ML080300114

NRC Staff Initial Statement of Position on Contention 1

ML080300114
Person / Time
Site:	Pilgrim
Issue date:	01/29/2008
From:	Sexton K NRC/OGC
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
50-293-LR, ASLBP 06-848-02-LR, RAS 14987
Download: ML080300114 (175)

Text

January 29, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

NRC STAFF INITIAL STATEMENT OF POSITION ON CONTENTION 1 INTRODUCTION Pursuant to 10 C.F.R. §§ 2.1207(a)(1) and 2.337(g)(2) and the Atomic Safety and Licensing Board Panels (Board) December 19, 2007 Order,1 the Staff of the U.S. Nuclear Regulatory Commission (Staff) submits its initial written statement of position and written testimony with supporting affidavits on Pilgrim Watchs admitted contention. Appended to this filing is the Staff testimony and certifications of Dr. James A. Davis, Terence L. Chan, and Andrea T. Keim concerning Contention 1 and Staffs Exhibits 1 through 20. For the reasons set forth below and in the testimony filed herewith, the Staff submits that a careful evaluation of Pilgrim Watchs Contention 1 demonstrates that Pilgrim Watchs challenge to the Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (collectively, Entergy) application for renewal of the Pilgrim operating license cannot be sustained.

1 Order (Revising Schedule for Evidentiary Hearing and Responding to Pilgrim Watchs December 14 and 15 Motions), (Dec. 19, 2007) (unpublished) (Scheduling Order).

BACKGROUND This matter arises from an application, filed by Entergy on January 25, 2006, to renew the operating license for the Pilgrim Nuclear Power Station (Pilgrim) for an additional twenty-year period following the June 8, 2012 expiration date.2 On May 25, 2006, Pilgrim Watch filed a petition to intervene in this matter.3 Pilgrim Watch submitted five contentions for consideration by the Board. On October 16, 2006, the Board admitted two of those contentions.4 As admitted, Pilgrim Watch Contention 1 reads:

The Aging Management program proposed in the Pilgrim Application for license renewal is inadequate with regard to aging management of buried pipes and tanks that contain radioactively contaminated water, because it does not provide for monitoring wells that would detect leakage.5 On June 8, 2007, Entergy filed a summary disposition motion asserting that, as to the issues raised in Contention 1, there were no material facts in issue and, thus, Entergy was entitled to a decision as a matter of law.6 The Staff filed a response supporting the motion and Pilgrim Watch opposed the motion.7 On October 17, 2007, the Board issued a Memorandum and Order denying Entergys motion.8 It found a genuine dispute regarding:

(continued...)

2 See Letter from Michael Balduzzi, Entergy Nuclear Operations, to U.S. NRC, Re: License Renewal Application, (January 25, 2006) (Agencywide Documents and Access Management System (ADAMS) Accession No. ML060300028).

3 Request for Hearing and Petition to Intervene by Pilgrim Watch (May 25, 2006).

4 Entergy Nuclear Generation Co. and Entergy Nuclear Operations Inc. (Pilgrim Nuclear Power Station), LBP-06-23, 64 NRC 257 (2006) (Memorandum and Order on Contentions). The second admitted contention, Contention 3, was disposed of by summary disposition granted on October 30, 2007. See Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), LBP-07-13, 66 NRC __ (Oct. 30, 2007) (slip op.).

5 Memorandum and Order on Contentions at 315.

6 Entergys Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 8, 2007).

7 NRC Staff Response to Entergys Motion for Summary Disposition of Pilgrim Watch Contention whether those Pilgrim aging management programs, or AMPs, that relate to relevant buried pipes and tanks are adequate on their own, without need of any leak detection devices (Intervenors propose monitoring wells), to assure that the pipes and tanks in question will perform their intended functions and thereby protect public health and safety.9 To clarify for all parties involved, the Board refined the issue by stating that:

the only issue remaining... is whether or not monitoring wells are necessary to assure that the buried pipes and tanks at issue will continue to perform their safety function during the license renewal period or, put another way, whether Pilgrims existing AMPs have elements that provide appropriate assurance as required under relevant NRC regulations that the buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions.10 On October 29, 2007, Entergy filed a motion for reconsideration of the Boards denial of summary disposition of Contention 1.11 The Board denied Entergys Reconsideration Motion, finding that a genuine dispute continued to exist with respect to whether Entergy's aging management program has leak detection provisions sufficient to prevent the subject buried pipes and tanks from failing to satisfy their intended safety function.12

(...continued) 1 (June 28, 2007); Pilgrim Watchs Answer Opposing Entergys Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 27, 2007).

8 Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (Pilgrim Nuclear Power Station), LBP-07-12, 66 NRC ___ (Oct. 17, 2007) (slip op.) (Summary Disposition Order).

9 Id. at 16.

10 Id. at 18.

11 Entergys Motion for Reconsideration of LBP-07-12 (Oct. 29, 2007) (Reconsideration Motion).

12 Memorandum and Order (Ruling on Entergys Motion for Reconsideration of [LBP]-07-12)

(Nov. 14, 2007) (unpublished) at 4.

On December 19, 2007, the Board issued an order revising the schedule for the evidentiary hearing.13 Within that Scheduling Order, the Board again attempted to clarify the scope of the proceeding, stating:

Ongoing monitoring is not within the scope of this proceeding; only challenges to errors or omissions from the Applicants Aging Management Program (AMP) are properly within the scope. The single admitted contention relates to whether or not Applicants AMPs are sufficient to enable it to determine whether or not certain buried pipes and tanks are leaking at such great rates that they cannot satisfy their respective intended safety functions.

Therefore, unless and until the Applicant expressly advises this Board and the Agency that it intends to rely upon monitoring wells for making its determination that buried pipes and tanks are not leaking at such great rates that they cannot satisfy their intended safety functions, information related to monitoring wells is irrelevant to the issues at hand before this Board.

Further, the Board detailed exactly what information each party is to submit in their prefiled direct testimony. Entergy was to:

pipe-by-pipe and tank-by-tank: (a) clearly identify each buried pipe and tank which may potentially contain radioactive fluids; (b) identify the intended safety function of such pipe or tank; (c) specify the procedures by which Entergy will determine, during the license extension period, whether there are leaks present which might endanger the ability of that pipe or tank to meet its intended safety function, whether or not such procedures are part of routine maintenance and operation or part of the aging management program.14 The Staff and Pilgrim Watch were to respond with the same requested information and provide any other specifically relevant information.15 13 Scheduling Order at 1-2.

14 Id. at 2-3.

15 Id. at 3.

In response to the Scheduling Order, on December 21, 2007, Pilgrim Watch filed a motion for clarification seeking guidance on two issues: (1) What buried pipes and tanks are now under consideration and (2) What materials must be provided by Entergy by January 8, 2008.16 The Board denied the Clarification Motion.17 In another response to the Scheduling Order, on December 28, 2007, Pilgrim Watch filed a motion for reconsideration of the Scheduling Order based chiefly upon the dissenting opinion provided by Judge Ann Marshall Young.18 The Board denied this motion as well, and again made clear that the only issue remaining before the Board is that:

either the application omits to describe the programs and procedures by which it will determine whether or not buried pipes and tanks containing radioactive fluids are leaking at such great rates that they cannot satisfy their respective designated safety functions, or that there are no such programs.19 For the reasons set forth below, the contention lacks merit.

DISCUSSION I.

Legal and Regulatory Requirements The scope of license renewal proceedings is limited. The Commissions [l]icense renewal reviews are not intended to duplicate the Commissions ongoing review of operating reactors. Florida Power & Light Co. (Turkey Point Nuclear Generating Plant, Units 3 & 4), CLI-01-17, 54 NRC 3, 7 (2001) (citing Final Rule, Nuclear Power Plant License Renewal, 56 Fed.

Reg. 64,943, 64,946 (Dec. 13, 1991)). Therefore, the license renewal safety review process focuses on the potential detrimental effects of aging that are not routinely addressed by 16 Pilgrim Watch Motion for Clarification (Dec. 21, 2007) at 2 (Clarification Motion).

17 Order (Denying Pilgrim Watchs Motion for Clarification) (Jan. 11, 2008) (unpublished).

18 Order (Denying Pilgrim Watchs Motion for Reconsideration) (Jan. 11, 2008) (unpublished).

19 Id. at 8.

ongoing regulatory oversight programs. Id. Consequently, 10 C.F.R. Part 54 requires renewal applicants to demonstrate how their programs will be effective in managing the effects of aging during the period of extended operation. Id. at 8 (citing 10 C.F.R. § 54.21(a)). Applicants are required to identify any additional actions, i.e., maintenance, replacement of parts, etc., that will need to be taken to manage adequately the detrimental effects of aging. Id. (citing Final Rule, Nuclear Power Plant License Renewal; Revisions, 60 Fed. Reg. 22,461, 22,463 (May 8, 1995)). The Commission has recognized that these [a]dverse aging effects generally are gradual and thus can be detected by programs that ensure sufficient inspections and testing.

Id. (citing 60 Fed. Reg. at 22,475). License renewal proceedings are limited to a review of the plant structures and components that will require an aging management review for the period of extended operation and the plants systems, structures, and components that are subject to an evaluation of time-limited aging analyses. Duke Energy Corp. (McGuire Nuclear Station, Units 1 and 2; Catawba Nuclear Station, Units 1 and 2), CLI-01-20, 54 NRC 211, 212 (2001) (citing 10 C.F.R. §§ 54.21(a) and (c), 54.4; 60 Fed. Reg. 22,461).

Pilgrim Watchs Contention 1, as clarified, asks whether or not monitoring wells are necessary to assure that the buried pipes and tanks at issue will continue to perform their safety function during the license renewal period or, put another way, whether Pilgrims existing AMPs have elements that provide appropriate assurance as required under relevant NRC regulations that the buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions.20 The adequacy of the Staffs review of Entergys application is not at issue; instead, the sole focus of the hearing is on whether the application satisfies NRC regulatory requirements. Final 20 Summary Disposition Order at 18.

Rule, Rules of Practice for Domestic Licensing Proceedings-Procedural Changes in the Hearing Process, 54 Fed Reg. 33,168, 33,171 (Aug. 11, 1989) (citing Pacific Gas and Electric Co. (Diablo Canyon Nuclear Power Plant, Units 1 and 2), ALAB-728, 17 NRC 777, 807, review declined, CLI-83-82, 18 NRC 1309, 1983)). The overall burden is on Entergy to demonstrate that its AMPs for the buried pipes and tanks systems within the scope of license renewal are adequate to manage the aging effects so that their intended safety function will be maintained during the period of extended operations. See 10 C.F.R. § 2.325. Pilgrim Watch, however, must come forward with evidence supporting its claim that Entergys AMPs are inadequate. Louisiana Power & Light Co. (Waterford Steam Electric Station, Unit 3), ALAB-732, 17 NRC 1076, 1093 (1983).

Although a plants current licensing basis (CLB)21 will be reviewed during the course of license renewal, the Commission has determined that intervenors may not challenge the CLB because such issues: (1) are not germane to aging management concerns; (2) previously have been the subject of thorough review and analysis; and, accordingly (3) need not be revisited in a license renewal proceeding. AmerGen Energy Co. (Oyster Creek Nuclear Generating Station),

LBP-07-17, 66 NRC __ (Dec. 18, 2007) (slip op. at 14, n.17); see also Turkey Point, CLI-01-17, 54 NRC at 10 (Issues... which already are the focus of ongoing regulatory processes - do not come within the NRC's safety review at the license renewal stage.). Further, a finding of compliance of a plant with its [CLB] is not required for issuance of a renewed license. 56 Fed.

Reg. at 64,951. Therefore, the CLB is only reviewed to determine whether there is reasonable 21 The CLB consists of the NRC regulations contained in 10 C.F.R. parts 2, 19, 20, 21, 26, 30, 40, 50, 51, 52, 54, 55, 70, 72, 73, 100 and appendices thereto; orders; license conditions; exemptions; and technical specifications [plus]... the plant-specific design-basis information [contained]... in the most recent final safety analysis report (FSAR)... and the licensee's commitments... [made through]

responses to NRC bulletins, generic letters, and enforcement actions, as well as licensee commitments documented in NRC safety evaluations or licensee event reports. 10 C.F.R. § 54.3.

assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB.22 See 10 C.F.R. § 54.29(a).

The Commissions requirements regarding the adequacy of Pilgrims program to monitor the condition of the buried pipes during the license renewal period are described in the testimony filed herewith. Specifically, as set forth in the Staffs NUREG-1891, Safety Evaluation Report Related to the License Renewal of Pilgrim Nuclear Power Station (Sept.

2007, Published Nov. 2007) (SER), the applicable legal standard for the Staffs approval of Pilgrims program is whether Entergy has demonstrated that the effects of aging [of Pilgrims buried pipe and tank systems] will be adequately managed so that the intended function(s) [i.e.,

delivering water23] will be maintained consistent with the CLB for the period of extended operation. 10 C.F.R. § 54.21(a)(3). One way for a licensee to make the demonstration required by § 54.21(a)(3), is to commit to following the guidance provided by the GALL Report.

Exhibit 20, SER ¶ 3.0.2 at 3-4. Entergy claimed that its four AMPs for managing the effects of aging of the two in-scope piping systems are consistent, with at most two exceptions for each, with applicable provisions of GALL. See id., SER Table 3.0.3-1 at 3-8 to 3-9. Therefore, the Staff reviewed Pilgrims program to determine consistency with GALL and, in addition, reviewed each exception to determine whether it was acceptable and whether the program, as modified, would adequately manage the effect for which it was credited. See id., SER ¶¶ 3.0.2, 3.0.2.1 at 3-4 to 3-5.

22 As such, while this Statement of Position will be addressing inspections and tests, and operational and maintenance activities performed under Pilgrims current license, it is not because the Staff believes such inspections, tests and activities are required as a part of an aging management review. Instead, they will be discussed as context to show Pilgrims current monitoring systems and also to demonstrate the consistency of Pilgrims AMPs with the CLB.

23 Memorandum and Order (Ruling on Entergys Motion for Reconsideration of [LPP]-07-12)

(Nov. 14, 2007) (unpublished) at 4, quoting Entergys Motion for Reconsideration of LPB-07-12 [sic] (Oct.

29, 2007) at 6.

II.

Staffs Witnesses The attached testimony presents the opinions of a panel of three highly qualified witnesses as follows: 1) Dr. James A. Davis, a Senior Materials Engineer in the Division of License Renewal, Office of Nuclear Reactor Regulation (NRR), Davis at A1; 2) Terence L.

Chan, the Chief of the Piping and NDE Branch in the NRR Division of Component Integrity, Chan and Keim at A1a; and 3) Andrea T. Keim, a Materials Engineer in the NRR Division of Component Integrity, id. at A1b.

Dr. Davis, a metallurgical engineer, with a Doctorate in metallurgical engineering, was the audit team leader of the license renewal safety audit team at Pilgrim. Davis at A3-4. As the audit team leader, Dr. Davis led three safety audits with a team of four NRC staff members, three contractors, two NRC trainees, and one foreign assignee. Id. at A4. Dr. Davis reviewed portions of Entergys LRA, including AMPs, and ensured that the remaining AMPs were adequately reviewed. Id. Prior to becoming a safety audit team leader, Dr. Davis was responsible for conducting reviews of coating issues, corrosion of metals, service water issues, threaded fasteners, and license renewal. Id. at A2. Dr. Davis has worked on coating and corrosion control since 1968, and has worked on coatings issues at nuclear facilities for the past seventeen years at the NRC. Id. Dr. Davis testimony addresses the adequacy of the AMPs in place at Pilgrim to manage the effects of aging during the period of extended operation such that there is reasonable assurance that the buried piping that contains or could contain radioactive liquids will be able to perform their intended function in accordance with CLB. Id. at A6.

Mr. Chan, the Branch Chief for Piping and Nondestructive Examination (NDE),

manages and provides technical review to eight engineers involved in the evaluation of generic and plant-specific materials degradation and NDE issues, American Society of Mechanical Engineers (ASME) Code and standards activities, and inservice inspection (ISI) activities.

Chan and Keim at A1a, A2a. Mr. Chan represents the NRC on four groups within the ASME that address materials degradation or inspection issues: Task Group on Alloy 600, Task Group on Alternate NDE, Working Group on General Requirements, and Subgroup on NDE. Id. at A2a. Mr. Chans testimony will address the inspections and tests required to be performed under Entergys current license for routine maintenance and operation of those buried pipes that are within the scope of the contention. Id. at A5.

Ms. Keim, a materials engineer, performs safety reviews of nuclear power plant piping and NDEs of operating nuclear power plants, license renewal applications, and new reactor design certifications. Id. at A1b, A2b. Ms. Keim is further responsible for conducting reviews of corrosion of metals, NDEs, risk-informed ISI programs and repair/replacement activities. Id. at A2b. Ms. Keim represents the NRC at ASME Section XI Code on the working group on Implementation of Risk Based Examinations. Id. Ms. Keims testimony will address the inspections and tests required to be performed under Entergys current license for routine maintenance and operation of those buried pipes that are within the scope of the contention. Id.

at A5.

III.

The Concerns Raised by the Contention Lack Merit The Staffs testimony presents its position that the concerns raised by Pilgrim Watchs contention, as refined by the Board, lack merit because the AMPs alone are sufficient to manage aging such that there is reasonable assurance that the buried pipes containing, or potentially containing, radioactive liquid at Pilgrim will maintain their intended functions for the period of extended operation and will not develop leaks large enough to prevent the pipes from fulfilling their intended function. In addition, the inspections and tests performed as routine maintenance and operation provide reasonable assurance that significant leaks in the in-scope buried pipes will be detected before affecting their ability to perform their intended function.

Therefore, it is not necessary to have leak detection devices or additional programs installed or in place to detect leakage in these piping systems. The bases for this position are described in detail in the testimony.

A.

Buried Pipes and Tanks in Scope for Contention 1 When the Board admitted Contention 1, it limited the contentions scope to those underground pipes and tanks that do fall within those described in 10 C.F.R. Part 54.24 Pilgrim Watchs Contention 1 addresses only those buried pipes and tanks within the scope of license renewal that contain radioactive liquid... BOTH by design and not by design.25 There are six buried piping systems in scope for license renewal: the condensate storage (CS) system, salt service water (SSW) system, the standby gas service system, the fuel oil system, the station blackout diesel generator system, and the fire protection system. Davis at A7. There is only one buried tank within the scope of license renewalthe fuel oil diesel tankand it does not contain any radioactive liquid. Id.

Of those buried pipes within the scope of license renewal, only one piping system, the CS system, contains radioactive water by design. Id. There is a small possibility that one other system, the SSW system, which contains non-radioactive cooling water, could become cross contaminated. Id. Neither of these systems contains buried tanks. Thus, there are no buried tanks that contain, or could contain, radioactive liquid. Id. Therefore, for purposes of Contention 1, the only systems that need to be addressed are the CS and SSW piping systems.

B.

GALL Report In September 2005, the NRC issued the GALL Report, which created a series of general AMPs the Staff determined are adequate to manage the aging effects of particular systems, 24 Memorandum and Order on Contentions at 66.

