ML20058M030

Forwards Listed Info,In Response to Asking NRC to Address Issues Raised in Ltr from Constituent Me Lampert Re Problems at Pilgrim,W/Exception of Issue of Loss of Power & Fpc.Issue of Loss of off-site Power & FPC Related to SSES

ML20058M030
Person / Time
Site:	Pilgrim, Susquehanna
Issue date:	09/10/1993
From:	Taylor J NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO)
To:	Studds G HOUSE OF REP.
Shared Package
ML20058L986	List: ML20058L984 ML20058M030
References
CCS, NUDOCS 9309170203
Download: ML20058M030 (2)

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, WASHINGTON. D.C. 20555-4001 September 10, 1993 The Honorable Gerry E. Studds Member, United States House of Representatives 1212 Hancock Street Quincy, Massachusetts 02169

Dear Congressman Studds:

In your letter of July 27, 1993, you asked us to address the issues raised in correspondence from your constituent Mary Elizabeth Lampert. With the .

exception of the issue of " loss of off-site power and fuel pool coolant," th'e issues have been addressed in various prior correspondence to you and other constituents of yours.

I am enclosing copies of the following issue-related correspondence:

1. Issue: Water Level Measuring Device - Condensate Pot and Turbine Cracks Related Correspondence: Letters of August 4, 1993, to Congressman Studds and Senators Kennedy and Kerry

2. Issue: Motor-0perated Valves Related Correspondence: Letter of March 26, 1993, to Ms. Lampert

3. Issue: Emerger.cy Planning Related Correspondence: Letter of August 11, 1993 (from the Federal Emergency Management Agency), to Ms. Fleming The issue of loss of offsite power and fuel pool cooling relates to concerns raised at the Susquehanna Steam Electric Station. Regarding the Susquehanna plants and the possible generic issue for the remaining boiling water reactors (BWRs), the staff conducted spent fuel pool design reviews for all BWRs before licensing and found them to be acceptable. The staff is currently reevaluating this issue to confirm its original findings. The staff has determined that there is no undue risk to the public while this review is taking place because the probability is low of the concurrant events required

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The Hcnorable Gerry E. Studds for this postulated event. The staff will make its findings public when the reevaluation is completed. I hope the information we are providing is responsive to your needs.

Sincerely, 30PC'/- (' ,

apes M. Tay)2r Secutive Director for Operations

Enclosures:

1. Ltrs. dtd. 8/4/93 to ,,

Congressman Studds, and Senators Kennedy and Kerry

2. Ltr. dtd. 3/26/93 to Ms. Lampert

3. Ltr. dtd 8/11/93 to J. Fleming i

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, '993 CHAIRMAN The Honorable Gerry E. Studds United States House of Representatives Washington, D.C. 20515-4611

Dear Congressman Studds:

In your letter of June 29, 1993, you and Senators Kennedy and Kerry raised several questions about the instrumentation for reactor vessel water level and the cracks on the disks of the low pressure turbines at the Pilgrim Nuclear Power Station. The Pilgrim plant shut down on July 22, 1993. During the shutdown, the licensee installed the modification to the reactor vessel '.

water level instrumentation to ensure high functional reliability for long term operation as described in NRC Bulletin 93-03.

After installation and testing of the modification, the plant was restarted on July 25, 1993, and returned to power operation.

Enclosed are the staff's responses to your questions on the reactor vessel water level issues.

In addition, I have enclosed a copy of the NRC staff's analysis that forms the basis for the conclusion that the turbine may be operated until the next refueling outage (spring 1995) without any undue risk to the health and safety of the public. In reaching its conclusion, the staff reviewed the GE and SIA a: alyses performed on the turbine flaw indications, and found that although the SIA analysis is less conservative than the GE analysis (see enclosed analysis for details), sufficient.

conservatisms were built into the SIA analysis to conclude that no safety concerns exist for normal operation of the turbine to the end of the current fuel cycle. Boston Edison plans to replace the turbine rotors during their next refueling outage scheduled for April, 1995.

I hope that the information we are providing will help resolve your concerns.

Sincerely, j ll

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Ivan Selin

Enclosures:

1) Questions on level indication, w/ attachment

2) Low pressure turbine assessment, v/2 attachments r O '

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/ August d. 1993 CHAIRMAN The Honorable John F. Kerry United States Senate Washington, D.C. 20510

Dear Senator Kerry:

In your letter of June 29, 1993, you and Senator Kennedy and Congressman Studds raised several questions about the instrumentation for reactor vessel water level and the cracks on the disks of the low pressure turbines at the Pilgrim Nuclear Power Station. The Pilgrim plant shut down on July 22, 1993.

During the shutdown, the licensee installed the modification to the reactor vessel water level instrumentation to ensure high functional reliability for long term operation as described in NRC Bulletin 93-03. After installation and testing of the modification, the plant was restarted on July 25, 1993, and returned to power operation. Enclosed are the staff's responses to your questions on the reactor vessel water level issues.

In addition, I have enclosed a copy of the NRC staff's analysis that forms the basis for the conclusion that the turbine may be operated until the next refueling outage (spring 1995) without any undue risk to the health and safety of the public. In reaching its conclusion, the staff reviewed the GE and SIA analyses performed on the turbine flaw indications, and found that although the SIA analysis is less conservative than the GE analysis (see enclosed analysis for details), sufficient conservatisms were built into the SIA analysis to conclude that no safety concerns exist for normal operation of the turbine to the end of the current fuel cycle. Boston Edison plans to replace the turbine rotors during their next refueling outage scheduled for April, 1995.

I hope that the information we are providing will help resolve your concerns.

Sincerely, e

Ivan Selin

Enclosures:

1) Questions on level indication, w/ attachment

2) . Low pressure turbine assessment, w/2 attachments

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• e f' August 4, 1993 CH AIRMAN The Honorable Edward M. Kennedy -

United States Senate Washington, D.C. 20510

Dear Senator Kennedy:

In your letter of June 29, 1993, you and Senator Kerry and Congressman Studds raised several questions about the instrumentation for reactor vessel water level and the cracks on the disks of the low pressure turbines at the Pilgrim Nuclear Power Station. The Pilgrim plant shut down on July 22, 1993.

During the shutdown, the licensee installed the modification tp the reactor vessel water level instrumentation to ensure high functional reliability for long term operation as described in NRC Bulletin 93-03. After installation and testing of the modification, the plant was restarted on July 25,.1993, and returned to power operation. Enclosed are the staff's responses to your questions on the reactor vessel water level issues.

In addition, I have enclosed a copy of the NRC staff's analysis that forms the basis for the conclusion that the turbine may be operated until the next refueling outage (spring 1995) without any undue risk to the health and safety of the public. In reaching its conclusion, the staff reviewed the GE and SIA analyses performed on the turbine flaw indications, and found that although the SIA analysis is less conservative than the GE analysis (see enclosed analysis for details), sufficient conservatisms were built into-the SIA analysis to conclude that-no safety concerns exist for normal operation of the turbine to the end of the current fuel cycle. Boston Edison plans to replace the turbine rotors during their next refueling outage scheduled for April, 1995. j I hope that the information we are providing will help resolve your concerns.

Sincerely, j Ivan Selin

Enclosures:

1) Questions on level indication, w/ attachment

2) Low pressure turbine assessment, w/2 attachments

e Enclosure 1 RESPONSE TO OVESTIONS ON REACTOR VESSEL WATER LEVEL INDICATION QUESTION 1 In the case of the Pilgrim Plant, the licensee will not be required to make the modification until the next planned cold shutdown, which isn't until April 1994. If the problem is serious enough to require a plant that is shut down on August 1,1993, to make modifications, why are the other plants allowed almost a year before they are required to take 'the same action?

ANSWER On July 22, 1993, the Pilgrim Nuclear Power Station was placed in a cold shut down condition to investigate and repair an unidentified leak that occurred after returning to power operation-from their refueling outage.

Consistent with the NRC staff's request in Bulletin 93-03, Pilgrim installed a modification to the reactor vessel water level indication before restarting the plant.

On May 28, 1993, the NRC issued Bulletin 93-03, in which it requested that each boiling water reactor (BWR) licensee implement hardware modifications necessary to ensure that the level instrumentation system is of high functional reliability for long-term operation. The NRC staff requested that these modifications be implemented at the next cold.

shutdown beginning after July 30, 1993, or if a facility is in cold ,

shutdown on July 30, 1993, before starting up from that outage. The staff also requested each licensee to submit a report by July 30, 1993, describing the hardware modifications to be implemented. If a licensee chooses not to implement a hardware modification as requested by the bulletin, its report shall contain a description of the proposed-alternative course of action, the schedule for completing it, and a justification for any deviations from the requested actions.

For transient and accident scenarios initiated from full power conditions, the level instrumentation should actuate safety systems as designed. The operators have received guidance and training as requested by Generic Letter (GL) 92-04 to ensure that any level errors will not result in improper operator actions. Further, the staff believes that an abrupt depressurization event resulting in a common-mode / common-magnitude level indication error is unlikely.

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The staff determined that additional short-term compensatory measures were necessary for a normal cooldown for transient and accident scenarios begun from reduced pressure conditions. In Bulletin 93-03, the staff requested that each licensee implement certain snort-term compensatory actions within 15 days and complete augmentea operator training by July 30, 1993. Because the hardware modifications were requested to be implemented at the next cold shutdown after July 30, 1993, each plant is expected to be in cooldown conditions only once before the licensee makes modifications. If the level indication is erroneous while the plant is being cooled down, the compensatory measures and operator training requested by Bulletin 93-03 should enable the operators to mitigate the consequerices of any loss-of-inventory event.

An operating plant waiting until the next cold shutdown to make hardware modifications, instead of forcing an unplanned shutdown, sould not

increase the risk from event scenarios begun during reduced pressure conditions. The staff also finds no immediate safety concern with event scenarios that begin during full pressure conditions. Therefore, the staff has concluded that plant operation is acceptable with adequate compensatory measures as requested by Bulletin 93-03 and with the actions already completed by licensees in response to GL 92-04 until a permanent hardware modification is made.

QUESTION 2a Is Mr. Blanch correct that the regulations and GL 91-18 require an operability determination in this case that would look at all functions and determine whether the system is capable of performing its function?

Please include with your response a copy of the relevant regulations and guidance.

ANSWER Mr. Blanch is correct that licensees must continuously ensure operability, which involves verifying functional capability, if called into question. The technical specifications for each plant define

" operability", which, simply stated, is the ability of equipment to perform a specific safety function. In GL 91-18, attached, the staff gave guidance on acceptable methods for addressing questions about degraded or nonconforming conditions, and determining how these conditions relate to operability. The Pilgrim plant's Technical Specification 1.0.E states the following:

A system, subsystem,- train, component or device shall be OPERABLE or have.0PERABILITY when it is capable of performing its specified function (s). Implicit in this definition is the assumption that all necessary attendant instrumentation, controls, normal and emergency electrical power sources, cooling or seal water,

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lubrication or other auxiliary equipment that are recuired for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s).

QUESTION 2b Is Mr. Blanch correct that the technical specifications for this particular device state that if the level measurement is inoperable it-must be fixed immediately?

ANSWER Pilgrim Nuclear Power Station Technical Specifications 3.1.A, " Reactor Protection System"; 3.2. A, " Primary Containment Isolation"; 3.2.B, " Core and Containment"; 3.2.F, " Surveillance Information Readouts"; and 3.2.G,

" Recirculation Pump Trip and Alternate Rod Insertion," all would require the reactor to be shut down if the reactor vessel water level instrumentation is inoperable; that is, if this instrumentation is not capable of performing its specific safety function (s). If the plant is already shut down, the level instrumentation must be returned to an operable status before the plant is restarted. Other boiling water reactors have similar technical specification requirements for the level instrumentation.

The NRC staff position is that current BWR water level instrumentation systems, together with the short-term compensatory measures required in Bulletin 93-03, provide reasonable- assurance that required safety functions will be successfully carried out. .

QUESTION 2c If Mr. Blanch's assertions are accurate, does NRC Bulletin 93-03 conflict with the requirements of the regulations and guidance?

ANSWER Bulletin 93-03 does not conflict with NRC regulations or guidance concerning operability. Bulletin 93-03 does not grant any licensee relief from the obligation to ensure operability. - On the contrary, the NRC issued both the bulletin and GL 92-04 to request specific actions to i give additional assurance that the system is capable of performing'its intended safety function.

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QUESTION 3 As you know, Boston Edison is not convinced of the applicability of the Millstone solution to its plant and is evaluating other options. Does the NRC have the authority to review this evaluation? Can the NRC make l an independent determination on the applicability of the Millstone l solution to Pilgrim or must it accept the licensee's decision?

l J ANSWER Boston Edison installed a modification to the reactor vessel water level i indication that was very similar to the modification adopted at the Millstone plant. Bulletin 93-03 does not require NRC licensees to adopt a specific solution to the water level indicator problem. Rather, each licensee may choose the solution which it deems most appropriate. The NRC requested that each licensee submit a report by July 30, 1993, to'

, describe the hardware modifications to be implemented. The NRC staff i j

' weighs the acceptability of the selected option against the requests i discussed in GL 92-04 and Bulletin 93-03.

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- ittacnment to Enclosure-1

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\, .....f' November 7,1991 70: ALL NUCLEAR POWER REACTOR LICENSEES AND APPLICANTS SUBJECT INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL SECTIONS ON RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY (GENERIC LETTER 91-18) ,

The NRC staff has issued two sections to be included in Part 9900, Technical  !

Guidance, of the NRC Inspection Manual. The first is, " Resolution of Degraded anc Nonconforming Conditions." The second is, " Operable / Operability: Ensuring

ne Functional Capability of a System or Component." Copies of the additions to

ne NRC Inspection Manual (enclosure) are provided for information only. No-s:ecific licensee actions are required.

The additions to the NRC Inspection Manual are based upon previously issued guidance. However, because of the complexity involve ~d in operability ceterminations and the resolution of degraded and nonconforming conditions, there have been differences in application by NRC staff during- past inspection activities. Thus, the purpose of publishing this guidance is to ensure consistency in application of this guidance by the NRC. Regional inspection personnel have been briefed on this guidance. The NRC will conduct further i training on these topics to ensure uniform staff understanding.

The use of this guidance by inspectors may raise backfitting issues for specific licensees. The NRC backfitting procedures apply in such cases. Licensees should consult with the Regional office regarding the application of specific staff pcsitions in the guidance.

Please contact the appropriate NRC Project Manager if you have any questions regarding this matter, r

T Jam es G. Partlow Assaciate Director for Projects .

Office of Nuclear Reactor Regulation I

Enclosure:

As stated i

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ENCLOSURE 1

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PART 9900: TECHNICAL GUl0ANCE B

RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS t

.i 9900 Degraded Conditions

!ssue Date: 10/31/91

4 RESOLUTION OF DEGRADE 0 AND NONCONFORMING CONDITIONS l

Table of Contents f.H!t 1

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1.0 PURFOSE AND SCOPE.... . .. ..................................... 1 2.0 DEFINITIONS. ... ....... .. .............................. 2

' i l 2.1 Current Licensing Basis.................................... 2 j 4

1 2.2 Design Basis........ ...................................... 2 2.3 Degraded Condition....... ...............................2, ,

2.4 Nonconforming Condition.................................... 2 2.5 Full Qualification......................................... 2 3.0 BACKGROUNO. ..................................................... 3 4.0 DISCUSSION OF NOTABLE PROVIS10NS................................. 3 4.1 Public Health and Safety................................... 3 4.2 Operability Determinations................................. 3 4.3 The Current Licensing Basis and 10 CFR 50 Appendix B...................... ................ 3 4.3.1 10 CFR 50, Appendix B.......................... 3 4.3.2 Changing the Current Licensing Basis to Satisfy an Appendix B Corrective Action..... 4

. 4.4 Discovery of an Existing But Previously Unanalyzed Condition or Accident. . . . . . . . . . . . . . . . . . . . . . . . . . . 4 4.5 Justi fication for Continued Operation (JCO) . . . . . . . . . . . . . . . . 4 4

4.5.1 Background.....................................

5 4.5.2 JC0 Definition.................................

5 4.5.-3 Items for Consideration in a JCO...............

4.5.4 Discussion of Industry-Type JCOs............... 5 4.6 Reasonabl e As surance of 5afety. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 5.0 RE F E RE N C E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

• !ssue Dam W3W k "i'_ _ _ _ _ _ _ _ ___ _I _ __ _ _ _ __ _ _ _ _ _ _ _ _ _ _ -

RE501.UT10N OF DEGRADED AND NONCONFORMING CONDITIONS 1.0 PUPPOSE AND SCOP _{:

To provide guidance to NRC inspectors on resolution of degraded and nonconformir.g conditions affecting the following systems, structures, or components (SSCs):

(i) Safety related SSCs, which are those relied upon to remain functional during and following design basis events (A) to ensure the integrity of the reactor coolant pressure boundary, (B) to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition, or (C) to ensure the capability to prevent or mitigate the consequences of accidents that could result in potential offsite consequences comparable to the 10 CFR Part 100 guidelines. Design basis events are defined the same as in 10 CFR 50.49(b)(1).

(ii)

All SSCs whose f ailure could prevent satisfactory. accomplishment of any of the required functions identified in (i) A B, and C.

(iii)

All SSCs relied on in the safety analyses or plant evaluations that are a part of the plant's current licensing basis. Such analyses and evaluations include those submitted to support license amendment requests, exemption requests, or relief requests, and those submitted to demonstrate compliance with the Commission's regulations such as fire protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout (10 CFR 50.63).

(iv) Any SSCs subject to 10 CFR Part 50, Appendix B.

(v) Any SSCs subject to 10 CFR Part 50, Appendix A, Criterion 1.

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(vi) Any SSCs explicitly subject to facility Technical Specifications (TS).

(vii) Any SSCs subject to facility TS through the definition of operability (i.e., support SSCs outside TS).

(viii) Any SSCs described in the FSAR.

This guidance is directed toward NRC inspectors that are reviewing actions of licensees that hold an operating license. Although this guidance generally reflects existing staff practices, application on specific plants may constitute a backfit. Consequently, significant differences in licensee practices should be discussed with NRC management to ensure that the guidance is applied in a reasonable and consistent sanner for all licensees.

-1 9900 Degraded Conditions Issue Date: 10/31/91

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2.0 DEFINITIONS

2.1 Current Licensina Basis Current licensing basis (CLB) is the set of NRC requirements applicable to a t spec 1fic plant, and a licensee's weitten commitments for assuring compliance with ' i an:: operation within applicable NRC requirements and the plant-specific design Dasis (including all modifications and additions'to such commitments over the life of the license) that are docketed and in effect. The CLB includes the NRC ,

regulations contained in 10 CFR Parts 2, 19, 20, 21, 30, 40, 50, 51 55,:72, 73. -

100 and appendices thereto; orders; license conditions; exemptions, and Technical Specifications (TS), it also includes the plant-specific design basis information defined in 10 CFR 50.2 as documented in-the most recent Final Safety Analysis Report (FSAR) as required by 10 CFR 50.71 and the licensee's connitments remaining in effect that were made in docketed licensing correspondence such as licensee responses to NRC bulletins, generic letters, and enforcement actions, -

as well as licensee commitments documented in NRC safety evaluations or licensee ,

event reports.

2.2 Desien Basis ,

Design basis is that body of plant-specific design bases inforWation defined by 10 CFR 50.2.  :

2.3 Deoraded Condition A condition of an SSC in which there has been any loss of quality or functional ,

capability.

2.4 Nonconformino Condition A condition of an SSC in which there is failure to meet requirements or licensee commitments. Some examples of nonconforming conditions include the following:

1. There is failure to conform to one or more applicable codes- or ,

standards specified in the FSAR.

2. As-built equipment, or as-modified equipment, does not meet FSAR design requirements. q

3. Operating experience or engineering reviews demonstrate a design -)

inadequacy. ,

Documentation required by NRC requirements such as 10 CFR 50.49 is j

4. u not available or deficient.

2.5 Full Qualification Full qualification constitutes conforming to all aspects'of the current licensing .

basis, including codes and standards, design criteria, and cosmitments.

