ML16266A152

Forwards Request for Addl Info Re Plant IPE Submittal for Generic Issues 105, Interfacing Sys LOCA at Lwrs, 153, Loss of Essential Svc Water in LWRs & 23, RCP Seal Features

ML16266A152
Person / Time
Site:	Oconee
Issue date:	07/21/1992
From:	Wiens L Office of Nuclear Reactor Regulation
To:	Hampton J DUKE POWER CO.
References
REF-GTECI-023, REF-GTECI-105, REF-GTECI-153, REF-GTECI-NI, TASK-023, TASK-105, TASK-153, TASK-23, TASK-OR TAC-M74440, TAC-M74441, TAC-M74442, NUDOCS 9207300194
Download: ML16266A152 (30)

Text

July 21, 1992 Docket Nos. 50-269, 50-270 and 50-287 Mr. J. W. Hampton Vice President, Oconee Site Duke Power Company P. 0. Box 1439 Seneca, South Carolina 29679

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION CONCERNING OCONEE INDIVIDUAL PLANT EXAMINATION (IPE) SUBMITTAL FOR GENERIC ISSUES (GI)-105, 153, AND 23 (TACS M74440/M74441/M74442)

As part of the Oconee IPE submittal, Duke Power Company proposed GI-105, "Interfacing Systems LOCA at LWRs," GI-153, "Loss of Essential Service Water in LWRs," and GI-23, "Reactor Coolant Pump Seal Failures," for resolution.

Based on our ongoing review of the Oconee IPE submittal and its associated documentation, we find that additional information is required in order to complete our review of these issues. Enclosed are specific questions relating to each of the GIs. You are requested to provide written responses to the questions within 45 days of receipt of this letter. If you have questions regarding this matter, contact me at (301) 504-1495.

This requirement affects fewer than 10 respondents and, therefore, is not subject to Office of Management and Budget clearance under P.L.96-511.

Sincerely,

/s

/

Leonard A. Wiens, Project Manager Project Directorate 11-3 Division of Reactor Projects -

I/IL Office of Nuclear Reactor Regulation

Enclosures:

1. GI-105 Questions 77

2. GI-153 QuestionsUL L

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3. GI-23 Questions cc w/enclosures:

Document Name:

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/2/92 9207300194 920721 PDR ADOCK 05000269

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555 July 21, 1992 Docket Nos. 50-269, 50-270 and 50-287 Mr. J. W. Hampton Vice President, Oconee Site Duke Power Company P. 0. Box 1439 Seneca, South Carolina 29679

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION CONCERNING OCONEE INDIVIDUAL PLANT EXAMINATION (IPE) SUBMITTAL FOR GENERIC ISSUES (GI)-105, 153, AND 23 (TACS M74440/M74441/M74442)

As part of the Oconee IPE submittal, Duke Power Company proposed GI-105, "Interfacing Systems LOCA at LWRs," GI-153, "Loss of Essential Service Water in LWRs," and GI-23, "Reactor Coolant Pump Seal Failures," for resolution.

Based on our ongoing review of the Oconee IPE submittal and its associated documentation, we find that additional information is required in order to complete our review of these issues. Enclosed are specific questions relating to each of the GIs.

You are requested to provide written responses to the questions within 45 days of receipt of this letter. If you have questions regarding this matter, contact me at (301) 504-1495.

This requirement affects fewer than 10 respondents and, therefore, is not subject to Office of Management and Budget clearance under P.L.96-511.

Sincerely, Leonard A. Wiens, Project Manager Project Directorate 11-3 Division of Reactor Projects -

I/II Office of Nuclear Reactor Regulation

Enclosures:

1. GI-105 Questions

2. GI-153 Questions

3. GI-23 Questions cc w/enclosures:

See next page

Mr. J. W. Hampton Duke Power Company Oconee Nuclear Station cc:

Mr. A. V. Carr, Esquire Mr. M. E. Patrick Duke Power Company 422 South Church Street Comp Charlotte, North Carolina 28242-0001 Oconee Nuclear Site P. 0. Box 1439 J. Michael McGarry, III, Esquire Seneca, South Carolina 29679 Winston and Strawn 1400 L Street, NW.

Mr. Alan R. Herdt, Chief Washington, DC 20005 Project Branch #3 U. S. Nuclear Regulatory Commission Mr. Robert B. Borsum 101 Marietta Street, NW. Suite 2900 Babcock & Wilcox Nuclear Power Division Suite 525 Ms. Karen E. Long 1700 Rockville Pike Assistant Attorney General Rockville, Maryland 20852 North Carolina Department of Justice Manager, LIS P. 0. Box 629 NUS Corporation Raleigh, North Carolina 27602 2650 McCormick Drive, 3rd Floor Clearwater, Florida 34619-1035 Mr. R. L. Gill, Jr.

