting the provisions of this Mandatory Appendix, including 

exercising in accordance with para. III-3600 and the determination of proper MOV test 

interval in section III-6000, risk insights shall be applied to inservice testing of LSSC 

MOVs by the following:

(a) LSSC grouping shall be technically justified, but the provision for similarity in 

subpara. III-3500(a) may be relaxed. The provisions in subpara. III-3500(b) related to 

evaluation of test results for MOVs in that group continue to be applicable to all MOVs 

within the scope of this Mandatory Appendix.

(b) LSSC MOVs may be associated with an established group of other MOVs. When a 

member of that group is tested, the test results shall be analyzed and evaluated in 

accordance with section III-6000, and applied to all LSSC MOVs associated with that 

group.

(c) LSSC MOVs that are not associated with an established group shall be inservice 

tested, in accordance with para. III-3300, using an initial test interval of three refueling 
325

cycles or 5 yr (whichever is longer) until sufficient data exist to determine a more 

appropriate test interval as described in para. III-6440.

(d) LSSC MOVs shall be inservice tested at least every 10 yr in accordance with para. 

III-3310.

Comment: These requirements incorporate OM Code Case OMN-11, Rev. 0, 

reaffirmed 1999A Addenda. RG 1.192 accepted the use of Code Case OMN-11 with 

conditions.

III-4000 TO BE PROVIDED AT A LATER DATE

Comment: None

III-5000 TEST METHODS

III-5100 Test Prerequisites

All testing shall be conducted in accordance with plant-specific technical specifications, 

installation details, acceptance criteria, and maintenance, surveillance, operation, or 

other applicable procedures.

III-5200 Test Conditions

Test conditions shall be sufficient to determine the MOV’s functional margin per para. 

III-6400. Test conditions shall be recorded for each test per section III-9000.

III-5300 Limits and Precautions

Testing limits and precautions include

(a) MOV exposure to dust, moisture, or other adverse conditions shall be minimized 

when normally enclosed compartment covers are removed while performing tests.

(b) Manufacturer or vendor limits and precautions associated with the MOV and with the 

test equipment shall be considered, including the structural thrust and torque limits of 

the MOV.

(c) Plant-specific operational and design precautions and limits shall be followed. Items 

to be considered shall include, but are not limited to, water hammer and intersystem 

relationships.

(d) The benefits of performing a particular test should be balanced against the potential 

increase in risk for damage caused to the MOV by the particular testing performed.
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III-5400 Test Documents

Approved plant documents shall be established for all tests specified in this Mandatory 

Appendix and shall provide for

(a) methodical, repeatable, and consistent performance testing

(b) collection of data required to analyze and evaluate the MOV functional margin in 

accordance with section III-6000

III-5500 Test Parameters

Sufficient test parameters shall be selected for measurement to meet the requirements 

of section III-6000 in determining the MOV functional margin.

Comment: The requirements for sections III-5000, III-5100, III-5200, III-5300, III5400, and III-5500 represent common elements found in ASME OM Code Section 

ISTA and ISTC, GL 89-10, GL 96-05, and 10 CFR 50 Appendix B. Plants 

transitioning to Mandatory Appendix III should have no to minor impact with meeting 

these requirements for MOVs addressed as part of the GL 89-10 and GL 96-05 

programs.

III-6000 ANALYSIS AND EVALUATION OF DATA

III-6100 Acceptance Criteria

The Owner shall establish methods to determine acceptance criteria for the operational 

readiness of each MOV within the scope of this Mandatory Appendix. Acceptance 

criteria shall be based upon the minimum amount by which available actuator output 

capability must exceed the valve operating requirements. Thrust, torque, or other 

measured engineering parameters correlated to thrust or torque consistent with paras. 

III-6100 through III-6500, may be used to establish the acceptance criteria. Motor 

control center testing is acceptable if correlation with testing at the MOV has been 

established. When determining the acceptance criteria, consider the following sources 

of uncertainty:

(a) test measurement and equipment accuracy

(b) valve and actuator repeatability (e.g., torque switch repeatability)

(c) analysis, evaluation, and extrapolation method

(d) grouping method
327

III-6110 Parameter Measurements. MOV margins may be expressed in terms of stem 

force or other parameters, if those parameters are consistent with paras. III-6100 

through III-6500.

III-6200 Analysis of Data

Data obtained from a test required by this Mandatory Appendix, shall be analyzed to 

determine if the MOV performance is acceptable. The Owner shall determine which 

methods are suitable for analyzing necessary parameters for each MOV and 

application.

Whenever data are analyzed, all relevant operating and test conditions shall be 

considered.

The Owner shall compare performance test data to the acceptance criteria. If the 

functional margin, determined per para. III-6430, does not meet the acceptance criteria, 

the MOV shall be declared inoperable, in accordance with the Owner’s requirements.

Data analysis shall include a qualitative review to identify anomalous behavior. If 

indications of anomalous behavior are identified, the cause of the behavior shall be 

analyzed and corrective actions completed, if required.

III-6300 Evaluation of Data

The Owner shall determine which methods are suitable for evaluating test data for each 

MOV and application.

The Owner shall have procedural guidelines to establish the methods and timing for 

evaluating MOV test data. Evaluations shall determine the amount of degradation in 

functional margin that occurred over time. Evaluations shall consider the influence of 

past maintenance and test activities to establish appropriate time intervals for future test 

activities.

The evaluations shall apply changes in functional margin to other applicable MOVs to 

establish appropriate time intervals for future test activities.

Comment: The requirements for sections III-6000, III-6100, III-6110, III-6200, and 

III-6300 represent common elements found in ASME OM Code Section ISTA and 

ISTC, GL 89-10, GL 96-05, and 10 CFR 50 Appendix B. Plants transitioning to 
328

Mandatory Appendix III should have no to minor impact with meeting these 

requirements for MOVs addressed as part of the GL 89-10 and GL 96-05 programs.

III-6400 Determination of MOV Functional Margin

The Owner shall demonstrate that adequate margin exists between valve operating 

requirements and the available actuator output capability to satisfy the acceptance 

criteria for MOV operational readiness. In addition to meeting the acceptance criteria, 

adequate margin shall exist to ensure that changes in MOV operating characteristics 

over time do not result in reaching a point at which the acceptance criteria are not 

satisfied before the next scheduled test activity.

III-6410 Determination of Valve Operating Requirements.

Design basis valve operating requirements, including stem factor for rising stem valves, 

shall be determined from

(a) measurements taken during testing at design basis conditions, or

(b) analytical methods using valve parameters determined from testing at conditions 

that may be extrapolated to design basis conditions, or

(c) application of justified industry methodologies.

III-6420 Determination of Actuator Output Capability

III-6421 Available Output Based on Motor Capabilities. Available actuator output 

shall be determined based on motor capabilities at the motor’s design basis conditions. 