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9900 Degraded Conditions- -2. Issue Date:- 10/31/91-

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3.0 BACKGROUND

A nuclear power plant's SSCs are designed to meet NRC requirements, satisfy the current licensing basis, and conform to specified codes and standards. For degraced or nonconforming conditions of these SSCs, the licensee say be required to take actions required by the Technical Specifications (TS). The provisions of Title 10 of the Code of Federal Regulations (10 CFR), Part 50 Appendix B, Criteria XVI, may apply requiring the licensee to identify promptly and correct conditions adverse to safety or quality. Reporting may be required in accordance with Sections 50.72. 50.73, and 50.9(b) of 10 CFR Part 50,10 CFR Part 21, and (ne Technical Specifications (TS). Collectively, these requirements may be viewed as a process for licensees to develop a basis to continue operation or to place the plant in a safe condition, and to take prompt corrective action.

Changes to the facility in accordance with 10 CFR S0.59 may be made as part of the corrective action required by Appendix B. The process displayed by means of the attached chart titled, " Resolution of Degraded and Nonconforming Conditions,'

recognizes these and other provisions that a licensee may follow to restore or establish acceptable conditions. These provisions are success paths that en'able licensees to continue safe operation of their facilities.

4.0 DISCUSSION OF NOTABLE PROVISIONS 4,1 Public Health and Safety .

All success paths, whether specifically stated or not, are first directed to ensuring public health and safety and second to restoring the systems, structures, or components (SSCs) to the current licensing basis of the plant as an acceptable level of safety. Identification of a degraded or nonconforming condition that may pose an immediate threat to the public health and safety requires the plant to be placed in a safe condition.

Technical Specifications (15) address the safety systems and provide Limiting Conditions for Operation (l.COs) and Allowed Outage Times (A0Ts) required to ensure public health and safety.

4.2 Ooerability Determinations Manual, Part 9900, For guidance on operability see the Inspection

'0PERABLE/0PERABILITY: ENSURIM THE FUNCTIONAL CAPABILITY OF A SYSTEM O COMPONENT "

and see the Inspection Manual, Part 9900, ' STANDARD TECHNICAL SPECIFICATIONS STS SECTION 1. OPERABILITY."

4.3 The Current Licensino Basis and 10 CFR 50. Accendix B 4.3.1 10 CFR 50, Appendix B The design and operation of a nuclear plant is to be consistent with the current licensing basis. Whenever degraded or nonconforming conditions of SSCs subject to Appendix 6 are identified, Appendix B requires prompt corrective action to correct or resolve the condition. The timeliness of this corrective action should be commensurate with the safety significance of the issue.

9900 Degraded Conditions Issue Cate: 10/31/91

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4.3.2 Changing the Current Licensing Basis to Satisfy an Appendix B Corrective Action A licensee may change the design of its plant. as described in the FSAR in -

accordance with 10 CFR 50.59 at any time. Whenever such changes are sufficient to resolve a degraded or nonconforming condition involving an SSC that is subject both to Appendix B and 50.59, they may be used to. satisfy the corrective action requirements of Appendix B, in lieu of restoring the affected equipment to its-original design. However, whenever such a change involves a unreviewed safety question (USQ) or change in a Technical Specification (TS), the licensee must i obtain a license amendment in accordance with 10 CFR 50.90 prior to operating the  !

plant with the degraded or nonconforming condition. In' order to resolve the .;

degraded or nonconforming condition without restoring the affected equipment to its original design, a licensee may need to obtain and exemption from 10 CFR'50 '

in accordance with 10 CFR 50.12, or relief fron'a design code in accordance with 10 CFR 50.55a. The use of 10 CFR 50.59, 50.12 or 50.55a in fulfillment of- '

Appendix B corrective action requirements does not relieve the licensee of the responsibility to determine the root cause, to examine other affected systems, or to report the original condition, as appropriate.

Further guidance on 10 CFR 50.59 is provided in the NRC Inspection Manual, Part 9900, '50.59 Changes. Testing, and Experiments." . 1 4.4 Discovery of an Existina But Previously Unanalyzed Condit' ion or Accident In the course of its activities, the licensee may discover a ' previously unanalyzed condition or accident. Upon discovery'of an existing but previously ,

unanalyzed condition that significantly compromises plant safety, the licensee-shall report that condition in accordance with 10 CFR 50.72 and 50.73, and put the plant in a safe condition.

For. a previously unanalyzed condition or accident that is' considered a- 3 significant safety concern, but is not part of the design basis,' the licenste may.

subsequently be required to take additional action after consideration of backfit issues (see Section 50.109(a)(5)).

4.5 Justification for continued coeration (JCO)

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4.5.1 Background The license authorizes the licensee to operate the' plant in accordance with_the regulations, license conditions and the TS. If- ' an SSC is degraded 1 or nonconforming but operable, the license provides authorization to operate and the licensee does- not need further justification. The licensee must, 'however,  ;

promptly identify and correct the condition adverse to- safety or quality in accordance with '10 CFR Part 50, Appendix 8 Criterion XVI.

Under. certain defined and limited circumstances, the licensee may . find that strict compilance with the TS would cause an unnecessary plant action not in the-best. interest of public health and safety. NRC review and response is required prior to the licensee taking actions that are contrary to compliance with the license conditions or TS unless an emergency situation is present such that 10-9900 Degraded Conditions- =.4 Issue Date: 10/31/91 ,

1 CFR 50.54(X) is appiled. A JCO, as defined herein for general NRC purposes, is the licensee's technical basis for requesting NRC responses to such action.

4.5.2 JC0 Definition A Justification for Continued Operation' (JCO) is the licensee's technical basis for requesting authorization to operate in a manner that is prohibited (e.g.,

outside TS or license) absent such authorization. The preparation of JCOs does not constitute authorization to continue operation.

4.5.3 Items for Consideration in a JC0 Some items which are appropriate for consideration in a licensee's development of a JC0 include:

o Availability of redundant or backup equipment o Compensatory measures including limited administrative controls o Safety function and events protected against **

o Conservatism and margins, and o Probability of needing the safety function.

o PRA or Individual Plant Evaluation (IPE) results that determine how operating the facility in the manner proposed in the JC0 will impact the core damage frequency. -

a.5.4 Otscussion of Industry-Type JCOs Currently, some licensees refer to two other documents or processes as JCOs that are not equivalent to and do not perform the same function as the NRC-recognized JC0 (as defined in 4.5.2). This is an acceptable industry practice and to the extent the industry JC0 fulfills other NRC requirements, the JCOs will be selectively reviewed and audited accordingly.

In the first industry type JCO, the licensee may consider the entire process depicted in the attached chart as a single JC0 that includes such things as the basis for operability, PRA, corrective action elements, and alternative operations.

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In the second industry-type JCO, the licens'ee may consider the documentation that is developed to support facility operation after the operability decision has been made as a JCO. This documentation can cover any or all of the items listed under "Interia Operation

• on the attached chart.

' Regulations, generic letters, and bulletins may provide direction on specific issurJCOs, which do not require that they be submitted. Licensees may also use the JC0 for situations other than for operating in a prohibited manner.

The JC0 ters has been used in Generic Lette,rs 88-07 on Environmental Qualifications of Electrical Equipment and 87-02 on Seismic Adequacy. Licensees l should continue to follow earlier guidance regarding the preparation of JCOs on specific issues.

Issue Date: -5 9900 Degraded Conditions 10/31/91

a Although the 'JCO' is used differently by some licensees, the NRC concern is that the c:erability decision is correct, documentation of licensee's actions are appro:riate, and submittals to the NRC are complete. The licensee's documentation of the JCO's is normally proceduralized through the existing plant record system, which is auditable.

4.6 Deasemable assurance of Safety For SSCs that are not expressly subject to TS and that are determined to be inoperable, the licensee should assess the reasonable assurance of safety. If the assessment is successful, then the facility may continue to operate while prompt corrective action is taken. Items to be considered for such an assessment include the following:

o Availability of redundant or backup equipment o Compensatory measures including limited administrative controls o Safety function and events protected against o Conservatism and margins, and .

o Probacility of needing the safety function.

o PPA or Individual Plant Evaluation (IPE) results that determine how operating the facility in the manner proposed in the JC0 will impact the core damage frequency.

5.0 REFE ENCE See attached chart on next page titled, " Resolution of Degraded and Honconforming Conditions."

9900 Degraded Conditions -6 Issue Date: 10/31/91

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5,,' c.,i j NRC INSPECTION MANUAL 0T58 i

PART 9900: TECHNICAL GUl0ANCE OPERABLE /0PERABILITY:

ENSURING THE FUNCTIONAL CAPABILITY OF A SYSTEM OR COMPONENT a

i 4

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i 9900 Operability ;

Issue Date: 10/31/91

OPE RABLE/0PE RABILITY :

ENSURING THE FUNCTIONAL CAPABillTY OF A SYSTEM OR COMPONENT Table of Contents f.121 1.0 PURPOSE AND SCOPE. . ................... .. . ..I 2.0 DEFINITIONS. . ... . .. ........................ 2 2.1 Current Licensing Basis. ...... ............... .......... 2 2.2 Design Basis.. ... .. ................ ........... 2 2.3 Degraded C:ndit on. .. . .. ....... ................... 2 2.4 Nonconforming Cendition. ................................. 2 2.5 Full Qualification. ..... ............................,..... 2 3.0 STANDARD TECHNICAL SPECIFICATION OPE RABI L ITY DEF INITION AND DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3.1 Op e r ab i l i t y 0e fi n i t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3.2 yariation of Operability Definition in Plant Specific T5... 3 3.3 S p ec i f i ed f unc t i on ( s ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 3.4 Support System Operability -

Underst anding System Interrel ationships. . . . . . . . . . . . . . . . . . . . 3 4.0 BACKGROUNO ...................................................... 4 5.0 ADDITIONAL GUIDANCE FOR OPERABILITY DETERMINAT10N5. . . . . . . . . . . . . . . 5 5

5.1 Focus on 5afety............................................

5.2 Full Qu al i f i c at i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 5.3 Deal with Operability and Restoration of Qualification Separately. . . . . . . . . . . . . . . . . . . . 6 5.4 Determining Operability and Plant Safety is a Continuous Deci s i on Making Proce s s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 5.5 Timeliness of Operability Determinations................... 7 9900 Operability -1 Issue Date: 10/31/91

5 OPERABLE /0PERABILITY :

ENSURING THE FUNCTIONAL CAPABILITY OF A SYSTEM OR COMPONENT Yable qf_ Contents f15Lt 5.0 ADCITIONAL CU10ANCE FOR OPERABILITY DETERMINATIONS (continued) 5.6 Timel i ne s s of Correct ive Act ion. . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 5.7 hstification for Continued Operation...................... 7 6.0 DETAILED CISCUSSION OF SPECIFIC OPERABILITY ISSUES..... ......... 8 6.1 Scoce and Timing of Operability Determinations. . . . . . . . . . . . 8 ..

6.2 Treatment of Single Failures in 0;erability Determinations.. ........................... 9 6.2.1 Definition of Single Failure............,....... 9 6.2.2 Capability to Withstand a Single Failure is a Design Consideration...................... 9 6.2.3 Discovery of a Design Deficiency in Which Captbility to Withstand a Singl e Failure i s Lost. . . . . . . . . . . . . . . . . . . . . . 10 6.3 Treatment of Consequential Failures i n Ope ra t i t ty De t e rminat i on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 6.3.1 Definition of Consequential Failure. . . . . . . . . . .10 1

6.3.2 Consequential Failures and l Operability Determinations.................... 10 1

6.3.3 Consequential Failures and Appendix 8......... 10 I 6.4 Operability During TS Surveillances and Preventive Ma int enanc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 6.5 Surveillance and Operability Testing in Sa fety Con figura t ion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6.6 Mis sed Technical Specification Surveillanco. . . .. ..........12 6.7 Use of Manual Action in Place of Automatic Action.........12

' Issue Date: 10/31/91 -ii. 9900 operability

OPERABLE /0PERABILITY:

ENSURING THE FUNCTIONAL CAPABILITY OF A SYSTEM OR COMPONENT Table of Contents f.111 6.0 DETA! LED DliCUS$10N OF SPECIFIC OPERABILITY .!SSUES (continued) 6.8

• I nd e t e rmi n a t e " S t a t e o f Ope rabil i ty. . . . . . . . . . . . . . . . . . . . . . 13 6.9 Use of Probabilistic Risk Assessment in Operability Decisions.................................. 14 6.10 Environmental Qualification............................... 14 6.11 Technical Specification Operability vs.

ASME Code.Section II Operative Criteria. . . . . . . . . . . . . . . . . .15 6.12 Support System Operability....................,........... 16 6.13 Piping and Pipe Support Requirements...................... 17 6,14 Flaw Evaluation........................................... 18 6.'S Operational Leakage....................................... 19 6.16 Structural Requirements................................... 19 Issue Date: 10/31/91 9900 Operability ..iit.

1 OPERABLE /0PERABILITY:

ENSURING THE FUNCTIONAL CAPABILITY OF A SYSTEM OR COMPONENT P

5 P

1.0 PUcPOSE aND SCOPE To provide guidance to NRC inspectors for the review of licensee operability determinations affecting the following systems, structures, or components (55Cs):  :

(i) Safety-related 55Cs. which are those relied upon to remain . functional during and following design basis events (A) to ensure the integrity of the reactor coolant pressure boundary (8) to ensure the capability to shut down the reactor and maintain it in a safe shutdown condition, or (C) to ensure the capability to prevent or sitigata the consequences of accidents that could result in potential offsite consequences temparable to the 10 CFR Part 100 guidelines. Design basis events are defined the same as in 10 CFR 50.49(b)(1).

(ii) All 55Cs whose failure could prevent satisfactort accomplishment of <

any of the required functions identified in (1) A, 8, and'C. .

(iii) All 55Cs relied on in the safety analyses or plant evaluations that are a part of the plant's current licensing basis. Such ar.alyses and 4 3 evaluations include those submitted. to . support license amendment  ;

requests, exemption requests, or relief requests, and those submitted to demonstrate compliance with the Consnission's regulations such as fire protection (10 CFR 50.48).- environmental qualification . ,

(10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout (10 CFR 50.63).

(iv) Any SSCs subject to 10 CFR Part 50, Appendix 8. ,

(v) Any SSCs subject to 10 CFR Part 50, Appendix A, Criterion.1.

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(vi) Any $$Cs expiteitly subject to facility Technical Specifications (TS). "

(vii) Any $$Cs subject to facility TS through the definition of operability (i.e., support 55Cs outside TS). )

(viii) Any SSCs described in the FSAR.

I This guidance is directed toward NRC inspectors that are reviewing u.tions of l licensees that hold an operating license. Although this guidance generally l reflects existing staff practices, application on specific plants may constitute a backfit. Consequently, significant differences. in licensee practices should-be discussed with NRC management to ensure that-the guidance is applied in a-reasonable and consistent sanner for all licensees.

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9900 Operability-Issue Date: 10/31/91

2.0 DUINITIONS

2.1 Current Licensina Basj,.1 Current licenstng basis (CLB) is the set of NRC requirements applicable to a specific plant, and a licensee's written commitments for assuring compliance with I and operation within applicaole NRC requirements and the plant specific design basis (including all modifications and additions to such commitments over the life of the license) that are docketed and in effect. The CLB includes the NRC regulations contained in 10 CFR Parts 2. 19, 20, 21, 30, 40, 50, 51, 55, 72, 73, 100 ano appendices thereto: orders; license conditions; exemptions, and Technical Specifications (TS). It also includes the plant specific design basis information defined in 10 CFR 50.2 as documented in ti.e most recent Final Safety Analysis Report (FSAR) as required by 10 CFR 50.71 and the licensee's comitments remaining in effect that were made in docketed licensing correspondence sucli as licensee responses to NRC bulletins, generic letters, and enforcement actions, as well as licensee commitments documented in NRC safety evaluations or licerrs4e event reports.

2.2 Desicn Basis Design basis is that body of plant specific design bases information defined by 10 CFR 50.2.

2.3 Deoraded Condition A condition of an SSC in which there has been any loss of quality or functional capability.

2.4 Nonconformino Condition A condition of an SSC in which there is failure to meet requirements or licensee commitments. Some examples of nonconforming conditions include the following:

1. There is failure to conform to one or more applicable codes or standards specified in the FSAR.

2. As built equipment, or as-modified equipment, does not meet FSAR design requirements.

3. Operating experience or engineering reviews demonstrate a design inadequacy.

4. Documentation required by NRC requirements such as 10 CFR 50.49 is not available or deficient.

2.5 Full Ous11fication Full qualification constitutes conforming to all aspects of the current licensing basis, including codes and standards, design criteria, and commitments.

9900_0cerability_ _ _ 2- Issue Date: 10/31/91

3.0 STANDAoD TEtuN! Cat SPEC!riC ATIONS OPERA 8illTY DEFINITION AND DISCUSSION 3.' Ooerability Definition The Standard Technical Specifications (STS) define operable or operability as follo s;

'A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified functions, ano when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or 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)."

3.2 Variations of Ocerability Definition in Plant Soecific TS There are several variations in existing plant specific TS of the above basic definttion. Therefore, some judgement is required in application of this guidance on operability. Word differences that exist are not viewed by the NRC to imply any significant overall difference in application of the plant specific TS. Any problems that result from existing inconsistencies' between a plant specific definition of operability and this guidance should be' discussed with regional management, who should discuss the issues with NRR if deemed necessary.

In all cases, a licensee's plant-specific definition is governing.

3.3 Soecified Function (s)

The definition of operability refers to capability to perform the 'specified functions." The specified function (s) of the system, subsystem, train, component, or device (hereafter referred to as system) is that specified safety function (s) in the current licensing basis for the facility.

In addition to providing the specified safety function, a system is expected to perform as designed, tested and maintained. When systes capability is degraded to a point where it cannot perform with reasonable assurance or raliability, the system should be judged inoperable, even if at this instantaneous point in time the systes could provide the specified safety function. See Section 6.11, which discusses ASME Section XI, for an exaamle.

3.4 Sunnart System Coerability - Understandino Systes Interrelationshins The definition of operability embodies a principle that a systes can perform its specified safety function (s) only when all its necessary support systems are capable of performing their related support functions. Therefore, an NRC inspector should expect that each licensee understands which support systems are necessary to ensure the operability of main systees and components that perform specified safety functions. Such an understanding is sandatory. Otherwise the licensee will not be able to implement the definition of operability.

Issue Date: 10/31/91 9900 Operability

4.0 BACKGROUND

The purpose of the Technical Specifications is to ensure that the plant is operated within its design basis ard to preserve the validity of the safety analyses, whicn are concerned with both the prevention and mitigation of acct:ents. Because both prevention of accidents and the ability to mitigate them must be continuously ensured, the process of ensuring OPERABILITY for safety or safety support systems is ongoing and continuous. The focus of operability is foremost on the capability to ensure safety.

The process of ensuring operability is continuous and consists of the verification of operability by surveillances and formal determinations of operability whenever a verification or other indication calls into question the system's or component's ability to perform its specified function.

Verification of operability is supplemented by continuous and ongoing processes such as:

o Day-to day operation of the facility o Implementation of programs such as inservice testing and inspection e Plant walkdowns or tours ~

o Observations from the control room o Quality assurance activities such as audits and reviews o Engineering design reviews including design basis reconstitution.

Without any information to the contrary, once a component or system is established as operable, it is reasonable to assume that the component or system should continue to remain operable, and the previously stated verifications should provide that assurance. However, whenever the ability of a system or structure to perform its specified function is called into question, operability must te determined from a detailed examination of the deficiency.

The determination of operability for systems is to be made promptly, with a timeliness that is cospensurate with the potential safety significance of the issue. If the licensee chooses initially not to declare a system inoperable, the licensee must have a reassnable expectation that the system is operable and that the prompt determination process will support that expectation. Otherwise, the

. licensee should issediately declare the system or structure inoperable. Where there is reason to suspect that the determination process is not, or was not prompt, the Region may discuss with the licensee, with NRR consultation as appropriate, the reasoning for the perceived delay.