Senior Resident Inspector Licensing U. S. Nuclear Regulatory Commission P. 0. Box 1007 Route 2, Box 610 Charlotte, North Carolina 28201-1007 Seneca, South Carolina 29678 Regional Administrator, Region II U. S. Nuclear Regulatory Commission 101 Marietta Street, NW. Suite 2900 Atlanta, Georgia 30323 Mr. Heyward G. Shealy, Chief Bureau of Radiological Health South Carolina Department of Health and Environmental Control 2600 Bull Street Columbia, South Carolina 29201 Office of Intergovernmental Relations 116 West Jones Street Raleigh, North Carolina 27603 County Supervisor of Oconee County Walhalla, South Carolina 29621

ENCLOSURE 1 REQUEST FOR ADDITIONAL INFORMATION ON GI-105, "INTERFACING SYSTEM LOCA IN PWRS" The Oconee IPE discussion of GI-105, "Interfacing-System LOCA in PWRs" invokes NUREG/CR-5102, "Interfacing Systems LOCA: Pressurized Water Reactors,"

February 1989, in part to support the conclusion that this issue should be considered resolved for Oconee. NUREG/CR-5102 was in turn based in part on the "Oconee PRA", NSAC-60, June 1984. The IPE derived an annual core-melt frequency of 4.5E-10 for ISLOCAs at Oconee.

The most recent studies of ISLOCAs at PWRs (in publication) are much more comprehensive than NUREG/CR-5102. Core-melt frequencies of 2E-6 per R-Y are the norm for these studies with an ongoing investigation into auxiliary building designs indicating that ISLOCA CMF could be significantly higher at some plants. One of the recent studies, "Assessment of ISLOCA Risks -

Methodology and Application: Babcock and Wilcox Nuclear Power Station",

NUREG/CR-5604, April 1992 indicates that human errors during testing and transition between modes of operation must be addressed in ISLOCA analyses. In addition, break location and possible damage to injection equipment by ISLOCA flooding or a high temperature/high humidity environment are also necessary considerations for an ISLOCA analysis to be complete. In part because of the foregoing and in part because other information is not included in the IPE, the IPE treatment of GI-105 cannot be considered adequate to consider the issue resolved at Oconee. In particular, the following information is required:

1.

Valve failure modes considered.

2.

Valve failure rates used.

3.

Have procedures been analyzed for:

a.

identification of possible errors of commission involving motor operated pressure isolation valves (PIVs)?

b.

identification of procedurally sanctioned or other defeat of PIV interlocks?

c.

inclusion of appropriate warnings and independent verifications regarding PIV operation?

4.

To what extent has industry operating experience been factored into the analysis, including human errors?

5.

Are valves leak-tested individually or together as one barrier (e.g.,

check valves in the LPI system)?

6.

What attention was given to identification of likely break locations and ISLOCA flooding and environmental effects on injection equipment necessary for recovery? A comment is made in the IPE to the effect that ISLOCAs are considered nonrecoverable, yet later mention is made that an

-2 ISLOCA through the auxiliary spray line is within the capacity of one HPI pump. Following an auxiliary spray line ISLOCA, is there an HPI pump operational? Are any injection pumps available after an ISLOCA and if so, for how long? NUREG/CR-5604 and companion volumes produced by the NRC GI-105 resolution program have indicated that because ISLOCA frequencies can be higher than estimated by past PRA approaches to the problem, recovery actions can be important to prevention of core melt.

7.

Only three interfacing system pathways were discussed in the IPE.

Each of the identified pathways should be discussed, or provide a more detailed justification for not including the interface in the analysis.

Any justification should include details such as ability of motor operated valves to operate under anticipated differential pressures, impact of human errors, and estimated frequency of occurrence.

8.

When procedures, human errors, and transition between modes of operation are considered, different sequences are possible in the same system.

Were these factors included in the analysis of the identified interfacing system pathways? If not, please provide a discussion of these factors for each of the analyzed sequences.

ENCLOSURE 2 REQUEST FOR ADDITIONAL INFORMATION ON GI-153, "LOSS OF ESSENTIAL SERVICE WATER IN LWRS"

1.

Provide additional detail of your analysis to substantiate the following statements:

a.

"The total Unit 3 core-melt frequency attributable to a loss of LPSW initiator is less than 1.OE-08 per year for Unit 3."

b.

"The probability of a core melt due to LPSW pump failures for Units 1 and 2 is estimated to be less than 1.OE-08..

2.

Based on the statements in Item 1. above, the core-melt frequency has accounted for only the contribution due to "a loss of LPSW initiator."

It should be noted that this contribution due to a loss of LPSW initiator represents only part of all service water related contributions to the plant core-melt frequency. Other risk contributions which are indicated in the following should also be addressed:

a.

The contribution due to LPSW failure or degradation following other initiating events;

b.

The contribution due to functional failures induced by SWS problems, e.g., unavailability resulting from maintenance.

Provide a list of all dominant accident sequences involved and their associated contributions to core-melt frequency.

3.

Should the total core-melt frequency attributable to the LPSW system become significant resulting from the considerations stated above, provide your technical basis for resolving the issue. This information should include consideration of alternatives to reduce the risk, if needed. The alternatives considered could include the following:

Improving procedures, training, or maintenance practice.

Improving hardware.

Changing system dependency.

4.

It is stated that the total Unit 3 core-melt frequency attributable to a loss of LPSW initiator is based on the ability to recover via the cross connect with Units 1 and 2. Provide information of recovery actions and time period required to perform these actions, and the success criteria for these actions.

ENCLOSURE 3 REQUEST FOR ADDITIONAL INFORMATION ON GI-23, "REACTOR COOLANT PUMP SEAL FAILURES" Additional information is needed for the staff to make a determination regarding whether GI-23 can be considered resolved for the Oconee Station. On April 19, 1991, the staff published draft Regulatory Guide DG-1008 for public comment. Since many of the staff questions below are related to this draft Regulatory Guide, a copy is enclosed for your information.