25 Pilgrim Watch Answer Opposing Entergys Motion for Summary Disposition of Pilgrim Watch Contention 1 (June 27, 2007) at 9.

structures and components that are subject to aging management reviews (AMR). Applicants may reference the GALL Report in their LRA, thus committing to the use of the generic AMP.

Pilgrims AMPs for their in-scope piping systems are consistent with the GALL Report, with minor exceptions. The Board was clear that compliance with the GALL Report was insufficient, for the purposes of contention admissibility considerations, to overcome [] factual challenges; however, the Board stated that it would re-consider that argument on the merits at the appropriate stage of the proceeding.26 C.

Condensate Storage System

1.

Intended Safety Function The CS system does not provide a credited safety function. Chan and Keim at A7. It does, however, provide the preferred supply of water to the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems. Id.

2.

Routine Maintenance and Operation There are no NRC regulations for routine maintenance and operation examinations pertaining to the CS system buried pipes, because although the CS tanks and associated piping provide the preferred water supply to the HPCI and RCIC systems, the CS system is not relied upon for accident mitigation. Id. at A8. However, there are tests and surveillances that would detect leaks in the buried pipes. Id. at A9-A10. Testing requirements for the HPCI and RCIC systems would detect leaks in the CS system. Id. at A9. These are required by the inservice testing (IST) program, under 10 C.F.R. § 50.55a(f) and the technical specifications (TS). Id.

Both the HPCI and RCIC systems are tested quarterly to verify flow rate and pump operability.

Id. The test is performed by creating a flow path with suction from and discharge to the CS 26 Memorandum and Order on Contentions at 63, n.255.

system tank. Id. The flow path uses the CS system buried pipes. Id. If there was a leak large enough to prevent water from being delivered to the pumps, the test would fail and the pumps would be declared inoperable. Id. This testing would allow the licensee to identify a leakage problem in the buried piping of the CS system. Id.

3.

Aging Management Plans The GALL Report AMP for the external surface of the CS system, XI.M34, Buried Piping and Tanks Inspection, calls for an inspection for corrosion during maintenance that uncovers the piping, at least one inspection in the 10 years prior to the period of extended operation, and at least one more inspection in the first 10 years of the period of extended operation. Davis at A9. However, the CS system at Pilgrim contains buried stainless steel piping, which is not subject to external corrosion. Id. at A13. Even though corrosion is not expected, Pilgrims AMP for external corrosion management (B.1.2. Buried Pipes and Tanks Inspection Program) nevertheless still complies with the GALL Reports inspection procedures. Id.

To minimize internal corrosion and stress corrosion cracking, Pilgrims AMP (B.1.32.2 Water Chemistry Control - BWR Program), which is consistent with the GALL Report AMP (XI.Ms, Water Chemistry), optimizes the contaminate levels in the reactor coolant system by using hydrogen water chemistry to reduce the level of dissolved oxygen in the treated water and introduces noble metal additions to the primary water. Id. The effectiveness of the AMP will be verified by conducting a one-time inspection of the CS system prior to the period of extended operation, which will confirm that unacceptable cracking, loss of material, and fouling has not occurred. Id.

Operating history for the CS system confirms that Pilgrims AMP for internal corrosion is effectively managing aging, above what the GALL Report guidelines suggest. Pilgrim proactively set its administrative limits more conservatively than the industry guidelines stated in the EPRI Report so that detection would occur, and corrective actions would be taken, prior to exceeding EPRI acceptance limits. Id. at A14. Between 1998 and 2004, several condition reports were issued for adverse trends in parameters regarding internal corrosion; however, the monitoring called for in the Water Chemistry Control - BWR Program caught the trends early and the staff was able to return the parameters to within administrative limits prior to meeting the industry limits. Id. Further, the Pilgrim staff in 2006 created a program basis document for review by the safety audit team that evidenced continuous monitoring of water quality and demonstrated how corrective actions would be taken before parameters reach control limits. Id.

D.

Salt Service Water System

1.

Intended Safety Function The SSW system provides a heat sink for the reactor building closed cooling water (RBCCW) system under transient and accident conditions. Chan and Keim at A11. Pilgrim provides assurance that the SSW will continue to perform its intended safety functions because it is designed (1) with sufficient redundancy so that no single active component failure can prevent the system from achieving its safety objective; and (2) to continuously provide a supply of cooling water to the secondary side of the RBCCW heat exchangers adequate for the requirements of the RBCCW under transient and accident conditions. Id. at A15.

2.

Routine Maintenance and Operation There are a number of NRC regulations that address the safety of the SSW buried piping. For instance, Generic Letter 89-13 Service Water System Problems Affecting Safety-Related Equipment, reiterates that nuclear power plant licensees and applicants are required to meet the minimum requirements for quality assurance in 10 C.F.R. Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants. Id. at A12.

Pilgrims FSAR demonstrates their requisite test program as required by Appendix B,Section XI, Test Control. Id. at A12-13.

Applicable NRC regulations also require inspections and examinations. 10 C.F.R. § 50.55a(g) requires plants whose construction permit was issued before January 1, 1971, such as Pilgrims, to implement an ISI program that meets 10 C.F.R. §§ 50.55a,(g)(4)-(5) to the extent practical. Id. at A14a. Entergy submitted its fourth 10-year ISI interval27 program plan for Pilgrim on June 29, 2005. Id. The ISI program plan was developed in accordance with the requirements of the 1998 Edition of the ASME Boiler and Pressure Vessel Code,Section XI, through the 2000 Addenda (ASME Code), except where specific alternatives to these requirements have been authorized by the NRC. Id. The SSW system is included in Pilgrims ISI program plan and will be examined and pressure tested in accordance with the requirements of the ASME Code to provide reasonable assurance of structural integrity and that significant degradation will be identified in a timely manner such that safety related systems will be able to perform their safety function. Id.

Pilgrims ISI program plan referred to routine inspection, maintenance, and test requirements for the SSW system piping and heat exchanger inspections, along with the associated acceptance criteria for compliance with GL 89-13. Id. at A14b. These inspections are in addition to the ASME Code ISI inspections. Id. In the NRCs Annual Assessment Letter for Pilgrim from March 2, 2007, the regional inspector verified the heat sink performance and found nothing of significance. Id. The verifying of the heat sink performance provides assurance that the heat sink is capable of meeting its safety function. Id.

3.

Aging Management Plans The GALL Report has two AMPs for the SSW system: XI.M34, Buried Piping and Tanks Inspection (BPTI) and XI.M20, Open-Cycle Cooling Water System. Davis at A9. The BPTI 27 The fourth 10-year ISI interval runs from July 1, 2005 until June 30, 2015.

AMP calls for using preventive measures, such as the use of protective coatings, combined with the periodic inspections28 to determine if corrosion is occurring that could affect the pressure-retaining capacity of the buried steel piping and tanks. Id. The Open-Cycle Cooling Water System AMP calls for testing and inspections to be conducted annually and during refueling outages to manage aging effects caused by biofouling, corrosion, erosion, internal coating failures, and silting in the open-cycle cooling water or service water system. Id. at A9-10.

Entergys LRA contains two AMPs, which are consistent with the GALL Report AMPs with minor exceptions, to manage the effects of aging in the SSW system. Id. at A10. The first AMP is the Buried Piping and Tanks Inspection Program, which is consistent with the GALL AMP XI.M34, Buried Piping and Tanks Inspection with one exception: For cases of excavation solely for the purpose of inspection - methods such as phased array ultrasonic testing (UT) may be used to determine wall thickness without excavation. Id. Phased array UT uses an array of ultrasonic probes that send ultrasonic waves into the pipe at different angles to determine wall thickness, the presence of cracks, and the presence of geometric discontinuities such as laps or delaminations, which can be performed from the inside of the piping. Id. The Staff found this exception to be acceptable because it provided a superior method of examination than that called for in the GALL Report: it adequately searches for indications of pipe degradation yet eliminates the possibility of excavation damage to the coating during the inspection. Id.

The second AMP is the Service Water Integrity Program, which is consistent with the GALL AMP XI.M20, Open-Cycle Cooling Water System, with two exceptions. Davis at A10.

28 Inspections will occur each time the piping is uncovered for maintenance plus at least one inspection of the coating within 10 years of the beginning of the period of extended operation and at least one inspection during the first 10 year period of extended operation. Davis at A9.

The first exception is that GALL states that systems and components are lined or coated to protect the underlying metal surfaces from being exposed to aggressive cooling water environments. Id. However, at Pilgrim, components are only lined or coated where it is necessary to protect the underlying metal surfaces. Id. The SSW supply piping and other components that are not lined or coated are constructed using either titanium or copper alloys that are corrosion resistant in the seawater environment found in the SSW at Pilgrim. Id.

Therefore, because it is not necessary to protect the titanium or copper alloys from the cooling water environment, the Staff found this exception to be acceptable. Id.

The second exception is that GALL states that the testing and inspections are performed annually, and also during the refueling outages that occur every two-years. Id. The Pilgrim AMP only requires testing and inspections during each refueling outage. Id. However, the Staff has found that adverse conditions caused by aging effects in the SSW system develop over a period of several years, and that the difference between a one-year and a two-year interval for testing and inspection is insignificant. Id.

Operating history for the SSW system confirms that Pilgrim is effectively managing aging, above what the GALL Report guidelines suggest. Although certain portions of the SSW piping system have experienced leaks, internal corrosion, or both, it was due to a failure of the rubber lining caused by contact with seawater. Id. at A11. The affected pipes have since been replaced with either titanium or carbon steel, and the entire length of both SSW discharge loops were internally lined with cured in place linings. Id. The Staff has found that the replacement piping and coatings are far superior to the original materials and are not expected to be affected by the contact with seawater during the period of extended operation. Id.

E.

NRC Treatment of Unexpected Leakage from Condensate Storage and Salt Service Water Systems Should any unexpected leakage occur from either the CW or SSW systems, they are treated as current operating issues. Chan and Keim at A17. Industry experience has shown that operational leakage does occur from typical service water systems as a result of corrosion due to the nature of service water environments. Id. Any such leakage is a nonconformance to the expected operating condition of the CS and SSW systems and are treated by NRC regulations contained in GL 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability, as revised by NRC Regulatory Issue Summary (RIS) 2005-20, Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability. Id. Further, Appendix C, Article C.12, Operational Leakage from Code Class 1, 2, and 3 Components, to NRC Inspection Manual Part 9900, attachment to the RIS, provides guidance for evaluating the structural integrity of the leaking component to perform its safety function and identifies actions which may be taken to determine the operability of the component. Id.

CONCLUSION For the reasons discussed above, the AMPs alone are sufficient to manage aging of the buried pipes in the CS and SSW systems such that there is reasonable assurance that the buried pipes containing, or potentially containing, radioactive liquid at Pilgrim will maintain their intended functions for the period of extended operation and will not develop leaks large enough to prevent the pipes from fulfilling their intended purpose. In addition, the inspections and tests performed as routine maintenance and operation provide reasonable assurance that significant leaks in the in-scope buried pipes will be detected before affecting their ability to perform their intended function. Therefore, it is not necessary to have leak detection devices or additional programs installed or in place to detect leakage in these piping systems.

Respectfully submitted,

/RA/

Kimberly A. Sexton Counsel for NRC Staff Dated at Rockville, Maryland this 29th day of January, 2008

January 29, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

NRC STAFF TESTIMONY OF DR. JAMES A. DAVIS CONCERNING PILGRIM WATCH CONTENTION 1 Q1.

Please state your name, occupation, and by whom you are employed.

A1.

My name is James A. Davis. I am a Senior Materials Engineer in the Division of License Renewal, Office of Nuclear Reactor Regulation (NRR), U.S. Nuclear Regulatory Commission (NRC). A statement of my professional qualifications is attached hereto.

Q2.

Please describe your responsibilities as a Senior Materials Engineer in the Division of License Renewal.

A2.

Since November 2005, I have served as an audit team leader and as an audit team member for license renewal safety audits. Prior to joining the Division of License Renewal, I was the lead researcher on steam generator issues in the Materials Engineering Branch of the Office Nuclear Regulatory Research and a technical reviewer in the Materials and Chemical Engineering Branch of NRR, Division of Engineering. In those positions I was responsible for conducting reviews of coating issues, corrosion of metals, service water issues, threaded fasteners, and license renewal. I have worked on coatings and corrosion control since 1968 and have worked on coating issues in nuclear facilities for the past seventeen years at the NRC.

Q3.

Please describe your experience relating to coatings and corrosion control.

A3.

I received a Ph.D. in Metallurgical Engineering from The Ohio State University in 1968. My dissertation topic was on the initiation of stress corrosion cracks in nuclear power plant condenser tubing materials and was supported by the Atomic Energy Commission. I was the Project Manager for a joint pipeline coating research project between the Kendall Company and the All Soviet Union Oil and Gas Pipeline Institute in Moscow. I presented papers on pipeline coating at numerous technical meetings including at the annual meeting of the National Association of Corrosion Engineers (NACE), at the Western Canadian Meeting of NACE; for the Minister of Oil and Gas in Bagdad, Iraq; for the Minister of Oil and Gas in Cairo, Egypt; at the Australasian Corrosion Association in Adelaide, Australia as a lead speaker; at the BHRA Conference in Nice, France; and at the Tenth International Conference on Slurry Technology in Lake Tahoe, Nevada.

As part of my responsibilities at the Kendall Company, I examined the condition of pipeline coatings as a function of years of service. The general approach was to dig a bell hole using a backhoe to uncover the coated pipe and to take pictures of the coating to preserve the observed condition. Using the bell hole approach, I verified the condition of the coated buried piping on the Northern Border Pipeline that extended from the Canadian Border in North Dakota to Chicago, approximately every 100 miles. I also examined the coating of the 40 year old TransCanada Pipeline from Toronto to Edmonton every several hundred miles.

I have been involved in all aspects of corrosion and corrosion control including basic research, technical service, technical committee work, and preparation of sections of GALL related to corrosion and coatings. I have also authored numerous technical papers on corrosion issues. For the past 17 years while employed at the NRC I had been involved in the review of licensee submittals on stress corrosion cracking, boric acid corrosion, corrosion of service water piping, microbiological corrosion, crevice corrosion, pitting corrosion, and galvanic corrosion.

Q4.

Please explain your duties in connection with the NRC staffs (Staff) review of the License Renewal Application (LRA) submitted by Entergy Nuclear Generation Co. and

Entergy Nuclear Operations, Inc. (collectively, Entergy) for the renewal of the Pilgrim Nuclear Power Station (Pilgrim).

A4.

As part of my official duties during the review of Entergys LRA, I was the safety audit team leader for the license renewal safety audit at Pilgrim. As safety audit team leader, I led three safety audits with a team of four NRC staff members, three contractors, two NRC trainees, and one foreign assignee (from the Japanese equivalent of the NRC visiting the NRC for a year) at Pilgrim. License renewal audits are divided into two teams, an environmental audit team and a safety audit team. The safety audit team audits the LRAs aging management programs (AMP) and the application of those AMPs to manage the effects of aging during the period of extended operation. The purpose of the audit is to conduct an in-depth review of the program basis document for each AMP. The audit team members review each AMP, develop questions for the applicants staff, discuss the questions with applicants staff and review the applicants response to each question. Any question that is not resolved by the end of the audit is converted to a request for additional information (RAI). The applicant has 30 days to provide a response to the RAI. If the question cannot be resolved, it may generate a license condition.

The first safety audit at Pilgrim was held from May 26 to 29, 2006, during which time 37 of the 38 Pilgrim AMPs were reviewed. The 38th and final AMP was reviewed by the engineering staff at NRC headquarters. I personally reviewed the following AMPs: B.1.2, Buried Piping and Tanks Inspection; B.1.3, BWR Control Rod Drive Return Line Nozzle; and B.1.4, BWR Feedwater Nozzle and ensured that the remaining AMPs were adequately reviewed. The second safety audit occurred from June 19 to 23, 2006, and included the same team members plus one additional NRC staff member. The purpose of the second safety audit was to audit the aging management reviews (AMR), which were included in the LRA that lists each system, the components in that system, the material of construction for each component, the environment that the component is exposed to, any potential aging effects for that

material/component/ environment combination, and the proposed AMP to manage the effects of aging for that material/component/environment combination. A third safety audit was held from July 17 to 19, 2007, to resolve any open items from the previous audits and to conduct the Safety Audit Public Meeting to end the audit. My duties during the second and third audits were to help resolve any open items remaining from the first audit or that arose during the second and third audits.

Q5.

Are you familiar with Pilgrim Watchs Contention 1, as refined by the Atomic Safety and Licensing Board (Board)?

A5.

Yes. Pilgrim Watchs Contention 1, as admitted reads:

The Aging Management program proposed in the Pilgrim Application for license renewal is inadequate with regard to aging management of buried pipes and tanks that contain radioactively contaminated water, because it does not provide for monitoring wells that would detect leakage.

Contention 1 was clarified in the Boards Order dated October 17, 2007 as follows:

Thus, the only issue remaining before this Licensing Board regarding Contention 1 is whether or not monitoring wells are necessary to assure that the buried pipes and tanks at issue will continue to perform their safety function during the renewal period - or, put another way, whether Pilgrims existing AMPS have elements that provide appropriate assurance as required under relevant NRC regulations that buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions.

Q6.

What is the purpose of your testimony?

A6.

My testimony will address the adequacy of AMPs in place at Pilgrim to manage the effects of aging during the period of extended operation such that there is reasonable assurance that the buried piping that contains or could contain radioactive liquids will be able to perform their intended function in accordance with the current licensing basis (CLB).

Q7.

Are there buried pipes and tanks for systems within the scope of license renewal that could contain radioactive liquids?

A7.

There are buried pipes, but no buried tanks, within scope that could contain radioactive liquids.

The buried piping in scope for license renewal are part of the following systems: the condensate storage (CS) system, salt service water (SSW) system, the standby gas service system, the fuel oil system, the station blackout diesel generator system, and the fire protection system. The only system that contains radioactive liquid by design is the CS system, which contains buried piping, but no buried tanks. The SSW system is designed to contain non-radioactive cooling water. However, the SSW system cools the reactor building closed-cooling water system, which cools systems that contain radioactive water. Thus, there is a possibility that the SSW could become cross contaminated. The SSW system contains buried piping but no buried tanks.

The standby gas treatment system could contain radioactive gas following an accident, but would not contain radioactive liquid.

The only tank in scope for license renewal is the fuel oil diesel tank and it does not contain any radioactive liquid.

The station blackout diesel generator system and the fire protection system do not contain any radioactive liquids.

Q8.

Are you familiar with the Generic Aging Lessons Learned (GALL) Report?

A8.

Yes. The GALL Report contains Staff developed guidance for AMPs and AMRs that the Staff finds acceptable for controlling the effects of aging for the period of extended operation. Generic Aging Lessons Learned Report, NUREG-1801, Vol. 2, Rev. 1 (Sept. 2005).