The TS establish operability requirements on systems required for safe operation and include surveillance requirements to demonstrate periodically that these systems are operable. Performance of the surveillance requirement is usually 1

considered to be sufficient to demonstrate operability provided that there is reasonable assurance that the system continues to conform to all appropriate criteria in the current licensing basis (CLB). Whenever conformance to the appropriate criteria in the CLB is called into question, performance of the surveillance requirement alone is usually not sufficient to determine operability.

9900 Operability -

4 Issue Date: 10/31/91

h When operability verification or other processes indicate a potential deficiency or loss of quality, licensees should make a prompt determination of operability anc cuality the act on the results of the system of that determination.

in accordance The with 10licensee should CFR Part 50 also restore Appendix B, Criterion XVI. Corrective Action.

5.0 ADDITIONAL GUIDANCE FOR OPEoABILITY DETERMINATIONS In the course of review activities or through normal plant operation, a licensee may become aware of degraded or nonconforming conditions affecting the SSCs defined a Section 1. These activities include, but are not limited to, the follow,ng:

o Review of operational events o Design modifications to facilities o Examinations of records o Additions to facilities ,,

o Vendor reviews or inspections o Plant system walkdowns.

These and other paths for identifying degraded or nonconforming conditions, including report; from industry and other utilities, should result in the prompt identification and correction of the deficiency by the licenser. Licensees shoul.: ?L.ke an operability determination and take follow-on corrective action in the foliowing circumstances:

o Discovery of degraded conditi0ns of equipment where performance is called into question o Discovery of nonconforming conditions where the qualification of equipment (such as conformance to codes and standards) is called into question o Discovery of an existing but previously unanalyzed condition or accident. NOTE: For a previously unanalyzed condition or accident that is considered a significant safety concern,'but is not nart of the design basis, the licensee say subsequently be required to take

• additional action after consideration of backfit issues (See 10 CFR 50.1M (a)(5)).

The following guidance for dealing with issues that are closely associated with opersbility determinations has been derived from the NRC regulations and from previous guidance issued to licensees.

5.1 Focus on Safety The ir_2ediate and primary attention mu:;t be directed to safety oncerns.  ;

Reporting and procedural requirements should not interfere with ensuring the health and safety of the public. To' continue operation while an operability ,

i determination is being made, the licensee sust have a reasonable expectation that i the systes is operable and that the determination process will support that expectation.

u l Issue Date: ~ 10/31/91 -5 9900 Operability

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l 5.2 full Oualification Full qualification constitutes conforming to all aspects of the current licensing basis, including codes and standards, design criteria, and comitments {

i The SSCs defined in section 1 are designed and operated, as described in'the -

current licensing basis (CLB), to include design margins and engineering margins  !

of safety to ensure, among other things, that some loss of quality 'does not mean ';

imeciate failure. The CLB includes commitments to specific emes and standards,. '!

design criteria, and some regulations that also dictate margins, Many license 6s '

add conservatism so that a partial loss of quality does not affect their  !

comitments to the margins. The loss of conservatism not taken credit for in the i safety analyses and not comitted to by the licersee to .satisf j requirements does not require a system to be declared inoperable.y All licensing other -

losses of quality or margins are subject to an operability determination and Corrective action. '

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5.3 Deal with Operability and Restoration of-0ualification Senaratelv l

Operability and qualification are closely related concepts. However, the fact. ,

that a system is not fully qualified does not, in all cases, render that system unable to perform its specified function if called upon.- According to' the; definition of operability, a safety or safety-support system or structure must ,

be capable of performing its specified function (s) of prevention or eitigation  :

..s described in the current licensing basis, particularly the'T5 bases or FSAR.  !

ihe prompt determination of operability will- result in decisions or actions ~

pertaining to continued plant operation, while qualification or requalification . 1 becomes a corrective action goal. Qualification concerns, whether it is a lack '

of required quality or loss of quality because of degradation, can and should be .

promptly considered to determine the effect of the concern on the operability of. l the system. '

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If operability is assured based on this' prompt determination, plant operation can i continue while an appropriate corrective ' action program is taplemented to restore -  !

full qualification. This is consistent with the p l ant T5 being the control 11ag. 1 document for making decisions about- plant. operations, while 10 CFR Part 50,

- Appendix B, Criterion XVI,~ Corrective Action,its the requirement document for-dealing with restoring equipment qualification. . .

The principle of treating the related concepts of operability and restoration of-  :!

-qualification separately _ is 'to ensure that the. operability determinationTisi S focused on safety and .is not delayed by decisions'or~ actions necessary to ~ plan; ,

or. implement the corrective action,- i.e., restoring full' qualification. .

.j 9900! Operability. -6 Issue Date: 10/31/91:

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5.4 Detemin$no Ooerability and Plant Safety is a Continuous Decision-Makino Process Licensees are obligated to ensure the continued operability of SSCs as specified by TS, or to take the remedial actions addressed in the TS. For other SSCs which may be in a degraded or nonconforming condition, it must be determined whether a condition adverse to quality exists and whether corrective actions are needed.

Operability is verified. as discussed above, by day to-day operation, plant tours, observations from the control room, surveillances, test programs, and o*her similar activities. Deficiencies in the design basis or safety analysts or problems identified by the operability verification lead to the operability detemination process by which the specific deficiency and overall capability of the component or system are examined. The process, in one form or another, is ongoing and continuous. As a practical matter, decision making requires good information and takes time. However, the process used by licensees should call for prompt and continuous attention to deficiencies and potential system inoperabilities, in addition, the licensee's process should call for imediately declaring equipment inoperable when reasonable expectation of operability doet not exist or mounting evidence suggests that the final analysis will conclude that the ecuipment cannot perform its specified safety function (s).

5.5 Timeliness of Ooerability Determinations .

Timeliness of operability determinations should be comensurate with the safety significance of the issue. Once the defiriency has been identified and the specific component or system has been identified, the determination can be made regarding the capability to perform the specified function (s). There is not an explicit requirement in the regulations for the timing of the decision. As discussed further in Section 6.0, timeliness is important and is determined by the safety significance of the issue. The Allowed Outage Times (A0Ts) contatnad in TS generally provide reasonable guidelines for safety significance.

5.6 Timeliness of Corrective Action Timeliness of corrective action (i.e., the requirements in 10 CFR Part 50, Appendix B, Criterion XVI, for ' prompt" corrective action) should be cosamensurate with the safety significance of the corrective action.

The determination of operability establishes a basis for plant operation while the corrective action establishes or re-establishes the design basis / qualification of the safety or safety support system. As in Section 5.5 above, there is no explicit requirement in the regulations for timeliness of these corrective actions, except that 10 CFR Part 50, Appendix 8, Criterion XVI requires it to be ' prompt". Again, timeliness is determined by the safety significance of the issue.

i 5.7 Justification for Continued coeration See the NRC Inspection Manual. Part 9900, Technical Guidance, ' Resolution of Degraded and Nonconforming Conditions," for guidance on JCOs.

Issue Date: 9900 operability 10/31/91

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6.0 DETAILED DISCUSSION OF SPECIFIC OPERABIllTY ISSUES 6.1 Scoce and Timina of Ocerability Determinations Determining system, structure, or component (SSC) operability is a continuous process that cannot be avoided. Action is required any time an $$C that is required by TS or NRC requirement to be operable is found to be inoperable - If an immediate threat to public health and safety is identified, action to place the plant in a safe condition should begin as soon as this circumstance is known and should be completed expeditiously. l Once a degraded or nonconforming condition of specific SSCs is identified, an operability determination should be made as soon as possible consistent with the safety importance of the SSC affected. In most cases, it is expected that the decision can be made imediately (e.g., loss of motive power, etc.). In.other cases it is expected the decision can be made within approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of discovery even though complete information may not be available._ . Soot ew f exceptional cases may take longer. For SSCs in TS, the Allowed Outage Times (A0Ts) contained in TS generally provide reasonable guidelines - for - safety significance. For 55Cs outside TS, engineering judgement must be used. to determine safety significance. The . decision should be based on the best information available and must be predicated on the ' licensee's reasonable expectation that the SSC is operable and that the prompt detmaination process-will support that expectation. When reasonable expectation does not; exist, the SSC should be declared inoperable and the safe course of action sh)uld be taken.

The licensee should examine the full scope of the current licensing basis, including the TS and FSAR comitments, to establish the conditions and .

performance requirements to be met for determining operability. The operability decision may be based on analysis. . a test or partial ' test, experience with operating events, engineering judgment, or a combination of these factors taking into consideration equipment functional requirements.. An initial determination regarding operability should be revised, as appropriate.Has new or additional information becomes available.

l The scope of an operability determination needs to be sufficient to address the capability of the equipment to perform its' safety; function (s). Operability determinations should therefore include the following 2ctions:

o Determine what equipment is_ degraded or potentially nonconforming.

o Determine the safety-function (s) performed by the equipment.-

1 o Detemine the circumstances' of ~the potential nonconformance, including the possible failure mechanism.

o Determine'.the requirement or' comunitment . established ' for the:

l~ equipment, and-why the requirement or: commitment may not be met.

o Detemine by what means and when the potentially nonconforming equipment was first discovered. . i 9900 Operability 8- !ssue Date: 10/31/91I

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o Determine safest plant configuration including the effect of transitional action, r

o Determine the basis for declaring the affected system operable, ,

through:  ;

a. analysis

b. test or partial test.

c. operating experience, and d, engineering judgement.

if an NRC approved action (such as provided in an LCO action statement) is immediately taken to compensate for failed equipment (e g., placing one channel-of reactor protection in the tripped condition upon failure of the channel such that the specified safety function can be maintained), continued operation of the facility is permitted. 4 However. continued operation with an inoperable channel in the tripped cond,ition ,

is not advisable because a subsequent failure will result in a plant trip that' will challenge plant safety systems. It is also not advisable from the standpoint of plant availability.

6.2 Treate'ent of Sinole Failures in Ooerability Determinati~ ens

• 6.2.1 Definition of Single Failure 10 CFR Part 50, Appendix A, " General Design Criteria for Nuclear Poser Plants,"

defines a single failure as: ,

'A single failure means ..an' occurrence which results 'in' the' lo'ss ' of ~

capability of a component to perform 'its intended . safety: functions. -

Multiple failures resulting from a single occurrence are considered to be -

a single failure.'

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l 6.2.2 Capability to Withstand a Single Failure is a Design Consideration Appendix A contains general design. criteria (GDC) forL S$Cs that perform major safety functions. Many of the GDC contain a statement sistlar to the following:

• $sitable - redundancy . in ; components and. features: and; suitable?

. Interconnections, leak detection, isolation and containment capabilities!

shall be1provided to assure 1 that for onsite electrical powerf system, operation (assuming: offsite power in- not available) and . for. offsite. ,

. electrical power system operation' (assuming onsite power.1s not available)..  :

L - the system safety function can be accomplished annumina a sinale failure."

• j See, for example, GDC 17, 34, 35, 38, 41. 44. Therefore,l capability to withstand; i a single failure in fluid or - electrical systems is a plant.smcific- design consideration, which ensures that a single failure does not ress' t in a loss of-the capability of the ' system to perform its safety functions.

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..g. 9900 operability l IssueDate:.-10/31/913

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6.2.3 Discovery of a Design Deficiency in Which Capability to Withstand j a Single failure is Lost A desiga deficiency in which capability to withstand a single failure is lost, j should be evaluated and treated as a degraded and nonconfoming condition. As 1 with any degraced or nonconforming condition, a' prompt detersination of operability is required.  ;

i For any design deficiency in which the capability to withstand a single failure i is lost, the licensee must address the quality aspects and if the design deficiency affects the design basis requirements forthe particular plant.

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promptly correct the deficiency in accordance with 10 CFR Part 50, Appendix B, Criterion XVI. Corrective Action.

6.3 Treat ent of Consecuential Failures in Ooerability Determinations 6.3.1 Definition of Consequential Failure '..

A consequential failure is a failure 'of an SSC caused by a postulated accident within the design basis. - For example, if during a loss of coolant accident (LOCA) (a design basis event), the broken pipe could whip and incapacitate a nearby pump, then the pump would act be able to function. Sich a pump failure is called a consecuential f ailure because the pump failed as~a result of the design basis event itself. In ~ general, facility design . takes any such consequential failures that are deemed credible into consideration. In this case. that would mean that the broken pump was.not one that.the safety analysis would take credit-for to mitigate the LOCA.

6.3.2- Consequential Failures and Operability Determinations Operability determinations should be performed for those potential consequential f ailures (i.e., an SSC failure that..would be a direct consequence of ta design basis event)~for which the SSC in question needs to: function. .Where-consequential failures would cause a loss of. functton needed for lietting or mitigating the effects of the event, the affected $$C 1s inoperable because it cannot perform all of its specified functions. Such situationstare most likely discovered during design basis reconstitution studies, or when new credible failure modes are identified.

'.6.3.3 Consequential Failures ~and Appendix 8 q With any consequential failure, the licensee must address the quality aspects and if the failure affects the design-basis requirements for the particular plant, >

promptly correct the deficiency in accordance with 10 CFR part 50, Appendix 8. -

Criterion XVI, Corrective Action.

6.4 onorability Durina TS Surveillances and Preventive Maine-a 1

During preventive maintenance (PM),-equipment may be removed free service and - 1 rendered incapable of performing the function (s); specified for safety. This equipment is clearly inoperable. For --equipment subject to the; Testnical I

1 ,9900 Operability -10.- -

Issue Date: 10/31/91

I Specifications- (TS), the PM activity and any other action that may be required -'

by the Lititing Conditions for Operation (LCOs), is expected to be completed within the Allowed Outage Time (A0T). For safety equipment not subject to the T5 either explicitly by direct inclusion in the TS or implicitly through the definition of operability, the licensee's PM activities should be consistent with the importance of the equipment to safety and the function (s) of the equipment and a reasonaDie time goal should be set to complete the PM.

In all cases, care should be exercised in removing equipment from service for PM to avoid accueulating long out of-service times of safety trains. Th6 licensee should reestablish operability before the equipment is returned to service. The-licensee also may need to reestablish operability for systems or components, in whole or in part, that are actively dependent upon the equipment undergoing the PM activity. The need for testing to reestablish operability should be based on a reasonable judgement about how the inoperable equipment may have been affected.

if retesting to reestablish operability is not possible or practicable because

• of safety concerns, analysis or other means should be used to demgn, strate operability.

If TS surveillances require that safety equipment be removed from service and rendered incapable of performing its safety function, the equipment is inoperable. The LCO action statement shall be entered unless the TS explicitly direct otherwise. Upon completion of the surveillance, the licensee should verify restoration to operable status of at least those portions of the equipment or system features that were altered to accomplish the surveillance.

NOTE: With regard to surveillances or other similar activities (such as inservice testing) that render systems inoperable for extended periods (i.e., those that may exceed the Allowed Outage Time (A0T)), licensees must have prior NRC approval by license amendment for the surveillance '

requirement or redefine the tests. It is not-the intent of surveillances or other similar program requirements to cause unwarranted plant shutdowns or to unnecessarily challenge other safetyisystems. ,

see 'Matatenance - Voluntary Eat.rx into Liettia.al.a41,legferDration Action 1 5tatammats to Parf9W9MWdtWe hetwtsmance;Tnspection angel, part 9900, Technical Guidance.

~

6.5 surveillance and onorability Testina in safety confiauration - ,

Many systems are designed to perfors' both nomal operational 'and safety functions. -It is preferable that' both the . Technical Specification- (TS)  ;

surveillance requirement. testing and any other operability _ testing be performed -

in the same configuration as would be required to perfom the safety functton. . 3 1.e., safety mode. However, testing. in the normal configuration' or mode of.

operation any be required for systems if testinein the safety mode will result:

in unwarranted safety concerns or transients. themodeofoperationfortheTS l surveillance requirements test is usually prescribed and the acceptance criteria are established on that basis.

If a systes should fail while it is being-tested in the safety mode of operation - >

the system is to be declared inoperable. For ongoing periodic testing that must

. Issue Date: 10/31/91 9900 operability-  :

i be performed during normal mode operation, the licensee should establish normal mode operational acceptance criteria that are based on a direct relationship to the safety mode requirements. Operability verification is then provided by acceptable normal mode operational test results.

Test f ailures should be examined to determine the root cause and correct the-proolem eefore resumption of testing. Repetitive testing to achieve acceptable '

test results without identifying the root cause or correction of any problem in a previous test is not acceptable as a means to establish or verify operability. -

6.6 Missed Technical Soecification Surveillance  ;

The Standard Technical Specifications (STS) contain Surveillance Requirement-4.0.3 which states:

' Failure to perform a. Surveillance Requirement within the specified, time -  !

interval .shall constitute a f ailure to meet the OPERABILITY requirements for a Limiting Condition for Operation. Exceptions to these requirements-are stated in the individual specifications. Surveillance Requirements do not have to be performed on inoperable equipment."

Plant specific- Technical Specification (TS). variations of this statement may exist, in which case the plant-specific TS govern.

The Allowed Outage Time (A0T) in the action requirements' specifies a time .

interval that permits corrective action to be taken to satisfy the LCO. If such -

. a time interval is specified in the action requirements or if the licensee has. .

. adopted by license amendment, the 24-hour provision of amended Surveillance t

- Requirement 4.0.3 as discussed in Generic Letter'(GL) 87-09, thel completion of a missed surveillance within these time intervals meets the requirements.. As  :

with systems discovered to be inoperable, the time interval begins upon discovery of the missed surveillance. Failure .to perform a TS' requirement within the specified time interval is considered a condition-prohibited by the T5 and is reportable' _ at least under 10 CFR ' Part 50.73; _it- also say_ be subject to  :

enforcement action..

Generic Letter 87-09 and other documents provide extensive guidance on surveillance . extension, applicability, and success criteria. ' The_ above I

discussion. involves only the operability issues.  ;

6.7 una of Manual Action in Place of Automatic Action '!

Automatic action is frequently provided as. a design feature specific te each safety -system to ensure that the specified functions of the system will be ,

accompitshed. Limiting safety system settings'for nuclear rfactors-are defined'

-in 10 CFR Part 50.36, " Technical-- Spectfications,' as settir.gs for automatic;  ;

protective devices related- to those' variables' having significants safety functions. . Where a limiting safety system setting ~is specified for a variable  ;

on which a _ safety limit has been placed, the setting must be so chosenL that automatic protective action will correct the abnormal situation before a safety i limit is exceeded. Accordingly, it is not appropriate to take credit for manual-1 5 l I

9900l0perabilityl ~12-

.!ssue Date:--10/31/91-

1

. )

)

action in place of automatic action for protection of safety limits to consider 4

equipment operable. This does not preclude operator action to put the plant in a safe condition, but operator action cannot be a substitute for automatic safety,

~

limit protection.

The licensing of specific plant designs includes consideration of automatic and manual action. While approvals have been granted for either or both type actions, not every combination of circumstances has been reviewed, from an o;erability standpoint. Although it is possible, it is not expected that many-determnations of operability will be successful for manual action :in place of' Credit for manual initiation to mitigate the consequences of automatic action.

design basis accidents should have been established as part of the licensing review of a plant.

E for any other situation in which substitution of manual action for automatic action may be acceptable, the licensee's determination of operability with regard action must focus on the physical differences between' to the use of manual automatic and manual action and the ability of the manual action to accomplish the specified' function. The physical differences to be considered include, but--

are not limited to, the ability to recognize input signalf for action, ready access to or recognition of setpoints, design nuances that. may - complicate .

subsecuent manual operation such as auto reset, repositioning etc., ~onminious temperature or -

sanning pressure, timing required for automatic action, requirements, and emergency operation procedures written for the automatic mode.

) of operation. The licensee should have written procedures in plai:e and training accomplished on those procedures before substitution of any manual action.for the loss of an automatic action, hout written procedure and a full conside ation of all parti ent di b The consideration of manual action in remote areas a

$c'c#jtM'hj,frM*

e"In'c'ur'rdTu2 y hazards. 'One reasonable test of the reliability :and' ffe iveness of annual _ action may be the approval of manual. action for the same nt 1 the aut t c ac n can t r 1 corr cte in a cor a h gn . Appendix 8. Criterion XVI, Corrective Action.