Considerations shall include

(a) rated motor start torque

(b) minimum voltage conditions

(c) elevated ambient temperature conditions

(d) operator efficiency

(e) other appropriate factors

III-6422 Available Output Based on Torque Switch Setting. Where applicable, the 

available output shall be determined based on the current torque switch setting. For 

MOVs where testing does not sufficiently load the MOV to cause torque switch trip (e.g., 

butterfly and ball valves), available output based on the current torque switch setting 

shall be determined analytically from test data. Considerations shall include

(a) calibration of the torque switch spring pack

(b) the current torque switch setting

(c) repeatability of torque switch operation
329

III-6430 Calculation of MOV Functional Margin. MOV functional margin shall be 

calculated as the difference between the available actuator output and valve operating 

requirements. Available actuator output is determined as

(a) design basis motor operator capability for limit switch controlled strokes, or

(b) the lesser of design basis motor operator capability or motor operator capability at 

the current torque switch setting for torque switch controlled strokes

III-6440 Determination of MOV Test Interval. Calculations for determining MOV 

functional margin shall account for potential performance related degradation. 

Maintenance activities and associated intervals can affect test intervals and shall be 

considered. The inservice test interval shall be set such that the MOV functional margin 

does not decrease below the acceptance criteria.

Comment: The requirements for sections III-6400, III-6410, III-6420, III-6421, III6422, III-6430, and III-6440 represent common elements found in GL 89-10, and GL 

96-05. Plants transitioning to Mandatory Appendix III should have no to minor 

impact with meeting these requirements for MOVs addressed as part of the GL 89-

10 and GL 96-05 programs. For those plants that participated in the JOG, valve test 

intervals are based upon valve classification, risk, and margin. For those valves or 

their service conditions that were not covered by the JOG program, the requirements 

of III-3310 apply until sufficient test data is available to determine the test interval.

III-6500 Corrective Action

If the MOV performance is unacceptable, as established in para. III-6400, corrective 

action shall be taken in accordance with Owner’s corrective action requirements.

III-6510 Record of Corrective Action. The Owner shall maintain records of corrective 

action that shall include a summary of the corrections made, the subsequent tests, 

confirmation of operational adequacy, and the signature of the individual responsible for 

corrective action and verification of results.

Comment: The requirements for sections III-6500, and III-6510 represent common 

elements found in ASME OM Code Section ISTA and ISTC. Plants transitioning to 

Mandatory Appendix III should have no to minor impact with meeting these 

requirements.
330

III-7000 TO BE PROVIDED AT A LATER DATE

Comment: None

III-8000 TO BE PROVIDED AT A LATER DATE

Comment: None

III-9000 RECORDS AND REPORTS

III-9100 Test Information

Pertinent test information shall be recorded or verified for MOV testing, described in 

section III-3000. The following information shall be considered along with the 

information requirements in ISTA/ISTC:

(a) MOV plant-specific unique identification number.

(b) motor, valve, actuator nameplate data.

(c) test equipment unique identification numbers and equipment calibration dates.

(d) test method and conditions, described in section III-5000, including description of 

valve lineups, process equipment, and type of test. Descriptions shall include valve 

body, valve stem, electric motor-operator orientation, and piping configuration near the 

MOV.

(e) breaker setting/fuse size and motor starter thermal overload size, if used.

(f) MOV torque and limit switch configuration and settings.

(g) MOV performance test procedure and other approved plant documents containing 

acceptance criteria.

(h) name of test performer and date of test.

(i) system flow, system pressure, differential pressure, system fluid temperature, system 

fluid phase, and ambient temperature.

(j) significant observations: any comments pertinent to the test results that otherwise 

may not be readily identified by other recorded test data shall be recorded. 

Observations shall include any remarks regarding abnormal or erratic MOV action noted 

either during or preceding performance testing and any other pertinent design 

information that can be verified at the MOV.

III-9200 Documentation of Analysis and Evaluation of Data

The documentation of acceptable MOV performance, which has been analyzed and 

evaluated in accordance with section III-6000, shall include, as a minimum:
331

(a) values of test data, test parameters, and test information established by paras. III5500 and III-9100

(b) summary of analysis and evaluation required per paras. III-6200 and III-6300

(c) statement(s), by an individual qualified to make such a statement through the 

Owner’s qualification requirements, confirming that the MOV is capable of performing its 

intended safety function

(d) test results and analysis shall be evaluated by qualified individuals and documented 

to include signature and date. Independent verification shall be by individuals qualified 

to verify those specific analyses and evaluations through the Owner’s qualification 

requirements.

Comment: The requirements for sections III-9000, III-9100, and III-9200 represent 

common elements found in ASME OM Code Section ISTA and ISTC, and GL 89-10 

and GL 96-05. Plants transitioning to Mandatory Appendix III should have no to 

minor impact with meeting these requirements for MOVs addressed as part of the 

GL 89-10 and GL 96-05 programs.

Conclusion

ASME OM Code-2009 Mandatory Appendix III specifies provisions for testing MOVs to 

provide assurance that they are capable of performing their safety-related function. 

Mandatory Appendix III incorporates the guidance in ASME OM Code Cases OMN-1 

and OMN-11 to replace quarterly stroke-time testing with periodic exercising and 

diagnostic testing. The NRC staff accepted Code Cases OMN-1 and OMN-11 with 

conditions in RG 1.192. The NRC staff will evaluate whether any limitations or 

modifications are necessary for the implementation of Mandatory Appendix III when 

ASME OM Code 2009 Edition is incorporated into 10 CFR 50.55a. Plants that are 

transitioning to ASME OM-2009 Edition Mandatory Appendix III are reminded that 

questions concerning interpretation of the OM Code requirements must be directed to 

the ASME OM committee.

References

1) ASME OM-2009 Code for Operation and Maintenance of Nuclear Power Plants

2) USNRC Generic Letter 89-10, “Safety-Related Motor-Operated Valve Testing and 

Surveillance”

3) USNRC Generic Letter 95-07, “Pressure Locking and Thermal Binding of SafetyRelated Power-Operated Gate Valves”
332

4) USNRC Generic Letter 96-05, “Periodic Verification of Design-Basis Capability of 

Safety-Related Power-Operated Valves

5) USNRC Regulatory Guide 1.192, “Operation and Maintenance Code Case 

Acceptability, ASME OM Code”

6) USNRC Regulatory Guide 1.193, “ASME Code Cases Not Approved For Use”

7) MPR Associates Inc. topical report MPR-2524-A, “Joint Owners Group (JOG) Motor 

Operated Valve Periodic Verification Program Summary”

8) USNRC Safety Evaluation Report dated September 2006 on JOG MOV Periodic 

Verification Program and its supplement dated September 2008.
333

History of the ASME Code and NRC Regulatory 

Requirements with Respect to Inservice Testing of Pumps 

and Valves

Yun-Seng Huang* and Anthony C. McMurtray*

U. S. Nuclear Regulatory Commission

* This paper was prepared by staff of the U.S. Nuclear Regulatory Commission. It may 

present information that does not currently represent an agreed-upon NRC staff 

position. The NRC has neither approved nor disapproved the technical content.