The GALL report was developed by the Staff and repeatedly reviewed by the Nuclear Energy Institute (NEI) and the nuclear industry during its development. The GALL Report was published in the Federal Register to allow the public or any interested parties the opportunity to make public comments on the GALL Report. After the public comments were resolved, the report was published.

Q9.

What does the GALL Report require for the SSW buried piping?

A9.

The GALL AMPs for SSW include XI.M34, Buried Piping and Tanks Inspection,

(BPTI), (Staff Ex. 1), and XI.M20, Open-Cycle Cooling Water System (Staff Ex. 2). The BPTI AMP calls for using preventive measures to mitigate corrosion and periodic inspections to determine if corrosion is occurring that could affect the pressure-retaining capacity of the buried steel piping and tanks. The preventive measures to mitigate corrosion involve the use of protective coatings combined with the periodic inspections. Corrosion can occur as a result of exposure to an aggressive soil environment. The four relevant aging effects are general, pitting, crevice corrosion, and microbiologically-influenced corrosion (MIC). Inspections are to be conducted each time the piping is uncovered for maintenance. For example, the coating and external surface of two 40-foot sections of piping on the discharge loops were examined in 1999 when the two 40-foot sections were replaced. The coatings were found to be in good condition and no external corrosion was noted. Those coatings were then removed to inspect the outside surface of the piping which was also found to be in good condition.

The BPTI AMP requires that at least two inspections of the coating take place: one within 10 years prior to the period of extended operation and at least one inspection during the first 10 year period of extended operation.

The Open-Cycle Cooling Water System AMP was generated in response to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Components, (July 18, 1989). (Staff Ex. 3). This program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, internal coating failures, and silting in the open-cycle cooling water or service water system. (Staff Ex. 2 at XI M-72). This AMP addresses aging effects of material loss and fouling due to micro-or macro-organisms and various corrosion mechanisms. Id. The guidance in Generic Letter 89-13 includes surveillance and control of biofouling; a test program to verify heat transfer capabilities; a routine inspection and maintenance program to ensure that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of safety-related systems serviced by the open-cycle cooling system; a system walk down inspection to ensure compliance with the licensing

basis; and a review of maintenance, operating and training practices and procedures. Id.

Testing and inspections are conducted annually and during refueling outages. The five specific recommended actions in Generic Letter 89-13 are: I) For open-cycle service water systems, implement and maintain an ongoing program of surveillance and control techniques to significantly reduce the incidence of flow blockage problems as a result of biofouling; II)

Conduct a test program to verify the heat transfer capability of all safety-related heat exchangers cooled by service water; III) Ensure by establishing a routine inspection and maintenance program for open-cycle service water system piping and components that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of safety-related systems supplied by service water; IV) Confirm that the service water system will perform its intended function in accordance with the licensing basis for the plant, including a review of the ability to perform required safety functions in the event of failure of a single active component; and, V) Confirm that maintenance practices, operating and emergency procedures, and training that involves service water are adequate to ensure that safety-related equipment cooled by the service water system will function as intended and that operators of this equipment will perform effectively. (Staff Ex. 3 at 4-6).

Generic Letter 89-13 contains as an enclosure the Recommended Program to Resolve Generic Issue 51, which describes a program that is acceptable to the NRC staff for meeting the objectives of the requested Action I in the generic letter. (Staff Ex. 3, Enclosure 1). For a plant like Pilgrim that uses marine water in the service water system, the program recommends: A)

The intake structure should be visually inspected, once per refueling cycle, for macroscopic biological organisms such as blue mussels, sediment, and corrosion. Inspections should be performed either by scuba divers or by dewatering the intake structure or by other comparable methods. Any fouling accumulations should be removed; B) the service water system should be continuously chlorinated or injected with effective biocides whenever the potential for a microscopic biological fouling species exists; and C) Redundant and infrequently used cooling

loops should be flushed and flow tested periodically at the maximum design flow to ensure that they are not fouled or clogged. (Staff Ex. 3, Enclosure 1 at 1-2). In addition, another enclosure gives an acceptable program for testing of heat exchangers. (Staff Ex. 3, Enclosure 2).

Q10.

Which AMPs does Pilgrim use for the SSW system?

A10.

There are two AMPs for the SSW system piping. The first AMP is the Buried Piping and Tanks Inspection Program (Staff Ex. 4, LRA § B.1.2 at B-17). This Pilgrim AMP is consistent with the GALL XI.M34, Buried Piping and Tanks Inspection, with one exception.

The exception cited by Pilgrim is: For cases of excavation solely for the purpose of inspection -

methods such as phased array UT (ultrasonic testing) may be used to determine wall thickness without excavation. Phased array UT test uses an array of ultrasonic probes that send ultrasonic waves into the pipe at different angles to determine wall thickness, the presence of cracks, and the presence of geometric discontinuities such as laps or delaminations. This kind of inspection can be performed from the inside of the piping. The staff found this exception to be acceptable because it would adequately search for indications of pipe degradation yet eliminate the possibility of excavation damage to the coating during the inspection. Similar methods are commonly used in the oil and gas industry for inspecting their buried piping.

Pilgrims second program is the Service Water Integrity Program (Staff Ex. 5, LRA § B.1.28 at B-92). This program is consistent with the GALL XI.M20, Open-Cycle Cooling Water System, with two exceptions. The first exception is that while GALL states that all systems and components are lined or coated, at Pilgrim, components are only lined or coated where it is necessary to protect the underlying metal surfaces. The SSW supply piping that is not lined is constructed using titanium, which is not susceptible to corrosion in seawater environments such as that found in the SSW at Pilgrim. The other components in the SSW supply that are not coated or lined are small-bore piping for vents and drains, pump and valve bodies, and heat exchanger tubes. All of these components are constructed using copper alloys that are also corrosion resistant in Pilgrims environment. During the safety audit at Pilgrim, the staff found

this exception to GALL to be acceptable for service water piping (Staff Ex. 6, SER at 3-94).

GALL states that The system components are constructed of appropriate materials and lined or coated to protect the underlying metal surfaces from being exposed to aggressive cooling water environments. Titanium and copper alloys are not susceptible to corrosion by salt water, and hence, the Staff agrees that lining the pipes constructed using titanium or copper alloys is not necessary.

The second exception is that GALL states that the testing and inspections are performed annually, and during refueling outages, which are on a two-year frequency. The Pilgrim program only requires testing and inspections during each refueling outage. During the safety audit, the Staff evaluated Pilgrims testing and inspection interval and agreed that because adverse conditions caused by aging effects in the salt service water system develop over a period of several years, the difference between a one-year and a two-year interval for testing and inspection is insignificant.

Q11.

What is the operating history for Pilgrims SSW buried piping?

A11.

The SSW system has had leaks in the buried inlet piping due to internal corrosion. The inlet piping ran from the screenhouse to the auxiliary bays. The original piping material was internally rubber-lined carbon steel piping that was coated externally with coal tar enamel. The coal tar enamel coating is applied as follows: 1) the external surface is cleaned until free of loose mill scale, rust, corrosion products, dirt, grease, moisture, or other foreign material; 2) grease or heavy oil is removed by a suitable solvent; 3) a layer of primer is applied to the surface; 4) a 3/32 inch thick layer of coal tar enamel is applied; 5) fiberglass pipe wrap is applied while the coal tar enamel is still liquid in a spiral fashion with between 1/2 and one inch of overlap; 6) an additional 1/16 inch of coal tar enamel is applied over the fiberglass pipe wrap; 7) an asbestos felt saturated with coal tar enamel is applied over the final layer of coal tar enamel; and 8) a layer of heavy Kraft paper is applied in a spiral wrap over the entire coating system with between 1/2 and one inch of overlap. The coating is inspected for voids or holidays (defects

in the coating that exposes bare metal) in the field using a high voltage holiday detector.

(Entergy Ex. 3). The rubber lining had degraded from being in contact with the sea water.

These pipes were replaced in 1995 and 1997 with titanium pipe coated with the same external coating as was installed on the original pipe, as described above.

The SSW buried discharge piping from the auxiliary bays to the discharge canal experienced severe internal corrosion. This piping had the same external and internal coatings as the inlet piping, and again, the corrosion was caused by the failure of the rubber lining in contact with the seawater. Two 40-foot lengths of 22-inch diameter pipes were replaced in 1999 with carbon steel coated internally and externally with epoxy: one in A Loop and one in B Loop. The whole length of both SSW discharge loops were internally lined with cured in place linings: the B loop in 2001, and the A Loop in 2003. Based on my experience with these coatings and linings, I consider the replacement piping and coatings to be far superior to the original materials and coatings and are expected not to be affected by the contact with seawater for the period of extended operation. Also, any degradation would be detected by the inspections and testing before the systems are not able to perform their intended function.

Q12.

Does Pilgrim have any special requirements for handling buried piping?

A12.

Yes. Lifting of the pipe shall be with wide, non abrasive canvas or leather belts, or other equipment designed to prevent damage to the pipe. Id. Controlled backfill that is properly compacted will be used under and around the buried pipe. (Staff Ex. 7, PDC No. 99-21). The use of controlled backfill greatly reduces the probability of damage to the coating.

Uncontrolled backfill can contain rocks that can damage the coating.

Q13.

How do the AMPs address the CS system?

A13.

The CS system contains buried stainless steel piping. The LRA states that external corrosion of this piping will be managed by using the B.1.2 Buried Piping and Tanks Inspection Program, which is consistent with GALL AMP XI.M34, Buried Piping and Tanks Inspection. Stainless steel piping is not subject to external corrosion by contact with soil.

Nonetheless, even though corrosion is not anticipated, the external surface of the CS system piping is coated with the coal tar enamel coating system and will be inspected during maintenance that uncovers the piping.

Internal corrosion of this piping will be managed using B.1.32.2 Water Chemistry Control - BWR Program, which is consistent with GALL AMP XI.M2, Water Chemistry. The Water Chemistry Control - BWR Program optimizes the contaminate levels in the reactor coolant system to minimize potential loss of material and cracking. Pilgrim has started using hydrogen water chemistry to limit the potential for intergranular stress corrosion cracking by reducing the level of dissolved oxygen in the treated water. In addition, Pilgrim has introduced noble metal additions to the primary water which has been shown to be effective in eliminating primary water stress corrosion cracking. (Staff Ex. 8 at 3-34). The effectiveness of the Water Chemistry Control - BWR Program will be verified by conducting a one-time inspection of the CS system prior to the period of extended operation. The one-time inspection will confirm that unacceptable cracking, loss of material, and fouling has not occurred. (Staff Ex. 9, SER at 3 29).

Q14. What is the operating history for the CS system at Pilgrim?

A14.

From 1998 through 2004, several condition reports were issued by Pilgrim for adverse trends in parameters monitored by the Water Chemistry Control - BWR Program. The Pilgrim staff took appropriate actions to return the parameters to within administrative limits.

Although the parameters had exceeded administrative limits, they had not exceeded the EPRI acceptance limits which had been established by agreement between the EPRI staff and industry experts. The administrative limits had been set by the staff at Pilgrim to be below the EPRI acceptance limits, so that the administrative limits could be exceeded for a short time and corrective actions could be taken before the EPRI acceptance limits had been exceeded. For example, following a power outage on March 29, 2002, the dissolved oxygen measurement from the B high-pressure train was about 28 parts per billion (ppb), which is below the minimum

reading of 30 ppb (the EPRI action level 1). The dissolved oxygen measured in the A high-pressure train and condensate demineralizer effluent were acceptable at about 70 and 80 ppb.

The root cause was found to be that the B high-pressure sample line was defective and was replaced. A second example occurred on October 28, 2002, when the high-pressure train and the condensate demineralizer effluent dissolved oxygen levels spiked to between 400 and 500 ppb for about 15 minutes before returning to normal. The EPRI action level 1 for the high-pressure train is 200 ppb. The root cause was inadequate filling of the demineralizer prior to return to service. Procedural steps were emphasized for proper venting to mitigate elevated oxygen levels in the feedwater system. This gives additional assurance that undesirable aging would not occur. During the 2006 safety audits at Pilgrim, the Pilgrim Staff provided a program basis document for review by the audit team. This document pointed out the continuous monitoring of water quality and demonstrated how corrective actions would be taken before parameters reach control limits, thus providing evidence that the program effectively manages component aging effects. (Staff Ex. 8 SER 3-35).

Q15.

Are there any leak detection devices required to meet the requirements of 10 C.F.R. Part 54?

A15.

No. 10 C.F.R. Part 54 does not specify any leak detection devices for use in AMPs for buried pipes and tanks. In addition, there are no leak detection devices recommended in GALL AMP XI.M34, Buried Piping and Tanks Inspection.

Q16.

Can the standby gas treatment system contain radioactive liquid?

A16.

The standby gas treatment system limits the release of radioactive material to the environs from a postulated design-basis accident. The standby gas treatment system is part of the secondary containment system, which provides secondary containment for postulated loss-of-coolant-accidents and primary containment for postulated refueling accidents. The standby gas treatment system consists of two full-capacity trains with dampers, an exhaust fan, and an air filtration assembly. The standby gas treatment system shares ducting with the various

reactor building exhaust systems and can draw air from the reactor building clean and contaminated compartment exhausts, the refueling floor exhaust, the drywell, and suppression pool exhausts. After treatment, the air is discharged through a line of the underground vent duct system consisting of ducts, dampers, pipes, valves, and the 20-inch underground vent, which transports gaseous effluent from the standby gas treatment system to the primary containment atmospheric control system to the main stack. It does not contain any water and therefore, is not the subject of Contention 1.

Q17.

What is the Staffs conclusion regarding whether the AMPs for buried pipes are adequate to detect leaks to ensure that safety function challenging leaks will not occur in the buried pipes at Pilgrim?

A17.

The buried piping at Pilgrim that could potentially contain radioactive liquid has either been replaced or has not experienced external or internal degradation. In addition, aging of buried piping at Pilgrim is effectively managed by the Buried Piping and Tanks Inspection Program for the external surfaces, by the Service Water Integrity Program for SSW piping, and by the Water Chemistry Control - BWR Program and One-Time Inspection Program for the CS piping. As described in detail above, these AMPs provide reasonable assurance that the buried piping containing or potentially containing radioactive liquid at Pilgrim will not develop leaks so great as to prevent them from performing their intended safety function and they will maintain their intended functions for the period of extended operation. For these reasons, these AMPs are adequate as they are and no leak detection devices are required.

Q19.

Does this conclude your testimony?

A19.

Yes.

James A. Davis, Ph.D Statement of Professional Qualifications CURRENT POSITION:

Senior Materials Engineer Division of License Renewal, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Rockville, MD EDUCATION:

B. Met. E., The Ohio State University, 1965, Metallurgical Engineering M.S., The Ohio State University, 1965, Metallurgical Engineering Ph.D., The Ohio State University, 1968, Metallurgical Engineering

SUMMARY

Over 39 years of experience in materials engineering with over 20 years of experience in the nuclear power industry. Significant experience in the following areas:

Materials Engineering Corrosion and Control Protective Coatings and Linings Welding and Special Repair Processes License Renewal Nuclear Facilities Audits Allegations Reviews of Navy Submarine Power Plant Designs Quality Assurance American Society of Mechanical Engineers (ASME) Code Committees American Society for Testing and Materials (ASTM ) D-33 Committee on Coatings for Power Generation Facilities EXPERIENCE:

U.S. Nuclear Regulatory Commission, 11/11/1990 - Present 11/13/2005 to 12/31/2007 - Senior Materials Engineer, Division of License Renewal, Office of uclear Reactor Regulation N

Audit Team Leader for the license renewal safety audit at the Indian Point Nuclear Power Plant Backup Audit Team Leader for the license renewal safety audit at the Wolf Creek Generating Station Audit Team Leader for the license renewal safety audit at the Pilgrim Nuclear Power Station Audit Team Member for the license renewal safety audit at the Oyster Creek Generating Station 12/15/2001 - 11/13/ 2005 - Senior Materials Engineer, Division of Engineering Technology, ffice of Nuclear Regulatory Research O

Program Manager on the Steam Generator Tube Integrity Program overseeing work conducted at Argonne National Laboratory Acting Program Manager for Non-Destructive Examination research at Pacific Northwest National Laboratory 11/11/1990 - 12/15/2001 - Materials Engineer, Chemical Engineering and Metallurgy Section, Materials and Chemical Engineering Branch, Division of Engineering, Office of Nuclear Reactor Regulation ASTM Committee member for Coatings for nuclear power plants Lead reviewer for auxiliary systems for license renewal for Calvert Cliffs, Oconee, Arkansas Nuclear One, Hatch, and Turkey Point Responsible for all threaded fastener issues (such as stress corrosion cracking, boric acid corrosion, and fatigue)

Lead reviewer for full system chemical decontamination at Indian Point Lead reviewer for Boiling Water Reactor internals cracking Lead reviewer for pump and valve internals cracking Lead reviewer for pipe integrity issues Assisted the Spent Fuel Program Office in the review of corrosion behavior for dry cask storage and interaction of coatings with spent fuel water Coordinated the responses to a generic letter on containment coatings for nuclear power plants NRC representative to ASTM D-33 on coatings for power generation facilities Member of the Board of Directors for the National Board of Registration for Nuclear Safety Related Coating Engineers & Specialists Member of ASME on Welding and Special Repair Processes Member of an Augmented Inspection Team at Palisades on fuel handling problems Member of the Augmented Inspection Team at Point Beach on the hydrogen burn as a result of interactions between borated water and the inorganic zinc coating during dry cask loading operations Member of the Augmented Inspection Team at Davis-Besse on the boric acid corrosion of the vessel head.

Contract Technical Monitor and Project Officer for numerous contracts at Brookhaven National Labs Technical reviewer for the design of the Navy Seawolf Submarine and the Virginia Class Submarine Reviewer on the Department of Energy (DOE) project to produce tritium in a commercial reactor (Watts Bar)

Numerous presentations to senior NRC management including the Chairman, the Executive Director for Operations, the Committee to Resolve Generic Issues, and the Advisory Committee on Reactor Safety and Safeguards Testified before Representative Dingles staff on the safety of fasteners in nuclear power plants as a result of concerns raised by a private citizen.

Convinced Representative Dingles staff that there is no safety issue because of the redundant design of mechanical joints, the fact that the joints will leak before they break, and that the joints are inspected every refueling outage.