6.8' 'fatterminate* Stata of Onerability E

An $5C is operable when it is capable of performing itslspecified function (s) and when all necessary support 55Cs are also capable of performing their related; support functions. ,see-operability definition and-discussion in Section 3.0.t Otherwise, -the $$C'is inoperable. -When a licensee. has cause to question thei operability of an $$C, the: operability.. determination'is to. tr. prompt; the1l timeliness must be. commensurate with~ the potentialf 4 en the licensee's. reasonable expectation -that the 55C is operable and that the prompt determination process will support that expectation.

'j l

-13 9900.0perabilityL Issue.Date: ~10/31/91 __ _ _

l l

.1 1

1 In the absence of reasonable expectation that the SSC is operable, the SSC is to I te declared inoperable imediately. Subsequent evaluation may conclude that an SSC declared inoperable is in f act operable. The licensee's actions subsequent to declaring an SSC inoperable are guided by the regulations, TS, plant procedures, and so forth. In addition, the licensee should determine when and under what circumstances the system became inoperable so that reporting 1

. requirements may be met and NRC followup actions may properly reflect the. '

I circumstances and the licensee's efforts to correct and prevent recurrences. In sumary, an SSC is either operable or inoperable at all time. " Indeterminate" ,

is not a recognized state of operability.

6.9 Use of Probabilistic Risk Assessment in Ooerability Decisions Probabilistic rist assessment (PRA) is a valuable tool for the relative evaluation of accident scenarios while considering, among other things, the probabilities of occurrence of accidents or external events. The definition of operability states; however, that the SSC must be capable of performing its specified function (s). The inherent assumption is that the occurrence conditions or event exists and that the safety function can be performed. . The use of PRA '

or probabilities of the occurrence of accidents or external events is. not.

acceptable for making operability decisions. .

However, PRA may provide. valid and useful supportive information for a licensee amendment. The PRA is also useful for determining the safety significance of-SSCs. The. safety significance, whether determined by PRA or other analyses, is a necessary factor in decisions on the appropriate ' timeliness" of operability determinations. Specific guidance on the timeliness of determinations is presented in Section 5.5.

6.10 Environmental Qualification When the NRC or licensee identifies a potential deficiency in the environmental qualification of equipment (i.e., a licensee does.not have an adequate basis to; establish qualification), the licensee is expected to make a prompt determination of operability, to take immediate steps to establish a plan with a reasonable schedule-to correct the deficiency, and to write a Justification for Continued Operation (JCO) (See Note below), which will be available for NRC review. The licensee may be able to make a finding of operability using analysis and partial test data to. provide reasonable assurance that the equipment will _ perfore its.

safety function (s) in its accident environment uhen called upon to do so.- The licensee should also show that subsequent. failure of the equipment will not result in significant degradation of any safety function or provide misleading-information to the operator.

NOTE:. 'the JCO. referred to 'in questions of equipment qualification - is 1 specifically addressed by Generic Letter. 88 07 ~ dated April 7.1908. This l environmental qualification "JC0" includes an operability determination. -It also i states that the licensee should evaluate.whether the findings are reportable l under 10 CFR 50.72,10 CFR 50.73,10 CFR Part 21, the Technical Specifications, or any other pertinent reporting requirements, including 10 CFR 50.9.

9900. Operability- . 14 Issue Date: 10/31/91

4 h

The following actions should be taken if a licensee is enable to demonstrate equipment opera 011ity:

o for inoperable equipment in a system subject to the TS, the licensee shall follow the appropriate action statements. This could require that the plant be shut down or remain shut down.

o For inoperable equiement in a system not subject to the TS, the licensee may continue reactor operation if the safety function can A be accomplished by other designited equipment that is qualifid or if limited administrative controls can be used to ensure the safety function is performed.

6.11 Technical Soecification Ooerability vs ASME Code. Section XI-Ooerative Criteria l \

The Technical Specifications (IS) normally apply to overall system perfohnance i but sometimes contain limiting values for certain component performance, which are specified to ensure that the design basis and-safety analysis is' satisfied.

The values (e.g., pump flow rate, valve closure time, valve leakage rate, safety / relief valve set point pressure) are operability.ver.ification criteria.

If these values are not met at any time, the applicable LC0 shall be entered.

The ASME Section-XI. inservice testing. plans required under 10 CFR 50.55(a) for pumps and valves may contain the same or different limits and . additional component performance acceptance values which, if not met,'will indicate that the pump or valve has seriously degraded so that corrective action would be required to ensure or. restore the operability and operational readiness of the pump or valve. The ASME Section XI acceptance criteria include ' required action ranges" or limiting values for certain component performance parameters. These required action ranges or limiting values as defined by the code as component performance parameters, may be less conservative than the TS values which are safety analysis  !

limits. However, action must be taken when the T5 requirements are not est. i Generic Letter 89 04 Attachment 1. Position 8, defines the starting potn' t'for the ,

Allowed Outage Time (A0T) in T5 action statements for ASME 5ection XI pumps land i valves. When performance data fall in the required action range, regardless'of.

whether the limit is equal to or more conservative than the T5_ limit, the pump or valve must be declared inoperable immediately_ (the term " inoperative' .is used in the text of ASME Section XI; the pump or valve is both~ ' inoperative

• and- l ingoerable) and the. TS action statement- for the associated system mustJ be en ured.

In cases where the required action range. limit is more conservative than its corresponding TS limit, the corrective action may not be limited to replacement or repair;'it may be an analysis to demonstrate that the specific performance degradation does not impair operability'and that the pump or valve will.sti.ll L

fulfill its. function, such as delivering the required flow.1 A new required action range may be estabitshed after such analysis which would then allow a new determination of operability, l ,

1 Issue Date: -15 9900 Operability .

10/31/91 i

.. ~_ . . ._ _ _ _ . _ _

The durations specified by the Code for analyzing test results have not been accepted by the NRC for postponing entering a TS action statement. As soon as data are recognized as being within the required action range for pumps or as exceeding the limiting value of full stroke tima for valves, the associated component must be declared inoperable and, if subject to the TS, the A0T specified in the action statement must be started at the time the component was declared inoperable. For inoperable pumps and valves considered by ASME Section II but not subject to the TS, the action should be consistent with the safety significance of the issue and the functions served by the affected system (s).

Recalibrating test instruments and then repeating pump or velve tests is an acceptable alternative to the corrective action of repair or replacement, but is not an action that can be taken before F.laring the pump or valve inoperable.

However, if during a test it is obvious that a test instrument is malfunctioning, the test may be. halted and the instruments promptly recalibrated or replaced.

During a test, anomalous: data with no clear indication of the cause must be attr1 outed to the pump or valve under test. For this occurrence, a prompt determination of operability is appropriate with follow-on corrective action.ps necessary.

Note: In the above discussion, " required action range" and " inoperative' are ASME Section XI terms. ,

6.12 Suerort system Ooerability The definition of operability embodies the principle that a system can perform its function (s) only if all necessarY support systems are Ca;:able of perforBing their related support functions.- It is incumbent. upon. each licensee to understand which support systems are necessary to ensure operability of systems

• and components that perform specified safety functions.

When a support system is detemined to be inoperable, all systems for'which that support system is renuired for systems operability should be declared inoperable and the LCOs for those systems entered. Any appropriati remedial. sctions -

specified by a supported _ systen LC0 action statement _ (to compensate for the inoperable-supported system).should be taken. ,

When a support system is determined to be inoperable, the licensee should employ .

the .same operability determination process for the supported systems, as the licensee would for any other degraded systen.- In particular, the scope and timint of such operability decisions shou 11 follow the guidance in Section 6.1.- ,

There are cases where judgment on the part - of a' licensee .is appropriate?in-determining whether a support system is or 1s not required. One example is the case of a ventilation system. A ventilation systes may- be reautred to ensure that other safety related equipment can perfom its safety- function-in the ,

summer, but may not be taggiged in _the winter. Similarly, the electrical power.-

supply-for heat tracing may be reautred in-the winter to ensure that a safety-related system equipment can perfom its safety function, but any not be taggiInd in the summer. The need for judgment- in reviewing what individual licensees do in : specific cases should be- recognized. If a licensee determines that - a 1900 Operability !ssue Date: 10/31/91

Tecnnical Specification (TS) system is capable of performing its specified function (s) with an inoperable support system that is not in the TS, then no additional action outside of restoring the inoperable support systems is needed.

Furthermore, the licensee may modify the support function like any other change to the f acility by use of the 10 CFR 50.59 process and FSAR update.

For some suppcrt systems, there are specific Allowed Outage Times (A0Ts) spec 1fied in the TS. Ideally, the A0T contained in the TS for a support system should be equal to or less than the A0T for any system for which that support system is recubed for system operability. Problems where inconsistencies exist between an A0T for a support system and the A0T for a system for which that.

support system is required should be discussed with regional management- who stould discuss the issue with NRR if deemed necessary. While such.

int.onsistencies are being resolved, the more restrictive A0T should be used. In somt cases an amendment to the TS may be necessary.

In alt cases, the following principles should be used: ,,

a. Tre most important safety concern is to ensure that the capability- to

, perform a specified safety function is not lost as a result of more than one train of a support or sup'p orted system being declared inoperable.

When a support or supported system is declared inoperable in one train, the corresponding independent support or supported systems and all other associated support systems in the opposite train (s) should be ensured to be operable; i.e., the complete capability to perform the specified safety function has not been lost. The term "ensurei as used here, allows for an administrative check by examining logs or other information to determine if. required features are out-of service for maintenance or other reasons.

These actions are not to be used in lieu of required T5 actions. ]

b. Upon determining that a loss of functional capability condition exists, actions specified in the support and supported system 1.COs should be taken to mitigate the loss of functional capability.

~

6.13 Picino and pine Sunnort Renuirements All piping and pipe supports found to be degraded or nonconfoming should be subjected to an operability determination. - To assist licensees in the determinations, operability guidance :has been provided specific to various components. These components include the-piping, supports.: support plates, and l anchor bolts. It Bulletin No. 79-14 addressed the seismic analysis for as build j safety-related piping systems. The supplement to IE Sulletin 79-14 dated August  ;

15, 1979 and Supplement 2 to IE Bulletin 7914 dated September 7,1979 provide 3 additional guidance. Concrete anchor bolts and pipe supports are addressed with i specific operability criteria in Supplement I to Revision 1 of IE Sulletin 79 02.

The criteria for evaluating operability of seismic design alping supports and anchor bolts relating to Bulletins 79-02 and 7914 are detal' ed in the E. Jordan meno to the Regions dated July 1979, and the V. Noonan meno dated Au gust 7,1979. 1 Upon discovery of a nonconformance with piping and pipe supports, ' iconsees may use the ' criteria in Appendix F of Section III of the ASME- Code for operability determinations. These criteria and use of Appendix F are valid until.the next j refueling outage when the support (s) are to be restored to the FSAR criteria. l Issue Date: 10/31/91 -17 9900 operability

1 For systems determined to be otherwise operable but which do not meet the above criteria, licensees should treat the systems or components as if inoperable until NRC approval is obtained for any additional criteria or evaluation methods used to determine operability. Where a piping support is determined to be inoperable, a determination of operability should be performed on the associated piping system.

6.14 riaw Evaluation l Regulation 10 CFR 50.55a(g) and Standard Technical Specification -(STS) 3.4.10 (the section number may vary with plant specific TS) require that the structural  ;

integrity of ASME Code Class 1, 2, and 3 components be maintained according to '

Section XI of the ASME Code. In the conduct of inservice inspection maintenance activities, or during plant operation, flaws in components will be discovered.

The operability of such systems containing flaws may depend on Lthe flaw-characterization or evaluation performed by the licensee and the acceptability of continued service of the component. Since the characterization- and/or evaluation is vital to the determination of operability, the licensee's efforts following flaw detection must be prompt.

Components containing flaws characterized or determined .to be within the acceptance standards in IWB 3500 (IWC 3500 for Class 2 components) of Section XI are acceptable for continued service and, although no determination of operability is necessary, reporting must be in accordance with regulatory requirements.

Upon discovery of a flaw exceeding the acceptance standards in IWB-3500 (!WC-3500 for Class 2 components), the licensee should promptly determine operability. The evaluation and acceptance criteria of IWB-3600 may be used in the determination.

For Class 3 moderate energy piping, i.e., Class 3 piping with'a saximum operating temperature below 200 #F and a maximum operating pressure below 275 psig, the -

evaluation and acceptance criteria in Generic Letter 90 05 say be used.

l The licensee may treat the system containing the flaw (s), evaluated and found to l

meet the acceptance criteria in IWS 3600, as operable until NRC approval in accordance with IW8 3600 is obtained. For Class. 3 moderate energy piping, the l

licensee may treat the system containing the flaw (s), evaluated and found to meet i

- the acceptance criteria in Generic Letter 90-05, 'as operable untti relief is obtained from the NRC. The licensee must promptly submit its evaluation- for l either case to the NRC for review and. approval.

Alternative evaluation procedures and/or acceptance criteria may also be used for flaws exceeding IWB-3400 or Generic Letter 90 05. When alternative evaluation procedures anc/or acceptance criteria are used as a basis ' for acceptable-continued service, the licensee must treat the systes containing the flaw (s) as-inoperable until NRC approval of procedures and criteria is obtained. ' Prior-to the approval', the plant must be placed.in a safe condition or for systems in the TS, the plant must enter the corresponding Limit.ing Condition for. Operation. ,

l 18- Issue Date: 10/31/91-9140 Operability.

. .. . .- -- -. - - .. . = - . -

- 6.15 Ocerational teakace If leakage develops in the reactor coolant system, there are additional requirements. The Technical Specifications (TS) do not permit any pressure boundary leakage. The Operational Leakage Limiting Condition for Operation (LCO) must be entered upon discovery of pressure boundary leakage; therefore, an -

operability determination is not appropriate.

Article NB 2121 of Section 111 of the ASME Code excludes code requirements from materials not associated with the prtssure retaining function of a component, such as packing and gaskets. However, leakage from the reactor coolant system is limited to specified values in the f5 depending on whether the leakage is from ,

identified, unidentified, or specific sources.such as the steam generator tubes or reactor coolant system pressure iso 34 tion valves. If the leakage exceeds the TS limits, the LCO must be entered.

For reactor coolant system leakage within the limits. of the TS, the licensee '

should determine operability for the degraded component- and include in the-determination the effects of the leakage onto other components and materials.

Furthermore, the regulations and TS require that the structural integrity of ASME Code Class 1, 2, and 3' components _be maintained according to Section XI of the .

ei ASME Code. If a leak is discovered in a Class 1, 2, or 3 -component in the' conduct of inservice inspections, maintenance activities, or. during plant '

operation, IWA-5250 of Section XI requires corrective measures be taken based on repair or replacement in accordance with Section XI. In addition, a through wall flaw does not meet the acceptance criteria in (WB 3600.

Upon discovery of leakage from a Class 1, 2, or 3 component pressure boundary '

(i.e., pipe wall, valve body, pump casing, etc.) the' licensee should declare the-component inoperable. The only exception.is for Class 3 moderate energy piping.

For Class 3 moderate energy piping, the ,

as discussed in Generic Letter 90-05.

licensee may treat the system containing the through wall flaw (s), evaluated and found to meet the acceptance criteria in Generic Letter,90 05, as operable until- -

relief is obtained from the NRC. i 6.16 Structural Reauirements

- Category I structures and supports-(referred to herein as structures) which are -

subject to . periodic surveillance and -inspection in accordance with. the requirements of Technical Specifications (TS) shall be considered operable if the:

• limits' stipulated in the T5 are met. If these limits are not set,:the Limiting i

-Condition for Operations (LCOs) are to be entered for the.affected structure.

If the' degradation affects the ability of the s'tructure to' provide'_ths rewired an . operability.

design support for systems. attached to .the structure, determination must be performed for these systems as well. ,

Degradation affecting. Category I structures include, for example, concrete  ;

cracking and spalling, excessive deflection or deformation, water leakage,.robar corrosion, missing or. bent anchor bolts, etc. -!f these degradations are identifled in: Category. 1l structures which areL not . subject to periodic

- 19 .

9900-Operabt11ty  ;

LIOCue Date: .10/31/91 .

surveillance and inspection, they should be assessed by the licensee to determine tre capability of these structures to perform their specified function. As long as the identified degradation does not result in the exceedance of acceptance limits specified in applicable design codes and standards, referenced in the design basis document, the affected structures are operable.

Significant degradations resulting in the exceedance of the acceptance limits must be promptly reported in accordance with the requirements in 10 CFR 50.72 and evaluated by the licensee for determnation of operability. These evaluations should include the criteria used for the operability determination and the rationale for continued plant operation .n a degraded condition outside of the design basis. The licensee's evaluations should also include the plan for corrective action, as recuired by Criterion XVI of Appendix B to 10 CFR Part 50, to restore degraded structures to their original design requirements. As stated above, any system which depends upon the degraded structure for required support should also be examined for operability if the degradation or nonconformanc'e calls into question the performance of the system. NRC inspectors, with possible sup; ort from headquarters, should review licensees' evaluations of structural, degracations to determine their technical adequacy and conformance to licensing and regulatory requirements.

END 1

i

-20 Issue Date: 10/31/91 9900 Operability

ENCLCSURE 3 LIST OF RECENTLY ISSUED GENERIC LETTERS Generic Date of L e ge r, ,H,o,,,,

, Subject ,, , ,, ,,,,,

Issuance,,,,,,,1,ssued To,,,,,,,,,

91-17 GENERIC SAFETY ISSUE 29, 10/17/91 ALL HOLDERS OF OP

" BOLTING DEGRADATION OR LICENSES OR CONST FAILURE IN NUCLEAR POWER PERMITS FOR NUCLEAR PLANTS" POWER PLANTS 91-16 LICENSED OPERATORS' AND 10/03/91 HOLDERS OP LIC OR OTHER NUCLEAR FACILITY CONSTR, PERMITS FOR PERSONNEL FITNESS FOR DUTY NUC PWR/NPRs AND ALL LICENSED OPERATORS

& SENIOR OP'CRATORS 91-15 OPERATING EXPERIENCE 09/23/91 ALL POWER REACTOR FEEDBACK REPORT, SOLEN 0ID- LICENSEES AND OPERATED VALVE PROBLEMS AT APPLICANTS US REACTORS 91-14 EMERGENCY TELECOMMUNICA- 09/23/91 ALL HOLDERS OF OP TIONS LICENSES OR CONST.

PERMITS 91-13 REQUEST FOR INFO RELATED 09/19/91 LICENSEES AND APPLI-TO RESOLUTION OF GI130, CANTS Oraidwood, Byron

" ESSENTIAL SERVICE WATER Catawba, Comanche Peak SYS FAILURES AT MUTLI-UNIT Cook, Diablo, McGuire SITES," PURSUANT TO 10CFR50.54(f) 91-12 CPERATOR LICENSING NAT. 08/27/91 ALL PWR REACTOR EXAMINATION SCHEDULE AND APPLICANTS FOR AN OPERATING LICENSE RESOLUTION OF GENERIC 07/18/91 ALL HOLDERS OF 91-11 ISSUES 48, "LCOs FOR CLASS OPERATING LICENSES 1E VITAL INSTRtMENT BUSES "

and 49, " INTERLOCKS AND LCOs FOR CLASS 1E TIE BREAKER $"

PURSUANT TO 10CFR50.54(f)

EXPLOSIVES SEARCHES AT 07/08/91 ' TO ALL FUEL CYCLE 91-10 PROTECTED AREA PORTALS FACILITT LICENSEES WHO POSSESS, USE, IMPORT OR EXPORT FORMULA QUANTITIES OF STRATEGIC SPECIAL NUCLEAR MATERIAL INDIVIDUAL PLANT EXAMIMATION 06/28/91 ALL HOLDERS OF 88-20 OLs AND cps FOR SUPP. 4 0F EXTERNAL EVENTS (IPEEE)

NUCLEAR POWER FOR SEVERE ACCIDENT VULNERA.