1.

Are the QA provisions for the reactor coolant pump (RCP) seals provided at the Oconee Station consistent with the item 1 of the regulatory position of draft Regulatory Guide DG-1008? Section 10.3.2 of the Oconee IPE report briefly discusses installation and maintenance, but does not address the other aspects of QA.

2.

Are the operating procedures for RCP seals at Oconee consistent with the item 2.1 of the regulatory position of draft Regulatory Guide DG-1008?

Although Section 10.3.2 of the Oconee IPE report briefly mentions procedures, it does not provide sufficient detail for the staff to make a judgment.

3.

Is the instrumentation relative to the RCP seals at Oconee consistent with the item 2.2 of the regulatory position of draft Regulatory Guide DG-1008? Section 10.3.2 of the Oconee IPE report does not appear to cover this instrumentation.

4.

Regarding off-normal conditions, Section 10.3.3 (page 10-10) of the Oconee IPE report states that "... the core-melt frequency due to transient induced seal LOCAs is 6.2-06/yr...."

It is not clear whether this value includes the risk reduction achieved by the Standby Shutdown Facility (SSF), or whether it is largely based on the assumption that a seal leak rate of 100 gpm/pump will occur 15 minutes following loss of all seal cooling and will remain constant at that value for longer time periods.

Please clarify this point.

5.

The sub-parts of this question assume that the answer to question 4 is that the 6.2-06/year is based, at least in part, on the benefit provided by the SSF. If that is not the case, ignore this question and proceed to question 6.

a. Is the design of the SSF at Oconee consistent with the item 3.2 of the regulatory position of draft Regulatory Guide DG-1008, including the provisions of Appendices A and B of the draft guide?

b. Please provide clarification regarding the time at which the seal injection can be re-established using the SSF:

(1) Page 10 -

10 of the Oconee IPE report states that "Operators are trained that seal cooling must be re-established within 10 minutes following a loss of seal cooling to preclude damage."

Yet a probability of 90% at 15 minutes is assumed. Please discuss

the distinction between the 10 minutes and 15 minutes, or provide the probability of successful operator action in 10 minutes.

(2) Please confirm that the times quoted correspond to the actual onset of the loss of seal cooling, and not from the "declaration" of an event such as station blackout or loss of seal cooling, which may include the time required for the plant staff to perform a number of emergency operating procedures.

6.

The sub-parts of this question assume that the answer to question 4 is that the 6.2-06/year is based, at least in part, on the lack of dependency between seal cooling and various systems. If that is not the case, ignore this question.

a. The discussion of dependencies in Section 10.3.2 of the Oconee IPE report indicates that there is little or no concern about the service water dependency since both the Low Pressure Service Water and High Pressure Service Water Systems can provide cooling to the HPI pump.

Please confirm that these systems are independent of each other.

b. The Oconee IPE report does not appear to address inadvertent termination of RCP seal cooling from causes such as:

(1) containment isolation, (2) loss of pneumatic system, or (3) a safety injection signal.

Please confirm that the HPI will continue to provide seal injection under these conditions.

2

U.S.

NUCLAR REGULATORY COuissiou Division I OFFICE OF NUCLEAR REGULATORY RESEARCH Task OG-1008 DRAFT REGULATORY GUIDE

Contact:

J. E. Jackson (301) 492-3923 DRAFT REGULATORY GUIDE DG-1008 REACTOR COOLANT PUMP SEALS A. INTRODUCTION The General Design Criteria contained in 10 CFR Part 50,

'Domestic Licensing of Production and Utilization Facilities," in Appendix A, "General Design Cri teria for Nuclear Power Plants," provide for a high-quality'reactor coolant pressure boundary. Criterion 14 states that the reactor coolant pressure bound ary is to be designed, fabricated, erected, and tested to have an extremely low probability of abnormal leakage, rapidly propagating'failure, and gross rupture.

Criterion 1, "Quality Standards and Records'" of:-Appendix A to 10 CFR Part 50 includes a requirement for a quality assurance (QA) program to provide adequate assurance that structures, systems, and components important to safety will perform their safety functions.

Criterion 13, "Instrumentation andn tro," requires that instrumentation be provided to monitor variables and system over their anticipated ranges for normal operation, for anticipatedperational occurrences, and for accident con ditions as appropriate to assure dequd e safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.

Criterion 13 uires that controls be provided to maintain these variables and systems witil prescribed operating ranges.

Criterion 30, Q ity of Reactor Coolant Pressure Boundary," of Appendix A to 10 CFR Part 50requires that components that are part of the reactor coolant pressure boundary,!'e designed, fabricated, erected, and tested to the highest quality standards practical.

Criterion 30 requires that means be provided for This regulatory guide is being issued in draft form to involve the pbelic in the early stages o the develop ment of a regulatory position in this area.

It has not received complete staff review and does not represent an official NRC staff position.

Public conents are being solicited on the draft guide (including any implementation schedule) and its associ ated regulatory analysis or value/impact statement.

Comments should be accompanied by appropriate supporting data.

Written comments may be submitted to the Regulatory Publications Branch. oIsr Office of Administra tion, U.S.

Nuclear Regulatory Commission. Washington o

DC 20555.

Copies of cowients received may be examined

-at the NRC Public Dcument Rooc.

2120 L Street NW.,

Washington.

DC.

Comments will be most helpful if received by Jluly 31, 1991.