Abstract

The Code of Federal Regulation Section 10 CFR 50.55a requires that certain American 

Society of Mechanical Engineers (ASME) Code Class 1, 2, and 3 pumps and valves 

meet the inservice testing (IST) requirements specified in the applicable ASME Code for 

Operation and Maintenance of Nuclear Power Plants (OM Code). The regulation also 

requires that an initial 10-year program be established for the IST of pumps and valves 

which must be updated every ten years to meet the latest applicable ASME OM Code 

requirements incorporated by reference in 10 CFR 50.55a. During the 1980s, these IST 

programs, including relief and alternative requests, were submitted to the NRC for 

review and approval. The NRC review of IST programs entailed verifying that the 

program was based on the applicable ASME Code Edition and Addenda, and that the 

program covered testing of all appropriate pumps and valves, and that relief and 

alternative requests were authorized in accordance with regulatory requirements. The 

NRC completed its review of all IST programs around 1995. Once the reviews of the 

IST programs and associated relief and alternative requests were completed, 

subsequent reviews of the ten year updates were limited to changes to previously 

approved programs. This primarily involved new relief and alternative requests from 

revised OM Code requirements or modified relief and alternative requests to existing 

ones. Since around 1995, the NRC spent most of its resources reviewing new 

proposed or modified relief and alternative requests

In 1971, the ASME Boiler and Pressure Vessel Code (ASME Code), Section XI 

requirements were incorporated by reference into 10 CFR 50.55a. The IST 

requirements were approved in 1973 by ASME and incorporated into Subsections IWP 

and IWV of the ASME Code, Section XI. These IST requirements have been in 

existence for 40 years and have been required to be implemented in the design and 

operation of nuclear power facilities. This paper summarizes the history, development, 
334

and evolution, as well as implementation of the ASME Codes and NRC requirements 

with respect to IST of pumps and valves. 

Introduction

Prior to 1954, atomic energy was only allowed to be for military use. Since the Atomic 

Energy Act of 1954 was enacted, which declared that atomic energy may be used for 

free competition in private enterprise, nuclear power energy became a hot commodity 

and many utilities in the electric power industry wanted to engage in building nuclear 

power plants. By the end of 1970, the regulatory group in the Atomic Energy 

Commission (AEC), which was renamed the Nuclear Regulatory Commission (NRC) by 

the Energy Reorganization Act of 1974, had issued construction permits (CPs) and 

operating licenses (OLs) to 109 plants. By comparison, in the next four decades, only 

48 CPs were issued. Today we have 103 plants in operation, and the rest of the plants 

with CPs or OLs were either cancelled, shutdown, or decommissioned.

Back in the early 1960s, the reactor vessel received much of the attention of the AEC 

and industry. Various standards and inspection requirements were developed and 

incorporated into ASME Code, Section XI to ensure the safety and integrity of the 

reactor vessel. However, in the late 1960s, it became apparent that other safety-related 

components (e.g., pumps and valves) also played a very important role in keeping and 

maintaining safe operation and safe shut down of nuclear reactors. To ensure the 

operational readiness of safety-related pumps and valves, the AEC and the nuclear 

industry recognized that certain functional or performance testing needed to be 

developed and required for these pumps and valves. In the late 1960s, the AEC and 

the industry developed a proposal for an inservice testing (IST) program of pumps and 

valves. Based on the proposal, the IST requirements were approved in 1973 by ASME 

and incorporated into the ASME Code, Section XI in Subsection IWP, for pumps, and 

Subsection IWV, for valves.

Since 1971, the IST requirements for pumps and valves have come a long way from a 

dozen pages in the ASME Code, Section XI, to ten times this size in a stand-alone 

document in the current ASME OM Code. The following summarizes the history, 

development, and evolution as well as implementation of the ASME Codes and the 

NRC requirements with respect to IST of pumps and valves. 

ASME Code Requirements

As the industry identified that pumps and valves in nuclear power plants would have 

important safety function roles, the ASME started work to develop an industry standard 
335

for IST of these pumps and valves. A draft standard was developed around 1970, and 

an approval from the ASME was obtained in 1971 to include the draft standard in the 

ASME Code, Section XI. In the Summer 1973 Addenda of the ASME Code, 

Subsections, IWP on pumps, and IWV on valve testing, were approved by ASME and 

added to Section XI. In 1975, a new ASME Operations and Maintenance of Nuclear 

Power Plants (O&M) Committee was formed to review and update the Section XI 

requirements specifically for IST of pumps and valves for operating plants. To facilitate 

the review in these areas, the previous Section XI subgroup on pumps and valves was 

transferred to the ASME O&M Committee in 1979 and a new Working Group under the 

ASME O&M Committee was established in 1984 to review and develop pump and valve 

standards. In 1987, ASME O&M developed and published two standards, Part 6 for 

pumps and Part 10 for valves (later renamed OM-6 and OM-10). These two standards 

were approved by the American National Standards Institute (ANSI) on July 14, 1988, 

and added to ASME/ANSI OM-1987, which was incorporated by reference in the 1989 

Edition of the ASME Code, Section XI. In 1990, a transition was implemented in which 

OM Part 6 and OM Part 10 were incorporated into the ASME OM Code-1990, ”Code for 

Operation and Maintenance of Nuclear Power Plants.” This ASME OM-1990 is a 

replica of OM-6 and OM-10 and was issued in 1991 to replace the ASME Code, Section 

XI, Subsections IWP and IWV.

The ASME O&M Committee was chartered to develop, revise, and maintain codes and 

standards applicable to the safe operation of nuclear power plants. The committee’s 

persistent and devoted effort to seek and select improved testing methods, parameters, 

acceptance criteria, and innovative techniques that accomplished the intended 

objectives of IST has resulted in frequent updates and revisions to the ASME OM Code 

requirements.

1. History and Updates of ASME Code Requirements for Pumps

Prior to 1976, Subsection IWP of the ASME Code, Section XI required that IST of 

pumps be performed on a monthly basis. At that time, a monthly pump test was in 

agreement with the system-oriented pump test schedule required by plant technical 

specifications (TS). These TS pump tests were normally performed at close to pump 

design flow rate. Around 1976, IST of pumps in accordance with ASME Code, Section 

XI requirements was being implemented for all safety-related pumps including certain 

standby pumps. During the first three years of implementation, certain pumps were 

being over tested and resulted in unacceptable accelerated degradation, particularly for 

standby pumps that were being tested on mini-flow test lines. Therefore, the ASME 

Section XI Code Committee proposed that this test frequency be changed to quarterly. 
336

The NRC concurred with the proposed test interval as specified in 1979 Winter 

Addenda to the ASME Code, Section XI.