BILITIES - 10 CFR 50.54 (f) REACTORS

Enclosure 2 PILGRIM UNIT 1: ASSESSMENT OF LOW PRESSURE TURBINE ANALYSIS During the refueling outage in April 1993, General Electric (GE) inspected the rotor in low pressure turbine "A" (LPA) at Pilgrim Unit I and found flaw indications in disks 4, 5, 6, and 7.

GE recommended that the licensee either remove the seventh stage disk on the generator side (disk 7GA) or warm the LPA rotor before starting the turbine. The licensee later retained Structural Integrity Associates, Inc. (SIA) to evaluate flaw indications in disk 7GA.

On May 12, 1993, the licensee submitted the SIA analysis (Reference 1) to the NRC project manager, who requested that the NRC Materials and Chemical Engineering Branch (ENCB) review the SIA analysis to determine: whether th were any gross error in the SIA analysis and whether the flaws indications ,ere in the turbine disks would have any effect on plant safety.

Pilgrim Unit I has two low pressure turbines, LPA and LPB, with shrunk-on disks. The flaw indications of the 7GA disk are located in both the hub and web. Although the fourth and fifth stage disks have more and larger flaws than the 7GA disk has, GE determined that the 7GA disk is the limiting disk based on operating conditions, the fracture toughness of the disk, and the consequences of a disk failure.

SIA performed parametric studies to determine effects of the fracture appearance transition temperature (FATT), fracture toughness variability, pre-warming, crack growth rate, and stress intensity factors. The EMCB staff compared key parameters used in both the GE and SIA analyses to our estimates (see Attachment 1). Parameters used in the GE analysis were extracted from the SIA analysis because GE's analysis was not available at the time of this assessment.

For the 7GA disk, GE reported one indication of 3.556 mm (0.14 in] in the hub and an indication in the web which GE could not accurately size. For that indication, GE assumed a crack size of 6.35 mm (0.25 in] based on flaw indications from other power plants' inspection data and laboratory data. -The staff believes that the initial crack size of 6.35 mm [0.25 in) is conservative but could not quantify the uncertainty associated with the assumed size.

GE used a fracture mechanics model of an edge crack in an infinite plate having constant loading. GE's model is conservative because it is more-compliant than the actual geometry, which is a radial crack emanating from the keyway.

I

4 l

Moreover, its constant loading does not consider the radial decrease in hoop stress with increasing distance from the bore. SIA's model is a nole in an infinite plate with attenuated loading along the crack. The staff assumed a model of a thick wall cylinder with attenuated loading.

GE used a crack growth rate of 1.52 mm [0.06] inch each year, which was the median vaiue from a statistical study correlating the average crack growth rate with the wheel operating temperature from turbine inspection data of both BWR and PWR plants. SIA used 0.416 mm (0.0164 in), 0.51 mm (0.02 in], and 1.52 mm [0.06 in] each year in its studies. The staff calculated a crack growth rate of 0.51 mm [0.02 inch) each year from previous inspection data of the LPA rotor. The staff believes that the actual crack growth rate may be between 0.51mm [0.02 in) and 1.52 mm (0.06 in) each year. However, GE's data indicate the upper bound growth rate (2 standard deviations) at an operating temperature of 78 'C [172 *F] could be as high as 2.02 mm (0.08 in) each year.

The critical stress intensity (Kg) is an indicator of fracture toughness of the disk material. The lower the K t used in the fracture mechanics analysis the more conservative the results will be. GE used a lower bound value of 115 MPalm (105 ksi/in] which was taken from the graph of critical stress intensity v5. excess temperature (test temperature - FATT). The staff finds that the value of 115 MPa/m r105 ksi/in] is conservative.

GE and SIA calculated the critical crack sizes (depths) of 8.64 mm [0.34 in) and 13.72 mm [0.54 in), respectively. SIA conservatively assumed that the crack length is the length of the keyway bore. SIA indicated that if the crack aspect ratio is known, the critical crack size may be larger than 13.72 an [0.54 in). SIA's calculation results in a critical crack size of about 11.43 mm (0.45 in] for the thick wall cylinder model.

Using the above parameters, the staff estimated a factor of safety for flaw size ranging from 1.21 to 3.6 based on the ratio between the crack length at end of the current fuel cycle in April 1995 to that of the critical crack size of the cylinder model (see attachment). The factor of safety for stress intensity (K i) ranges from 1.1 to 1.89, which was estimated by taking square root of the safety factor for flaw size.

The NRC desires that the turbine disk failure probability be IE-5 each year or lower for an unfavorably orientated turbine. GE's - analysis is based on a turbine disk failure probability of IE-5 failure per year. SIA did not perform a probabilistic fracture mechanics analysis. Using engineering judgment , the staff estimated that the turbine disk failure probability for-the LPA turbine is between lE-5 and IE-4 per year. The NRC would permit a turbine in-this condition to remain in service until the next scheduled outage, at which time the licensee should ensure they meet the turbine disk failure probability to the IE-5 per year criterion (Attachment 2, Ref. 2).

Upon assessing the information available, the staff found no safety concern for normal operation of the LPA turbine to the end of the current fuel cycle, although the SIA analysis is less conservative than the GE analysis. The staff intends to perform a confirmatory review of the GE analysis and its methodology.

The Boston Edison Company has informed the NRC that it will be replacing both low pressure turbines during the next refueling outage, which is expected to be in April 1995.

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ATTACHMENT '. :: ENCLOSURE I PILGRIM TURBINE EVALUATION Initial Crack growth Kit lower cound Critical Time to crack (mm/yr(in/yr]) (MPadm(ksidin)) crack deotn failure size ana i ;. s t s (mm(in)) (years)

(mm (in}*)

GE 6.35(0.25] 1.52{0.06] 115(105] 8.64[0.24) 1.5 SIA 6.35(0.25] 1.52(0.06] 115(105] 13.72(0.54] 4.8 0.51[0.02] 14.5 NRC 6.35[0.25] 1.52(0.06) 115(105] 11.43[0.45] 4 0.51[0.02] [2 -

Actuai measured sizes range from 3.05 mm (0.12in) to 3.56 mm (0.14in]

GE SIA NRC APPLIED KI MODEL .

T e I d L1 FACTORS OF SAFETY ON FLAW SIZE / STRESS INTENSITY FACTOR (BASED ON NRC ASSUMPTIONS)

Crack growth Factor of Factor of rate per year safety at safety at mm (in) startup for flaw size normal operation for (at 24*C (75 *F] flaw size (at 78'C (172 *F])

1.52 (0.05] 1.21 2.82 0.51 (0.02] 1.55 3.60 Crack growth rate Factor of Factor of safety at normal per year safety at startuo operation for stress mm (in) for stress intensity intensity factor factor (at 78 *C (172 'F])

(at 24 *C (75 *F])

1.52 (0.06] 1.10 1.68-0.51 (0.02] 1.24 1.89

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3

-:tacnment 2 u Enclosure 2

References:

May 12, 1993, letter from D. Rosario anc P. Riccardella of Structural Integrity Assoc 1ates to J. Gerety of Boston Edison,

Subject:

Evaluation of the Pilgrim Unit 1 Low Pressure Turbine Rotor 7th Stage Shrunk-on Disk.

2.

NUREG-1048, Safety Evaluation Report related to the Operation of Hope Creek Generating Station, Supplement No. 6, July 1986.

l

Enclosure 2

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W x l MAR 2:133?,

Docket No. 50-293 Mary Elizabeth L1rnpert, Chairman

{ Duxbury Nuclear Advisory Committee l 148 Washington Street Duxbury, Massachusetts 02332

Dear Ms. Lampert:

J 4

I am responding to your letter to Secretary Chilk dated February 5,1993, containing questions l regarding reactor vessel water level instrumentation and motor-operated valves at the Pilgrim Nuclear Power Station. ..

I I The enclosed response provides the additional information you requested. The answers are provided in five enclosures. Each enclosure is devoted to one of the five general areas into which your 54 questions were grouped.  !

We note that much of the information contained in the enclosed answers provides further clarification to issues we've discussed with you at public meetings in the Plymouth area and in .

our response to your earlier set of questions. The bases for our answers comes from publicly- ~j available documents such as inspection reports and licensing corTespondence, and from J documents that are associated with the rulemaking process for the issues involved. Any additional safety-significant information on these and other issues relevant to the Pilgrim plant will be addressed in normal regulatory correspondence.

l While we recognize your interest as reflected in your questions, we're concerned that our continuing to respond to your questions in this depth will not be possible in light of our limited -

l resources which we, by necessity, have to devote to the direct confirmation of the safe operation l of the plant. We do, however, want you to continue to provide us with any issues or concerns you may have and, if appropriate, they will be considered in our regulatory program for the Pilgrim plant.

Your Freedom of Information Act request is being preswl by appropriate personnel within the NRC's organization, and will be addressed in separate correspondence. If you have any l

further questions regarding our public meeting in Plymouth or the enclosed rerponses to your questions, please contact Eugene Kelly of my staff at (215) 337-5183.

Sincerely, Original Signd Li:

James T. Wiggins, Acting Director Division of Reactor Projects O

jfl 3;;=:siaaom _ OFFICIAL R$ CORD COPT _

I l

J Mary Elizabeth Lampert 2

Enclosures:

As Stated cc w/encls:

Public Document Room (PDR)

Local Public Document Room (LPDR)

Nuclear Safety Information Center (NSIC)

NRC Resident Inspector K. Abraham, PAO (2 copies)

Commonwealth of Massachusetts OFitCIAL RECORD COPT

ENCLOSURE 1

" OPERABILITY OF THE CONDENSATE POT" I.1 Q. Based on this [an excerpt from NRC Inspection Report 50 293/92-23], is it fair to say that, during the October 23-24 shutdown, the condensate pot did not accurately measure the water level in the reactor?

A. Yes, it is correct to state that there were instances observed during the depressurization following the Pilgrim reactor shutdown in which the reactor vessel water level instrumentation did not accurately measure reactor vessel water level. However.

this only occurred at relatively low reactor pressures and for short periods of time, in a relatively narrow band of operation. This " spiking" of the reactor vessel water level instruments is not considered to be a significant safety concern.

I.2 Q. Is it fair to say that the " spiking" seen in October 23-24 shutdown was different from what was seen in previous shutdowns both in terms of the pressure at which it began and in amplitude, and similar to other occasions in that the condensate pot did not function adequately?

A. Yes. The reactor vessel water level instrumentation " spiking" observed during the

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October 24,1992 Pilgrim reactor depressurization was different from that experienced during recent reactor shutdown and depressurization evolutions. As was documented in NRC Inspection Report 50-293/92-23, Section 8.1.3, the " spiking" began at lower reactor pressures and was initially of lesser amplitude. However, these differences were not of any technical significance.

I.3 Q. Is it fair to say that the so-called ' corrective" action taken by BECo before October 23,1992, did little or nothing to eliminate the " spiking" problem?

A. Yes. Past corrective actions to improve condensing chamber and steam drain line performance appeared to have been minimally effective.

II.1 Q. Given the undisputed underlying fact that the condensate pot didn't give accurate readings, and that the extent to which the readings are inaccurate varies from event to event, what is the basis for saying that the " instrumentation response

... was consistent"?

A. The condensate pot itself does not measure reactor water level, and some important water level information was correctly measured by the water level instrumentation system. Therefore, the staff cannot technically agree with your premise that it is an

" undisputed underlying fact that the condensate pot didn't give accurate readings".

Nonetheless we understand the intent of your question to be directed at the fact that the precision of the reactor water level measurement system changed with each event, and this consideration appears to conflict with the staff's statement in Inspection Report 50-293/92-23 that " instrumentation response...was consistent".

Enclosure 1 2 The term " consistency" was used to describe a qualitatively similar response. The response of Pilgrim's reactor vessel water level instrumentation to the non-condensible gas phenomenon was consistent for the March and October 1992 depressurizations in that initial " spiking" pressure and recorded " spike" signature (i.e. shape, amplitude and duration) were qualitatively similar. Specifically, " spiking" has been consistently experienced on channel "B" at reactor pressures beginning at 350-450 pounds per square inch gauge (psig); while the channel "A" reference leg instrumentation " spiking" has been initially experienced at approximately 65 psig.

II.2 Q. For example, the ainount of " spiking" has varied considerably both between the "A" and "B" legs and at different times. Solkine a Manh E 1992, mpoeted in the NRC Report, May 27,1992, No. 50-293/92-04) stated, ". . . on March 26. . the "B" reference leg instrumentation experienced a spike of positive nineteen inches (from +29 to +48 inches); and, the snikina n October E 1222, as mported in NRC report Docket No. 50-293, stated the "B" reference leg instrumentation spiked 22 inches (from 21 inches to 51 inches) and the "A" was at different number at each occasion.

At the Febniary 3,1993 meeting Mr. Mcdonald (NRC Resident Inspector) showed a slide that effectively stated low pressum spikes became less pmdictable, " Low pressure spikes were more irregular and remained present longer". However, the next line on the slide read, " Instrument behavior was predictable and repeatable".

A. I also hear the NRC has agned with Pilgrim that the maximum error is 14 inches. How can this be?

B. To further complicate matters I understand BECo used the same consukants as NU and their error was 37 feet.

Please explain all these apparent inconsistencies.

A. As was stated in GL 92-04, significant errors in level indication can occur as a result of degassing the instrument reference leg if sufficient non-condensible gas is dissolved in the reference leg and if the reactor depressurizes below 450 psig. The effect (i.e., error) will differ, not only from plant to plant, but also between reference legs at the same plant, based upon leakage, configuration, run times, and other design features currently being investigated by the BWROG.

As has been documented in NRC Inspection Reports 50-293/92-04,-Section 8.2 and 50-293/92-23, Section 8.1.1 and 8.1.3, the amplitude of the " spiking" increases as reactor i pressure decreases. The material presented at the February 3,1992 Plymouth public -l meeting is consistent with this position. Additionally, as reactor pressure decreases to less than 10-15 psig, the " spiking" becomes more frequent and of greater duration, and therefore the EPIC recorder trace becomes less regular. Further, as noted in response

Enclosure 1 3 to question 11.1 above, the water level instrument response has been qualitatively similar.

Based on these observations, the staff considers the Pilgrim level instrumentation behavior to be consistent.

The 14 inch value, that you referred to, was discussed because it is the error already assumed in the setting for the two-thirds core coverage interlock, and, therefore, a continuous 14 inch error in indicated level at Pilgrim would render the interlock out of calibration. This calculation was not intended to be, nor was it interpreted by the NRC, as the maximum potential error due to non-condensible gas.

l To the best of our knowledge, there has been no definitive quantification of a maximum i i level error that could occur at Pilgrim, to date. It is expected by the NRC staff that the I magnitude of the error in level indication following a rapid depressurization event would be significantly less than that estimated by the conservative assumptions used in the earlier calculations performed by General Electric Company and S. Ixvy, Inc.

(see response to question 14 in T. T. Martin letter dated October 30,1992 to M. E. Lampert).

II.3 Q. Is it really fair for BECo to say, and for the "NRC staff independently [to]

agree", that because you know there's a problem, it becomes a non-problem shnply

! because it's always a problem?

1 A. No, the staff disagrees with such reasoning. While non-condensible gases may result in significant errors in the level instrumentation, the NRC has concluded that the required safety functions would still be satisfied. However, the NRC considers the reliability and accuracy of reactor vessel water level instrumentation to be a matter of importance, and continues to closely monitor industry efforts to further analyze and correct the instrument performance. BECo has committed to apply the results of the ongoing BWR Owners l Group program to its plant to assure high functional reliability of the water level  !

instrumentation systems.  !

11. 4 Q. How does the NRC define " operability"?

i A. Operability is defined by each plant's Technical Specifications, and simply stated is the ability of equipment to perform a specific safety function.

Pilgrim Technical Specification 1.0.E states: " A system, subsystem, train, component or device shall be OPERABLE'or have OPERABILITY when it is capable of performing l

its specified function (s). Implicit in this definition shall be the assumption that all necessary attendant instrumentation, controls, normal and emergency electrical power l sources, cooling or seal water, lubrication or other auxiliary equipment that are required i for the system, subsystem, train, component or device to perform its function (s) are also capable of performing their related support function (s)." Further guidance on operability is provided in Generic letter 91-18.

______ ______m_____ _ _ _ _ __.____

4 Enclosure 1 4 II.5 Q. On October 30, 1992, T. T. Martin advised the Duxbury Nuclear Affairs Conunittee that several NRC regulations "would require a nactor shutdown if the reactor vessel water level instrumentation was inoperable." Is this still true? In making this statement, what meaning did the NRC attribute to the word

" inoperable?"

A. Yes, Pilgrim Nuclear Power Station Technical Specifications 3.1. A " Reactor Protection System", 3.2.A " Primary Containment Isolation", 3.2.B " Core and Containment", 3.2.F " Surveillance Information Readouts" and 3.2.G " Recirculation Pump Trip and Alternate Rod Insertion" all would require a reactor shutdown if the reactor vessel water level instrumentation were inoperable-meaning not capable of performing its safety function (s). Refer to the response to question II.4 for the definition of operability.

III.la Q. Do you know whether these are the only causes [ configuration of the referrace and b legs and leaks]? Do you know which, if either, is the nudor cause?

A. The three principal contributors are believed to be: 1) the concentration of non-condensible gas in the condensing chamber, 2) instrumentation system configuration; and,

3) instrumentation system leakage. Other contributing factors associated with the non-condensible gas problem are depressurization rate, final system pressure, and vibration of the instrument. However, other factors not related to the non-condensible gas problem have the potential to affect instrumentation accuracy, such as local ambient drywell temperature, restrictions in instrumentation system thermal growth, and electrical interferences. As of this time, neither instrumentation system configuration nor leakage have been identified as the principal cause(s).

III.lc Q. What is being done to fix (1) the leaks and (II) the reference leg configuration, and when?

A. BECo identified and quantified reference leg leakage. Reference leg joints and fittings that were identified to have external leakage were tightened, and the leakage was greatly reduced. This is documented in NRC Inspection Report 50-293/92-23, Sections 8.1.2 and 8.1.4.

The BWROG program for resolution of this issue is scheduled to be completed in July 1993. This program includes full-scale testing of prototypical reference legs. At least six different reference leg configurations will be tested which will identify which configurations may be more susceptible to errors due to non-condensible gases. It may or may not be concluded that changing the reference leg configuration will solve this problem. Any hardware modifications that are proposed to address this problem including possible changes to the reference leg configuration will be made by licensees at the earliest opportunity but prior to startmg up after the next refueling outage commencing after October of 1993.

1

i Liclosure 1 5 III.2 Q. (A) What reports has the NRC received of "very small leaks" (similar to these described by BECo) at other B%R plants, and to what extent have these other plants had " spiking" problems similar to those endemic to Pilgrkn? (B) Is the '

configuration of the reference leg at other BWR plants the same as that at Pligrim, and to what extent have any other plants having such reference legs had " spiking" problems?

A. The NRC has received reports of leakage at three other plants. Two of the three plants have not experienced spiking. The third plant reported an event that occurred on January 21,1993, at their facility involving both levelinstrument spiking and a sustained level indication error.

The configuration or geometry of the reference legs is highly plant specific; therefore, other plants would not likely hav< n nme geometric configuration as Pilgrim, althqugh the overall reference leg desig! b sin 2 in concept at BWR plants. " Spiking" of the reactor vessel level indication nas been reported at four other BWR plants, in varying magnitude.

III.2c Q. What " corrective" actions have been taken at any other plant, and when?

A. On the basis of information gathered from the licensee, the NRC staff is aware that modifications have been made to the Millstone Unit I water level instrumentation system.

A constant backflush system was installed to eliminate the accumulation of dissolved non-condensible gases in the reference leg. This was performed during August of 1992. Of.

the three plants discussed in response to question number 2a above, The NRC staff is also aware that small leaks in the reference leg piping were repaired at two plants in September and December of 1992.

III.3 On what basis did the " licensee", i.e., BECo, conclude that "the primary manav of the level spiking was noncondensible gases coming out of solution during ,

depressurization?" Did the licensee attribute this cause to any particular defect?