Requests for single copies of craft guides (which may be reproduced) or for placement on an automatic dis-ri bution list for single copies of future draft guides in specific divisions should be made In writing to,-e U.S. Nuclear Regulatory Commission.

Washington, DC 20555, Attention:

Director. Division of Information Support Services.

detecting and, to the extent practical, identifying the location of the source of reactor coolant leakage.

Criterion 44, "Cooling Water," requires a cooling water system be provided to transfer heat from structures, systems, and components important to safety to an ultimate heat sink. The system safety function is to transfer the com bined heat load of these structures, systems, and components under normal oper ating and accident conditions.

Suitable redundancy in components and features, as well as suitable interconnections, leak detection, and isolation capabilities, are to be provided to ensure that for onsite electric power system operation (assuming offsite power is not available) and for offsite electric power system operation (assuming onsite power is not available) the system safety function can be accomplished, assuming a single failure.

Paragraph (a), "Requirements," of 10 CFR 50.63, "Loss of All Alternating Current Power," requires that each light-water-cooled nuclear power plant be able to withstand and recover from a station blackout (i.e., loss of the offsite electric power system concurrent with reactor trip and unavailability of the onsite emergency ac power source) of a specified duration. Section 50.63 requires that, for the station blackout duration, the plant be capable of main taining core cooling and appropriate containment integrity. It also identifies the factors that should be considered in specifying the station blackout dura tion, including leakage from reactor coolant pump (RCP) seals.

The development and promulgation of 10 CFR 50.63 made an assumption regarding the magnitude of RCP seal leakage during a station blackout event. It was left to GI-23 to validate that assumption regarding seal leakage with no seal cooling.

This guide describes means acceptable to the NRC staff for enhancing safety by including the RCP seals in the QA program to better ensure that the reactor coolant pressure boundary has an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture. This guide also describes methods acceptable to the NRC staff for enhancing the capability of nuclear power plants to withstand loss-of-seal-cooling events, given the poten tial for failure of RCP seals.

Any information collection activities mentioned in this draft regulatory guide are contained as requirements in 10 CFR Part 50, which provides the regu latory basis for this guide. The information collection requirements in 10 CFR Part 50 have been cleared under OMB Clearance No. 3150-0011.

2

8. DISCUSSION Failure of an RCP seal that can result in a loss-of-coolant accident (LOCA) can occur during normal operation when leakage through the seals exceeds the capacity of the normal makeup systems, as has occurred in operating plants.

RCP seal failure can also occur during off-normal (abnormal) conditions such as station blackout, loss of component cooling water (CCW), or loss of service water (SW) scenarios when loss of seal cooling represents a potential common cause failure (CCF) for all RCP seals.

RCP seals limit the leakage of reactor coolant along the pump shaft, directing the majority of this flow back to the chemical and volume control system (CVCS), with the remainder being directed to the reactor coolant drain tanks.

In limiting the reactor coolant leakage to containment, the RCPs use a series of primary and secondary seals. Therefore, these seals become part of the reactor coolant system pressure boundary. The primary seals (metallic oxides, carbides, and graphite) limit the leakage of reactor coolant across the interface between rotating and stationary RCP elements. The secondary seals (elastomer 0-rings, U-cups, and teflon channel seals) prevent leakage between stationary mechanical elements of the RCP seal or those elements that have only a slight relative motion. Both the primary and secondary seals are intended to be continuously cooled during pump operation and at hot shutdown conditions when RCPs are not operating.

Some RCP seal failures have resulted in a loss of primary coolant that exceeded the normal makeup capacity of the plant. These seal failures were therefore a small LOCA. In all the seal failures that have occurred to date, emergency core cooling capability was available to replenish reactor coolant lost through seal leakage. However, RCP seal failures have continued to occur, and such failures represent a source of further challenges to the emergency core cooling system (ECCS).

There are also some potential common mode vulnerabilities that could both cause an RCP seal LOCA and render the mitigating systems inoperable, and thus they could lead to core melt. One such scenario involves the complete loss of the CCW system, which provides cooling water to the seal thermal barrier heat exchanger. In some plants, the reactor coolant makeup system pumps or CVCS charging pumps that supply RCP seal injection flow are also cooled by the CCW system. Furthermore, in some plants, the reactor coolant makeup pumps are used 3

as the high pressure safety injection pumps. Other plants may have separate high pressure safety injection pumps, but these may also be cooled by CCW.

Therefore, for some plants, complete loss of CCW could result in the equivalent of a small-break LOCA caused by seal degradation, with no high pressure safety injection pumps available for emergency core cooling. This sequence of events could lead to core melt and could be caused by the loss of all ac power (station blackout).

Another potential common mode scenario involves the complete loss of all service water (SW).

Essentially all plants rely on the SW system, either directly or indirectly via the CCW system, for cooling the CVCS charging pumps and the high head safety injection pumps. For plants with this common mode vulnerability, loss of all SW could result in a sequence of events that could lead to core melt.

The objectives of the actions described in the Regulatory Position of this guide are to:

(1) Reduce the probability of RCP seal failures, (2) Have plant procedures that would minimize the safety impact of RCP seal failure or degradation, (3) Have sufficient instrumentation to permit proper implementation of the procedures, (4) Have independent means of providing cooling to the RCP seals for severe events, such as station blackout, which make the normal seal cooling systems inoperable.