In 1983, and 1986, ASME Code, Section XI was updated but no significant changes 

were introduced in Subsection IWP. However, in the 1988 Addenda, Subsection IWP 

was replaced by ASME/ANSI OM Part 6, later renamed OM-6, which was incorporated 

as Subsection ISTB into the ASME OM Code-1990. The following are major changes 

contained in Subsection ISTB:

● Deleted suction pressure, bearing temperature and lubrication requirements

● Specified different acceptance criteria for centrifugal, vertical line shaft, and 

positive displacement pumps

● Changed the run time between stabilization and data collection from five minutes 

to two minutes

● Provided vibration acceptance criteria in velocity units

● Increased the upper end acceptable range of pressure differential or flow rate

from 1.03 to 1.10

In 1995, the ASME OM Code-1990 was updated and the following major changes were 

incorporated into Subsection ISTB of the ASME OM Code-1995:

● Pumps were reclassified in Group A and Group B, and the pump tests were 

classified into Group A, Group B, and Comprehensive tests.

● Different test requirements and acceptance criteria were specified for centrifugal, 

vertical line shaft, and non-reciprocating/reciprocating positive displacement 

pumps.

● Instrument accuracy of pressure and pressure differential measurements for 

comprehensive tests were tightened from ± 2% to ±1/2%.

From 1996 to present, no significant changes in the ASME OM Code have been made 

for IST of pumps. 
337

2. History and Updates of ASME Code Requirements for Valves

Prior to 1976, IST specified in Subsection IWV of ASME Code, Section XI was required 

for all ASME Code Class 1, 2, and 3 valves, and seat leakage tests were also required 

for all Category A valves including containment isolation valves. 

In 1983, and 1986, ASME Code, Section XI was updated but no significant changes 

were made to Subsection IWV. However, in the 1988 Addenda, Subsection IWV was 

replaced by ASME/ANSI OM Part 10, later renamed OM-10, which was incorporated as 

Subsection ISTC into the ASME OM Code-1990. The following are major changes 

contained in Subsection ISTC:

● Clarified the scope and included relief valves

● Allowed testing of certain check valves to be extended to a refueling outage 

frequency

● Changed the acceptance criteria for stroke time testing of power operated valves

● In lieu of quarterly exercise testing, allowed disassembly, reassembly and 

inspection to be used for check valve testing on a refueling outage frequency

● Identified testing requirements in OM-1 for safety/relief valves

● Deleted containment isolation valves from IST leak testing requirements

● Deleted trending and corrective action from leak testing requirements for 

Category A valves

● Started issuing OM Code Cases for acceptable alternatives to ASME OM Code 

requirements

In 1998, the ASME OM Code-1990 was updated and the following major changes were 

incorporated into Subsection ISTC of the ASME OM Code-1998:

● Added bi-directional testing requirements for check valves
338

● Specified separate testing requirements for motor-operated valves, 

pneumatically-operated valves, hydraulically-operated valves, and solenoidoperated valves

● Added allowance for a Condition Monitoring Program as an acceptable 

alternative to check valve testing

● Added test requirements for manual valves

● Added instrumentation requirements for valve testing

In 2000, manual valve test requirements were added to ASME OM Code-2000 and 

were required to be performed every five years. In 2006, the test frequency for manual 

valves was reduced to every two years. This revision was incorporated into the ASME 

OM Code-2009. In ASME OM Code-2009, another update was added with mandatory 

Appendix III testing requirements for active electric motor-operated valves (MOVs). 

NRC Regulatory Requirements

1. History of 10 CFR 50.55a

In 1971, the ASME Code, Section XI requirements were incorporated by reference into 

10 CFR 50.55a. In 1977, major revisions were made to reflect which 10 CFR 50.55a 

requirements licensees needed to meet depending on when their construction permit 

(CP) was issued. For CPs issued prior to January 1, 1971, 10 CFR 50.55a(g)(1) 

required that the components shall meet the IST requirements for pumps and valves to 

the extent practical. This is because prior to 1971, there were no regulatory 

requirements to perform IST and for the handful nuclear power plants in operation, IST 

of pumps and valves were addressed and required by “custom” plant technical 

specifications. For CPs issued on or after January 1, 1971, but before July 1, 1974, 10 

CFR 50.55a(g)(2) required that the plant be designed and provided with access to 

perform IST tests set forth in ASME Code, Section XI in effect six months prior to the 

date of the CP issuance. This was because the IST requirements for pumps and valves 

had been published by ASME for six months and had been incorporated into 10 CFR 

50.55a(g) at the time when the CP was issued. For CPs issued on or after July 1, 1974, 

the applicant should have been fully aware of the IST requirements and therefore, 10 

CFR 55.55a(g)(3) required that the plant be designed to implement all applicable IST 

requirements that were set forth in ASME Code, Section XI or the ASME OM Code at 

the time when the CP was issued.
339

Another significant change to 10 CFR 50.55a that was introduced in 1977 was the 40-

month update requirement which was later modified in 1980 to a ten-year update 

requirement. 10 CFR 55.55a(g)(4)(i) required that an IST program be updated every 10 

years to comply with the IST requirements of the latest Code incorporated by reference 

in 10 CFR 50.55a. The NRC expected that as time went on, better and improved codes 

and standards would be developed by the ASME, and implementation of these updated 

codes offered the potential to improve IST effectiveness in detecting and/or predicting 

degradation or failure. Therefore, 10 CFR 50.55a acted as a forward looking regulation 

with the intent to implement new, better, and more effective IST methods and 

techniques included in the ASME OM Code.

The NRC also expected that implementation of the revised Code requirements could be 

impractical or result in a hardship or burden to some licensees. Therefore, the 

regulation allowed licensees to submit alternative requests under 10 CFR 50.55a(3)(i) 

and (3)(ii), and relief requests under 10 CFR 50.55a(g)(6)(i), which was replaced by a 

new section, 10 CFR 50.55a(f)(6)(i), in 1993. 10 CFR 50.55a(g)(6)(i) or (f)(6)(i) may 

only be used to address new or updated requirements. For plants with a CP issued 

prior to 1971, (g)(6)(i) or (f)(6)(i) may be used for granting relief requests, because all 

IST requirements are deemed to be new for plants with a CP issued prior to 1971. 

No significant changes regarding IST requirements were made to 10 CFR 50.55a from 

1985 through 1992 except that in 1989, the 1986 Edition of ASME Code, Section XI was 

included by reference in 10 CFR 50.55a. 