A. Boston Edison Company (BECo) used ultrasonic equipment to confirm the travel of gas bubbles in the "B" reference leg during the October 24, 1992, Pilgrim reactor depressurization. The ultrasonically verified presence of non-condensible gas _was correlated with " spikes" in el recorded by the emergency plant information computer (EPIC) system. BECo a.; lysis currently attributes the cause to any one of three contributors (discussed previously in response to question III-la), and concludes that elimination of any one of these contributors may ameliorate or eliminate the spiking. j This was documented in NRC Inspection Report 50-293/92-23, Section 8.1.3.

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Enclosure 1 6 1

III.4 Q. He NRC Report, May 27,1992 (No. 50-293/92-04), reporting on the March 24, 1992 spiking often cited Tech Specs. However, the NRC Report (Docket No. 50-.

293/92-23) dated December,1992, reporting on the October 23-24 spikleg stated, "NRC inspection ... have identified no violations of Pilgrim license condkiens."

Why the discrepancy? ,

A. NRC Inspection Report 50-293/92-04, Sections 2.3 and 8.2, documented the March 26-27,1992 reactor shutdown and depressurization during which " spiking" and three primary containment isolation system (PCIS) Group I actuations were experienced. -

Independent NRC assessment of Pilgrim equipment and BECo personnel performance ..

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during the reactor shotdown (including responses to the " spiking" and PCIS actuations) identified no violations associated with those events. .

How ver, on April 3,1992, subsequent to the plant shutdown, implementation of an inadequate :emporary procedure developed to investigate the " spiking" phenomenon caused an unplanned engineered safety features (ESP) actuation. The event was documented in Section- 8.1.2 of NRC Inspection Repoit 50-293/92-04, and .was ,

dispositioned as a licensee-identified,' noncited violation. The violation cited in l Inspection Report 92-04 was related to the management controls associated vdth the troubleshooting, and was not related to the operability of. the reactor vessel level .

instrumentation.  :

NRC Inspection Report 50-293/92-23 documented the October 23-24, 1992 reactor shutdown and depressurization during which spiking also occurred. As was the case-  ;;

during the March 26-27, 1992 shutdown and depressurization, no violations were identified as,ociated with that spiking event.

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O ENCLOSURE 2

" REDUNDANT WATER LEVEL INSTRUMENTATION"

1. Q. Exactly what is the undensa9 pot supposed to measure and under what circumstances?

A. The condensing chamber (or condensate pot) is a passive component in the reactor vessel water level instrumentation system, and as such provides no indication or control functions, by itself. The chamber provides a source of water through condensation to keep the reference legs of the water level instruments full. The reactor vessel water level instrumentation provides indication of the water level in the reactor vessel during all modes of plant operation.

2, 3. Q. Is there any other particular instrumentation that precisely replicates what the condensate pot is supposed to do? If so, what is it? *-

A. No, there is no other instrument that can readily measure the level of water in the reactor vessel at Pilgrim.

4 Q. If not, what other instrumentation,if any, approximates ndundancy? What are the primary purposes of that lastrumentation?

A. Aside from the five water level instrumentation systems which use the condensing chamber design, there are no other instrumentation systems which can readily measure reactor vessel water level.

5. Q. To the extent that other instrumentation is supposed to give an imucation of

" anomalous" condensate pot readings, please explain how that other instr ==*=*

shows that the condensate pot is " anomalous". Pncisely can (or shoukij an operator do to detennine the actual water level in the reactor?" What is the potential for error or inconsistency?

A. An operator is limited to the indication provided by the reactor vessel water level instrumentation systems to determine reactor vessel water level. It is expected that any errors in the water level indication that may occur during depressurization will not be of the same magnitude or occur at the same time on different instruments, therefore, a mismatch in the level indication will alen operators to erroneous level indication.

Operators have been sensitized to the potential for level indication errors during ,

depressurization, and in the event that reactor vessel water level cannot be determined, the operators are instructed by Pilgrim emergency operating procedure (EOP-16, Reactor Pressure Vessel Flooding), to flood the reactor vessel to ensure adequate core cooling until reliable level indication can be restored. Indirect, non-level related instrumentation such as reactor pressure and safety-relief valve position can provide evidence that the fuel is being adequately cooled (i.e., water level is adequate to assure safety) in the event ;

that the reactor is flooded per the EOPs. l I

9 Enclosure 2 2  ;

6. Q. IIow long would it take for an operator to " read" the condemmase pet measurement? In contrast, how long does it take for an operator to "resd". the 15 other instruments and, from them, determine that the condensate pot measureement was " anomalous?"

A. Control room operators can read all control room instmments that provide reactor ,

vessel water level indication within a time estimated to be a few seconds. Therefore, the l detection of any anomalous instrumentation response would be similarly prompt. j i

7. Q. If the operators am required to read a lot of "information" and maske )

calculations, what does this allocation of time mean in terms of their attention to i l

other expected duties? What are they not able to do?

A. Obse:ving reactor vessel water level instrumentation is a normal operator action during steady state and transient conditions. The operators do not have to make calculations in order to read the instruments and determine that the reactor vessel water level instruments are erroneous. Pilgrim emergency operating procedures provide symptom-based instructions to cope with level inoication anomalies. Operators are trained to be capable of promptly identifying inoperable or unreliable level instrumentation.

8. Q. The operators were not adequately trained to " read" the other instrumentation.

Please up-date us on the status of their training.

l l

A. In Section 5.1 of NRC Inspection Report 50-293/92-17, the NRC concluded that operators were sufficiently aware of possible reactor vessel water level perturbations, such that there is high confidence that they would take the proper actions in the event of a vessel level anomaly occurring during a rapid depressurization. The NRC identified the opportunity for BECo to improve operator capabilities with the safety parame'.er display system (SPDS) in Section 4.1 of NRC Inspection Report 50-293/92-17, howwer, the NRC did not conclude that operators were not adequately trained to use the SFDS.

Since that NRC inspection, the simulator SPDS has been made functional. Additional computer work remains to improve SPDS speed and availability before it is considered fully operational. Computer training modules for iriitial licensed operator candidates '

were rewritten to improve SPDS content. Additionally, licensed operator requalification training generated two new modules to addmss the SPDS function. One module is a classroom lecture on system capabilities and the second moduleis a practical session with the system in the simulator.

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9 Enclosure 2 3

9. Q. To ncap, is the other " instrumentation" truly redundant? And, unest importantly and remembering that the reactor would have to be shut down if the condensate pot were " inoperable", de the other systems combined or individuaNy really replicate what the condensate pot is intended to do?

A. (See response to question 4.)

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ENCLOSURE 3

" WATER INJECTION SYSTEMS" I.1 Q. What is the current statue of these two systems?

A. The high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems are currently (as of March 12, 1993) operable.

A probabilistic risk assessment (PRA)-based inspection was conducted by the NRC in December 1992 (Inspection Report No. 50-293/92-81), which included an in-depth review of the HPCI system. That inspection concluded that the HPCI system was being operated, maintained, tested and modified in a manner which assured operability and reliability.

I.2 Q. When is the last time there was a problem with either? -

A. On January 26, 1993, while performing a monthly HPCI surveillance test, a flow controller failed. The cause of the failure was a blown fuse; the fuse was immediately replaced, and the system was returned to service that same day. This condition was reported to the NRC in accordance with 10 CFR 50.72. On March 4,1993, the HPCI system was taken out of service for approximately 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> to replace the flow controller.

On February 25,1993, while performing a quarterly in-service test of the RCIC system, the steam admission valve failed in the mid-position. The valve was subsequently repaired, and the system was returned to service on February 28th. This condition was also reported to the NRC under 10 CFR 50.72.

This information is current as of March 12, 1993.

1.3 Q. Is either system intended to operate, automatically, in response to the sensed water level in the reactor? If so, (i) How do the systems compensate for inaccurate readings fivn the condensate pot? (ii) Does " spiking" have the effect of prevendag either system from operating?

A. The HPCI and RCIC systems automatically start upon receipt of a low reactor vessel water level signal when the reactor pressure is still greater than 600 psig, before significant errors in the level indication will occur. Additionally, the HPCI system, which is an emergency core cooling system (ECCS), will automatically start upon receipt of a high containment pressure signal for events that result in high containment pressure.

HPCI and RCIC are designed to isolate upon receipt of a high water level signal.

Therefore, a false high signal (spike) of sufficient size would shutdown these systems.

From a safety perspective, this has the following impact: These systems are designed primarily to provide injection at high reactor pressure, when the low pressure systems are unable to inject. Since significant potential errors can occur only after the reactor

o Enclosure 3 2 has been depressurized below approximately 450 psig, the low pressure systems would be available and the high pressure system would not be required for accident mitigation.

Therefore, the safety function of the RCIC and HPCI systems is not expected to be affected by non-condensible gas buildup in level reference legs.

II.1 Q. Would you also explain this. We also understand that IAw Pressure Iaiection and 2 System (LPCI) kicks-in about at the point where the condensate pot starts giving troubles, including what LPIS is supposed to do, the extent to which there has ever been a problem with it, and the extent (if any) to which its operation teletes to measured water levels in the reactor? Q. In particular, can inaccurate readings from the condensate pot prevent LPCI from " kicking-in" to provide core coelaat or effect LPCI in any other way?

A. The low pressure coolant injection (LPCI) system is designed for lower oressure operation, and automatically starts upon receipt of a low reactor vessel water level or high primary containment pressure signal. The LPCI logic will initiate at the same time that HPCI and RCIC initiate, when reactor pressure is still above 600 psig; however, it cannot inject water into the reactor vessel until reactor pressure is reduced below the discharge pressure of the LPCI pumps. The pressure at which the LPCI pumps start to inject water (400 psig) is coincidentally near the pressure at which " spiking" has been initially observed during Pilgrim reactor depressurization. But the introduction of LPCI flow to the reactor vessel is accomplished by the opening of injection valves that are controlled by pressure (not level) instrumentation. In addition, unlike the HPCI and RCIC systems, the low pressure emergency core cooling systems do not automatically shutdown on high reactor vessel water level. Therefore, there is no danger of system shutdown from level spiking.

I l

ENCLOSURE 4

" MOTOR-OPERATED VALVES" 1, 2 Q. With respect to Motor Operated Valves (MOVs), has Pilgrim and the NRC determined that all ECCS will function under design conditions? Has PWersn performed an operability determination that clearly demonstrates that all of these MOVs will operate under design or accident conditions?

A. Yes, the NRC considers that the emergency core cooling systems at Pilgrim will function. BECo's continuing determination of the operability of the associated motor-operated valves provides reasonable assurance that Pilgrim can be operated without undue risk to the health and safety of the public.

The determination of safety system and component operability is the responsibility of licensees and is a continuing process. Operability may be determined through tests or analysis, and the corrective actions to ensure continued operability would be based on the condition which has caused the component to be inoperable.

For motor-operated valves (MOVs), a periodic assessment of continued operational readiness is required by NRC regulations in 10 CFR 50.55a(f) for inservice testing of .

pumps and valves. Additionally, based on a concern that MOV behavior under specific operating conditions was not conservatively modeled in typical valve and actuator sizing equations utilized by the nuclear industry, and as such may not have the proper switch settings and/or torque requirements for all operating conditions, the NRC issued guidance for motor-operated valves. That guidance recommended testing beyond the requirements in 10 CFR 50.55a(f), to confirm that safety-related MOVs are capable of providing their intended design basis function. Generic Letter (GL) 89-10, " Safety-Related Motor-Operated Valve Testing and Surveillance," was issued in June 1989 to provide a recommended approach to resolve concerns regarding the adequacy of MOV design, configuration control, and maintenance / inservice testing practices. It recommended that licensees develop a systematic approach to confirm the capability of each safety-related MOV to perform under all design-basis conditions. If, in the course of the program, a motor-operated valve is found to have incorrect switch settings, inadequate torque or thrust for certain operating conditions, or otherwise may not be capable of functioning under all required conditions, the valve would be considered inoperable until corrective actions are taken. GL 89-10 requested licensees to develop a program with the following elements:

a. Performance of reviews to document all design bases operating conditions under which the MOV could be required to operate,

b. Preparation of procedures for proper settmg and maintenance of MOV torque switches, torque switch bypass, and limit switches.

, Enclosure 4 2

c. Testing of MOVs under design-basis differential pressure and flow conditions, 1

where practicable.

d. Periodic verification of continuing capability to function under design-basis conditions. j l

l 1

e. Implementation of a process to ensure adequate corrective action in response to )

MOV failures.

I 8

1 I

f. Trending of various types of problems identified by MOV testing and I maintenance.

l 1

The NRC performed an inspection in Maxh 1992 to review the program developed in ,

response to GL 89-10 at Pilgrim. In addition, prior to issuance of the operating licpnse I I

l for Pilgrim, the NRC independently determined that the emergency core cooling systems (ECCS) would function to provide adequate cooling of the reactor core under abnormal transient and postulated accident conditions. The analysis of the acceptability of the design of the ECCS is provided in the NRC Safety Evaluation for the Pilgrim Nuclear l Power Station dated August 25,1971. Finally, following initial startup system testing l (and upon being licensed), the ECCS motor-operated valves that perform safety-related f functions at Pilgrim are required to be (and have been) tested in accordance with 10 CFR l 50.55a(f) under the inservice testing program established by BECo.

3. Q. Is it true Pilgrim has experienced a few losses of offsite power during the past l'

few yan?

A. Yes. Pilgrim lost all offsite power on October 31,1991 (NRC Inspection Report 50-I 293/91-24). Also, as noted in NRC Inspection Report 50-293/87-53, Pilgrim lost offsite power four times from June 1972 to November 1987. Offsite power includes both the 345 kilovolt (KV) sources from Bridgewater and Canal, and the 23 KV Manomet line.

In addition, there have been approximately 23 instances of partial loss of offsite power (i.e., 345 KV sources) including the most recent event on March 13, 1993.

1

4. Q. What will happen if Pilgrim loses offsite power and their onsite poer also falls?

A. In the unlikely event thtt all offsite power sources and both emergency diesel generators fail, then core cooling would be provided by the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems. Station batteries would pmvide the necessary power to initiate, control, and monitor these systems. This condition is defined as a station blackout, and is govemed by 10 CFR Part 50.63 which was issued in June 1988. This SBO rule required licensees to either perform a " coping analysis" proving that the station could withstand this event for a specified period of time, or provide an independent alternating current (AC) source capable of powering the

Enclosure 4 3

" shutdown" busses within 10 minutes of the initiation of this event. As stated in NRC Inspection Report 50-293/92-16, BECo installed an attemate AC source at Pilgrim (a third diesel generator) to comply with these requirements.

5. Q. Is it fair to say that this event is probable?

A. No. Loss of offsite power combined with a sustained loss of onsite power is unlikely. The plant response to such an event is discussed in the answer to question 6 below.

6. Q. Has Pilgrim demonstrated that they can maintain the plant in a safe condition should this event occur?

A. Yes, BECo has demonstrated through a combination of testing and analysis. that Pilgrim can cope with a station blackout for eight hours. The NRC s'aff's review and acceptance of BECo's method of dealing with an SBO were summarized in safety evaluations issued on February 13,1991 and January 15, 1992. Also, as part of BECo's demonstration, cenain modifications and testing are scheduled to be completed during the refueling outage beginning in April 1993.

7. Q. Is it true the NRC issued a Generic Letter (89-10) Informing all licensees that nearly 20% of the motor operated valves (MOVs) are not expected to perform properly when required; and, this was based upon testing by NRC staff 7 A. It is true that the NRC issued GL 89-10 based on MOV testing and operating experience, but the generic letter did not specify a failure rate of 20%. In considering the issuance of a generic letter on motor-operated (MOVs), the NRC contracted with Brookhaven National Laboratory (BNL) to prepare a value/ impact analysis for an industry program to confirm the capability of all safety-related MOVs to perform their design basis function. In NUREG/CR-5140, "Value-Impact Analysis for Extension of NRC Bulletin 85-03 to Cover All Safety-Related MOVs," published in July 1988, BNL relied on a 1987 NRC staff revbw of information on earlier MOV test results. The estimated MOV failure rates were based on the results of then existing signature analysis techniques used at operating nuclear plants, and predicted that approximately 8% of the safety-related MOVs in nuclear power plants at that time may have been mcapable of performing their design basis function. The staff believes that the actions taken by licensees in response to GL 89-10 have substantially reduced the concerns with MOV operation. Further, the NRC is conducting an inspection program to verify that licensees are implementing programs consistent with the GL 89-10 recommendations.

Enclosure 4 4 As discussed in more detail in response to Questions 8 and 8B, the licensees of boiling water reactor (BWR) nuclear power plants modified approximately 20% of the MOVs used for containment isolation in the steam lines of the high pressure coolant injection j and reactor core isolation cooling systems and in the supply line to the reactor water I cleanup system as part of their response to Supplement 3 to GL 89-10. The licensees f

also performed less extensive maintenance (such as adjusting torque switch settings) on additional MOVs within the scope of Supplement 3. Those modifications and maintenance activities were performed to provide assurance that the MOVs could operate ,

under their design-basis conditions and, thereby, restore the design margin. i i

i I

8A. Q. What specific steps have the NRC and Pilgrim taken to demonstrate that these l emergency [ core) cooling systems will operate under accident conditions? l

' A. As discussed in response to Questions 1 and 2 above, the capability of the ECCS to operate under accident conditions is assured by testing performed during startup of the Pilgrim Station, and subsequent analysis, inservice testing, and maintenance. In a letter to the NRC dated January 15,1990, BECo committed to develop a program in response to the GL 89-10 recommendations. The NRC performed an initial inspection of the GL 89-10 program at Pilgrim in March 1992. During this inspection, the staff identified i certain inconsistencies in the Pilgrim MOV program with respect to the recommendations l of GL 89-10. These included MOV program implementation procedures, torque switch setpoint control, test accuracy, and prioritization of work. The staff also reviewed BECo's April 14, 1992, response to Supplement 3 of GL 89-10. As discussed in the response above, this supplement requested that licensees advance the schedule for addressing certain MOVs required to isolate a pipe break against high differential pressures in the high pressure coolant injection, reactor core isolation cooling, and the reactor water cleanup systems. BECo's response to this supplement was adequate for l continued operation (NRC Inspection Report 50-293/92-80). The NRC intends to conduct further inspections of the MOV program at Pilgrim.

New information regarding the HPCI steam supply MOVs was recently identified by BECo on March 5,1993 regarding valve size. As the NRC would expect, BECo is currently (as of March 19,1993) evaluating the new information. The NRC will follow their stetment as part of our normal inspection program, including additional maintenance planned for these valves during the April 1993 refueling outage, and an eventual update of the information in BECo's April 14,1992 letter.

8, 8B Q. Is it true, the [ generic] letter required each licensee to develop a plan and in the next 5 years demonstrate the operability of mil safety related MOVs? Why has the NRC allowed utilities 5 years for this very significant problesu before they have to demonstrate operability? This appears to be in conflict with NRC Regulations.

Enclosure 4 5 A. As discussed in response to Questions 1 and 2 above, the determination of safety system operability is a continuing process. This may be done through tests or analysis, or both. The five-year GL 89-10 program is a confirmation program and does not relieve licensees of the continuous responsibility to assure operability.

As background, the NRC issued Bulletin 85-03 that requested nuclear power plant licensees to confirm the capability of MOVs in high pressure safety-related systems to perform their design basis functions as a result of MOV failures at the Davis Besse nuclear power plant in 1985. Following the review of the implementation of Bulletin 85-03, the NRC contracted Brookhaven National L2.boratory to perform a cost-benefit study of a proposed expansion of the scope of Bulletin 85-03 to include MOVs in all safety-related systems. Based on the BNL study, MOV test research, and operating experience, the NRC prepared Generic letter 89-10 in June 1989 to request that licensees verify the capability of all safety-related MOVs to perform their design basis functions. (In Supplement I to GL 89-10, the NRC staff focused the scope of the generic letter on safety-related MOVs in piping systems.)