Clearly, the General Design Criteria contained in Appendix A to 10 CFR Part 50 provide for a high-quality reactor coolant pressure boundary. Criterion 14 states that the reactor coolant pressure boundary is to be designed, fabri cated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture. Paragraph (c) of 10 CFR 50.55a, "Codes and Standards," requires that components that are part of the reactor coolant pressure boundary meet the requirements for Class 1 compo nents in Section III of the ASME Boiler and Pressure Vessel Code. However,Section III of the ASME Boiler and Pressure Vessel Code has included specific exemptions for seal components under NB-3411.2 and NB-2121(b). As a result, the RCP seal has not always been treated as important to safety in the pressure 4

boundary; based on operating experience, its failure probability is considerably higher than that of the passive elements of the primary system boundary.

The safety concerns regarding seal failure apply to pressurized water reactor (PWR) plants, since boiling water reactors (BWRs) exhibit significantly lower leak rates from seal failures, primarily because of their lower system pressure. In addition, the effects of leakage from pump seal failures in 8WRs can be mitigated by several systems, including reactor core isolation cooling, high pressure coolant injection, and normal feedwater. BWRs also have isolation valves in the recirculation loops.

The Reactor Safety Study, WASH-1400 (Ref. 1), published in October 1975, estimated that breaks in the reactor coolant pressure boundary from all sources in the range of 0.5 to 2 inches in diameter would occur with a frequency of 1E-3 per reactor year. This frequency of small-break LOCA was the largest contribu tor to the PWR core-melt sequences in WASH-1400. Based on licensee event report (LER) review in the early 1980s, RCP seal failures, with leak rates equivalent to those of small-break LOCAs, were actually occurring at a frequency of about 1E-2 per reactor year, an order of magnitude greater than the pipe break fre quency used in WASH-1400.

Thus the overall probability of core melt caused by small breaks is dominated by RCP seal failures.

RCP seal failures have occurred from many causes during normal operation, including maintenance errors, wear out, vibration, corrosion, contamination, abnormal pressure staging, overheating of the seal cavity, operator error, improper venting, and defective parts. The resulting seal leakage has varied from very low rates up to 500 gallons per minute. Further, when such failures occur there is no way to isolate the seal.

Plant shutdown and depressurization are necessary to control the leak, and partial draindown of the system is often necessary to stop the leak. RCP seal failures are important from a risk per spective when the seal leakage exceeds the capacity of the normal makeup systems (i.e., a LOCA results) or, because of station blackout or loss of CCW scenarios, when there is a loss of seal cooling that can lead to a common cause failure for all RCPs.

Technical studies of RCP seal and operating experience have identified a need for improving quality control over seal materials and fabrication, instal lation, and maintenance, as well as seal operations. These improvements are expected to decrease the current failure rate for the RCP seals. There is also a need to improve instrumentation and monitoring capabilities in order to 5

identify degraded seal performance early enough to take corrective action to mitigate seal failure.

Research involving RCP seal parameters typical of station blackout conditions indicated that certain secondary seal materials are not adequate to remain functional for representative station blackout durations. Also, seal instability (popping open) has been identified as a likely seal failure mode under station blackout conditions. Seal "popping open" can occur because of seal face flashing, increased axial seal friction, or partial extrusion and jamming of the axial seal.

Based on the results of such studies, there is a need to provide seal cooling during postulated loss of cooling events such as station blackout or failure of the CCW or SW systems to prevent or minimize the probability of common mode failure of all RCP seals.

Reference 2 is a summary of the technical findings of the staff's studies of the RCP seal failure issue.

C. REGULATORY POSITION

1.

QA CONSIDERATIONS Each PWR plant should treat the RCP seal assembly as a component of the safety-related reactor coolant pressure boundary. The QA program should include the RCP seal assembly consistent with its importance to safety, in accordance with Criterion II of Appendix B to 10 CFR 50.

Licensee and vendor QA programs should cover design, manufacture, testing, procurement, installation, mainte nance, inspection, and training and qualification of personnel.

2. OPERATING PROCEDURES AND INSTRUMENTATION In conjunction with the RCP seals being included in the QA program, each PWR plant should provide appropriate operating procedures and instrumentation.

2.1 Operating Procedures Each PWR plant licensee should provide procedures to properly operate the seals under normal conditions and to detect and identify the correct course of action for any given off-normal situation. These procedures should provide 6

guidance on how to use the monitored parameters to identify degradation early enough to prevent or mitigate cascade failure of multi-stage seal assemblies.

These procedures should reflect RCP seal manufacturer and nuclear steam supply system (NSSS) vendor instructions and any plant-specific features. In addition, operators should be trained and qualified in the proper implementation of these procedures.

As a minimum, RCP seal procedures should be provided for normal plant operation conditions, including pump startup, pump shutdown, and off-normal conditions including:

Loss of seal injection flow (where applicable),

Loss of cooling to the thermal barrier heat exchanger, Loss of all seal cooling (the procedures should be consistent with Regulatory Position 3 of this guide),

Pump restart after loss of all seal cooling.

Table 1 gives an example of some types of off-normal conditions for which instructions have been provided by one RCP seal manufacturer. Additional details are in NUREG/CR-4544, Reference 3.