Polyken Division of the Kendall Company, Senior Research Associate, 1981 - 1990:

Responsible for Technical Marketing for the pipeline coating division providing technical data and reports to domestic and international customers Company representative to the National Association of Corrosion Engineers, the American Water Works Association coatings committees, and ASTM coating committees Arthur D. Little, Senior Consultant, 1979 - 1981:

Consultant to DOE on Defense Nuclear Waste and Waste Tank corrosion issues Consultant on numerous commercial contracts on corrosion, coating, metallurgical, and plating issues Allied Tube and Conduit Corp., Director of Research, 1978-1979:

Responsible for research and development for metallurgical tube forming, welding, chemical cleaning of steel, galvanizing, surface treatment and coating of electrical conduit, fence posts, and specialty tubing Responsible for Quality Assurance and Process Control Departments Allegheny Ludlum Steel Corp., Research Specialist, 1976-1978:

Responsible for customer service for use of stainless steels in corrosive service Responsible for conducting failure analyses Conducted research on corrosion mechanisms for stainless steels Bell Aerospace Company, Senior Research Scientist, 1970-1976:

Program Manager on numerous Navy sponsored programs involving corrosion of aluminum alloys, stainless steels, and titanium alloys in high velocity sea water for the Navys high performance ships program Conducted research on corrosion fatigue, stress corrosion, and fouling in sea water Conducted research on the compatibility of rocket fuels and oxidizers with fuel handling equipment U.S. Steel Corporation, Senior Research Engineer, 1968-1970:

Conducted research on the mechanism of pitting/crevice corrosion, stress corrosion cracking, hydrogen embrittlement, and intergranular corrosion using electrochemical techniques, transmission electron microscopy, optical microscopy, and scanning electron microscopy PUBLICATIONS-PRESENTATIONS:

1.

J. A. Davis and R. W. Staehle, "Initiation of Stress Corrosion Cracks in Iron-Chromium-Nickel Alloys: an Electron Microscopy Study," Presented at the Research in Progress Symposium, Corrosion/69, March, 1969, Houston, Texas

2.

J. A. Davis, "Resistance of 18 Cr-18Ni-2Si Stainless Steel to Stress Corrosion Crack Propagation in Boiling magnesium Chloride" Corrosion, Vol. 26, No. 3, 1970

3.

J. A. Davis and B. E. Wilde, "Electrochemical Measurements on Austenitic Stainless Steels in Boiling Magnesium Chloride," Jnl. Electrochemical Soc., Vol. 117, No. 11, November, 1970, p 1348-1351

4.

J. A. Davis, A. A. Staklis, and A. A. Watts, "Potential and pH Measurements During Stress Corrosion of Some Metallic Alloys," Presented at Corr/71, Research in Progress, Chicago, Ill. Mar., 1971

5.

J. A. Davis, A. A. Staklis, and A. A. Watts, "Potential and pH Changes During Stress Corrosion of Some Metallic Alloys," Institute of Environmental Sciences Proceedings, 7th Annual Conference, Living in Our Environment, Los Angeles, California, Apr 26-30, 1971, p 117-122

6.

J. A. Davis, "pH and Potential Measurements During Stress Corrosion of Aluminum Alloys," AGARD-CP-98 NATO Conference, Brussels, Belgium, 1972, p9/1-13

7.

J. A. Davis and G. A. Gehring, Jr., "The Effect of Velocity on the Sea Water Corrosion Behavior of High Performance Ship Materials," Corr/74 International Corrosion forum, Paper 78, Mar 4-8, 1974, Houston, Tx p78/1-78/17

8.

J. A. Davis, "Use of Miscroelectrodes for Study of Stress Corrosion of Aluminum Alloys,"

International Conference on Localized Corrosion, Williamsburg, Va., NACE No. 3, 1974, p32-39

9.

J. A. Davis and G. A. Gejring, Jr., "The Effect of Velocity on the Sea Water Corrosion Behavior of High Performance Ship Materials," Materials Performance, Vol 14, No. 4, 1974, p 32-39

10.

J. A. Davis, A. A. Watts and G. A. Gehring, Jr., "Pitting Behavior of Aluminum Alloys in High Velocity Sea Water," Presented at the annual Conference of the Electrochemical Society, Las Vegas, Nevada, Oct 18-22, 1976

11.

T. J. Nichol and J. A. Davis, "Intergranular Corrosion Testing and Sensitization of Two High-Chromium Ferritic Stainless Steels," ASTM Spec. Tech. Publication STP 656, Intergranular Corrosion of Stainless Alloys, May 2-3, 1977, p179-196

12.

R. A. Lula and J. A. Davis, "Intergranular Corrosion in 12 Chromium Ferritic Stainless Steels," ASTM Spec. Tech. Publication STP 656, Intergranular Corrosion of Stainless Steels, May 2-3, 1977, p233-247

13.

J. A. Davis and M. J. Johnson, "The Effect of Temperature on the Pitting Behavior of High Performance Stainless Steels, Presented at Corr/78, Chicago, Ill., Mar., 1978

14.

J. A. Davis, H. E. Deverell and M. J. Johnson, "Comparison of Stainless Steels with Cooper Nickel Alloys in Polluted Seawater," presented at Corr/78, Chicago, Ill., Mar.

1978

15.

J. A. Davis and M. J. Johnson, "Corrosion Characteristic of Stainless Steels," Presented at the Pittsburgh Section of ASM Sept., 1978

16.

J. A. Davis, "Stabilization of High Chromium Ferritic Stainless Steels," Presented at the Annual Meeting of the Electrochemical Society, Seattle, Washington, Oct., 1978

17.

J. A. Davis and T. J. Nichol, "Intergranular Corrosion Testing of High Chromium Stainless Steels," Presented at the Pittsburgh Section of the Electrochemical Society, Oct., 1978

18.

J. A. Davis, H. E. Deverell, and T. J. Nichol, "Intergranular Corrosion Resistance of 26 wt. % Chromium, 1 wt. % Molybdenum Ferritic Stainless Steel Containing Niobium,"

Corrosion, 36, No. 5, 1980, p215-220

19.

J. A. Davis, "Performance of Polyethylene Tape Coated Steel Water Pipe," L. B. Foster Seminar on Large Diameter Steel Water Pipe, Feb. 18, 1982, Houston, Texas

20.

J. A. Davis, "Performance of Polyethylene Tape Coated Pipelines for Underground Service," Shreveport, La, NACE, July 6, 1982

21.

J. A. Davis, "Polyethylene Tape Coating for Underground Service," Northeastern Regional Meeting of NACE, Great Gorge, N. J., Oct. 15, 1982

22.

J. A. Davis, "Performance of Polyethylene Coated Pipelines with Underground Burial,"

NACE Eastern Canadian Regional Conference, November 23-25, 1982, Montreal, Quebec

23.

J. A. Davis, "Performance of Polyethylene coated Pipelines With Underground Burial,"

Proceedings of the Australian Pipeline Industry Association Annual Conference, Camberra, New South Wales, Australia, Nov., 1983

24.

J. A. Davis and S. J. Thomas, "Properties and Application Procedures for Polyethylene Tape Coating systems," Pipeline Engineering Symposium of ASME, Dallas, Tx Feb. 17-21, 1985, p11-16

25.

J. A. Davis, D. Rizzone and R. N. Stretton, "Polyurethane Foam, PE Tape Thermal Insulation System for Underground Pipelines," Western Canadian Regional NACE Meeting, Feb. 25-28, 1985, Victoria, British Columbia

26.

J. A. Davis and S. J. Thomas, "Properties and Application Procedures for Polyethylene Tape Coating Systems," Proceedings of the Tenth International Conference on Slurry Technology, Lake Tahoe, Nevada, Mar 26-28, 1985, p26-28

27.

J. A. Davis, J. D. Kellner, and H. J. Dritt, "Comparison of Laboratory Soil Stress Results with In Service Behavior of Pipeline Coatings," Proceedings of the BHRA Conference, Nice, France, Nov. 4-8, 1985

28.

J. A. Davis, "Polyethylene Tape Coatings for Underground Service," Presented to the Toronto Section of NACE, Dec.10, 1985, Toronto, Ontario

29.

J. A. Davis et al, "Analysis of Stresses on Buried Pipelines," Presented at the NACE Western Canadian Regional Meeting, Calgary, Alberta, Feb. 25-27, 1986

30.

J. A. Davis, Polyethylene Tape Coatings for Underground Service, "Presented to the Calgary Section of NACE, Sept. 15, 1986, Calgary, Alberta

31.

J. A. Davis et al, "Soil Stress Effects on Pipeline Coatings," Lead Speaker, Pipeline Coating Section, Australasion Corrosion Association, Inc, Conference 26, Adelaide, Australia. Nov. 17-21, 1986

32.

J. A. Davis et al, "Interaction Between Soil and Coatings on Buried Pipelines," Presented at Corr/87, Underground Corrosion Symposium, San Francisco, Cal., Mar. 9-19, 1987

33.

J. A. Davis, "Polyethylene Tape Coatings for Underground Service," Presented at the North Central NACE Regional Meetings, Cleveland, Ohio, Sept. 28-30, 1987

34.

J. A. Davis and J. D. Kellner, "Electrochemical Principals Applied to Operating Pipelines," Presented at Corr/89, Underground Corrosion Symposium, New Orleans, Louisiana, April 17-21, 1989

35.

F. J. Witt, J. A. Davis and R. A. Hermann, "Second EPRI Balance-of-Plant Heat Exchanger NDE Workshop, The U. S. Nuclear Regulatory Commission Perspective,"

Second SPRI Balance-of-Plant Heat Exchange NDE Workshop, Key West, Florida, May 26-29, 1992

36.

J. A. Davis, "Full Reactor Coolant System Chemical Decontamination, NRC Approval of the Westinghouse Owners Group Topical Report" Fifth SPRI Workshop on Chemical Decontamination, Charlotte, North Carolina, June 8-9, 1993

37.

Richard E. Johnson and James A. Davis, "The Regulatory Approach to Fastener Integrity in the Nuclear Industry," Symposium on Structural Integrity of Fasteners, Sept.

8-19, 1993

38.

James A. Davis, "Nuclear Power Plant Service Water Systems, NRC Perspective,"

International Joint Power Generation Conference, ASME Power Division, Heat Exchange Committee, Kansas City, Mo., October 17-21, 1993.

39.

J. A. Davis, G. P. Hornseth, and R. A. Hermann, "NRC Regulatory Perspective for Service Water Systems, Third EPRI Balance-of-Plant Heat Exchanger NDE Workshop, Myrtle Beach, SC., June 6-8, 1994.

40.

Herman, R., Davis, J., and Banic, M., Primary Water Stress Corrosion Cracking of Alloy 600, International Atomic Energy Agency Specialists Meeting in Light Water Reactor Head Penetrations, Philadelphia, PA, May 2-4, 1995.

41.

Herman, R. A., Davis, J. A., and Banic, M. J. Age Related Degradation in Operating Nuclear Plants, Joint ASME/JSME Pressure Vessel and Piping Conference, Honolulu, HI, July 23-27, 1995.

42.

J. A. Davis, A Regulatory Perspective on Service Water Problems," Invited Keynote Speaker, Fourth EPRI Balance-of-Plant Heat Exchange Workshop, Jackson Hole, WY, June 10-12, 1996.

43.

J. A. Davis, Nuclear Power Plant Fastener Thread Gaging - NRC Staff Perspective, the Eighth International Symposium on Environmental Degradation of Materials in Nuclear Power Systems, Amelia Island, FL, August 10-14, 1997.

44.

J. A. Davis, A Regulatory Perspective on Service Water Problems," Invited Keynote Speaker, Fifth EPRI Balance-of-Plant Heat Exchange Workshop, Lake Tahoe, NV, June 15-17, 1998.

45.

J. Strosnider, Jr., W.H. Koo, J.A. Davis, M.C. Modes, A Regulatory History of BWR Pipe Cracking in the U.S., IAEA Regional Workshop on Environmentally Assisted Cracking in Nuclear Power Plant Austenitic Piping, Slavutych, Ukraine, June 22-26, 1998.

46.

J. A. Davis, Licence Renewal in the Nuclear Power Industry - Its Application to Balance-of-Plant, Invited Keynote Speaker, Sixth EPRI Balance-of-Plant Heat Exchange Workshop Scottsdale, AZ, June 19-21, 2000.

47.

J. A. Davis, C. L. Lauron, and A. D. Lee, Code Cases Currently Being Reviewed by the NRC Staff on Bolting and Erosion Corrosion, 2001 ASME Pressure Vessel and Piping Conference, Atlanta, Georgia, July 22-26, 2001.

48.

James A. Davis, Recent Failures of Control Rod Drive Mechanisms and Jet Pump Hold-Down Beams in Operating Nuclear Power Plants, ASM Albany, NY spring meeting, Albany, NY, April 22, 2002.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

PREFILED TESTIMONY OF DR. JAMES A. DAVIS I, James A. Davis, do declare under penalty of perjury that my statements in the foregoing testimony and my attached statement of professional qualifications are true and correct to the best of my knowledge and belief.

/Original Signed By/

James A. Davis Executed at Rockville, Maryland This 29th day of January, 2008.

January 29, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

NRC STAFF TESTIMONY OF TERENCE L. CHAN AND ANDREA T. KEIM CONCERNING PILGRIM WATCH CONTENTION 1 Q1.

Please state your name, occupation, and by whom you are employed.

A1a.

My name is Terence L. Chan (TLC). I am employed as Branch Chief of the Piping and Nondestructive Examination (NDE) Branch within the Division of Component Integrity, Office of Nuclear Reactor Regulation (NRR), U.S. Nuclear Regulatory Commission (NRC). A statement of my professional qualifications is attached hereto.

A1b.

My name is Andrea T. Keim (ATK). I am a Materials Engineer in the Division of Component Integrity, NRR, NRC. A statement of my professional qualifications is attached hereto.

Q2.

Please describe your current responsibilities.

A2a.

(TLC) As Chief of the Piping and NDE Branch since 2001, I manage eight engineers involved in the evaluation of generic and plant-specific materials degradation and NDE issues, American Society of Mechanical Engineers (ASME) Code and standards activities, and inservice inspection (ISI) activities. My branch is also involved in the review of certain power uprate and license renewal applications, and provides technical support to the regional offices. I provide day-to-day management of activities in my branch, which include administrative and technical review responsibilities. As part of my duties, I represent the NRC on four groups within the ASME that address materials degradation or inspection issues: Task Group on Alloy 600, Task Group on Alternate NDE, Working Group on General Requirements, and Subgroup on NDE.

A2b.

(ATK) I am responsible for performing safety reviews related to nuclear power plant piping and NDEs of operating nuclear power plants, license renewal applications, and new reactor design certifications. For the past twelve years, I have reviewed plant license and license renewal applications and have been involved in updating technical review guidance documents, such as standard review plans. As a technical reviewer in the Division of Component Integrity, I have been responsible for conducting reviews involving corrosion of metals, NDEs, risk-informed ISI programs and repair/replacement activities. I represent the NRC at the ASME Section XI Code on the working group on Implementation of Risk Based Examinations.

Q3.

Please explain your duties in connection with the NRC staffs (Staff) review of the License Renewal Application (LRA) submitted by Entergy Nuclear Generation Co. and Entergy Nuclear Operations, Inc. (collectively, Entergy) for the renewal of the Pilgrim Nuclear Power Station (Pilgrim).

A3.

(TLC) (ATK) We were not involved in the review of Entergys LRA.

Q4.

Are you familiar with Pilgrim Watchs Contention 1, as refined by the Atomic Safety and Licensing Board (Board)?

A4.

(TLC) (ATK) Yes. Pilgrim Watchs Contention 1, as admitted reads:

The Aging Management program proposed in the Pilgrim Application for license renewal is inadequate with regard to aging management of buried pipes and tanks that contain radioactively contaminated water, because it does not provide for monitoring wells that would detect leakage.

Contention 1 was clarified in the Boards Order dated October 17, 2007 as follows:

Thus, the only issue remaining before this Licensing Board regarding Contention 1 is whether or not monitoring wells are necessary to assure that the buried pipes and tanks at issue will continue to perform their safety function during the renewal period

- or, put another way, whether Pilgrims existing AMPS have elements that provide appropriate assurance as required under relevant NRC regulations that buried pipes and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions.

Q5.

What is the purpose of your testimony?

A5.

(TLC) (ATK) Our testimony will address the required tests and inspections being performed under Pilgrims current license for routine maintenance and operation of those buried pipes and tanks within the scope of the contention.

Q6.

Are there buried pipes and tanks for systems within the scope of license renewal that could contain radioactive liquids?

A6.

(TLC) (ATK) Yes, with respect to buried pipes, but there are no buried tanks within the scope of Contention 1. According to the testimony of James A. Davis, PhD., the buried piping in scope for Entergys license renewal application are part of the following systems: the condensate storage (CS) system, salt service water (SSW) system, the standby gas service system, the fuel oil system, the station blackout diesel generator system, and the fire protection system. The only system that contains radioactive liquid by design is the CS system, which contains buried piping but no buried tanks. The SSW system is designed to contain non-radioactive cooling water. However, the SSW system cools the reactor building closed cooling water (RBCCW) system, which cools systems that contain radioactive water.

Thus, there is a small possibility that the SSW could become cross contaminated. The SSW system contains buried piping but no buried tanks.

The standby gas treatment system could contain radioactive gas following an accident, but would not contain radioactive liquid.

The only buried tank in scope for license renewal is the fuel oil diesel tank and it does not contain any radioactive liquid.

The station blackout diesel generator system and the fire protection system do not contain any radioactive liquids.

These systems are consistent with those discussed in the Applicants testimony dated January 8, 2008.1 Q7.

What is the intended function of the CS system?

A7.

The CS system does not provide a credited safety function. It does however provide the preferred supply of water to the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems.

The RCIC system provides makeup water to the reactor vessel whenever the vessel is isolated. The HPCI system provides and maintains coolant inside the reactor vessel to prevent fuel clad melting in the event of a postulated small break in the reactor coolant system.

Q8.

What inspection or examinations are required by current NRC regulations or Pilgrims technical specifications for the CS system?

A8.

(TLC) The CS system provides for condensate system makeup and system rejection to accommodate fluctuations in power generation demands. Although the CS tanks and associated piping provide the preferred water supply to the HPCI and RCIC systems, the CS system is not relied upon for accident mitigation. The torus water storage provides the backup emergency HPCI and RCIC systems water supply. As such, there are no inspections or examinations of the CS system required by the NRC regulations or technical specifications.

Q9.

Are there any requirements that would detect leaks in the CS system buried pipes?

A9.

(ATK) Yes. There are testing requirements for the RCIC and HPCI systems that would allow the licensee to identify a leakage problem in the buried piping of the CS system.

1 Testimony of Alan Cox, Brian Sullivan, Steve Woods, and William Spatero on Pilgrim Watch Contention 1, Regarding Adequacy of Aging Management Program for Buried Pipes and Tanks and Potential Need for Monitoring Wells to Supplement Program (January 8, 2008), at 9, 13-15 The regulations at 10 C.F.R. § 50.55a(f) require plants whose construction permit was issued before January 1, 1971, such as Pilgrims, to implement an Inservice Testing (IST) program that meets 10 C.F.R. §§ 50.55a(f)(4)-(5) to the extent practical.

By letter dated December 6, 2002, the licensee submitted the fourth 10-year IST program plan for Pilgrim. (Staff Ex. 10). The fourth 10-year IST interval started on December 7, 2002 and ends December 7, 2012. The IST program plan was developed in accordance with the requirements of the 1995 Edition through the 1996 Addenda of the ASME Code for Operation and Maintenance of Nuclear Power Plants, except where specific alternatives to these requirements have been authorized by the NRC.