In 1988, ASME Code, Section XI, Subsections IWP and IWV were replaced by 

ASME/ANSI OM-6 and OM-10, which were incorporated as Subsections ISTB and ISTC 

into the ASME OM Code-1990. To reflect the removal of the IST requirements from 

ASME Code, Section XI, a new section, 10 CFR 50.55a(f), specifically written with the 

requirements for IST of pumps and valves, was added in 1993 to 10 CFR 50.55a. 

Furthermore, another new section 10 CFR 50.55a(b)(viii), was specifically added which 

referenced the applicable ASME OM Code. The ASME OM Code-1987 Edition through 

the 1988 Addenda was incorporated by reference into this newly added section in 1993.

In 2000, 10 CFR 50.55a(b)(viii), referencing the ASME OM Code, was replaced by a 

new section, 10 CFR 50.55a(b)(3). This new section which incorporated the ASME 

OM-1995 Edition and the 1996 Addenda by reference contained the following limitations 

and modifications:

● 10 CFR 50.55a(b)(3)(i) addressed the implementation of “Quality Assurance” 

requirements of NQA-1, “Quality Assurance Requirements for Nuclear Facilities,” 
340

and required that when applying the OM Code, the requirements of NQA-1 are 

acceptable, as permitted by the applicable OM Code, provided that the licensee 

use the 10 CFR 50, Appendix B, quality assurance program in conjunction with 

the OM Code requirements.

● 10 CFR 50.55a(b)(3)(ii) addressed the implementation of “MOV stroke-time 

testing,” and required that licensees shall comply with the provisions of stroke 

time testing in the applicable OM Code. Additionally, licensees needed to 

establish a program to ensure that MOVs continue to be capable of performing 

their design basis safety functions.

● 10 CFR 50.55a(b)(3)(iii) addressed the implementation of Code Case OMN-1, 

“Alternative Rules for Preservice and Inservice Testing for Certain Electric MOV 

Assemblies in the Light Water Power Plants,” and required that licensees 

choosing to apply the Code Case apply all of its provisions including the 

following:

(A) The adequacy of the diagnostic test interval for each MOV must be evaluated, 

as necessary, but cannot be later than five years or three refueling outages, 

whichever is longer, and

(B) When extending exercise test intervals for high-risk MOVs beyond a quarterly 

frequency, licensees shall ensure that the potential increase in core damage 

frequency and risk associated with the extension is small and consistent with 

the intent of the Commission Safety Goal Policy Statement. 

● 10 CFR 50.55a(b)(3)(iv) addressed the implementation of OM Code Mandatory 

Appendix II, “Check Valve Condition Monitoring Program,” and required that 

when applying Appendix II, the following modifications applied:

(A) Valve opening and closing functions must be demonstrated when flow testing 

or other methods are used,

(B) The initial interval for tests and associated examinations may not exceed two 

fuel cycles or three years, whichever is longer, and any extension of this 

interval may not exceed one fuel cycle per extension with the maximum 

interval not to exceed ten years, and

(C)If the Appendix II condition monitoring program is discontinued, then the OM 

Code requirements must be re-implemented. 
341

● 10 CFR 50.55a(b)(3)(v) addressed the inservice inspection and testing 

requirements for snubbers. This modification stipulated that, in lieu of applying 

the requirements of ASME Code, Section XI, licensees could use ASME OM 

Code, Subsection ISTD, “Inservice Testing of Dynamic Restraints (Snubbers) in 

Light-Water Reactor Power Plants,” contained in 1995 Edition through the 1996 

Addenda. (Note that snubbers are part of IST program but are not addressed in 

this paper.)

Prior to 2004, any ASME Code Case that was endorsed and listed in NRC Regulatory 

Guides (RG) 1.147 and 1.192 could be implemented without prior NRC approval. 

However, in 2004, a change was made to 10 CFR 50.55a(f) with respect to 

implementation of ASME OM Code Cases. 10 CFR 50.55.a(f) stipulated that only those 

code cases listed in RGs 1.147 and 1.192 that were incorporated by reference into 10 

CFR50.55a(b) could be applied without prior NRC approval. RG 1.147 (June 2003) and 

RG 1.192 (June 2003) were incorporated by reference into 10 CFR 50.55(b) in 2004, 

and remained unchanged through 2010. In 2004, the ASME OM-1995 Edition through 

2000 Addenda were incorporated by reference into 10 CFR 50.55a with one exception:

● 10 CFR 50.55a(b)(3)(vi) - Manual valves needed to be exercised on a 2-year 

interval rather than on the 5-year interval allowed by the ASME OM Code.

In 2005, the ASME OM-1995 Edition through 2003 Addenda was incorporated by 

reference into 10 CFR 50.55a with one change. 10 CFR 50.55a(b)(3)(iii), which 

implemented Code Case OMN-1, was removed from 10 CFR 50.55a since it was 

endorsed by the NRC in RG 1.192 (June 2003), as an acceptable alternative to the 

ASME OM Code requirements. This Code Case was also incorporated into the ASME 

OM Code-2009 Edition, as Mandatory Appendix III.

In 2008, 10 CFR 50.55a was revised to incorporate pumps and valves for facilities 

whose design certification or combine operating license (COL) was issued under 10 

CFR Part 52, on or after November 22, 1999. The only update made in 2009 and 2010 

was the incorporation of the ASME OM Code-1995 through ASME OM Code-2004, by 

reference, into 10 CFR 50.55a.

2. History of RG 1.147 and RG 1.192

Since March 1981, the NRC has issued RG 1.147 and subsequent revisions of the 

“Inservice Inspection Code Case Acceptability ASME Section Division I,” which listed 

the ASME Code Cases acceptable for use. 10 CFR 50.55a allows, without prior NRC 
342

approval, implementation of the Code Cases listed in RG 1.147 for ISI programs. After 

incorporating the ASME OM Code by reference into 10 CFR 50.55a, the NRC 

recognized the need for a new RG that would endorse OM Code Cases. In June 2003, 

the NRC issued RG 1.192, “Operation and Maintenance Code Case Acceptability, 

ASME OM Code,” which listed the OM Code Cases acceptable for use in the IST 

program.

In 2004, the NRC amended 10 CFR 50.55a with respect to implementation of ASME 

Code Cases. New requirements were established in paragraphs 50.55a(b)(4), (b)(5) 

and (b)(6) in which NRC’s RGs 1.84, 1.147 and 1.192 were incorporated by reference 

into the regulations. These RGs list those ASME Code Cases that are approved by the 

NRC (with or without conditions). Specifically, RG 1.192 lists ASME OM Code Cases 

that are approved by the NRC (with or without conditions). As the NRC issues revisions 

to these ASME-Code-Case RGs, the regulations in 10 CFR 50.55a(b)(4), (b)(5), and 

(b)(6) are amended to reflect the latest revision of the RGs. The issuance of revisions 

to the ASME-Code-Case RGs is coordinated with the issuance of the amended rule for 

10 CFR 50.55a to ensure they are issued concurrently. However, per these new 

requirements, prior NRC approval is required to implement those RG-listed ASME Code 

Cases that are not yet incorporated by reference in 10 CFR 50.55a. 