2.2 Instrumentation and Operating Limits Each PWR plant licensee should provide instrumentation sufficient to implement the operating and off-normal procedures and should be capable of moni toring variables and systems over their anticipated ranges for normal operation, anticipated operational occurrences, and accident conditions. In this regard, it is expected that the RCP seal manufacturer and NSSS vendor-recommended instrumentation and operational limits (e.g., alarm setpoints) on the monitored parameters would be available or exceptions justified. By means of proper pro cedures, instrumentation, and training, the operator should have the knowledge to determine the correct course of action for any operational conditions, anticipated operational occurrences, and accident conditions.

Although some exceptions will occur from design variations among the different seal manufacturers, the monitored parameters should include:

7

Valve positions referenced in operating procedures, RCP shaft axial and radial displacement and vibrations, Seal pressure, temperature, and leakage, and Temperature and flow rate for staging flow (hydrodynamic seal), seal injection, thermal barrier heat exchanger, and seal injection pump cooling.

Examples of seal instrumentation and alarm setpoints recommended by three major U.S. RCP seal manufacturers or NSSS vendors are shown in Table 2. This information has been taken from NUREG/CR-4544 (Ref. 3) and represents the knowledge at that time.

3.

SEAL COOLING FOR OFF-NORMAL CONDITIONS A number of off-normal plant conditions such as station blackout, loss of CCW, or loss of SW could lead to a loss of seal cooling, which in turn could lead to seal failure and a consequent loss of reactor coolant inventory (e.g.,

small-break LOCA). Of particular concern during such off-normal conditions would be the potential for a seal LOCA coincident with the loss of ECCS functions because of common dependencies.

The following conditions can result in loss of all RCP seal cooling if certain plant-specific dependencies exist:

Loss of all ac power (i.e., station blackout as defined in 10 CFR 50.2),'

Loss of CCW function, Loss of SW function, Inadvertent termination of RCP seal cooling from a safety-injection or containment-isolation signal or loss of a pneumatic system.

Therefore, in order to maintain seal cooling for off-normal conditions, each PWR should comply with either Regulatory Position 3.1 or 3.2:

'If, as part of the implementation of the station blackout rule, a plant is re-establishing seal cooling within 10 minutes (e.g., by an alternate ac supply which powers the seal injection function), then seal cooling is not considered lost.

8

3.1 Plant-Specific Dependencies Plant-specific dependencies associated with the conditions described in Regulatory Position 3 above should be evaluated and eliminated. Any modifica tions should, as a minimum, meet the design guidelines described in Appendix A of this guide and the quality assurance program in Appendix B of this guide.

If any dependencies can not be eliminated, independent seal cooling should be provided in accordance with Regulatory Position 3.2.

3.2 Independent Seal Cooling Seal cooling should be provided that, as a minimum, meets the design guidelines described in Appendix A of this guide and the quality assurance pro gram in Appendix 8 of this guide and that is independent of normal seal cooling and the support systems to the extent practicable. Some existing seal cooling piping runs may be shared if the probability of failure of the piping is shown to be acceptably low or if, upon piping failure, the leak can be isolated and other seal cooling can be maintained. An example arrangement is given in Figure 1.

D. IMPLEMENTATION The purpose of this section is to provide information to applicants regarding the NRC staff's plans for using this regulatory guide.

This proposed guide has been released to encourage public participation in its development. Except in those cases in which an applicant proposes an accept able alternative method for complying with specific portions of the Commission's regulations, the method to be described in the active guide reflecting public comments will be used in the evaluation of PWR licensees and applicants who are required to comply with General Design Criterion 14 of Appendix A to 10 CFR Part 50 and with 10 CFR 50.63.

9

f-REACTOR AUXILIARY BUILDING NEW 3"OR 4" LINEI 3" R 4 LIE ITFI,

.C

-EW CTEMPERATURE TO FIRE WATER INPLSTAIN STORAGE TANK DC FILL CONNECTION 250,000 GALLON Cv GM FO FIRE WATER OR OTHER STORAGE TANK FIRE WATER RETURN LINE SOURCE FROM RCPs EXISTING THERMAL BARRIERS

[CONTAINMENT I AUXILIARY BUILDING SELF COOLED BATTERY I

NEW STARTED, NORMALLY I 3 PRESSURE REDUCING TO FLOOR oEXISTIN STARTS AFTER ELECTRIC I

STTO -

DIESEL-DRIVEN FIRE PUMP, WHEN FIRE D

D DA FIRE PUMP -

HEADER PRESSURE DROPS TYPICALLY MINIMUM BELOW A SET PRESSURE.

1500 GPM AT 100 PSI, I

AMBIENT TEMPERATURE I

6 P F F NOTES:

MODIFICATIONS MAY BE REQUIRED TO ISOLATION COLNOAE A POINTS COIGWTRHAE SEVERAL CCW VALVES TO ALLOW THE OPERATOR (TYPICAL)

IN AUXILIARY BUILDING TO REMOTELY ISOLATE THE UNNECESSARY ITO REACTOR COOLANT CCW LOADS (e.g. RCP MOTORS) UNDER SBO CONDITIONS, PUMPS e.g. BY CONVERSION TO DC POWER, etc.T CIV: EXISTING CCW CONTAINMENT ISOLATION VALVE Figure 1. Example of Independent Seal Cooling

Table 1. Selected Off-Normal Operational Conditions for Which-Westinghouse Provides Instructions High flow at No. 1 seal leakoff Low flow at No. 1 seal leakoff High flow at No. 2 seal leakoff High flow at No. 3 seal High temperature at seal inlet (radial bearing)