In accordance with the Pilgrim IST program and the Pilgrim technical specifications, specifically Surveillance Requirement 4.5.C. for the HPCI system and Surveillance Requirement 4.5.D. for the RCIC system (Staff Ex. 11), the HPCI system and the RCIC system are tested quarterly to verify flow rate and pump operability. (Staff Ex. 10 at 17 of 179, 18 of 179). The test for HPCI and RCIC pumps are performed by establishing a flow path with suction from and discharge to the condensate storage tank. This suction path utilizes the buried piping from the condensate storage tank to the HPCI and RCIC pump suctions as identified by the Pilgrim January 8, 2008 testimony. Entergys Testimony at 13-14, 15) A leak large enough to prevent condensate storage tank water delivery to these pumps would cause the quarterly IST to fail and the tested pumps would be termed inoperable. This would require Pilgrim to take action pursuant to the TSs. The testing would allow the licensee to identify a leakage problem in the buried piping of the CS system.

Q10.

How does Pilgrims FSAR address the CS system?

A10.

(ATK) FSAR 11.9 discusses the power generation objective of the condensate storage system at Pilgrim. (Staff Ex. 12 ) As discussed above, the CS system provides the preferred supply of water to the HPCI and RCIC systems. The torus water storage provides the backup emergency HPCI and RCIC systems supply. There are two 275,000 gallon CS tanks that are above ground. The tanks are made of coated carbon steel with all inlet and outlet lines, overflows, vents, and instrument lines located at the tank bottom or toward the tank center to prevent freezing problems. All systems that take suction from the condensate storage tanks are located above the HPCI and RCIC suctions to provide a 75,000 gallon reserve in each tank for these systems.

Q11.

What is the intended safety function of the SSW system?

A11.

(ATK) The SSW system provides a heat sink for the RBCCW system under transient and accident conditions.

Q12.

What current NRC regulations address the safety of buried piping in the SSW system at Pilgrim?

A12.

(ATK) On July 18, 1989, the NRC issued Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment, after operating experience and studies led the Staff to question the compliance of service water systems in the nuclear power plants of licensees and applicants with certain general design criteria (GDC) and quality assurance requirements. (Staff Ex. 3).

As addressed in the purpose section of GL 89-13, nuclear power plant facilities or licensees and applicants must meet the minimum requirements for quality assurance in 10 C.F.R. Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants. In particular,Section XI, Test Control, requires that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents.

Q13.

Has Pilgrim established a test program as required by Appendix B?

A13.

(ATK) Yes, as stated in FSAR Section 1.10. (Staff Ex. 13).

Q14.

What inspection or examinations are required by NRC regulations for the SSW System?

A14a. (TLC) The regulations at 10 C.F.R. § 50.55a(g) require plants whose construction permit was issued before January 1, 1971, such as Pilgrims, to implement an ISI program that meets 10 C.F.R. §§ 50.55a(g)(4)-(5) to the extent practical.

By letter dated June 29, 2005, the licensee submitted the fourth 10-year ISI program plan for Pilgrim. (Staff Ex. 14). The fourth 10-year ISI interval started on July 1, 2005 and ends June 30, 2015. The ISI program plan was developed in accordance with the requirements of the 1998 Edition of the ASME Boiler and Pressure Vessel Code (Code),Section XI, through the 2000 Addenda, except where specific alternatives to these requirements have been authorized by the NRC. The SSW system is included in Pilgrims ISI Program Plan and will be examined and pressure tested in accordance with the requirements of the ASME Code,Section XI and Pilgrims augmented ISI requirements. (Id. at 1-11, 1-14, 1-15). In 10 C.F.R. § 50.55a(b) the NRC has approved the use of Section XI of the ASME Code including the 1970 Edition through the 1976 Winter Addenda, and the 1977 Edition through the 2003 Addenda, subject to certain limitations and modifications stated in 10 C.F.R. § 50.55a(b)(2). Pilgrims fourth 10-year ISI Program Plan complies with these limitations and modifications. ISI, including pressure testing, of the SSW system in accordance with ASME Code Section XI (Id. at 1-35), and provides reasonable assurance of structural integrity and that significant degradation will be identified in a timely manner such that safety related systems will be able to perform their safety function.

A14b. (ATK) The ISI program plan referenced routine inspection, maintenance, and test requirements for the SSW system piping and heat exchanger inspections, along with the associated acceptance criteria for consistency with GL 89-13. These inspections are separate from, but supplement, the ASME Code Section XI Class 3 ISI inspections.

Regional inspectors use Inspection Procedure (IP) 71111.07 to verify heat sink performance. (Staff Ex.15). As stated in Pilgrim Nuclear Power Station - NRC Integrated Inspection Report 05000293/2006002 dated May 12, 2006, The inspector reviewed performance tests, periodic cleaning, eddy current inspections, chemical control methods, tube leak monitoring, the extent of tube plugging, potential water hammer analysis, operating procedures, [and] maintenance practices. (Staff Ex. 16 at 6). The inspector also confirmed that controls for selected components conformed to Entergys commitments to Generic Letter 89-13, Service Water System Problems Affecting Safety Related Equipment. The inspector did not identify any findings of significance. (Id.). The verifying of the heat sink performance provides assurance that the heat sink is capable of meeting its safety function.

Q15.

How does Pilgrims Final Safety Analysis Report (FSAR) address the NRC regulations described above for the SSW system?

A15.

(ATK) FSAR § 10.7 discusses the safety objective of the SSW system at Pilgrim.

As discussed above, the SSW system provides a heat sink for the RBCCW system under transient and accident conditions. (1) The system is designed with sufficient redundancy so that no single active system component failure can prevent the system from achieving its safety objective. (2) The system is designed to continuously provide a supply of cooling water to the secondary side of the RBCCW heat exchangers adequate for the requirements of the RBCCW under transient and accident conditions. (Staff Ex. 17)

The SSW system consists of five vertical service water pumps located in the intake structure, and associated piping, valves, and instrumentation. The pumps discharge to a common header from which independent piping supplies each of the two cooling water loops.

Testing is performed on pumps and valves in accordance with the inservice testing program. The testing is performed per the ASME Code as required by 10 C.F.R. § 50.55a(f).

The buried portions of the 22-inch nominal diameter discharge piping from the last flange connections in the auxiliary building piping vault to the end of the discharge pipes at the seal well opening have been provided with a cured-in-place-pipe (CIPP) lining. The 240-feet total length loop A lining was installed in refueling outage (RFO-14) and the 225-feet total length B lining was installed in RFO-13. The CIPP liner material consists of a tube composed of nonwoven polyester felt material that is saturated with either an isophthalic polyester resin and catalyst system (Loop A) or epoxy resin and hardener system (Loop B) with a polyurethane or polyethylene inner membrane surface. The liner has a nominal 1/2 installed thickness. The resulting configuration is a rigid resin composite pipe within the original pipe with no requirements for bonding between the pipes. (Staff Ex. 17 at 10.7-2a)

Q16.

Will the tests and inspections described above continue to be performed during the period of extended operation?

A16.

Yes. The tests and inspections discussed above are performed as part of routine maintenance and operation. Those required under the regulations and TSs, will carry forward unless changed by an amendment to the regulations or to the operating license. Those tests and inspections covered by the FSAR can be changed by the Applicant, but only as permitted under 10 C.F.R. § 50.59. Changes to the ISI and IST are governed by 10 C.F.R. § 50.55a.

Q17.

How does the NRC treat unexpected leakage from systems such as the SSW and CS?

A17.

(TLC) Unexpected leakage from the pressure boundary of a system, such as the piping itself, welds, and valve bodies, is considered as operational leakage, and is a current licensing basis issue. Industry experience has shown that operational leakage from typical service water systems as a result of corrosion due to the nature of service water environments does occur. Because such leakage is a clear nonconformance to the expected condition of the system, treatment of operational leakage was provided in GL 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability. (Staff Ex.18). This guidance was revised in NRC Regulatory Issue Summary (RIS) 2005-20, Revision to Guidance Formerly Contained in NRC Generic Letter 91-18,Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability, dated September 26, 2005. (Staff Ex.19). Specific guidance regarding operational leakage is provided in Appendix C, Article C.12, Operational Leakage from Code Class 1, 2, and 3 Components, to NRC Inspection Manual Part 9900, attachment to the RIS. (Id. at C-9). Article C.12 provides guidance for evaluating the structural integrity of the leaking component to perform its safety function and identifies actions which may be taken to determine the operability of the component. (Id. at C-10). This guidance makes no distinction as to whether the component or piping is buried or exposed.

Q18.

What is the Staffs conclusion regarding whether the inspections being performed under Pilgrims current license for routine maintenance and operation of buried pipes and tanks that could potentially contain radioactive liquid are adequate to detect leaks prior to challenging the buried pipings ability to fulfill its safety function?

A18.

(TLC) (ATK) The buried piping at Pilgrim that could potentially contain radioactive liquid is effectively managed by the inspections, testing, quality assurance, and corrective action programs performed under the current license. These programs provide reasonable assurance that significant leaks would be detected in a timely manner that will allow for action to be taken prior to the system being unable to perform its intended safety function.

Q19.

Have you had an opportunity to review the testimony of Entergys witnesses regarding the testing, inspections and surveillances performed on the SSW, CS, and other systems?

A19.

(TLC) (ATK) We have each reviewed Entergys testimony dated January 8, 2008.

Q20.

Do you have an opinion regarding whether these tests and inspections are adequate to detect leaks before they would affect the ability of buried pipes to perform their intended safety function?

A20.

(TLC) (ATK) Yes. The tests and inspections are discussed in the testimony of the Applicants expert witnesses and include: water level indicators in the CS system tanks that are checked every four hours (Entergys Testimony at 48), quarterly waterflow rate testing of the HPCI and RCIC pumps and related corrective actions (Id. at 48-49), quarterly IST of flow rate to the HPCI and RCIC systems in accordance with the ASME code and Pilgrim TSs (Id. at 51),

flowrate tests once after every outage and once every two years (Id.), and monthly flowrate test of the SSW system (Id. at 53). In our opinion, they provide reasonable assurance that during routine operation, leaks in the buried pipes in the CS and SSW systems will be detected before affecting the ability of the buried pipes to perform their intended function.

Q21.

Does this conclude your testimony?

A21.

Yes.

Terence L. Chan, PE Statement of Professional Qualifications CURRENT POSTION:

Branch Chief, Division of Component Integrity Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission, Rockville, MD EDUCATION:

B. NE.

Georgia Institute of Technology, 1977, Nuclear Engineering MS Georgia Institute of Technology, 1981, Mechanical Engineering LICENSES:

Professional Engineer (Mechanical Eng.), Washington, DC #7997 (since 1983)

SUMMARY

Nearly 30 years of experience in nuclear, mechanical and materials engineering in the nuclear power industry. Significant experience in the following areas:

Mechanical Engineering

System Design

Nondestructive Examination Inspection Licensing Allegations Quality Assurance Construction American Society of Mechanical Engineers (ASME) Code Committees EXPERIENCE:

U.S. Nuclear Regulatory Commission, 02/09/1981 - Present 06/2001 to Present - Chief, Piping and NDE Branch, Division of Component Integrity, Office of Nuclear Reactor Regulation Manage the day to day technical and administrative responsibilities of a technical staff, dealing with materials degradation, welding, and inspection issues. Specific issues include reactor vessel head degradation, and cracking of dissimilar metal welds.

Responsible for the inservice inspection requirements of piping systems and components, pressure boundary integrity issues and nondestructive examination methods and qualification requirements.

NRC representative to ASME,Section XI o Task Group on Alternate NDE o Task Group on Alloy 600 o Working Group on General Requirements o Subgroup on Nondestructive Examination 05/2000 to 06/2001 - Senior Mechanical Engineer, Materials and Chemical Engineering Branch, Division of Engineering, Office of Nuclear Reactor Regulation Technical lead for ASME Code issues.

Peer reviewer of technical safety evaluations 10/1999 to 05/2000 - Commissioner Assistant, Office of Chairman Richard A. Meserve 02/1996 to 10/1999 - Commissioner Assistant, Office of the Chairman/Office of Commissioner Greta Joy Dicus Reviewed and advised on technical and policy matters related to reactor issues including License Renewal, Advanced Reactors, Risk-informed Regulations, Y2K, International Exports and Technology Transfer, Budget, NRC Organization Structure, Regulatory Reform, Decommissioning, and Deregulation.

08/1990 to 02/1996 - Section Chief, Mechanical Engineering Branch, Division of Engineering, Office of Nuclear Reactor Regulation Manage the day to day technical and administrative responsibilities of a technical staff, dealing with inservice surveillance and testing requirements of safety-related pumps and valves.

Responsible for piping design requirements, seismic design requirements, and effects of thermal stratification in piping systems.

04/1986 to 08/1990 - Senior Project Manager/Project Manager, Division of Reactor Projects III, IV, and V, Office of Nuclear Reactor Regulation Project Manager for Trojan Nuclear Plant and Surry Power Station; Senior Project Manager for Palo Verde Nuclear Generating Station. Responsible for all licensing activities related to the facilities; coordination of issues between NRC, licensee, and other State and Federal agencies; and coordination of all technical reviews.

Lead Project Manager for generic technical issues - pipe wall thinning, thermal stratification, and reactor vessel support embrittlement.

11/1983 to 04/1986 - Reactor Construction Engineer, Reactor Construction Programs Branch, Division of Quality Assurance, Safeguards and Inspection Programs, Office of Inspection and Enforcement Performed Construction Appraisal Team inspections at Clinton, Seabrook, Waterford, Shearon Harris, and Millstone 3. Lead inspector responsible for all mechanical engineering related systems and components (i.e., fluid piping systems, HVAC).

02/1981 to 11/1983 - Auxiliary Systems Engineer, Auxiliary Systems Branch, Division of Systems Technology, Office of Nuclear Reactor Regulation Performed licensing reviews of nuclear power plant applications. Reviewed Final Safety Analysis Reports. Determined the acceptability of the design of safety-related and "balance-of-plant" systems (e.g., spent fuel pool and cooling system, fuel storage, safe shutdown in the event of fire, emergency feedwater system, HVAC, ultimate heat sink, component cooling systems).

U. S. Tennessee Valley Authority; Bellefonte Nuclear Plant - Construction Engineer (06/1978 to 02/1981)

Construction engineer responsible for the installation and preoperational testing of safety piping systems, supports and components.

Andrea T. Keim Statement of Professional Qualifications CURRENT POSITION:

Materials Engineer Division of Component Integrity, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission (NRC), Rockville, MD EDUCATION:

Bachelors of Engineering - Stevens Institute of Technology, Materials and Metallurgical Engineering 1990 Masters of Science - Stevens Institute of Technology, Materials Science and Engineering 1995

SUMMARY

Over 15 years of experience in materials engineering with over 12 years of experience in the nuclear power industry. Significant experience in the following areas:

Materials Engineering Corrosion and Control Welding and Special Repair Processes License Renewal Nondestructive testing Review of Next Generation Power Plant Designs Quality Assurance American Society of Mechanical Engineers (ASME) Code Committees EXPERIENCE:

U.S. Nuclear Regulatory Commission, July 1995 - Present September 1997 to Present - Materials Engineer, Division of Component Integrity, Office of uclear Reactor Regulation N

Member of the Liquid Radioactive Release Lessons Learned Task Force, providing technical expertise on regulatory requirements for systems, structures and components related to radioactive leaks ASME Committee member for the working group on implementation of risk-based examinations Performed technical reviews related to plant relief requests Performed technical reviews related to license amendments including license renewal reviews July 1995 - September 1997-Reactor Engineer Intern, Office of Nuclear Reactor Regulations Completed extensive formal training in nuclear reactor technology t Performed a series of developmental assignments throughout the agency to gain a broad perspective of its role.

NOVON Products, a Division of Warner Lambert, Applications Testing Engineer, 1990-1993 1990:

Responsible for Technical Marketing for the biodegradable polymer productions providing technical data and reports to domestic and international customers.

Interacted between sales representatives, customers, managers and research staff to develop products and test procedures to identify appropriate materials.

Consolidated Edison, Summer Intern - Summer 1989 Failure analysis Evaluation of nondestructive testing equipment Stevens Institute of Technology, Teaching Assistant, 1990-1991 Responsible for research, development and teaching powder metallurgy laboratory class for sophomore level students.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

PREFILED TESTIMONY OF TERENCE L. CHAN I, Terence L. Chan, do declare under penalty of perjury that my statements in the foregoing testimony and my attached statement of professional qualifications are true and correct to the best of my knowledge and belief.

/Original Signed By/

Terence L. Chan Executed at Rockville, Maryland This 29th day of January, 2008.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

PREFILED TESTIMONY OF ANDREA T. KEIM I, Andrea T. Keim, do declare under penalty of perjury that my statements in the foregoing testimony and my attached statement of professional qualifications are true and correct to the best of my knowledge and belief.

/Original Signed By/

Andrea T. Keim Executed at Rockville, Maryland This 29th day of January, 2008.

January 29, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

Entergy Nuclear Generation Co. and

)

Entergy Nuclear Operations, Inc.

)

Docket No. 50-293-LR

)

)

ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station)

)

NRC STAFF EXHIBIT LIST EXHIBIT TITLE EXHIBIT #

NUREG-1801, Rev. 1 (Sept. 2005) EXCERPT -

1 XI.M34 BURIED PIPING AND TANKS INSPECTION NUREG-1801, Rev. 1 (Sept. 2005) EXCERPT -

2 XI.M20 OPEN-CYCLE COOLING WATER SYSTEM 07/18/1989 GENERIC LETTER RE SERVICE WATER SYSTEM 3

PROBLEMS AFFECTING SAFETY-RELATED EQUIPMENT (GENERIC LETTER 89-13)

PILGRIM LICENSE RENEWAL APPLICATION EXCERPT -

4 B.1.2 BURIED PIPING AND TANKS INSPECTION PILGRIM LICENSE RENEWAL APPLICATION EXCERPT -

5 B.1.28 SERVICE WATER INTEGRITY NUREG-1891 (Sept. 2007, Published Nov. 2007) EXCEPRT -

6 3.0.3.2.16 SERVICE WATER INTEGRITY PROGRAM PDC No. 99-21 EXCAVATION FOR SSW PIPE REPLACEMENT 7

(RFO #12 SCOPE)

NUREG-1891 (Sept. 2007, Published Nov. 2007) EXCEPRT -

8 3.0.3.1.13 WATER CHEMISTRY CONTROL BWR PROGRAM NUREG-1891 (Sept. 2007, Published Nov. 2007) EXCEPRT -

9 3.0.3.1.8 ONE-TIME INSPECTION PROGRAM 12/06/2002 LETTER FROM ENTERGY TO NRC RE PILGRIM NUCLEAR 10 POWER STATION FOURTH TEN-YEAR INSERVICE TESTING (IST)

PROGRAM AND REQUEST FOR APPROVAL OF IST RELIEF REQUESTS EXHIBIT TITLE EXHIBIT #

AMENDMENT NO. 176 EXCERPT (3/4.5 3/4.5-8) 11 PNPS-FSAR EXCERPT - 11.9 CONDENSATE STORAGE SYSTEM 12 PNPS-FSAR REV. 26 EXCERPT - QUALITY ASSURANCE PROGRAM 13 06/29/2005 LETTER FROM ENTERGY TO NRC RE PILGRIM FOURTH 14 TEN-YEAR INSERVICE INSPECTION PROGRAM PLAN, AND THE ASSOCIATED RELIEF REQUESTS FOR NRC APPROVAL ATTACHMENT 71111.07 (ISSUE DATE 05/25/2006) HEAT SINK 15 PERFORMANCE 05/12/2006 LETTER FROM CLIFFORD ANDERSON (NRC) TO ENTERGY 16 RE PILGRIM NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000293/2006002 PNPS-FSAR - EXCERPT - 10.7 SALT SERVICE WATER SYSTEM 17 11/07/1991 GENERIC LETTER (GENERIC LETTER 91-18) RE 18 INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL SECTIONS ON RESOLUTOIN OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY NRC REGULATORY ISSUE

SUMMARY

2005-20: REVISION TO 19 GUIDANCE FORMERLY CONTAINED IN NRC GENERIC LETTER 91-18, INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL SECTIONS ON RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY NUREG-1891 (Sept. 2007, Published Nov. 2007) EXCEPRT -

20 3.0.2 STAFFS REVIEW PROCESS

NRC STAFF EXHIBIT 1

XI.M34 BURIED PIPING AND TANKS INSPECTION Program Description The program includes (a) preventive measures to mitigate corrosion, and (b) periodic inspection to manage the effects of corrosion on the pressure-retaining capacity of buried steel piping and tanks. Gray cast iron, which is included under the definition of steel, is also subject to a loss of material due to selective leaching, which is an aging effect managed under Chapter XI.M33, "Selective Leaching of Materials."