IV. Implementation of 10 CFR 50.55a and ASME OM Code Requirements

To comply with the IST requirements of 10 CFR 50.55a, all licensees were required to 

submit IST programs to the NRC for review. In early 1980, a large number of IST 

programs were submitted and they were all in different forms and formats. The first big 

challenge during the NRC review was to determine the scope of what pumps and valves 

should be included in the IST program. The second challenge was to determine how to 

perform the review of such a huge number of IST programs and relief and alternative 

requests. To perform the review of the IST programs, vast amounts of time and 

resources were required. To expedite these reviews, the NRC contracted with Idaho 

National Engineering Laboratory to conduct the reviews of the baseline IST programs. 

In 1989, the NRC issued review guidance in Generic Letter (GL) 89-04 which provided 

information regarding program format and scope as well as acceptable relief and 

alternative requests. In 1995, the NRC published NUREG-1482, which summarized the 

lessons learned from the review of the IST programs and relief and alternative requests. 

In NUREG-1482, the NRC discussed the regulations, the components to be included in 

the IST program, cold shutdown justifications, refueling outage justifications, and 

acceptable requests for relief from and alternatives to the ASME OM Code 

requirements. In 2004, NUREG-1482, Revision 1 was issued. This reflected regulatory 

changes up to and including the 2003 version of 10 CFR 50.55a.
343

Around 1995, the NRC completed its review of the baseline IST programs for all 

operating plants. Subsequent reviews of the ten year updates for each plant were 

limited to changes to previously approved programs. This primarily involved new relief 

and alternative requests from revised ASME OM Code requirements or modified relief 

and alternative requests to supplement existing ones. Since 1995, the NRC has spent 

most of its resources reviewing new proposed or modified relief and alternative 

requests, in lieu of performing new baseline IST program reviews. 

Conclusion

IST programs are intended to identify problems by collecting relevant data on a periodic 

basis, evaluating the performance of pumps and valves based on inservice test results, 

and trending performance changes over time. The test information collected from IST 

activities may provide some indication of operability and availability of the component at 

the time of the test, but the primary goal of the IST program is to monitor critical

components for degradation and the rate of degradation so that timely action can be 

taken to correct deficiencies prior to an actual failure resulting in degraded plant safety 

systems and unplanned plant shutdowns. An effective IST program offers the best 

potential for focusing maintenance toward the most critical areas by identifying 

degradation of important components early enough to be able to schedule required 

maintenance. Therefore, continued focus by the ASME and NRC on incorporating 

better and more effective testing techniques and trending methods into the ASME OM 

Code and NRC regulations is very important in achieving the full potential of IST 

programs.

References

1. 10 CFR 50.55a, “Codes and Standards.”

2. GL 89-04, “Guidance on Developing Acceptable Inservice Testing Program.”

3. NUREG-1482, “Guidelines for Inservice Testing at Nuclear Power Plants.”

4. RG 1.84, “Design, Fabrication, and Material Code Case Acceptability, ASME III.”

5. RG 1.147, “Inservice Inspection Code Case Acceptability ASME Section Division I.”

6. RG 1.192, “Operation and Maintenance Code Case Acceptability, ASME OM Code.”
344

TIME LINE OF MAJOR

ASME CODE REVISIONS AND 10 CFR50.55a UPDATES

ASME 

CODE

MAJOR CHANGES YEARS REFERENCED IN10 

CFR 50.55a and UPDATES

SECTION 

XI, IWP 

AND IWV

1971

Summer 

1973

Addenda

Draft IST requirements developed 

and incorporated in Section XI

1971 thru 1976

Incorporated Section XI by 

reference into 10 CFR 50.55a

Added 10 CFR 50.55a(g) for 

ISI/IST

SECTION 

XI, IWP 

AND IWV

1974 1977 thru 1979

SECTION 

XI, IWP 

AND IWV

1977 Pump test changed from monthly to 

quarterly

Required on-line flow measurement

1980 thru 1981

Added 40-month update 

requirement in 10 CFR 

50.55a (g)(4)(iv)

SECTION 

XI, IWP 

AND IWV

1980 1982 thru 1985

Modified update requirement 

from 40-month to 10-year

SECTION 

XI, IWP

AND IWV

1983 1986 thru 1988

SECTION 

XI, IWP 

AND IWV

1986 1989 thru 1992
345

SECTION 

XI, IWP 

AND IWV

1989

1988

Addenda

Section XI references OM-1987 Part 

6 and Part 10 

Changes in Part 6 for pump test

Deleted suction pressure, bearing 

temperature and lubrication 

requirements

Specified different acceptance

criteria for centrifugal, vertical line 

shaft, and positive displacement 

pumps

Changed the run time between 

stabilization and data collection from 

5 minutes to 2 minutes

Provide vibration acceptance criteria 

in velocity units

Increase the upper end acceptable 

range from 1.03 to 1.10 

Changes in Part 10 for valve test

Clarified and included relief valves 

in the scope

Allowed testing of certain check 

valves to be extended to refueling 

outage frequency

Change the acceptance criteria for 

stroke time testing of power 

operated valves

Allowed disassembly, reassembly 

and 

inspection to be used for check 

valves

on a refueling outage frequency

Identified testing requirements in 

OM-1 for safety/relief valves

Deleted containment isolation 

valves from IST leak testing 

requirements

Deleted trending and corrective 

1993 thru 1997

Added 10 CFR 50.55a(f) 

specifically for IST of pumps 

and valves

Added 10 CFR 50.55a(b)(viii) 

for reference of ASME OM 

Code replacing ASME Code, 

Section XI
346

action from leak testing 

requirements for Category A valves

Started issuance of OM Code 

Cases for acceptable alternatives

SECTION 

XI, IWP 

AND IWV

1992 1998 thru 1999

OM CODE, 

ISTB AND 

ISTC

1995 ISTB for pumps and ISTC for 

valves 

Changes in ISTB for pump test

Pump tests were classified into 

Group A, Group B and 

Comprehensive test.

Different test requirements and

acceptance criteria were specified 

for 

centrifugal, vertical line shaft, and 

nonreciprocating/reciprocating positive 

displacement pumps.