The generic letter requested that licensees complete differential pressure and flow testing of the MOVs within the scope of GL 89-10 within 5 years after the issuance of GL 89-10 or three refueling outages after December 1989, whichever was later. The NRC considered the five year /three refueling outage schedule for GL 89-10 to be appropriate because (1) the test results and operating experience at the time ofissuance of GL 89-10 indicated that the most significant problems involved MOVs in high pressure systems that had been addressed under Bulletin 85-03, (2) the probability of a design basis accident is considered low, (3) there is redundancy in the design of safety systems and MOVs in individual systems, (4) the assumptions used to define the design basis requirements for MOVs (such as degraded voltage and differential pressure) are conservative, (5) many MOVs are accessible for manual operation in the event of motor-operator failure, and (6) three refueling outages would likely be needed to perform the requested MOV testing.

Allowing a period of time for licensees to address NRC recommendations is not in conflict with NRC regulations in that the generic letter was reviewed and approved for issuance as a "backfit" under 10 CFR 50.109(a)(4)(i) as imposition of a new staff position interpreting the Commission rules that was different from a previously applicable staff position. Section 50.109 requires that the staff consider how the backfit should be scheduled in light of other ongoing regulatory activities at the facilities and to consider information available concerning several specified factors, and any other information relevant and material to the proposed backfit (reference 10 CFR 50.109(c)).

During the implementation of GL 89-10, licensees have discovered more MOV concems and experienced greater difficulty in conducting MOV tests at full design-basis differential pressure and flow than envisioned when the GL 89-10 schedule was established. Where significant MOV problems are identified at a plant, the NRC ensures

Enclosure 4 6 that the licensee resolves these problems promptly. For example, following the identification of specific MOV problems at certain nuclear power plants (for example, FitzPatrick and Wolf Creek), the licensees did not restart those plants until the problems were adequately resolved to the staff's satisfaction.

In 1988 and 1989, the NRC contracted Idaho National Engineering Laboratory to conduct high pressure blowdown tests of several MOVs typically used in high pressure coolant injection systems in boiling water reactor (BWR) nuclear power plants. When the evaluation of those tests indicated potential problems with specific MOVs, the NRC staff prepared Supplement 3 to GL 89-10 in October 1990 that requested BWR licensees promptly evaluate the capability of MOVs used for containment isolation in the steam lines of the high pressure coolant injection and reactor core isolation cooling systems and in the supply line to the reactor water cleanup system. The NRC reduced the BWR licensee schedule to 18 months for evaluation of the MOVs within the scope, of Supplement 3 to GL 89-10. The eighteen month time frame was based on the following considerations: (1) the low probability of a high energy line break, (2) the redundancy of the MOVs in each line, (3) the MOV capability to operate under realistic accident conditions because of the margin inherent in the MOV design from design-basis assumptions, and (4) the potential for the MOV to close after a decrease in reactor pressure. The results of a study performed by Argonne National Laboratory (ANL) of the conditional probability of core damage given a postulated break in the lines within the scope of Supplement 3 to GL 89-10 (ANL Letter Report on Task Assignment No.

2 Under FIN A-2336, dated January 3,1991) supported the staff's decision on the allowable schedule.

In addition to the staff review of licensee submittals in response to GL 89-10 and its supplements, the NRC staff is conducting an extensive inspection program to evaluate the licensee programs developed in response to GL 89-10 at nuclear power plants. The NRC believes that licensees have substantially reduced the concerns with MOV operation under design basis conditions and are well on their way to restoring MOV design margm provided by design-basis capability. Nevertheless, where significant MOV problems are identified, the NRC will continue to take regulatory action on a plant-specific or generic basis as may be appropriate.

8C, D Q. Has Pugrim pernrmed an operability determination as required by GL 91-18 for all MOVs? If PUgrim has not performed an opersbility determination as requhtd by GL 91-18 for all MOVs, why?

A. As discussed in response to Questions I and 2, the licensee is required to evaluate operability on a continuing basis as it implements its testing and analysis programs per the ASMP Code and GL 89-10.

ENCLOSURE 5

" TIMING"

1. Q. What is the time schedule for resolving the water level instrumentation issue at Pilgrim?

A. The issue is scheduled to be resolved at Pilgrim at the earliest opportunity after the conclusion of the BWROG program. The staff expects BECo to notify the NRC by July 1993 of its plan for resolving this issue at Pilgrim. Any hardware modifications will be made by licensees at the earliest opportunity but prior to starting up after the next refueling outage commencing after October of 1993.

2. Q. When is testing to be complete?

A. The BWROG reference leg de-gas test and benchtop testing is scheduled.tp be completed on March 31, 1993. A condensing chamber performance test may be performed by the BWROG subsequent to completion of the de-gas test. A schedule for completion of this test has not been determined.

3. Q. When are proposed modifications supposed to be reported to the NRC for its review?

A. Utilities are expected to select plant modifications by July of 1993. At that time, proposed plant modifications to be utilized at plants to resolve this issue will be submitted to the NRC for its review.

4 Q. By what date are the problems supposed to be fixed?

A. Any hardware modifications that are proposed to address this problem will be made by licensees at the earliest opportunity but prior to starting up after the next refueling outage commencing after October of 1993.

5. Q. Will the NRC take any action if they are not fixed on time?

A. Yes, the staff will take regulatory action including orders for modifications if necessary to assure timely implementation. The need for action will depend upon the results of the BWROG test pmgram, plant operating histories, improvements made to date, and any competing safety considerations.

Enclosure 5 2

6. Q. I am curious as to when this spiking was first discovered by Pilgrim and when it was reported to the NRC? The water level instrumentation issue has been around a long time; and Pilgrim seems to be the " leader" in the field by having had the seest problems with this device.

A. To the best of our knowledge, reactor vessel level instrumentation " spiking" was first observed at Pilgrim on April 30,1991 (see NRC Inspection Report 50-293/91-07).

BECo did notify the NRC of this event (see Licensee Event Report 50-293/91-008-00).

The capability to record signatures oflevel signals with precision sampling and resolution at Pilgrim did not exist until the emergency plant information computer (EPIC) system was certified as operational on April 11, 1990.

7. Q. Is it fair to say, according to regulation, the condensate pot would be considered a " defect"? ..

A. No. According to 10 CFR Part 21 regulations, a defect is a deviation of a component that could create a substantial safety hazard. It is the NRC staff's judgement that potential errors due to the effects of non-condensible gas in the level instrumentation do not constitute a substantial safety hazard. However, the staff considers potential water level instrumentation inaccuracies to be an important issue because level indication has safety and control functions in all modes of BWR operation. It is for this reason that the.

NRC staff has requested licensees to make corrective actions, as necessary, to ensure that the level instrumentation system is of high functional reliability.

l. 8. Q. Is it true defects are supposed to be promptly reported to the NRC in l accordance with 10 CFR Part 21 for suppliers of equipment?

A. Yes. Responsible officers for supplying activities, subject to 10 CFR Part 21 requirements, are required to notify the Commission within two days when they obtain information that a basic component supplied to a facility contains a defect that could create a substantial safety hazard, unless the responsible officer has actual knowledge that

! the Commission has been adequately informed of the defect (see 10 CFR 21.1).

9. Q. Is it true this regulation requires a report within 60 days?

A. No. 10 CFR Part 21.21 requires the responsible organization to notify the NRC l within two working days after determining a reportable defect exists. However, the responsible organization is required to evaluate deviations within 60 days of discovery l

I to determine if they are reportable defects. A deviation is defined in Part 21 as a departure from the technical requirements of a procurement document. If an evaluation l

l cannot be completed within 60 days, then an interim report must be submitted to the Commission at that time.

4 Enclosure 5 3

10. Q. .When did General Electric thst report this under Part 21, and did they naset' the .

60 day requirement?

A. General Electric did not file a Part 21 report with the NRC regarding the reactor vessel water level issue.

F 4

I

?

Federal Emergency Management Agency Washington, D.C. 20472 A E l i 1993 Ms. Jane A. Fleming 8 Oceanwoods Drive Duxbury, Massachusetts 02332

Dear Ms. Fleming:

This is in response to your April 20, 1993, letter to FederalYour Emergency Management Agency (FEMA) Director James L. Witt.

letter to Director Witt referred to and anclosed an April 2, 1993, letter to Nuclear Regulatory Commission (NRC) Inspector General David Williams regarding two issues concerning radiological emergency preparedness at the Pilgrim Nuclear Power.

Station in Plymouth, Massachusetts. The first issue concerns tho' availability of the Massachusetts Highway Department (MHD) maintenance facility in Wellesley, Massachusetts to function as a reception center in the event of an emergency at the Pilgrim or Seabrook Nuclear Power Stations. The second issue concerns the description in the FEMA 1991 Exercise Report, dated Fabruary 23, 1993, of the development of a protective action recommendation (PAR). Your letter has been referred to my office for response.

1 Issue It Wellesley Reception Center S_tatus Recardina Unavailability of Welleslev RecebtT6hMYNY" -* ~ ~ ~ ' ~ ~ l With regard to the availability of the Wellesley facility, we  ;

have received a copy of the enclosed April 27, 1993,. letter from l l

MHD to the Boston Edison Company (BEco), the licensee for '

Pilgrim, informing them that "BEco's use of (the MMD maintenance facility in Wellesley) shall terminate as of December 31, 1993."

Enclosed is a letter dated June 8, 1993, from FEMA to  ;

Massachusetts Emergency Management Agency (MEMA) Director A.

David Rodham regarding the unavailability of the Wellesley facility and its impact on radiological emergency planning and preparedness at Pilgrim'and Seabrook. The letter also addresses-the staffing concerns identified in your April 2,1993, letter to Mr. Williams. In the enclosed July 9, 1993, letter to FEMA

- Deputy Associate Director Richard W. Krima responding to our ,

June 8, 1993, letter, MIMA indicated that it "has initiated a l

)

comprehensive program to address both the long and short-term We also met issues regarding [the Wellesley Reception1993, Center)."

on several issues, j

with representatives of MEMA on July 12, '

among which was a discussion of facilities being considered as alternates to the Wellesley MHD facility.

1

The Nuclear Regulatory Commission (NRC) has coordinated with BEco the and the North Atlantic Energy Service Corporation (NAESCo),

licenses for Seabrook, and asked the utilities to provide MEMA with assistance to affect a timely solution to the issues concerning the replacement of the Wellesley reception center before December 1993.

We have been aware of the potential sale or leasing of the Wellesley MED facility for some time. Enclosed, please find a copy of a November 6, 1992, letter from John C. Dolan, FEMA Region I Technological Hazards Branch Chief, to Mr. Rodham concerning the potential sale or lease of the Wellesley MHD facility and FEMA's recommendation that MEMA identify alternate facilities as soon as possible that could replace the Wellesley reception center.

Comments Concerninc Technical Assistance Review .

I would like to address some of the statements you made in your April 2, 1993, letter to Mr. Williams that appear under "Issua I" but do not exclusively relate to the availability of the Wellesley reception cantar. On page four of your latter, you indicated that you had " ascertained that the main body of information for the technical assistanceThe review issued22,Dec.

December 1992,22, 1992, was developed in SEPT. 1991..."

Technical Assistance Review of thefor Massachusetts Seabrook wasRadiological based solely on Emergency Response Plan (MARERP) the Seabrook planning documents that became effective on December 30, 1992--the date of the transition in offsite planning and preparedness responsibility from NAESco to the Commonwealth of' Massachusetts. These documents were developed and submitted to FEMA by MEMA and the Massachusetts Department of Public Health (MDPM) as late as December 18, 1992.

A partial "first draft" of the MARERP for Seabrook During was submitted the subsequent fifteen to FEMA on September 24, 1991.

months, FEMA Verked with officials from MEMA and NAESCo During thatin reviewing and amending the MARERP for Seabrook.

time, six major revisions to the MARERp, and several minor enes, were submitted to FEMA for review. The last MARERP revision was submitted to FEMA on December 17, 1992t an additional one-page revision to the Nuclear Incident Advisory Team Handbook wasThis information submitted to FEMA by MDPH on December 18, 1992.

was communicated to you by Ken HorakIndeed, of FEMA theRegion above I in your March 1993 telephone call with him.

information appears to be noted near the bottom of the page of the copy of the March 2, 1993 letter from Robert Erickson of the NRC to you (which you enclosed- in your letter to Mr. Williams) .

2

,_ z .

You question whether FEMA should have reviewed the Wellesley procedures developed for a response to a Seabrook emergency in light of the possible leasing or selling of the MHD Wellesley facility. MEMA officials assured FEMA in a meeting on October 14, 1992, that the MHD facility would be available until at least one year from that date. In a November 13, 1992, meeting, MEMA Director Rodham stated that the Wellesley facility would be At the November 13, available until at least November 1993.

1992, meeting, Mr. Rodham also stated that MEMA staff were continuing to look for possible alternate reception center sites.

Additionally, the enclosed September 28, 1992, letter from MHD Deputy commissioner and Chief counsel Patrick Moynihan to Duxbury Town Manager Thomas J. Groux, indicates that the Wellsaley facility would be available for "a minimum of one year,"

presumably from the date of the letter.

Since emergency planning and preparedness will always be a dynamic process, it was appropriate for FEMA to review and ..

approve the Wellesley procedures developed for a Seabrook emergency in December 1992 given that the Wellesley facility was to be available for at least one year after the Seabrook transition and possibly longer than that.

Notes on March 2. 1993. RAC Meetina Also on page four of your letter to Mr. Williams, you state "On meeting March 2, 1993 at a RAC (Regional Assistance Committee:

Bob Erickson, NRC, was presented with and concurred w:.th this outdated and invalid information (the FEMA Technical Assistance

~~

~ Review'of the MARERP for'Seabrock)." Please note that Mr.

Erickson, NRC Headquarters Emergency Preparedness Branch Chief, did not attend the March 2, 1993, RAC meeting at FEMA Ragion I's offices in Boston, Massachusetts. Craig Gordon from NRC Region It I

was the sole NRC representative at the March RAC meeting.  :

should be noted that the information concerning Wellesley in the FEMA technical assistance review of the MARERP for Seabrook was neither outdated nor invalid in early March 1993.  ;

With regard to the status of staffing for the Wellesley Recepti:n Center, the enclosed July 20, 1993, letter from MEMA Planning l Director Doug Forbes to Mr. Delan indicates that two full shifts of personnel are available to staff the Wellesley Reception In a l Center in the event of an emergency at Pilgrim or Seabrook.

July 26, 1993, telephone conversation With Joseph 1993, Austinletter of ourby 1 Region I staff, Mr. Forbes clarified the July 20, indicating that personnel from the North Shore civil Defense council had been trained and would be replacing the departing MHD personnel. Please note that other personnel from the North Shore  ;

civil Defense Council staff the initial monitoring and  ;

decontamination functions at the Wellesley facility.

3 L

Issue II: Protsotive Action Recommendation Process Utility 71E Z_ 1 tea ==nt

n. - .

,, s. , . ,

~~ - ..

l With regard to the second issue concerning a protective action recommendation, in your April 2, 1993, letter to Mr. Williams, l I

you assert that "the utility did not develop the correct and complete information (with regard to the development of the Protective Action Decision (PAD) at the General Emergency (GE))."

It is unclear what information was incomplete or incorrect. The NRC 1991 onsite Pilgrim Exercise Report (Docket No. 50-293/91-28), dated January 23, 1992, does not contain any statements

{

I indicating that the utility did not develop correct and complete information in its development of a protective action In fact the NRC recommendation (PAR) during the 1991 exercise.

report states that " Performance by key members of EOF (emergency This i

)

operations facility) support groups was very effective.  !

I included response actions in engineering and technical  !

assessment, radistion protection, dose assessment, and administration." Moreover, the NRC Inspection Report (No. 50-293/92-04), dated May 27, 1992, also does not conflict with the NRC or TEMA 1991 Pilgrim exercise reports in this area.

The description of the "somewhat slow" derelopmentin of the the FEMA offsite PAD at the GE amargency classification level (ECL) 1991 offsite Pilgrim Exercise Report (dated February 23, The 1993)

NRC is consistent with the NRC 1991 onsite Exercise Report.

onsite report states, "After the General Emergency was classified, a minor delay occurred in issuing PARS to State and local a'OdioYiYlii duiTo thi' staffs concentration on extraneous dose assessment information." The NRC report identifies this as an " area for improvement" for the utility personnel at the EOF.

Again, there is no indication that the utility PAR was incorrect or incocplete.

Eqle of Dr. Nancy R$_dlev at the State EOC

" Nancy's on page five of your letter to Mr. Williams, you state, (Dr. Nancy Ridley of MDPH) role in the exercise was to develop the correct Protective Action Guideline (PAG) for the State."

Dr. Gerald parker, not Dr. Ridley, was the MDPH StateDuring EOC the Representative during the December 1991 exercise. exercise, Dr. Ridle she would be assuming the lead MDPH role at the State EOC in future exercises. In addition, please note that the PAGs are not developed during an exercise or during an actual emergency, they j are determined by the United states Environmental Dr. Parken,apd Protection Dr. Ridley Agency and are listed in the MARERP.

4 L __. __ __ -- __ ._-. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

.em __

were responsible, along with other State EOC staff, for developing protective action recommendations for the Massachusetts' Governor or designee's consideration.

Communication of Meteorolocical Cata to MDPM from Utility on page six of your letter to Mr. Williams of the NRC, you state that, "By the time the utility developed the secondary notice they had obtained the weather information BUT, this information was sent to the EOF in Plymouth. Bob Hallisey, the MDPH EOF representative, did receive the weather information but was unaware that the secondary notification form was not sent to the Eoc in Framingham. Nancy Ridley did not receive the weather data and Hallisey did not contact her to tell her 'which way the wind was blowing.'"

Please note that the primary interface between onsite and offeita technical officials occurs at the EOF, not the State ECC.

Meteorological data is communicated from the utility to the offsite officials by means of Initial Notification and Follow-Up Information Forms. These forms are sent frcm the EOF by the utility to critical offsite facilities, including the State EOC, over the BEC6 Notification System (known a.s BECONS) which is a multiple-line, direct-drop communication system having both voice and facsimile capabilities, i

• Inclusion of Backup Meteorological Data on Initial Notification Form The previously-mentioned NRC Inspection Report (No. 50-293/92-04), dated May 27, 1992, notes that during the 1991 exercise, the

" licensee form documenting an exercise General Emergency condition, as sent from the licensee IOF to the Commonwealth of Massachusetts EOC, noted that the meteorological tower was out of service. The backup meteorological tower data (scenario wind speed and direction) were available in the EOF, but were not included on the notification form transmitted to the EOC." The NRC Inspection Report indicates that the backup weather information was available in the EOF on data sheets and-EOF status boards.

Curing the exercise, the Initial Notification Form for the GE ECL

sent to the State-EOC from the EOF at 1340 noted that the l meteorological data was "out of service." (Presumably, this i referred to the out-of-service condition of the primary l meteorological tower.) The form did not indicate the available l meteorological data obtained from the backup meteorological tower. The NRC Inspection Report indicates that, with regard to this issue, the utility intended to revise the notification forms to include backup meteorological data when primary meteorological 5

w. o. ... .

The NRC 1992 onsite Exercise Report tower data is not available. 50-293/92-07), dated July 2, 1992, indicates '

(Docket / Report No."the notification forms had been modified to remove the that specification of provision of primary meteorological tower data and thereby allow secondary tower information reporting when primary tower data is unavailable."

Please note that the Follow-Up Information Form for the General E=argency ECL sent to In theaddit State1~en, ECC please at 1417note did contain that thethe Initial meteorological data.

Notification and Follow-Up Information Forms for the Unnaual Event, Alert and Site Area Emergency ECLe all contained meteorological data.

• Transmission of Meteorological Data from the EOF to the state ECC Asido from the communication of meteorological data over the BECONS via the Initial Notification and Back-Up Information Forms, wind direction affecting PAR development in the State ECC was communicated from the EOF by the transmission of PARS to the State EOC. As noted in the FIMA 1991 Pilgrim Exercise Report, "theState the MEMA/MDPH ECC before EOF thestaff formulated utility their own had generated its PAR PAR."andThe sent it to MEMA/MDPH EOF PAR was a recommendation to evacuate out to two miles in a circle and to five miles in the three from the plant; the MEMA/MDPH EOF staffThe downwind converted this "

sectors keyhole" development of the PAR to specify the affected subareas.

keyhole recommendation indicates thatTherefore, the staffthe at the EOF we

"~~~~ ~ ~~ ' EOF as Mbted in the NRC Inspectich Report) .

transmission of the MEMA/MDPH PAR to the State ECC was also a transmission of information regarding "which way the wind was blowing."