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried piping and tanks are inspected when they are excavated during maintenance and when a pipe is dug up and inspected for any reason.

This program is an acceptable option to manage buried piping and tanks, except further evaluation is required for the program elementlattributes of detection of aging effects (regarding inspection frequency) and operating experience.

Evaluation and Technical Basis Scope of Program: The program relies on preventive measures such as coating, wrapping and periodic inspection for loss of material caused by corrosion of the external surface of buried steel piping and tanks. Loss of material in these components, which may be exposed to aggressive soil environment, is caused by general, pitting, and crevice corrosion, and microbiologically-influenced corrosion (MIC). Periodic inspections are performed when the components are excavated for maintenance or for any other reason.

The scope of the program covers buried components that are within the scope of license renewal for the plant.

2.

Preventive Actions: In accordance with industry practice, underground piping and tanks are coated during installation with a protective coating system, such as coal tar enamel with a fiberglass wrap and a kraft paper outer wrap, a polyotifin tape coating, or a fusion bonded epoxy coating to protect the piping from contacting the aggressive soil environment.

3.

Parameters Monitored/lnspected: The program monitors parameters such as coating and wrapping integrity that are directly related to corrosion damage of the external surface of buried steel piping and tanks. Coatings and wrappings are inspected by visual techniques. Any evidence of damaged wrapping or coating defects, such as coating perforation, holidays, or other damage, is an indicator of possible corrosion damage to the external surface of piping and tanks.

4.

Detection of Aging Effects: Inspections performed to confirm that coating and wrapping are intact are an effective method to ensure that corrosion of external surfaces has not occurred and the intended function is maintained. Buried piping and tanks are opportunistically inspected whenever they are excavated during maintenance. When opportunistic, the inspections are performed in areas with the highest likelihood of corrosion problems, and in areas with a history of corrosion problems, within the areas made accessible to support the maintenance activity.

September 2005 NUREG-1801, Rev. 1

The applicant's program is to be evaluated for the extended period of operation. It is anticipated that one or more opportunistic inspections may occur within a ten-year period.

Prior to entering the period of extended operation, the applicant is to verify that there is at least one opportunistic or focused inspection is performed within the past ten years. Upon entering the period of extended operation, the applicant is to perform a focused inspection within ten years, unless an opportunistic inspection occurred within this ten-year period.

Any credited inspection should be performed in areas with the highest likelihood of corrosion problems, and in areas with a history of corrosion problems.

5.

Monitoring and Trending: Results of previous inspections are used to identify susceptible locations.

6.

Acceptance Criteria: Any coating and wrapping degradations are reported and evaluated according to site corrective actions procedures.

7.

Corrective Actions: The site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, confirmation process, and administrative controls.

8.

Confirmation Process: See Item 7, above.

10.

Operating Experience: Operating experience shows that the program described here is effective in managing corrosion of external surfaces of buried steel piping and tanks.

However, because the inspection frequency is plant-specific and depends on the plant operating experience, the applicant's plant-specific operating experience is further evaluated for the extended period of operation.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NUREG-1801, Rev. 1 September 2005

NRC STAFF EXHIBIT 2

XI.M20 OPEN-CYCLE COOLING WATER SYSTEM Program Description The program relies on implementation of the recommendations of the Nuclear Regulatory Commission (NRC) Generic Letter (GL) 89-13 to ensure that the effects of aging on the open-cycle cooling water (OCCW) (or service water) system will be managed for the extended period of operation. The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW system or structures and components serviced by the OCCW system.

Evaluation and Technical Basis

1.

Scope of Program: The program addresses the aging effects of material loss and fouling due to micro-or macro-organisms and various corrosion mechanisms. Because the characteristics of the service water system may be specific to each facility, the OCCW system is defined as a system or systems that transfer heat from safety-related systems, structures, and components (SSC) to the ultimate heat sink (UHS). If an intermediate system is used between the safety-related SSCs and the system rejecting heat to the UHS, that intermediate system performs the function of a service water system and is thus included in the scope of recommendations of NRC GL 89-13. The guidelines of NRC GL 89-13 include (a) surveillance and control of biofouling; (b) a test program to verify heat transfer capabilities; (c) routine inspection and a maintenance program to ensure that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of safety-related systems serviced by OCCW; (d) a system walk down inspection to ensure compliance with the licensing basis; and (e) a review of maintenance, operating, and training practices and procedures.

Preventive Actions: The system components are constructed of appropriate materials and lined or coated to protect'the underlying metal surfaces from being exposed to aggressive cooling water environments. Implementation of NRC GL 89-1 3 includes a condition and performance monitoring program; control or preventive measures, such as chemical treatment, whenever the potential for biological fouling species exists; or flushing of infrequently used systems. Treatment with chemicals mitigates microbiologically-influenced corrosion (MIC) and buildup of macroscopic biological fouling species, such as blue mussels, oysters, or clams. Periodic flushing of the system removes accumulations of biofouling agents, corrosion products, and silt.

Parameters Monitored/lnspected: Adverse effects on system or component performance are caused by accumulations of biofouling agents, corrosion products, and silt. Cleanliness and material integrity of piping, components, heat exchangers, elastomers, and their internal linings or coatings (when applicable) that are part of the OCCW system or that are cooled by the OCCW system are periodically inspected, monitored, or tested to ensure heat transfer capabilities. The program ensures (a) removal of accumulations of biofouling agents, corrosion products, and silt, and (b) detection of defective protective coatings and corroded OCCW system piping and components that could adversely affect performance of their intended safety functions.

4.

Detection of Aging Effects: Inspections for biofouling, damaged coatings, and degraded material condition are conducted. Visual inspections are typically performed; however, nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer NUREG-1801, Rev. 1 XI M-72 September 2005

capability testing, are effective methods to measure surface condition and the extent of wall thinning associated with the service water system piping and components, when determined necessary.

5.

Monitoring and Trending: Inspection scope, method (e.g., visual or nondestructive examination [NDE]), and testing frequencies are in accordance with the utility commitments under NRC GL 89-13. Testing and inspections are done annually and during refueling outages. Inspections or nondestructive testing will determine the extent of biofouling, the condition of the surface coating, the magnitude of localized pitting, and the amount of MIC, if applicable. Heat transfer testing results are documented in plant test procedures and are trended and reviewed by the appropriate group.

6.

Acceptance Criteria: Biofouling is removed or reduced as part of the surveillance and control process. The program for managing biofouling and aggressive cooling water environments for OCCW systems is preventive. Acceptance criteria are based on effective cleaning of biological fouling organisms and maintenance of protective coatings or linings are emphasized.

Corrective Actions: Evaluations are performed for test or inspection results that do not satisfy established acceptance criteria and a problem or condition report is initiated to document the concern in accordance with plant administrative procedures. The corrective actions program ensures that the conditions adverse to quality are promptly corrected. If the deficiency is assessed to be significantly adverse to quality, the cause of the condition is determined, and an action plan is developed to preclude repetition. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8.

Confirmation Process: Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix 6. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix 6, acceptable to address the confirmation process and administrative controls.

9.

Administrative Controls: See l tem 8, above.

10.

Operating Experience: Significant microbiologically-influenced corrosion (NRC Information Notice [IN] 85-30), failure of protective coatings (NRC IN 85-24), and fouling (NRC IN 81-21, IN 86-96) have been observed in a number of heat exchangers. The guidance of NRC GL 89-1 3 has been irr~plemented for approximately 10 years and has been effective in managing aging effects due to biofouling, corrosion, erosion, protective coating failures, and silting in structures and components serviced by OCCW systems.

References 1 0 C FR Part 50, Appendix 6, Quality Assurance Criteria for Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 89-1 3, Service Water System Problems Affecting Safety-Related Components, U.S. Nuclear Regulatory Commission, July 18, 1989.

September 2005 NUREG-1 801, Rev. 1

NRC STAFF EXHIBIT 3

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, 0. C. 20555 July 18, 1989 TO :

ALL HOLDERS OF OPERATING LICENSES OR CONSTRUCTION PERMITS FOR NUCLEAR POWER PLANTS

SUBJECT:

SERVICEIWATER SYSTEM PROBLEMS AFFECTING SAFETY-RELATED EQUIPMENT (GENERIC LETTER 89-13)

Purpose:

Nuclear power p l a n t f a c i l i t i e s o f 1 icensees and applicants must meet the minimum requirements o f t h e General Design C r i t e r i a (GDC) i n 10 CFR Part 50, Appendix A.

I n p a r t i c u l a r, "GDC 44--Cool i n g Water!' requires provision o f a system (here c a l l e d the service water system) " t o transfer heat from struc-tures, systems, and components,important t o safety t o an ultimate heat sink" (UHS).

"GDC 45--Inspection o f Cool i ng Water System" requires the system design

" t o permit appropriate *periodic inspection o f important components, such as heat exchangers and piping, t o assure the i n t e g r i t y and c a p a b i l i t y o f the system. I' "GDC 46--Testing o f Cooling Water System" requires the design " t o permit appropriate periodic pressure and functional testing. It I n addition, nuclear power p l a n t f a c i l i t i e s o f licens'ees and applicants must meet the minimum requirements f o r qual i t y assurance i n ' l O CFR Part 50, Appendix 0.

I n particular,Section X I, "Test Control,It requires t h a t "a t e s t program s h a l l be established t o assure t h a t a l l t e s t i n g required t o demonstrate t h a t structures, systems, and components w i l l perform s a t i s f a c t o r i l y i n service i s i d e n t i f i e d and performed i n accordance w i t h w r i t t e n t e s t procedures which incorporate the requirements and acceptance lirnits'contained i n applicable design documents. I' Recent operating experience and studies have l e d the'NRC t o question the compliance o f the service water systems ii the nuclear power plants o f 1 icensees and appl icants w i t h these GDC and qual i t y assurance requirements.

Therefore, t h i s Generic Letter i s being issued t o require licensees and appli-cants t o supply information about t h e i r respective service water systems t o assure the NRC o f such compliance'and t o confirm t h a t the safety functions o f t h e i r. respective service water systems are being met.

Background:

B u l l e t i n No. 81-03:

The NRC s t a f f has been studying the problems associated w i t h service water cooling systems f o r a number o f years.

A t Arkansas Nuclear One, Unit 2, on September 3, 1980, the 1 icensee shut down the p l a n t when the NRC Resident Inspector discovered t h a t the service water flow r a t e through the CONTACT:

C. Vernon Hodge; NRR 492-1169 I

e

+ r n 8 0 2 1 1 I%*

Generic Letter 89-13 July 18, 1989 containment cooling units d i d not meet the technical specification requirement.

The 1 icensee determined the cause t o be extensive flow blockage by Asiatic clams (Corbicula species, a non-native fresh water bivalve moll usk).

Prompted by t h i s event and a f t e r determining that it represented a generic problem o f safety significance, the NRC issued B u l l e t i n No. 81-03, "Flow Blockage o f Cooling Water t o Safety System Components by Corbicula sp. (Asiatic Clam) and Mytilus sp. (Mussel). I' The bul l e t i n required 1 icensees and appl icants t o assess macroscopic biological foul ing (biofoul i ng) problems a t t h e i r respective faci 1 i t i e s i n accordance with specific actions.

A careful assessment o f responses t o the bul l e t i n indicated t h a t existing and potential fouling problems are generally unique t o each f a c i 1 i t y ("Closeout o f I E B u l l e t i n 81-03... 'I, NUREGAR-3054), but that surpris-ingly, more than h a l f the 129 nuclear generating units active a t that time were considered t o have a high potential f o r biofouling.

A t t h a t time, the a c t i v i -

t i e s o f 1 icensees and appl icants f o r biofoul i ng detection and control ranged widely and, i n many instances, were judged inappropriate t o ensure safety system r e l i a b i l i t y.

Too few o f the f a c i l i t i e s with high potential f o r biofouling had adopted effective control programs.

Information Notice No. 81-21; After issuance o f B u l l e t i n No. 81-03, one event a t San Onofre Unit 1 and two events a t the Brunswick station indicated that conditions not e x p l i c i t l y discussed i n the b u l l e t i n can occur and cause loss of d i r e c t access t o the UHS.

These conditions include

1.

Flow blockage by debris from s h e l l f i s h other than Asiatic clams and blue mussels.

2.

Flow blockage i n heat exchangers causing high pressure drops that can deform baffles and a1 low flow t o bypass heat exchanger tubes.

3, A change i n operating conditions, such as a change from power opera-t i o n t o a lengthy outage, that permits a buildup o f biofouling organisms.

The NRC issued Information Notice No. 81-21 t o describe these events and concerns.

Generic Issue 51:

By March 1982, several reports o f serious fouling events caused by mud, s i l t, corrosion products, or aquatic bivalve organisms i n open-cycle service water systems had been received.

These events led t o plant shutdowns, reduced power operation f o r repairs and modifications, and degraded modes o f operation.

This situation l e d the NRC t o establish Generic Issue 51, "Improving the Re1 i a b i l i t y of Open-Cycle Service Water Systems. " To resolve t h i s issue, the NRC i n i t i a t e d a research program t o compare alternative surveillance and control programs t o minimize the effects o f fouling on plant safety.

I n i t i a l l y, the program was restricted t o a study o f biofouling, but i n 1987 the program was expanded t o also address fouling by mud, s i l t, and corrosion products.

This research program has recently been completed and the results have been published i n "Technical Findings Document f o r Generic Issue 51...," NUREG/

CR-5210.

The NRC has concluded that the issue w i l l be resolved when licensees

' Generic Letter 89-13 July 18, 1989 and 'applicants imp1 ement either the recommended surveil 1 ance and control program described below (Enclosure 1) or i t s equivalent f o r the service water system a t t h e i r respective f a c i l i ties.

Many 1 icensees experiencing service water macroscopic biofoul i ng problems a t t h e i r plants have found t h a t these techniques w i l l effectively prevent recurrence o f such problems.

The examina-ti on o f a1 ternative corrective action programs i s documented i n "Val ue/Impact Analysis f o r Generic Issue 51...,I1 NllREG/CR-5234.

Continuing Problems:

Since the advent o f Generic Issue 51, a considerable number o f events wi'th safety implications f o r the service water system have been reported.

A number o f these have been described i n information notices, which are l i s t e d i n "Information Notices Related t o Fouliqg Problems i n Service Water Systems" (Enclosure 3).

Several events have been reported w i t h i n the past 2 years:

Oconee Licensee Event Report (LER) 50-269/87-04, Rancho Seco LER 50-312/87-36, Catawba LER 50-414/88-12, and Trojan LER 50-344/88-29.

I n the f a l l o f 1988, the NRC conducted a special announced safety system functional inspection a t - t h e Surry station t o assess the operational readiness o f the service water and recirculation spray systems; A number o f regulatory viola-tions were i d e n t i f i e d (NRC Inspection Reports 50-280/88-32 and 50-281/88-32).

AEOD Case Study:

I n 1987, the Office f o r Analysis and Evaluation o f Operational Data (AEOD) i n the NRC i n i t i a t e d a systematic and comprehensive review and evaluation o f service water system failures and degradations a t l i g h t water reactors from 1980 t o early 1987.

The results o f t h i s AEOD case study are pub1 ished i n "Operating Experience Feedback Report - Service Water System Fai 1 ures and Degradations," NLIREG-1275, Vol ume 3 (Enclosure 4).

O f 980 operational events involving the service water system reported during t h i s period, 276 were deemed t o have potential generic safety significance.

A majority (58 percent) o f these events with generic significance involved system fouling.

The foul i n g mechanisms included corrosion and erosion (27 percent),

biofoul i ng (10 percent), foreign material and debris intrusion (10 percent),.

sediment deposition (9 percent), and pipe coating' f a i l u r e and calcium carbonate deposition (1 percent):

The second most frequently observed cause o f service water system degradations and failures i s personnel and procedural errors (17 percent), followed by seismic deficiencies (10 percent), single f a i 1 ures and other design deficien-cies (6 percent), flooding (4 percent), and gignif icant equipment f a i 1 ures (4 percent).

During t h i s period, 12 events involved a complete loss o f service water system function.

Several o f the significant causes 1 i sted above f o r system degrada-t i o n were also contributors t o these 12 events involving system failure.

The study i d e n t i f i e d the following actions as potential NRC requirements.

\\

1.

Conduct, on a regular basis, performallce t e s t i n g o f a1 1 heat exchang-ers, which are cooled by the service water system and which are needed t o perform a safety function, t o v e r i f y heat exchanger heat transfer capability.

Generic L e t t e r 89-13 3uly 18, i989

2.

Require licensees t o v e r i f y t h a t t h e i r service water systems are not vulnerable t o a single f a i l u r e o f an a c t i v e component.

3.

Inspect, on a regular basis, important portions o f the p i p i n g o f the service water system f o r corrosion, erosion, and biofouling.

4.

Reduce human errors i n t h e operation, repair, and maintenance o f the service water system.

Recommended Actions To Be Taken by Addressees:

On the basis o f the discussion above, t h e NRC requests t h a t licensees and applicants perform the following o r equally e f f e c t i v e actions t o ensure t h a t t h e i r service water systems are i n compliance and w i l l be maintained i n compliance w i t h 10 CFR Part 50, Appendix A, General Design C r i t e r i a 44, 45, and 46 and Appendix 0,Section X I.

I f a licensee o r applicant chooses a course o f a c t i o n d i f f e r e n t from the recommendations below, the licensee o r applicant should document and r e t a i n i n appropriate p l a n t records a j u s t i f i c a t i o n t h a t the heat removal requirements o f the service water system are s a t i s f i e d by use o f the a1 t e r n a t i v e program.