High temperature at No. 1 seal leakoff Loss of seal injection water flow Loss of No. 3 seal injection water flow (cartridge seal system only)

Loss of component cooling water to the thermal barrier heat exchanger Loss of seal injection water flow and component cooling water flow (e.g., loss of CCW, station blackout)

Returning an RCP to operation (thermal shock) 11

Table 2. Example of Vendor-Recommended Instrumentation and Operating Limits A. Westinghouse Cartridge Seal System Normal Value Location Parameter (Range)

Setpoint No. 1 Seal Inlet Temperature 130 0 F Hi = 170aF (At Radial Bearing)

(60-150aF)

Outlet Temperature 150aF Hi = 190 0 F (60-2350F)

Leak Rate 3 gpm Hi = 5.0 gpm (0.2-5.0 gpm)

Lo = 0.8 gpm Inlet-Outlet Differential 2235 psid Lo = 275 psid Pressure (200-2470 psid)

No. 2 Seal Leak Rate 3 gph Hi = 1.0 gpm Pressure 30 psig N/A (15-60 psig)

No. 3 Seal Standpipe Varies Hi = 31 in.

Level Lo = 58 in.

No. 1 Seal Leakoff Pressure 40 psig N/A (Return Line)

Temperature 160aF N/A Flow Rate Same as No. 1 Same as No. 1 Seal Outlet Seal Outlet No. 2 Seal Leakoff Leak Rate 3 gph Hi = 1.0 gpm Seal Injection Temperature (120-1300F)

Hi = 135cF Flow Rate 8 gpm Lo = 6 gpm Differential N/A N/A Pressure Component Cooling Temperature 80aF Hi = 1050F Water (Thermal Barrier (60-1050F)

Heat Exchanger Inlet)

N/A = not available or not applicable.

12

Table 2. (Continued)

Westinghouse Cartridge Seal System (Continued)

Normal Value Location Parameter (Range)

Setpoint

.point m onent Coolin Flow Rate 40 gpm Lo = 35 gpm ter (Continued)

(Thermal Barrier (35-60 gpm)

Heat Exchanger

• 700F Inlet)

Flow Rate N/A N/A 900 F (Combined RCP CCW Return Flow)

.0 gpm P Shaft Vibration (X&Y (3-6 mil Hi = 10 mil

.8 gpm Shaft Orbit) peak-to-peak) 75 psid

.0 gpm in.

3 in.

No. 1 tlet 0 gpm 5OF

/A not available or not applicable.

13

Table 2. (Continued)

B. Byron Jackson RCP Seal Cartridge Normal Value Location Parameter (Range)

Setpoint Lower (1st) Seal Pressure 2140 psig None

(+/-100 psig)

Middle (2nd) Seal Pressure 1427 Lo = 1200 psig

(+/-100 psig)

Hi = 1600 psig Upper (3rd) Seal Pressure 713 psig Lo = 500 psig

(+/-100 psig)

Hi = 900 psig Temperature See Controlled Bleed-off (CBO) below Leak Rate 0-0.08 gpm Hi = 0.17 gpm (3-stage System)

Controlled Bleed-Flow Rate 1.5 gpm 1.8 gpm off (CBO)

(+/-0.15 gpm)

Temperature (125-1650F) 1650 F Seal Injection Flow Rate (8-10 gpm)

N/A Temperature (95-1350F)

N/A Component Cooling Flow Rate (45-60 gpm) 4.5 gpm Water Temperature (95-1050F)

N/A RCP Shaft Vibration (0-0.010 in.

0.015 in.

(X&Y Shaft peak-to-peak)

(peak-to-peak)

Orbit)

N/A = not available or not applicable.

14

00 Table 2. (Continued)

C.

Bingham International Seal System Normal Value Location Parameter (Range)

Setpoint Lower (1st) Seal Pressure 2150 psig N/A

(+/-50 psig)

Temperature 120aF 156 0 F

(+/-10 0 F)

Middle (2nd) Seal Pressure 1434 psig N/A

(+/-50 psig)

Upper (3rd) Seal Pressure 717 psig N/A

(+/-50 psig)

Temperature See Staging Flow (CBO) below Leakage Rate 0-0.39 gpm Hi = 1.0 gpm Staging Flow Flow Rate 1.5 gpm Hi = 1.80 gpm (CBO)

(+/-0.05 gpm)

Lo = 0.36 gpm Temperature 1340 F 165 0 F

(+/-100F)

Seal Injection Flow Rate 9.5 gpm N/A Water Temperature N/A N/A Heat Exchanger Temperature 122 0 F N/A Recirc. Flow

(+/-100 F)

Out of Bearing Flow Rate N/A N/A Cooling Water Temperature 850 F Lo = 600 F Hi = 105'F Flow Rate 50 gpm N/A RCP Shaft Radial 0 to 0.015 in.

+/-0.025 in.

Displacement (X&Y Shaft Orbit)

N/A = not available or not applicable.

15

REFERENCES

1.

U.S. Nuclear Regulatory Commission, "Reactor Safety Study," WASH-1400, October 1975.

2.

C.J Ruger and W.J. Luckas, "Technical Findings Related to Generic Issue 23:

Reactor Coolant Pump Seal Failure," NUREG/CR-4948, U.S. Nuclear Regulatory Commission, March 1989.