The NRC Inspection Report states, "No record or specific recollection of posting of that information (the backup mecaorological information) on the status boards or of communication of that information to commonwealth responders was provided." Nevertheless, an " area of strength" in the NRC 1991 onsite report notes that " Review of expected PARS and related information with offsite impact was continuously discussed with Overall Massachusetts staff who wara present within the EOF."

analysis of available data supports the position that meteorological data was appropriately communicated to MEMA and MDPH staff at the EOF for PAR development purposes during the December 1991 exercise.

~

6

6p o t: w , s. . .

. Appropriateness of Dr. Ridley Calling the National Weather service to obtain the Meteorological Data Since the utility notification sheet for the GE ECL did not indicate the wind direction (available from the backup meteorological tower), the State EOC did not initially have the current meteorological information. With these circumstances, l Dr. Ridley's calling the National Weather Service appears to have l been an appropriate ad hoc measure to obtain weather information.

However, upon receipt of the MIMA /MDPH EOF PAR, Dr. Parker (and the other members of the PAR decision making team at the state EOC) were aware that they had the information concerning wind direction. Moreover, the wind direction was confirmed when the utility sent its PAR to the EOC since the utility PAR corresponded with the keyhole PAR made earlier by the MEMA/MDPH EOF staff. If there was any confusion as to the source of this information, it would have been appropriate for the State EOC officials to talk to their counterparts at the EOF. ,,

Please note that it was appropriate that the controller gave State EOC officials the appropriate scenario meteorological data ,

after Dr. Ridley had called the National Weather Service since the weather for the exercise had been agreed to in the extent of play agreements and was n21 the actual weather for December 12, 1991. Your reference to a controller providing Dr. Ridley with "the correct PAG [ sic)" during the 1991 exercise is in error.

Comments Concernine Initial Notification to MDPH Aside from issues directly related to PAR development, I would like to address some of your other comments appearing under

" Issue II" of your letnt"tT MF. Willfast. On page seven of your letter, you ask, "What caused the communication failure between i the utility and MDPH and why wasn't there a backup system? (from l

the Exercise Report I have gathered the State Police is the back l up communication and they were delayed 20 minutes in the initial notification of Unusual Event, to MDPH...)"

There are no provisions in the MARERP for direct initial notification from the utility to MDPH. The Massachusetts State Police (MSP) Troop D has primary responsibility for contacting The MSP Troop D Shift MDPH in the event of a Pilgrim emergency.

Commander Procedure effective at the time of the exercise (IP-01S, October 16, 1991, Draft 5) instructs the Shift commander to-notify MDPH in the event of an emergency. Please note that the currently operative Shift commander procedure (AII-ClS, December 1992, Rev. 0) instructs the Shift Commander to notify MDPH through MSP Headquarters.

Please also note that the FEMA 1991 Pilgrim Exercise Report f identifies the delayed notification to MDPH by MSP Troop.D at the I

' Unusual Event ECL as an Area Requiring Corrective Action.

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ca==ents Concernina Timeliness of Pilerim Evarcisa Renort on page riva of your latter to Mr. Williams, you state, "The lack of timeliness in the issuance of the reports is merely one more example of FEMA's ineffectiveness in the Emergency Planning process." During 1992, upon the preference of the Commonwealth of Massachusetts, FEMA gave highest priority to the review of the MARERP for Saabrook in conjunction with the transition in offsite planning and preparedness responsibility at that site. MIMA  :

recommended that FEMA place greater urgency in completing the technical assistance review for the Seabrook plans rather than in finalizing the 1991 Pilgrim exercise report. This is the primary reason that the distribution of the final exercise report did not occur until February 1993. Also, please note that several key FEMA representatives who were involved in the development of the exercise report, were committed to assisting the Agency in its response to Hurricanes Andrew and Iniki during Septamber and ,,

October 1992.

We have not responded to some of your comments and questions that are specific to the NRC. Additionally, in the enclosed copy of the letter dated June 25, 1993, the NRC has asked FEMA to reply directly to you about " State and local axarcise issues within FEMA's purview" addressed in your June 15, 1993, 13ther to James Taylor, NRC Executive Director for Operations. We will reply to any new offsite issues discussed in your June 15, 1993, letter in the near future.

please be assured that FEMA will continue to monitor offsite planning and preparedness activities at Pilgrim, including the replacement of the Wellesley ' reception cantar."-" ~~~~ -- ~ ~ ~

Sincerely,-

R ard W. Krimm

)

Deputy Associate Director State and Local Programs and supper-Enclosures 8

l April 27, 1993 CERTIFIED MAIL Boston Edison Company

" p8anier Viss Presidaat - Nuclear 800 seylston Street Boston, MA 02190 Ra: Notice to Terminate Licensa Agressent for wallasisy Xaintenanos racility Dear sirs This is(MHD)

Departzent to provide notica that the Massachusetts Highway

, forzar1 known as the Massachusatts Departsent ofPublicWorks,isextro{singitsrighttoterminatathelicanso agressant betvaan capital Planning a.5.estgA. 241 son and nd operationi,' _CesI!nny=(51Cci r thedated the Department, Division c!

October 6, 1989, for RE00's use of MMD's maintenanos facility located in Wallesley, Notica is hereby given that BEco's use of said property shall terminata as of Decamber 31, 1993.

The Dapartment recognises BEco's need to use the preparty for its. national readiness test in Decembar and hereby authorissa BEco's use of Wallasley for that purposa. SECC should ba prepare <:

to uma its evn personnai, or all MMC functions and employama v:,:.1 l

have bear,;elocated fr:m Wellesley by Oscomber.

sites The Department for reception Will assist in its efforts to identify new cantars. W6 aise suggest that DICO explors sene of the military facilitias, including the National cuard si,a nearby the maintenanca depot in Walleslay.

Massachusetts Highway Department l By Edward JJ corocran II Its chief Counsel ces otrasser L W , Massasausetts W ^

• taercency

"- '~ Manag_ ament Agency /

a JUN - 8 ;;;j Mr. A. David Rodham Director Massachusetts Emergency Management Agency 400 Worcestar Road P.O. Sox 1496 Framingham, MA 01701-0317 A

Dear ih m wiam:

The Faderal Emergency Management Agency (FEMA) has received a '-

copy of the .enclesed April 27, 1993, latter from Edward J.

Corcoran II, Chief Counsel to the Massachusetts Highway Department (MMD), to the Senior Vice President-Nuclear of the Boston Edisen Company (BEco) informing BEco that "BEco's use of (the MHD maintenanca facility in Wellesley) shall terminate as of December 31, 1993." As you know, the Wellsalay MHD facility currently serves as the raception canter for the communities of Duxbury and Marshfield in the avant of an accident at the Pilgrim Nuclear Power Station and for the communities of Newbury and Newburyport in the event of an accident at the Seabrook Nuclear Power Station. We remain highly concerned with the Massachusetts Emergency Management Agency's (MIMA) efforts to identify a new = ' - ~ ~

reception cantar facility (or facilities)-to replace the factrity-at Wellesley.

We have been aware for some time that MHD was considering selling er leasing its Wallaslay maintenance facility as part of its censolidation and privatization plan. However, the Decerter :*.,

1993, ter=ination of the agreement for the use of the Wallaslay fa:ility dictates that a suitable replacemen: faci'ity f:: tr.a Wellesley recaptien cantar be identified as seen as pessit14.

TEMA understands, threugt. discussiens with your staff, that MIMA is censidering using :W reception cantar facilities--ene f:r the affected Seabrook ccmmunities and another for the affected pilgrim towns--to replace the Wellesley MED maintenance facility.

Changing reception centers will necessitate substantial plan changes to the Massachusatts Radiological Emergency Response ?lan (MARERP) for Pilgrim and Seabrook. For example, plans and precedures, public information materials, amargency broadcas system messages and other documents such as traffic management manuals will have to be amended to address issues concerning the new reception center (s). In additien, a new evacuation time estimate study will have to be conducted for each sita and its findings incorporated ints the MARERP. New staff may have to ha

({ _ . _ - - _ _ _ - _ _ - -_________

o identified, and the staff for the new reception center (s) will ,

have to be trained on the set-up of the facility as vall as on l l

monitoring, decontamination and registration activities.

l Moreover, new congregata care centers and host schools may also have to be identified which would require additional plan and map changes. The revised planning decuments must be submitted to FEMA for review and approval, j l

FEMA raquests MEMA to develop and submit a plan with milestones established for accomplishing the necessary tasks to resolve the issues concerning the withdrawal of the Wellesley reception cantar as an available facility for radiological emergency preparedness purposes.

Given the critical importance of reception cantar functions in j radiological amargency planning and preparedness, unless 1 alternate reception center facilities and trained personnel are l' available at the time the Wellesley facility is no longer-available, including appropriate plan and procedura changes, FEMA.

believes that this could affect the health and safety of. the public residing in the pilgrim emergency planning zone .(EPZ) or the Massachusetts portion of the Seabrook EPZ in the event of a radiological amargancy.

If planning and preparedness issuas concerning the new reception center (s) are resolved by December 1993, FIMA requests that the new Pilgrim reception center be demonstrated as part of the 1993 pilgrim exercise. If outstanding issues remain at the time that axercise is conducted, FIMA would like to see the new reception center demonstrated once those issues have been resolved. If there is a separate reception center facility for Saabrook, we would like to see that facility demonstrated as part of the 1994 Seabrook exercisa. It is no longer useful to demonstrata the Wellesley reception center during the pilgrim 1993 exercise becausa cf the imminant unavailability of the MHD facility.

It should be noted that even at the present time staffing capabilities for the Wellesley facility are cf majer cencarn.

The April 27, 1993, latter from Mr. Cerecran states that, "all MHD fun::1 ns and a=pl yees will have been rel:cated fr:m Wellesley by Decembar," and that ene MHD empicyaas curren:*.y assigned to reception center fune::.:ns will net be availab'.s ::

perform their duties at that time. 1; is FEMA's position that whenever sufficient trained MHC staff fer the Wellesley faci'.ity are no lenger available, alternate trained staff must ce provided. TEMA requesta MIMA to pr: vide a schedule for the withdrawal of MHD persennel from their assigned responsibilities at the Wellesley recepti:n cancer. Staffing r:sters and :: :.n:.ng records for new persennel shculd be submitted :: TIMA to decuren:

the availability of replacement staff for the MHD personnel.

2

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._____-_________________________________________________________________-________D

O e -- avi a.4 4.

rzMA is available at your convenience to discuss issues related to the identification of the new reception center (s) and the necessary plan modifications.  !

l l If you have any questions or concerns please feel free to centact  !

i ma at (202) 646-3692 or Craig Wingo, Assistant Associate Dire ---

cf the Office of Technological Hazards, at (202) 646-3026.  ;

sincerely, i

I Richard W. Kri n Deputy Associate Director .  :

State and Lccal Programs and Support i

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Enclosure ,

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MASSACHUSETTS EMERGENCY MANAGEMENT AGENCY A :wo p::sw use p www A *EW ocve*Noa July 9, 1993 I

Mr. Richard W. Krimm Deputy Associate Director Federal Emergency Management Agency Washington, D.C. 20472 ..

Daar Mr. Krimm:

This is in responsa to your letter dated June 8, 1993 concerning the status cf the Wellesley R6 caption Center.

Please be advised that tha Massachusetts Emergency Managa:ent Agency (MEMA) has initiated a comprehensive program to address both long _nd short-tars issues regarding this site. This basic slamanu of this program have baan discussed many. times with members of the FEMA staff over the past months and they will be provided with a further/ updata at a masting scheduled for July 12, 1993. Whila va appreciate and understand your interest ,in this ...

' '~

issua va f eel- that-my/. vork -plan for accomplishing these tasks is an internal MEMA management, tool and submission of any such documents to FEMA Esadquartars is not nacassary.

We are fully awara that a changa in reception cantars, as vall as interin staffing fer the prenant sita, will nacassitata a nu:dar cf plan modifications. These changes vill ba =ada and the appecpriata supporting documan=atien submitted :: FIMA for review and cc mant.

As va h:ve indicated in travi:us c:rrespendanca if :..e r a v'x

~

air.her plan: todav, the trained staff veu ~.d 'c e incidan: at '

available. ,

If planning and preparadness issues c0ncerning the nov recap:f on center (s) are resc1vad in tima for the Daca bar 1993 Pilgrim Exarcise it will be demonstrated. If not, va are fully committed to a full demonstratien once those issues have baan resolved.

MEMA is fully cognizant of the critical importance of reception cantar functions in the protection of the health and safety and you

?

}(r. Richard W. Krir3 July 9, 1993 l can be assured that we are taking the necessary steps to resolve this natts: in a tinely and efficacicus canner. r i

a Sincarel p ; ',-

/ / I

/

/ l . ~ t-

- Dave Rod..a.5 Direc or

cc

Jack Delan, TEMA Region 1 KRIKI.ADR t

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~~~ ~~.~T.*._~~.'~~*.'.'L'.'.'"..

i 8

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Federal Emergency Managemeu Agency AsgienI J.W. McC0ntsk Post Ofts &

Ccer.ccse BuiM!ng. Roots 42 Bos::m.MA 02109 Novatbar 6, 1992 Mr. A. David Rodhas, Director Massachusetts Z argency Manage = ant Agency 400 Worcentar Road -

P.O. Scx 1496 -

Framingham MA 01701-0317 ,,

Daar M. amt This is to request clarification of the Massachusetts Highway capart= ant (MED) staffing capabilities and ccamitment to the Wallasley Raceptien Cantar in the avant of an a=argency at Pilgri:

. Nuclear power Statien (PNPS) ~or at the Sathrock Nuclear P:Ver Station, after the transition of offsita responsibility from Ncrth

. Atlantic Energy Service Corporation to the Cct=cnvaalth of Massachusetta has baan completed. This issue was inferr. ally

discussed with Mr. Michaal Philbin of your staff at an October i 14,1992, saating held at MEMA's Araa I facility in Tavksbury. TIMA is awara of 'and appreciataa the affert that MZMA has =ada te fellev "- --

the issues concerning tha potential lease or sala cf the MED Wallasley maintananca facility.

TIMA has received a ccpy of a September 23, '993 lattar frc: ths MHD Deputy commissionar and Chief Ccussal, Mr. patrick J. Meynihan, ec the Dux-W Tcvn Managar, .'tr. Thor.as Orcux. In that lottar, Mr.

Moynihan confir:s MED's c ~ it= ant .c public safa:y and planning MHO would nc-with closeragard te an amarI.ancy its Wallasley at PFPS s a "w"-~ and asserts

- -aking plans tna

ra;11:a:3 :.:s tunction in another iacility. "

FEXA has also received a copy of your Septstbar 15, 1992, *. attar ::

MHD Cctaissionar James Kara.sistas in which ycu requestad a prepcsad clesing data for Wallaslay, a proposed data that the preparty will ha offered for sala er lease and a list of other MHD tacilitias Whala wa ara that nay be avalla.ble for usa as a recaption cantar.

unawara of any raspense frcm MHD, to our Knowledge, existing corraspendanca dcas not address the issue of MHD staffing at the Wallasley Reception canter or at an alternata sita, the Wallasley plan and proceduras call for HED staff to sat up the facility.

FINA is uncertain as to the availability of the designated MHD ctaff to parform their rolas if they ara transfarred out of the Wallasley facility.

__l

.g,

/,t the October 14, 1992, Saabrock transition testinU, Mr. Philbin of your staff infor:ad us that it was his understand;,ng that staff l recently transferrad from Wellesley vara ngt the MHD staff trained to respond to a Pilgrim (or Saabrcck) amargency. They ware, rather, empicyaas ta:porarily assignad to the Wallasley facility as a result of other MHD censolidation efforts. FDA vould apprac.ata ,

a written confirmation of the status of the staff trained to l respond to a radiological amargancy.

FD!A strongly encourages you to investigata othar facilities in  ;

addition to those belonging to MED for use as substitute receptien canter facilities when Wallasley becomes unavailable. From experience, va kncv that it =ay be difficult to identify and establish an alternata f acility to function as a raception cantar.-

While a sale or lease of the Wallsalay facility nay net .be 1 .minant, prudent planning suggests that altarnata sit.as ha

~~ ~ ' ~ ' - - ~ ~ --"-

investigated as soon as possible. -

rzxA locks forward to continuing our work tegather in addressing the commonwealth's effsita amargency preparadness cencarns. If ycu have any 7:sstion regarding this request, pisasa contact Mr. Joseph Austin of =y staff at (617) 223-9578.

$1ncaraly,

+

J n C.  ! clan, dhist , , , _ , , _ , _ _ _ _ _ , . _ _ . . . . . ..

.achnological Hazards Eranch cc: Craig Gorden,1GC, Ragion :

Margara: I.awlass, FDu Handraartsrs

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.musw A 1fa of.Lngwdaan.andL$, $1VED fWhtY0 h& Opks, wtuAu r WELO h' lbe Yomnuhdavtw NY!?

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vstem omemon RICHAsto L, TAyt,on (81D D 7000 KemAM JAMES J KEftA3lo7CS CDhM t pC747 september 28, 199:

1

. 1 Mr. Thomas J. Groux Duxbury Town Manager 078 Tremont Street Duxbury, MA 02332

Dear Mr. Groux:

This is a response to your September 14, 1992 letter to commissioner Department's Marasiotes regarding b oer concerns with the Highwe y possible plans to noli or lease its Wellesley maintenance facility.

- --- Tht r atjerfcy ~is Well aware of the~ miscion the Wellesley facility will play in the event of an emergency at the Pilgrim Powcr plant.

Your assertion that this agency would cloco the site without makin:

plans to replicate its function in anothar f acility is untcunded and with=ut merit. ?!

• Highway Ccpartment has a proven track rec rd l

of public safety str. ice and planning.

Itere are additiona: incts ycu should be aware Of; the Commonwealth's pr=perty dispesal pr cess is lengthy and exhaustive, a minimum cf cne yeart the prasent laase for the Ecergency operation Center is a tenancy at will, as agreed to ':y both the Massachusetts Highway Copartment and Boston Edison; at the time of the agreement all parties vers informed that the Commonwealth may sell er j laawu this facility sometime in the futura.

l

Mr..Thoma September 28, 1s93 Fligo 2 I hope this letter clarifies the issues raised in your youswannen, W. have additional questions please fell free to contact Miew.

Chief Engincor, at (617) 973-7830.

\ Sincerely, w

Patrick Moyn nan Deputy Commissioner and Chief Counsel .

1

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MASSACHUSETTS EMERGENCY MANAGEMENT AGEN '

wittidu eLo A oAvi moyau July 20, 1993 Mr. John C. Dolan RAC Chairman and' Chief, Technological Mazards Branch Federal Emergency Management Agency - Region I John W. McCormack Post Office and Courthouse Boston, Massachusetts 02109-4595

Dear Mr. Dolan,

This latter is to inform you that during the week of July 14, 1993, two shif ts of personnel for the Wellesley Reception Centar received training on response to an emergency at the Pilgrim or Seabrook nuclear power plants. Prior to conducting this training the capability did exist to fully statf the Reception Center at Wellesley.

t In keeping with the commitment to maintain preparedness at all times, we are currently considering enlisting the service of the State Guard to further support reception center operations.

If you require any-other- information,..pLease. contact _me at, J50,8[ ,, .,

820-2040.

m Since .

~ .. . ..,,X m' lDoug?:::as Direcc:r cf Planning Massachusetts Emergency Ma agement Agency cc: Margaret Lawless, FEMA 40c Worcester Roac e P.O. Box 149e

• Frart. .gham, MA 017010317

• 508-82o-2000

• Fax 508 820-20JC ,

i

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