Because t h e c h a r a c t e r i s t i c s o f the service water system may be unique t o each f a c i l i t y, the service water system i s defined as the system o r systems t h a t t r a n s f e r heat from safety-related structures, systems, o r components t o the UHS.

I f an intermediate system i s used between the safety-related items and the system r e j e c t i n g heat t o the UHS, it performs the function o f a service water system and i s thus included i n the scope o f t h i s Generic Letter.

A closed-cycle system i s defined as a p a r t of the service water system t h a t i s not subject t o s i g n i f i c a n t sources o f contamination, one i n which water chemis-t r y i s controlled, and one i n which heat i s n o t d i r e c t l y rejected t o a heat sink.

I f a l l these conditions are not s a t i s f i e d, the system i s t o be consid-ered an open-cycle system i n regard t o the s p e c i f i c actions required below.

(The scope of closed cooling water systems i s discussed i n the i n d u s t r i a l standard "Operation and Maintenance o f Nuclear Power P l ants,I' ASME/ANSI OM-1987, P a r t 2. )

For open-cycle service water systems, implement and maintain an ongoing program o f surveillance and control techniques t o s i g n i f i -

c a n t l y reduce the incidence of flow blockage problems as a r e s u l t o f b i o f o u l ing.

A program acceptable t o t h e NRC i s described i n "Recom-mended Program t o Resolve Generic Issue 51" (Enclosure 1). It should be noted t h a t Enclosure 1 i s provided as guidance f o r an acceptable program.

An equal l y e f f e c t i v e program t o preclude b i o f o u l i n g would also be acceptable.

I n i t i a l a c t i v i t i e s should be completed before p l a n t startup f o l l o w i n g the f i r s t r e f u e l i n g outage beginning 9 months o r more a f t e r t h e date o f t h i s l e t t e r.

A l l a c t i v i t i e s should be documented and a1 1 relevant documentation should be retained i n appropriate p l a n t records.

11.

Conduct a t e s t program t o v e r i f y the heat t r a n s f e r c a p a b i l i t y o f a l l safety-related heat exchangers cooled by service water.

The t o t a l t e s t

~ e n e r i c Letter 89-13 I

July 18, 1989 program should consist of an initial t e s t program and a periodic retest program.

Both the initial t e s t program and the periodic retest program should include heat exchangers connected to or cooled by one or more open-cycle,systems as defined above.

Operating experience and studies indicate that cl osed-cycle service water systems, such as component cool i ng water systems, have,the potential for significant fouling as a consequence of aging-re1 ated in-1 eakage

, and erosion or corrosion.

The need for testing of closed-cycle system heat exchangers has not been considered necessary because of the assumed high qual.jty of existing chemistry control ~programs. If the adequacy of these chemistry control programs cannot be confirmed over the total operating history of the plant or if during the conduct of the total testing program any unexplained downward trend in heat exchanger performance is identified that cannot be remedied by maintenance of an open-cycle system, it, may. be necessary t o selectively extend the t e s t program and the routine inspection and maintenance program addressed i n Action 111, be1 ow, to the attached closed-cycle systems.

A program acceptable t o the NRC for heat exchanger testing is de-scribed i n "Program for Testing Heat Transfer Capabi 1 i ty" (Enclosure 2).

I t should be noted that Enclosure 2 is provided as guidance for an acceptable program.

An equally effective program to ensure satisfaction of the heat removal requirements of the service water system would a1 so be acceptable.

Testing should be done with necessary and sufficient instrumentation, though the instrumentation need not be permanently installed.

The relevant temperatures.should be verified to be w i t h i n design limits.

If similar or equivalent tests have not been performed during the past year, the i n i t i a l tests should be completed before plant startup foll owing' the f i r s t refueling outage beginning 9 months or more after the date of this letter.

As a part of the initial t e s t program, a licensee or applicant may decide t o take corrective action before testing..Tests should be performed for the heat exchangers after the corrective actions are taken to establish basellne data for future monitoring of heat exchanger performance.

In the periodic retest program, a,licensee or applicant should determine after three tests the best frequency for testing,to provide assurance that the equipment will -perform the intended safety functions during the intervals between tests.

Therefore, i n the periodic retest program, to-assi s t that determination, tests should be performed for the heat exchangers before any corrective actions are taken.

As i n the initial t e s t program, tests should, be repeated after any corrective actions are taken to establish,basel i ne data for future monitoring of heat exchanger performance.

An example of an alternative action that would be acceptable t o the NRC i s frequent regular maintenance of a heat exchanger in lieu of testing for degraded performance of the heat exchanger.

T h i s alter-native might apply to small heat exchangers, such as lube oil coolers or pump bearing coolers or readily serviceable heat exchangers-located i n low radiation areas of the facility.

Generic Letter 89-13 July 1#; 1989 I n implementing the continuing program f o r periodic retesting o f safety-re1 ated heat exchangers cooled by service water i n open-cycl e systems, the i n i t i a l frequency of testing should be a t least'once each fuel cycle, but a f t e r three tests, licensees and applicants should determine the best frequency f o r testing t o provide assurance that the equipment w i l l perform the intended safety functions during the intervals between tests and meet the requirements o f GDC 44, 45, and 46.

The minimum f i n a l testing frequency should be once every 5 years.

A summary o f the program should be documented, including the schedule f o r tests, and a l l relevant documentation should be retained i n appropriate plant records.

111. Ensure by establishing a routine inspection and maintenance program f o r open-cycle service water system piping and components that corrosion, erosion, protective coating failure, s i l t i n g, and biofouling cannot degrade the performance o f the safety-related systems supplied by service water.

The maintenance program should have a t least the following purposes:

A.

To remove excessive accumulations o f biofouling agents, corro-sion products, and s i l t ;

B.

To repai r defective protective coatings and corroded service water system piping and components that could adversely a f f e c t performance o f t h e i r intended safety functions.

This program should be established before plant startup f o l lowing the f i r s t refueling outage beginning 9 months a f t e r the date o f t h i s l e t t e r.

A description of the program and the results o f these mai ntenance inspections should be documented.

A1 1 re1 evant documen-t a t i o n should be retained i n appropriate plant records.

IV.

Confirm that the service water system w i l l perform i t s intended function i n accordance with the licensing basis f o r the plant.

Reconstitution o f the design basis o f the system i s not intended.

This confirmation should include a review of the a b i l i t y t o perform required safety functions i n the event o f f a i l u r e o f a single active component.

To ensure that the as-built system i s i n accordance with the appropriate 1 icensing basis documentation, t h i s confirmation should include recent (within the past 2 years) system walkdown inspections.

This confirmation should be completed before plant startup following the f i r s t refueling outage beginning 9 months or more a f t e r the date of t h i s l e t t e r.

Results should be documented and retained i n appropriate p l ant records.

V.

Confirm t h a t maintenance practices, operating and emergency proce-dures, and t r a i n i n g that involves the service water system are adequate t o ensure that safety-related equipment cooled by the service water system w i l l function as intended and that operators of t h i s equipment w i 11 perform effectively.

This confirmation should include recent (within the past 2 years) reviews o f practices, procedures, and t r a i n i n g modules.

The intent o f t h i s action i s t o

Generic Letter 89-13 July 18, 1989 reduce human errors i n the operation, repair, and maintenance o f the service water system.

This confirmation should be completed before plant startup following the f i r s t refu'eling outage beginning 9 months I

I' o r more a f t e r the date o f t h i s l e t t e r..Results should be documented,

and retained i n appropriate plant records.

Reporting Requi rements:

Pursuant t o the provisions o f Section 182a o f the Atomic Energy Act o f 1954, as amended, and 10 CFR 50.54(f),, each 1 icensee and applicant shall advise the NRC whether it has established programs t o implement Recommendations I - V o f t h i s Generic Letter o r t h a t it has pursued an equally effective alternative course o f action.

Each :addressee1 s response to' t h i s requirement f o r information shall be made t o the NRC w i t h i n '180 days of receipt o f t h i s Generic Letter.

Licensees and appl icants shall include schedules o f plans f o r imp1 ementation o f the various actions.

The detailed documentation associated,.

with t h i s "Generjc' Letter should be retained i n appropriate plant records'..

t Z

The response shall be submitted t o the appropriate regional adrni n i s t r i t o r under oath and affirmation under the provisions of Section 182a, Atomic Energy Act of.

1954, as amended and 10 CFR 50.54(f).

I n addition; the ori'ginal covek l e t t e r and a copy o f any attachment shall be transmitted t o the U.S.

Nuclear Kegu-1 atory Commi ssi on, Document Control Desk, Washington DC 20555, f o r reproduction and distribution.

i I n addition t o the 180-day response, each licensee and applicant shall confirm t o the NRC t h a t a1 1 the recommended actions or' their. j u s t i f i e d 'a1 ternatives have been implemented w i t h i n 30 days o f such implementatioh; This response need only be a single response t o indicate t h a t a l l i n i t i a l tests o r -act'ivities have been completed and t h a t continuing programsshave been'es'tablished.

This request i s covered by the Office o f Management and Budget Clearance Number 3150-0011, which expires December 31, 1989.

The estimated average burden i s 1000 man-hours per addressee response, including assessing the actions t o be taken, preparing the necessary plans, and preparing the 180-day response.

This estimated average burden pertains only t o these i d e n t i f i e d response-re1 ated matters and does not include the time f o r actual implementation o f the recom-mended actions.

Comments on the accuracy o f t h i s estimate and suggestions t o reduce the burden may be directed t o the Office o f Management and Budget, Reports Management, Room 3208, New Executive Office Building, Washington, DC 20503 and t o the U. S. Nuclear Regulatory Commission, Records and Reports Management Branch, Office o f Information and Resources Management, Washing-ton, DC 20555.

Although no specific request o r requirement i s intended, the following informa-t i o n would be helpful t o the NRC i n evaluating the cost o f t h i s Generic Letter:

1.

Addressee time necessary t o perform the requested confirmation and any needed follow-up actions.

2.

Addressee time necessary t o prepare the requested documentation.

Generic Letter 89-13 July 18, 1989 I f there are my questions regarding t h i s l e t t e r, please contact the regional administrator e f the appropriate NRC regional o f f i c e o r your project manager i n t h i s office.

Sincerely,

g.z?;ak J mes G. Partlow

~ d s o c i a t e Director for Projects Office of Nuclear Reactor Regulation

Enclosures:

1. "Rec-d Program t o Resolve Generic Issue 51"

2.

"Program f e r Testing Heat Transfer Capability"

3.

"Infwmation Notices Related t o Fouling Problems i n Service Water Systems"

4.

"Operating Experience Feedback Report - Service Water System Fai 1 ures and Degradations i n Light Water Reactors,'I NUREG-1275, Volum 3

5.

L i s t o f b s t Recently Issued Generic Letters RECOMMENDED PROGRAM TO RESOLVE GENERIC ISSUE 51 This enclosure describes a program acceptable t o t h e NRC f o r meeting the objectives o f the requested Action I i n the proposed generic l e t t e r.

Both Action I and t h i s enclosure are based upon,the recommendations described i n "Technical Findings Document f o r Generjc Issue 51:. Improving the Re1 i a b i 1 i ty o f Open-Cycle Service-Water Systems," NUREG/CR-5210, August 1988,' and "Value/Impact Analysis f o r Generic Issue 51:

Improving the Re1 i a b i 1 i ty o f Open-Cycle Service-Water Systems,I1 NllREG/CR-5234, February 1989.

The NRC has concluded t h a t Generic Issue 5 1 wi 11 be resolved when 1 icensees and applicants implement e i t h e r the recommended surveillance and control program addressed i n t h i s enclosure o r an equally e f f e c t i v e a l t e r n a t i v e course o f a c t i o n t o s a t i s f y the heat removal requirements o f the service water system.

Water Source Type Survei 11 ance Techniques Marine o r Estuarine A

(brackish) o r Freshwater w i t h clams Control Techniques B and C Freshwater without clams A and D B and C A.

The intake structure should be v i s u a l l y inspected, once per r e f u e l i n g cycle, f o r macroscopic b i 01 ogical f o u l i ng organisms ( f o r example, b l ue mussels a t marine plants, American oysters a t estuarine plants, and A s i a t i c clams a t freshwater plants), sediment, and corrosion.

Inspections should be performed e i t h e r by scuba divers o r by dewatering the intake s t r u c t u r e o r by other comparable methods.

Any f o u l i n g accumulations should be removed.

B.

The service water system should be continuously ( f o r example, during spawning) chlorinated (or equally e f f e c t i v e l y t r e a t e d w i t h another biocide) whenever the p o t e n t i a l f o r a macroscopic b i o l o g i c a l f o u l i n g species e x i s t s ( f o r example, blue mussels a t marine plants, American oysters a t estuarine plants, and A s i a t i c clams a t freshwater plants).

Chlorination o r equally e f f e c t i v e treatment i s included f o r freshwater p l a n t s without clams because it can help prevent m i c r o b i o l o g i c a l l y i n f l u -

enced corrosion.

However, the c h l o r i n a t i o n ( o r equally e f f e c t i v e )

treatment need not be as s t r i n g e n t f o r plants where t h e p o t e n t i a l f o r macroscopic b i 01 ogical f o u l i n g species does n o t e x i s t compared t o those plants where it does.

Precautions should be taken t o obey Federal, State, and 1 ocal environmental regulations regardi ng the use of b i ocides.

C.

Redundant and infrequently used cooling loops should be flushed and flow tested p e r i o d i c a l l y a t the maximum design flow t o ensure t h a t they are n o t fouled o r clogged.

Other components i n the service water system should be tested on a regular schedule t o ensure t h a t they are n o t fouled o r

clogged.

Service water cooling loops should be f i l l e d w i t h chlorinated o r equivalently treated water before layup.

Systems t h a t use raw service water as a source, such as some f i r e p r o t e c t i o n systems, should also be chlorinated o r equally e f f e c t i v e l y treated before layup t o help prevent microbiological l y influenced corrosion.

Precautions should be taken t o obey Federal, State, and l o c a l environmental regulations regarding the use o f biocides.

D.

Samples o f water and substrate should be collected annually t o determine i f A s i a t i c clams have populated the water source.

Water and substrate sampling i s only necessary a t freshwater plants t h a t have not previously detected the presence o f A s i a t i c clams i n t h e i r source water bodies.

I f A s i a t i c clams are detected, u t i l i t i e s may discontinue t h i s sampl i n g a c t i v i t y i f desired, and the c h l o r i n a t i o n (or equally e f f e c t i v e ) treatment program should be modified t o be i n agreement w i t h paragraph B, above.

PROGRAM FOR TESTING HEAT TRANSFER CAPABILITY This enclosure describes a program acceptable t o the NRC f o r meeting the objectives o f the requested Action I1 i n the proposed generic l e t t e r.

Both Action I1 and t h i s enclosure are based i n p a r t on "Operating Experience Feed-back Report - Service Water System Failures and Degradations," NUREG-1275, Volume 3, November 1988 and "Technical Findings Document f o r Generic Issue 51:

Improvi ng the Re1 i abi 1 i t y o f Open Cycle Service Water Systems," NlIREG/CR-5210, August 1988.

This enclosure ref1 ects continuing operational problems, inspection reports, and industry standards ("Operation and Maintenance of Nuclear Power Plants,It ASME/ANSI OM-1987, Part 2. ) The NRC requests 1 icensees and applicants t o implement either the steps addressed i n t h i s enclosure o r an equally effective alternative course o f action t o s a t i s f y the heat removal requirements o f the service water system.

Both the i n i t i a l t e s t program and the periodic r e t e s t program should include a l l safety-related heat exchangers connected t o o r cooled by one o r more open-cycle service water systems.

A closed-cycle system i s defined as a p a r t o f the service water system that i s not subject t o significant sources o f contamination, one i n which water chemistry i s controlled, and one i n which heat i s not d i r e c t l y rejected t o a heat sink.

(The scope o f closed cooling water systems i s discussed i n the industrial standard, "Operation and Ma i ntenance of Nucl ear Power Pl ants,Ii ASME/ANSI OM-1987, Part 2. ) I f duri ng the conduct o f the t o t a l testing program any unexplained downward trend i n heat exchanger performance i s i d e n t i f i e d that cannot be remedied by maintenance o f an open-cycle system, it may be necessary t o selectively extend the t e s t program t o the attached closed-cycle system.

Testing should be done with necessary and s u f f i c i e n t instrumentation, though the instrumentation need not be permanently i n s t a l 1 ed.

As a p a r t o f the i n i t i a l t e s t program, a licensee o r applicant may decide t o take corrective action before testing.

Tests should be performed f o r the heat exchangers a f t e r the corrective actions are taken t o establ i s h base1 ine data f o r future monitoring o f heat, exchanger performance.

I n the periodic retest program, a licensee o r applicant should determine a f t e r three tests the best frequency f o r testing t o provide assurance t h a t the equipment w i l l perform the intended safety functions during the intervals between tests.

Therefore, i n the periodic retest program, t o assist t h a t determination, tests should be performed f o r the heat exchangers before any corrective actions are taken.

As i n the i n i t i a l t e s t program, tests should be repeated a f t e r any corrective actions are taken t o establish baseline data f o r future monitoring o f heat exchanger performance.

An example o f an alternative action t h a t would be acceptable t o the NRC i s frequent regular maintenance of a heat exchanger i n l i e u o f testing f o r degraded performance o f the heat exchanger.

This a1 ternative might apply t o small heat exchangers, such as lube o i l coolers or pump bearing coolers o r readily serviceable heat exchangers located i n low radiation areas of the f a c i l i t y.

I n imp1 ementi ng the continuing program f o r periodic r e t e s t i n g o f safety-related heat exchangers cooled by service water i n open-cycle systems, the i n i t i a l frequency o f t e s t i n g should be a t l e a s t once each f u e l cycle, b u t a f t e r three t e s t s, licensees and applicants should determine the best frequency f o r t e s t i n g t o provide assurance t h a t the equipment w i l l perform the intended safety functions during the i n t e r v a l s between t e s t s and meet the requirements o f GDC 44, 45, and 46.

The minimum f i n a l t e s t i n g frequency should be once every 5 years.

I. For a1 1 heat exchangers Monitor and record cooling water flow and i n l e t and o u t l e t tempera-tures f o r a l l affected heat'exchangers during the modes o f operation i n which cooling water i s flowing through the heat exchanger.

For each measurement, v e r i f y t h a t the cooling water temperatures and flows are w i t h i n design 1 i m i t s f o r the conditions o f the measurement.

The t e s t r e s u l t s from p e r i o d i c t e s t i n g should be trended t o ensure t h a t flow blockage o r excessive f o u l i n g accumulation does not exist.

11.

I n a d d i t i o n t o the considerations f o r a l l heat exchangers i n Item I, f o r water-to-water heat exchangers A.

Perform functional t e s t i n g w i t h the heat exchanger operating, i f p r a c t i c a l, a t i t s design heat removal r a t e t o v e r i f y i t s capa-b i l i t i e s.