Instrument accuracy of pressure 

and 

pressure differential measurements 

for 

comprehensive tests were tightened 

from ±2% to ±1⁄2%

2000 thru 2002

Included 4 modifications to 

OM Code in 10 CFR 50.55a 

(b)(i)/(ii)/(iii)/(iv)

Replaced 10 CFR 

50.55a(b)(viii) by 10 CFR 

50.55a(b)(3) for referencing 

ASME OM Code 

OM CODE, 

ISTB AND 

ISTC

1998 Changes in ISTC for valve test

Added bi-directional testing 

requirements for check valves

2003 thru 2004

Added one additional 

modification to ASME OM 

Code in 10 CFR 50.55a 
347

Specified separate testing

requirements for motor-operated

valves, pneumatically-operated 

valves, 

hydraulically-operated valves, and

solenoid-operated valves

Added Condition Monitoring 

Program as an acceptable option for 

check valve testing

Added manual valve test every 5 

years in OMa-1999 Addenda

Added instrumentation requirements 

for valve testing

(b)(vi)

OM CODE, 

ISTB AND 

ISTC

2001 ISTC for valve test

Incorporated 5 year manual valve 

test frequency 

2005 thru 2008

Removed 10 CFR 50.55a 

(b)(iii) modification 

In 2008, added facilities with 

combined license issued 

under 50.52

OM CODE, 

ISTB AND 

ISTC

2004 2009 thru 2010

OM CODE, 

ISTB AND 

ISTC

2010 to present

In process to incorporate 

2005 addenda and 2006 

addenda into 10 CFR 50.55a, 

and expected to be published 

in 2011

349

Papers Not Presented in a Symposium Session

 

351

Update on ISTOG Activities for 2011

Ed Cavey

ISTOG Chairman

Newport, Michigan, USA

Abstract

This presentation will introduce the InService Testing Owners Group (ISTOG) to those 

attendees who are unfamiliar with our group, highlight ISTOGs accomplishments, and 

will brief the attendees on our current and planned activities. ISTOG was formed 

several years ago to provide a forum for Inservice Testing (IST) experts to share 

knowledge and experience. This dynamic group is dedicated to promoting high 

standards for nuclear plant pump and valve testing. New IST engineers are helped 

tremendously by having access to more experienced peers. ISTOG is also embarking 

on a new mission to create detailed technical documents which cover specific American 

Society of Mechanical Engineers (ASME) Code for Operations and Maintenance of 

Nuclear Power Plants (OM Code) implementation guidance. These documents will be 

targeted to the areas of OM Code implementation which have been identified as the 

most relevant and needed. Such guidance standards, developed from a large pool of 

knowledgeable experts with field IST experience and reflecting best practices, will 

provide benefit to the entire industry. Two examples of planned guidance documents 

are: 

• Allowable variance from fixed reference values during pump testing 

• Post maintenance testing and controls for packing adjustments / backseating of power 

operated valves 

ISTOG has already developed several excellent position papers and best practices 

documents such as: 

• Guidance on pre-conditioning as it relates to IST 

• Standard for IST Program Manager position qualification 

• Check Valve Condition Monitoring guideline (developed jointly with the Nuclear 

Industry Check Valve Group) 

• Guidance for implementation of Motor Operated Valve (MOV) Code Case OMN-1 

(developed jointly with Motor Operated Valve Users Group) 

ISTOG members who post a question to the community using our email distribution 

network typically receive a dozen or more responses within a few days. Personnel with 

experience specific to the question often share documentation related to investigations 
352

and analysis. By collecting and organizing all of these Q&A topics, ISTOG has created a 

powerful database of IST-related operating experience. A current and growing collection 

of 415 individual pump and valve testing topics with a total of over 2840 related postings 

can be found at our members’ website.

Introduction

The ISTOG Charter contains the following Purpose and Objectives statements:

PURPOSE

ISTOG collects, integrates, and shares industry knowledge, resources, and products so 

that members will benefit from improved implementation of IST programs. The benefits 

of this collaborative effort include cost reduction, error reduction, improved performance, 

aging workforce knowledge capture for future generations, and increased regulatory 

influence.

OBJECTIVES

To accomplish the ISTOG purpose, the following objectives have been established:

• Provide forum for joint discussions and resolution of IST issues through 

communication between ISTOG members and other industry organizations, e.g. 

ASME and the Nuclear Regulatory Commission (NRC).

• Provide a mechanism for making recommendations on IST issues to industry 

organizations, e.g., ASME and NRC.

•Provide improved plant safety and availability through recommendations of improved 

IST.

• Capture knowledge and experience of industry personnel in the IST field.

The ISTOG action items for 2011 are dominated by the effort to provide 

recommendations to the NRC for the proposed NUREG-1946. In 2010 the NRC 

released a draft version of the new NUREG-1946 which was planned to supersede 

NUREG-1482. IST owners from all over the nation were concerned due to the possible 

loss of many guidance areas [from NUREG-1482] which had helped form the very basis 

of modern IST programs. The ISTOG Steering Committee commissioned a survey 

intended to identify and prioritize the various guidance areas being dropped in NUREG1946. That survey result and the actions being taken in 2011 by ISTOG are discussed 

in this paper.
353

NUREG-1482 Related Activity

The ISTOG survey on NUREG-1482 guidance began by assembling a listing of the 

important topical areas within the NUREG. That listing is as follows:

NUREG Section / Element description

3.1.1 Guidance on preparing acceptable Cold Shutdown Justifications (CSJ) / 

Refueling Outage Justifications (ROJ) deferrals

3.1.1.2 Testing during power ascension

3.1.3 IST exam scheduling, including discussion on grace

3.4 Skid-mounted components

4.1.2 Check valve non-intrusive testing

4.2.1 Limiting stroke time values for Power Operated Valves (POVs)

4.4.2 Post Maintenance Testing (PMT) following packing adjustments / backseating

4.4.4 Pressure Isolation Valve (PIV) testing

5.2.2 Use of pump reference curves

5.3 Variance from fixed reference values

5.5.2 Use of tank level change in lieu of flow measurement

5.5.3 Use of tank level change in lieu of differential pressure (DP) measurement

5.1 Alternatives to Comprehensive Pump Testing requirements

IST Program Managers were asked to rank each of these items in a 1-5 scoring system 

where 5 identifies critical guidance important to IST Programs. A score of 1 would 

indicate that loss of this guidance area from the NUREG would not be significant.

15 utilities responded to the survey and the scores for each NUREG section were 

tabulated. The following were the survey results:
354

NUREG Topical Area 

Guidance on preparing acceptable

Score

CSJ / ROJ deferrals 3.1

Testing during power ascension 3.2

IST exam scheduling, including 

discussion on grace 3.9

Skid-mounted components 3.3

Check valve non-intrusive testing 2.9

Limiting stroke time values for POVs 2.7

PMT following packing adjustments

and backseating 4.1

PIV testing 3.2

Use of pump reference curves 4.0

Variance from fixed reference values 4.3

Use of tank level change instead of 

flow measurement 3.1

Use of tank level change instead of 

DP measurement 3.3

Alternatives to Comprehensive Pump 

Testing requirements 3.3

Based on the survey results, the ISTOG Steering Committee attempted to bin each of 

the topical areas into the following categories:

1) ISTOG - A Position Paper could be created by ISTOG to capture the essential 

elements of the NUREG topical area. This position paper would provide program 

implementation guidance to IST owners as a replacement for the "loss" of the NUREG 

1482 guidance.