3. W.J. Luckas, C.J. Ruger, A.G. Tingle, et al., "Reactor Coolant Pump Seal Related Instrumentation and Operator Response," NUREG/CR-4544 (BNL-NUREG 51964), U.S. Nuclear Regulatory Commission, December 1986.

16

APPENDIX A Design Guidelines for Independent Seal Cooling Safety-Related Equipment Not necessary to meet Regulatory Position 3 of this guide, but the existing Class 1E electrical systems must continue to meet all applicable safety-related criteria.

Redundancy Not necessary.

Power Independence Any power required should be independent of both the normal and emergency ac power systems.

Independence from Other Safety-Ensure that the existing safety system Related Systems functions are not compromised, including the capability to isolate components, subsystems, or piping, if necessary.

Seismic Qualification Not necessary, but ensure that it does not degrade the seismic design of the Seismic Class 1 Systems, Structures, or Components.

Environmental Consideration Needed for station blackout event only and not for design basis accident conditions.

Procedures should be in place to effect the actions necessary to maintain acceptable environmental conditions for required equipment.

Capacity In the event of a station blackout, provide sufficient water capacity for RCP cooling for the plant-specific duration to meet 10 CFR 50.63 and Regulatory Guide 1.155.

For other loss-of-all-seal-cooling events, A-1

provide sufficient water capacity for an assumed maximum duration event (approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />).

Functional Criteria Provide sufficient seal cooling to maintain manufacturer's recommended temperature limits.

Ensure that the two-phase flow is avoided.

(This requires cooling within 10 minutes.)

Quality Assurance As indicated in Appendix B.

to this guide.

Technical Specifications for Should be consistent with the Interim Surveillance, Limiting Commission Policy Statement on Technical Condition of Operation Specifications (Federal Register Notice 52 FR 3789) as applicable.

Instrumentation and Monitoring Should meet system functional requirements.

Single Failure Criterion Not necessary to satisfy the single failure criterion.

Common Cause Failure (CCF)

Design should, to the extent practicable, minimize CCF between safety-related and non safety-related systems.

Human Factors Good human factors principles should be considered and documented in the design of the system, instrumentation, and procedures.

A-2

APPENDIX B Quality Assurance Program for Non-Safety-Related Independent Seal Cooling The quality assurance (QA) program provided here is applicable to the non-safety-related independent seal cooling in Regulatory Position 3 of this guide. Additionally, non-safety equipment installed in conformance with this guide must not degrade the existing safety-related systems. This is accom plished by making the non-safety equipment as independent as practicable from existing safety-related systems. This appendix outlines an acceptable QA pro gram for non-safety equipment to provide backup cooling to the RCP seals when this equipment is not already covered by existing QA requirements. Activities should be implemented from this section as appropriate, depending on whether the equipment is being added (new) or is existing.

1. Design Control and Procurement Document Control Measures should be established to ensure that all design-related criteria used in complying with this guide are included in design and procurement documents, and that deviations therefrom are controlled.

2.

Instructions, Procedures, and Drawings Inspections, tests, administrative controls, and training should be prescribed by documented instructions, procedures, and drawings, and they should be implemented in accordance with these documents.

3.

Control of Purchased Material, Equipment, and Services Measures should be established to ensure that purchased material, equipment, and services conform to the procurement documents.

B-1

4.

Inspection A program for independent inspection of activities should be established and executed by (or for) the organization performing the activity to verify conformance with documented installation drawings and test procedures for accomplishing the activities.

5.

Testing and Test Control A test program should be established and implemented to ensure that testing is performed and verified by inspection and audit to demonstrate conformance with design and system readiness requirements. The tests should be performed in accordance with written test procedures; test results should be properly evaluated and acted on.

6.

Inspection, Test, and Operating Status Measures should be established to identify items that have satisfactorily passed required tests and inspections.

7. Noncomforming Items Measures should be established to control items that do not conform to specified requirements to prevent inadvertent use or installation.

8.

Corrective Action Measures should be established to ensure that failures, malfunctions, deficiencies, deviations, defective components, and nonconformances are promptly identified, reported, and corrected.

9.

Records Records should be prepared and maintained to furnish evidence that the criteria enumerated above are being met.

B-2

10.

Audits Audits should be conducted and documented to verify compliance with design and procurement documents, instructions, procedures, drawings, and inspection and test activities described above.

8-3

REGULATORY ANALYSIS A separate regulatory analysis was not prepared for this regulatory guide.

Draft NUREG-1401, "Regulatory Analysis for Generic Issue 23, Reactor Coolant Pump Seal Failures," provides the regulatory basis for this guide and examines the cost and benefits of implementing this regulatory guide.

A more detailed cost/benefit analysis is contained in NUREG/CR-5167, "Cost/Benefit Analysis for Generic Issue 23, Reactor Coolant Pump Seal Failure."

These NUREG documents are available for inspection and copying for a fee at the NRC Public Document Room, 2120 L Street NW, Washington, DC.

NUREG-1401, a draft, is available free, to the extent of supply, upon written request to the Office of Informa tion Resources Management, Distribution Section, U.S. Nuclear Regulatory Com mission, Washington, DC 20555. Copies of NUREG/CR-5167 may be purchased from the Superintendent of Documents, U.S. Government Printing Office, P.O.

Box 37082, Washington, DC 20013-7082; or from the National Technical Information Service, Springfield, VA 22161.

RA-1