2) ASME - The topical area identified is such that ASME ISTB or ISTC should reconcile 

the loss of the NUREG guidance as an OM Code change or a new Code Case.

The items categorized as ASME reflect guidance which might be construed as OM 

Code clarification. The goal was to coordinate with the ASME OM Code committees to 

seek appropriate OM Code changes or new Code Cases that provide the necessary 

guidance to IST Program owners. It was felt that the new alignment of ISTOG annual 

meetings with the winter ASME OM committee meetings would provide a solid 

mechanism for such cooperation.
355

The following is a listing of the NUREG topical areas by the ownership categorization:

NUREG Topical Area 

Guidance on preparing acceptable

Ownership

 CSJ / ROJ deferrals ISTOG

Testing during power ascension ASME

IST exam scheduling, including 

discussion on grace ASME

Skid-mounted components ISTOG

Check valve non-intrusive testing ISTOG

Limiting stroke time values for POVs ISTOG

PMT following packing adjustments

and backseating ISTOG

PIV testing ASME

Use of pump reference curves ISTOG

Variance from fixed reference values ISTOG

Use of tank level change instead of 

flow measurement ASME

Use of tank level change instead of 

DP measurement ASME

Alternatives to Comprehensive Pump 

Testing requirements ASME

During the ISTOG meeting held in Clearwater Beach, FL during December 2010, there 

were many hours of discussion on the topical areas highlighted above. The NRC 

representatives at the meeting provided feedback that indicated intent to consider 

restoring some of the NUREG-1482 guidance in the new NUREG 1946. The ISTOG 

welcomed the opportunity to provide consensus recommendations for all of these key 

items. 

One issue in particular, allowable variance about the fixed reference value, was very 

challenging because of the many strong opinions on the subject. ISTOG sought to 

achieve a full consensus recommendation while the ASME ISTB Committee also sought 

to develop improved guidance. This issue is very important to plant IST personnel 

because it directly affects the testing methodology for all IST-scope pumps. I believe 

that the ISTOG recommendation is aligned with the planned changes to ISTB, and it is 

hoped that the upcoming revision to NUREG-1946 (or 1482) will reflect the overall 

consensus.
356

ISTOG has also recently released a revised position paper on preconditioning. 

Preconditioning has been a topic of great interest in recent years due to increasing 

attention by the NRC. This position paper provides IST program managers with an 

excellent source of information intended to prevent situations where unacceptable 

preconditioning could occur.

ISTOG has also been upgrading and enhancing the "ISTOG OE" database. Since the 

group’s inception in 2004, there have been a tremendous number of email questions 

and answers. These individual "Q&A" topics represent a very useful source of 

information to new or inexperienced IST Engineers. The ISTOG OE database is well 

organized and searchable. High level bins are Pump, Valve, and General IST, with 

several further groupings under each. One example of a recent Q&A topic was a 

question regarding lower than expected baseline performance data following a pump 

replacement. Ten responses came from veteran IST Engineers within 2 days. Some 

responses requested additional information from the question initiator in order to provide 

more accurate responses. Another example was a simple survey of plants to determine 

which plants continue to perform partial stroke tests of Main Steam Isolation Valves 

while at power. That request elicited 23 responses within 4 days, and several of those 

responses provided important amplifying information related to the issue. Archival and 

query access to this IST Q&A database is an important product being provided by 

ISTOG to its members.

Conclusion

The Inservice Testing Owners group is providing its members with an organized, 

effective forum to share ideas and problems. ISTOG is also producing written 

consensus standards addressing key industry-wide topics, as well as acting as a single 

interface for representing owners before such groups as ASME and the NRC. 

Acknowledgments

Bob Parry - ISTOG Vice Chairman

Dennis Swann - ISTOG Steering Committee

Brad Scott - ISTOG Steering Committee

Mark Clouse - ISTOG Steering Committee

John Dore - ISTOG Steering Committee

Tom Robinson - ISTOG Steering Committee

Corey Thomas - ISTOG Steering Committee

Brian Payne - ISTOG Steering Committee

Brian Lindenlaub - ISTOG Steering Committee

Bryan Andrie - ISTOG Steering Committee

Ron Lippy - True North Consulting

Mark Gowin - TVA Corporate IST
357

Mike Hanley - PG&E Comanche Peak IST

Wavel Justice - Entergy Corporate IST

John Kin - Dominion Corporate IST

Jeff Neyhard- True North Consulting

Shelly Neyhard- True North Consulting

References

www.istog.net - Note that much of this website content is available only to actual 

members of ISTOG.

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse)

NRC FORM 335

(12-2010)

NRCMD 3.7

U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

 (Assigned by NRC, Add Vol., Supp., Rev.,

 and Addendum Numbers, if any.)

NUREG/CP-0152, Vol. 8

3. DATE REPORT PUBLISHED

MONTH

August

YEAR

2011

4. FIN OR GRANT NUMBER

2. TITLE AND SUBTITLE

Proceedings of the Eleventh NRC/ASME Symposium on Valves, Pumps and Inservice Testing

5. AUTHOR(S)

Editor: M. D. Orenak

6. TYPE OF REPORT

Conference Proceedings

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

U.S. Nuclear Regulatory Commission

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Division of Component Integrity, Wasington, DC 20555-0001

provide name and mailing address.)

and mailing address.)

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

The 2011 Symposium on Valves, Pumps, Snubbers, and Inservice Testing, jointly sponsored by the Board on Nuclear Codes

and Standards of the American Society of Mechanical Engineers and by the U.S. Nuclear Regulatory Commission, provides a

forum for exchanging information on technical, programmatic, and regulatory issues associated with the inservice testing

programs at nuclear power plants, including design, operation, and testing of valves, pumps, and snubbers that help ensure their

reliable performance. The participation of industry representatives, regulatory personnel, and consultants ensures the

presentation of a broad spectrum of ideas and perspectives regarding the improvement of inservice testing programs and

methods for valves, pumps, and snubbers at nuclear power plants.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.)

Inservice Testing

Valves

Pumps

Snubbers

Motor-Operated

Air-Operated

ASME Bioler & Pressure Vessel Code

ASME Code for Operation and Maintenance of Nuclear Power Plants

14. SECURITY CLASSIFICATION

13. AVAILABILITY STATEMENT

unlimited

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (12-2010)

Board on Nuclear Codes and Standards of the American Society of Mechanical Engineers

ASME Board on Nuclear Codes and Standards, Three Park Avenue, New York, NY, 10016-5990


UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

--------------------

OFFICIAL BUSINESS
NUREG/CP-0152, Vol. 8 PROCEEDINGS OF THE ELEVENTH NRC/ASME SYMPOSIUM ON VALVES, 

PUMPS, AND INSERVICE TESTING