Temperature and flow compensation should be made i n t h e calculations t o adjust the r e s u l t s t o the design conditions.

Trend the r e s u l t s, as explained above, t o monitor degradation.

An example o f t h i s type of heat exchanger would be t h a t used t o cool a diesel generator.

Engine jacket water f l o w and tempera-t u r e and service water flow and temperature could be monitored and trended during the diesel generator survei 11 ance testing.

B.

I f it i s n o t p r a c t i c a l t o t e s t the heat exchanger a t the design heat removal rate, then trend t e s t r e s u l t s f o r the heat exchang-e r e f f i c i e n c y o r the overall heat t r a n s f e r c o e f f i c i e n t. V e r i f y t h a t heat removal would be adequate for the system operating w i t h the most l i m i t i n g combination o f flow and temperature.

111.

I n a d d i t i o n t o the considerations f o r a l l heat exchangers i n Item I, f o r air-to-water heat exchangers A.

Perform e f f i c i e n c y t e s t i n g ( f o r example, i n conjunction w i t h surveillance testing) w i t h the heat exchanger operating under the maximum heat load t h a t can be obtained p r a c t i c a l l y.

Test r e s u l t s should be corrected f o r the off-design conditions.

Design heat removal capacity should be v e r i f i e d.

Results should be' trended, as explained above, t o i d e n t i f y any degraded equipment.

0. If it i s notpossible t o t e s t the'heat exchanger t o p r o v i d e s t a t i s t i c a l l y significant results ( f o r example, i f error i n the measurement exceeds the value o f the parameter being measured),

then

1.

Trend t e s t results f o r both the a i r and water flow rates i n the heat exchanger.

2.

Perform visual inspections, where possible, o f both the a i r and water sides o f the heat exchanger t o ensure cleanliness o f the.heat exchanger.

I V.

I n addition t o the considerations f o r a l l heat exchangers i n Item I, f o r types of heat exchangers other than water-to-water o r a i r-to-water heat exchangers ( f o r example, penetration coolers, o i 1 coolers, and motor coolers)

A.

I f p l a n t conditions allow testing a t design heat removal condi-tions, v e r i f y t h a t the heatsexchanger performs i t s intended functions.

Trend the t e s t results, as explained above, t o monitor degradation.

B.

I f testing a t design conditions i s not possible, then provide f o r extrapolation o f t e s t data t o design conditions.

The heat exchanger efficiency o r the overall heat transfer coefficient o f the heat exchanger should be determined whenever possible. Where possible, provide f o r periodic visual inspection o f the heat exchanger.

Visual inspection o f a heat exchanger t h a t i s an integral p a r t o f a larger component can be performed during the regularly scheduled disassembly of the 1 arger component.

For example, a motor cooler can be visually inspected when the motor disassembly and inspection are scheduled.

NRC STAFF EXHIBIT 4

Pilgrim Nuclear Power Station License Renewal Application Technical Information 8.1.2 BURIED PIPING AND TANKS INSPECTION The Buried Piping and Tanks Inspection Program at PNPS is comparable to the program described in NUREG-1801,Section XI.M34, Buried Piping and Tanks Inspection.

This program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and titanium components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance.

A focused inspection will be performed within the first 10 years of the period of extended operation, unless an opport~~nistic inspection (or an inspection via a method that allows assessment of pipe condition without excavation) occurs within this ten-year period.

NUREG-1 801 Consistency The Buried Piping and Tanks lnspection Program at PNPS will be consistent with program attributes described in NUREG-1801,Section XI.M34, Buried Piping and Tanks Inspection, with one exception.

The Buried Piping and Tanks Inspection Program at PNPS will be consistent with program attributes described in NUREG-1801,Section XI.M34. Buried Piping and Tanks Inspection, with the following exception.

Attributes Affected

4.

Detection of Aging Effects Exception Inspections via methods that allow assessment of pipe condition without excavation may be substituted for inspections requiring excavation solely for the purpose of inspection.'

I I

I Exception Note

1. Methods such as phased array UT technology provide indication of wall thickness for buried piping without excavation. Use of such methods to identify the effects of aging is preferable to excavation for visual inspection, which could result in damage to coating or wrappings.

Appendix Aging Management Programs and Activities Page B-17

Pilgrim Nuclear Power Station License Renewal Application Technical Information Enhancements None The Buried Piping and Tanks lnspection Program at PNPS is a new program for which there is no operating experience.

Conclusion Implementation of the Buried Piping and Tanks lnspection Program will provide reasonable assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Appendix B Aging Management Programs and Activities Page 6-1 8

NRC STAFF EXHIBIT 5

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.28 SERVICE WATER INTEGRITY Proaram Description The Service Water lntegrity Program at PNPS is comparable to the program described in NUREG-1 801,Section XI.M20, Open-Cycle Cooling Water System.

This program relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the salt service water (SSW) system are managed for the period of extended operation. The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the SSW system or structures and components serviced by the SSW system.

NUREG-I 801 Consistency The Service Water lntegrity Program at PNPS is consistent with the program described in NUREG-1 801,Section XI.M20, Open-Cycle Cooling Water System with exceptions.

The Service Water lntegrity Program at PNPS is consistent with the program described in NUREG-1801,Section XI.M20, Open-Cycle Cooling Water System with the following exceptions.

Attributes Affected

2.

Preventive Actions

/ each refueling outage.2 Exception Notes Exceptions NUREG-1801 states that system components are lined or coated.

Components are lined or coated only where necessary to protect the underlying metal

5.

Monitoring and Trending

1. NUREG-1801 states that system components are constructed of appropriate materials and lined or coated to protect the underlying metal surfaces from being exposed to aggressive cooling water environments. Not all PNPS system components are lined or coated. Components are lined or coated only where necessary to protect the underlying metal surfaces.

surfaces.

NUREG-1 801 states that testing and inspections are performed annually and during refueling outages. The PNPS program requires tests and inspections Appendix B Aging Management Programs and Activities Page B-92

Pilgrim Nuclear Power Station License Renewal Application Technical Information

2. NUREG-1801 program entails testing and inspections performed annually and during refueling outages. The PNPS program requires tests and inspections each refueling outage, but not annually. Since aging effects are typically manifested over several years, the difference in inspection and testing frequency is insignificant.

Enhancements None Results of heat transfer capability testing of the reactor building closed cooling water (RBCCW) heat exchangers from 2001 through 2004 show that the heat exchangers are capable of removing the required amount of heat. Confirmation of adequate thermal 'performance provides evidence that the program is effective for managing fouling of SSW cooled heat exchangers.

Results of SSW visual inspections, eddy current testing, ultrasonic testing, and radiography testing from 1998 through 2004 revealed areas of erosion and areas of corrosion on internal and external surfaces. SSW butterfly valves, pump discharge check valves, air removal valves, and pipe spools have been replaced with components made of corrosion resistant materials. Also, RBCCW heat exchanger channel assemblies have been replaced and tubes have been sleeved to address erosion and corrosion. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing loss of material for SSW system components.

Visual inspections of SSW piping revealed degradation of the lining in original SSW carbon steel rubber lined piping. Pipe lining is intended to protect pipe internal surfaces from erosion and corrosion. Therefore, SSW piping has been replaced with carbon steel pipe with cured-in-place rubber lining, relined with a ceramic epoxy compound, or replaced with titanium pipe.

ldentification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing loss of material for SSW system components.

Conclusion The Service Water Integrity Program has been effective at managing aging effects. The Service Water lntegrity Program provides reasonable assurance that effects of aging will be managed such that applicable components will continue to perform their intended function consistent with the current licensing basis for the period of extended operation.

Appendix B Aging Management Programs and Activities Page B-93

NRC STAFF EXHIBIT 6

confirmed that their implementation prior to the period of extended operation would make the existing AMP consistent with the GALL AMP to which it was compared. The.staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement A.2.1.28 for this AMP and concludes that it provides (pending incorporation of the applicant's commitments) an adequate summary description of the program, as required by 10 CFR' 54.21(d).,

3.0.3.2.16 Service Water lntegrity program Summary of Technical 'Information in the Application. LRA Section B.1.28, "Service Water Integrity," describes the existing Service Water lntegrity Program as consistent, with exceptions, with GALL AMP XI.M20, "Open-Cycle. Cooling Water System."

This program relies on implementation of the recommendations of GL 89-13 to manage the

effects of aging on the SSW system for the period of extended operation. The program includes surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the SSW system or structures and components it services.

Staff valuation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report and documented a detailed audit evaluation of this AMP in Audit and Review Report Section 3.0.3.2.16. The staff reviewed the exceptions to determine whether the AMP remained adequate to manage the aging effects for which it is credited.

The staff reviewed those portions of the Service Water lntegrity Program for which the applicant claims consistency with GALL AMP XI.M20 and found them consistent. Furthermore, the staff concludes that the applicant's Service Water lntegrity Program reasonably assures management of aging effects so components crediting this program can perform intended functions consistent with the CLB during the period of extended operation. The staff finds the applicant's Service Water lntegrity Program acceptable as consistent with the recommended GALL AMP XI.M20, "Service Water Integrity," with exceptions as described:

Exception 1. The LRA states an exception to the GALL Report program element "preventive actions," specifically:

NUREG-1801 states that system components are lined or coated. Components are lined or coated only where necessary to protect the underlying metal surfaces.

The LRA states that the GALL Report states that system components are constructed.of appropriate materials and lined or coated to protect the underlying metal surfaces from exposure to aggressive cooling water environments. Not all system components are lined or coated, only where necessary to protect the underlying metal surfaces.

During the audit and review, the staff asked the applicant for applications in which components are not coated or lined and the materials of construction.

The applicant responded that the SSW supply piping is constructed of titanium, a material which has shown excellent corrosion.resistance in this environment. The other components in the SSW supply are small-bore piping for vents and drains, pump and valve bodies, and heat exchanger tubes. All of these components are constructed of copper alloys with demonstrated good corrosion resistance in this environment and operating experience shows that the Service Water Integrity Program manages loss of material and takes corrective action before loss of component intended functions.

On this basis, the staff finds the exception acceptable.

Exception 2. The LRA states an exception to the GALL Report program element 'monitoring and

'trending," specifically:

NUREG-1801 states that testing and inspections are performed annually and during RFOs. The PNPS program requires tesis and inspections during each RFO.

The LRA states that the GALL Report program entails testing and inspections annually and during RFOs. The applicant's program requires tests and inspections during each RFO but not annually. As aging effects typically are manifested over several years, the difference in inspection and testing frequency is insignificant.

During the audit and review, the staff evaluated the applicant's inspection interval and agreed that adverse conditions caused by the agirlg effects in the service water systems manifest over several years. Operating experience shows that a two-year interval has not led to adverse service water system operating conditions; therefore, the difference between a one-year and two-year inspection and testing frequency is insignificant.

On this basis, the staff finds the exception acceptable.

In addition, the applicant stated that it will enhance this program to clarify the procedures for trending heat transfer test results (Commitment No. 24). The staff finds this acceptable.

Operating Experience. LRA Section B.1.28 states that results of heat transfer capability testing of the reactor building closed cooling water (RBCCW) heat exchangers from 2001 through 2004 show that the heat exchangers can remove the required amount of heat. Confirmation of adequate heat removal provides evidence that the program effectively manages fouling of SSW-cooled heat exchangers.

Results of SSW visual inspections, eddy current testing, UT, and radiography testing from 1998 through 2004 revealed areas of erosion and corrosion on internal and external surfaces. SSW butterfly valves, pump discharge check valves, air removal valves, and pipe spools have been replaced with components made of corrosion-resistant materials, RBCCW heat exchanger channel assemblies have been replaced, and tubes have been sleeved to address erosion and corrosion. Revelation of degradation and corrective action prior to loss of intended function provide evidence that the program effectively manages loss of material for SSW system components.

Visual inspections of SSW piping revealed degradation of the lining in original SSW carbon s'teel

rubber-lined piping intended to protect pipe internal surfaces from erosion and corrosion.

Therefore, SSW piping has been replaced with carbon steel pipe with rubber lining cured in place, relined with a ceramic epoxy compound, or replaced with titanium pipe. Revelation of degradation and corrective action prior to loss of intended function provide evidence that the program effectively manages loss of material for SSW system components.

The staff reviewed the operating experience presented in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience.

The staff confirmed that the "operating experiencen program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A.2.1.30, the applicant provided the UFSAR supplement for the Service Water lntegrity Program. The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audif and review of the applicant's Service Water lntegrity Program, the staff determines that those program elements for which the applicant claimed consistency with the GALL Report are consistent. In addition,.the staff reviewed the exceptions and their justifications and determined that the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes t h d it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.17 Structures Monitoring Program Summary of.~echnical' Information in the Application. LRA Section 8.1.29.2, "Stiuctures Monitoring," describes the existing Structures Monitoring Program as consistent,'with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program."

Structures monitoring in accordance with 10 CFR 50.65 (Maintenance Rule) is addressed in Regulatory Guide 1.I60 and Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants 93-01. These two documents guide development of licensee-specific programs to monitor the condition of structures and structural components within the scope of the Maintenance Rule so there is no loss of structure or structural component intended function.

As protective coatings are not relied upon to manage aging effects for structures in the Structures Monitoring Program, the program does not address protective coating monitoring and maintenance.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report and documented a detailed audit evaluation of this,AMP in Audit and Review Report Section 3.0.3.2.17. The staff reviewed the enhancements to determine whether the AMP remained adequate to manage the aging effects for which it is credited.

NRC STAFF EXHIBIT 7

K.ARR.ATI\\'E (Rcv. 2)

A.

D E

Problcm Sla~cnrnt: Salt Scrvicc Water (SSIV') A Loop pipc spmls JF 29.1 I4 and 5. md B Loop pipc s p l s JF 29-15-5 and 6, arc dcgndd and m y q u i r t rcplaccmcn~. Ttrcsc scc~ions of pipc arc lmed in lllc sxd a m jun ID lhc south of the circulating !cur infakc and seal wd] strumrcs, mind \\rill rquin: a shard cscawion appro.xirnntcly 10 8. \\+idc by 90 fl. long by I2 ft. dcxp (400 cu.yl. of rnatcrial).

hisintaunce activity undpr a scparatc pachgc.

Design \\rrrdi is being pcrformcd in phases lo suppon 'm cxpcditcd schcdulc for irnplcrncnration. Phvc 1 is bcing rclcsscd at this time. If additional p h c r or other dmgcs arc rquircd drc). will be rcfmcd using rhc thc FRV praccss.

P h a I - This scopc cavcrs rhc dcsign af rhc cxcajrion boundcd by Piks 1E chrough 9E, and IW through 9iY. to access ID A toop pipc spool JF 29-1 1-5. and B Limp pipc spool JF 29-13-6. This scapc INS prctioul!. rclrsrscd for inplcmcntation undcr chc Exhibit 5B process (NOP83EI). This P h c 1 scapc is incorpontcd now as pan of rhi PDC.

Thc fallowino clarifimlions arc prooidcd to dclmc~clnc safc~r. rclarcd imoacq:

In-sir^ maturial snd backfill (LC. struaunl fill or flo\\\\ablc 511) phccd undcr Ihc SSW pipc, and bilckfiil.

p(cd around and abvc thc SSSW prpc far a d~smce of 2 kt o w the top. providcs support and prorcaion for dcsign condidons. a d IS considend Class 1.

Rctaining structures supponing soils not affcci~ne sarcry rclaicd componcm pcrfomi no s;lfc~!. function

\\vih rcspcct lo dlc SS\\V pipc during th~s modifics~on. md arc considcrcd Chss 11. No11 SafcryRchcd.

backfill ouu~dr: Class I lin~i~s is cons~dcrud Class 11. Non Saic~y-Rclatcdd.

Ihc SS\\Y PIP is co~isidcrcd opablc from it c~r?listructural pcrspcc~ivc \\\\IICII prntcr~cd Ily backfill laring! 3 tllicknccs o f 4 rcct ovcr tlic I O ~

of dw PIP

~in~ntcnar~cs Rg!cChps: No~ic

B, PROCUKEMEN'I'OF hlA1'ERIt~l,SICOMPQNEN7~

EYQIJI~

soils \\\\-ill hc wad 10 k d rtlx nqkmxncnt pip d for backfill. Floi~blc fill may also bc uscd in rc]c~~cd locations, procud by CGI for Clus I qplicadons, and pcr the GEI Spccifiwdan for Clus I1 appliotions. Marcrials sprxificd for construclioll of Ihc excrrmtion a d ssocia[Cd suppon slruc[urcs may bc prohlrcd Non-Q. It is mticipatcd that most of thcscmtcrials will bc hmishcd by Lhc contractor C.

CONTROLLED D0C:UMENTS~RhlNING AFFECTED PNPS Procdurcs Nonc Vendor Manuals Nonc Technical Spccifru6ons:

Nonc Priority A Dcsign Da-umcnts:

Nonc Priorily B Dcsign Dmrncnts:

Dndng C20 FSAR Sections:

NMC Opcrnlor Tnining:

Nonc Tcchniml Tmining.

Nonc D. DOCUMENTS GOV'ERNIKG DESIGN AND MSTALLATION BECo Dniiing C20-J-REP GEI Dmiing ES-I GEI Gwlcchnid Spccificaaon for SS\\V Piping Rcplaecrncn~

E SAFETY IMPACT DURIh'G IMPLEMENTATION

-4s discussed prctiously, SS\\V pipu rcptaccmcnt acthirics dl1 tnlic phcc when thc plml is in n cold condition, and decay hurt rcmoval is being pcrformcd indcpcndcntly by r third SSW rcturn linc insldlcd undcr.Tcmponry

!iIodifiwrion 99-35. Coruquy[l!.. both thc A and B Loop SSW rctum lincs ttill bo out-af-scrvicc. and not roquircd to be pcrfonnin~. or aiailablc to pcrform, safety functions during this timc, k a rcsuh, afc[y impacts during implmcnhtion arc timircd to rhc prorcciion of othcr nfcty rcl;ucd components ti*hich could bc aficrcd by constmclion actiiitics. This a.ould includc for c.sim~plc, dw Appcndis R Manholc 28A and associntcd duct banks

~rnmcdiatcly djdjaccnl 10 thc propscd csuvation timil, and my othcr itcrns having w&ty rda~cd fimctions tvhicli arc ~iirhin. or in closc prosimlry of. lllc osmvation as dctcnincd by Engineering.

NIi3 211 RCV I

... / _ _.....................

s,--J--i-,.,<

....I I.-.'..

L...,

s..,....

I. I.....

F. mSIGN ADEOill\\<.It:

E'IUVJ~~MI for possiblc rtphcmlcnt of dcgndcd SSW p i p dl1 bc momplishcd u-ilhin a soldicr pildtirnbcr s h a ~ i n g structurc, e n ~ u t ~ ~ r c d lo mist Inlcnl soil prcssurc. During drilling J R ~

cstxiwlion activirics, both tho A md 0 Loop SSW rcturn lincs \\\\*ill bc outqkcrvicc, md not rcquircd to be perfomling, or n\\ailablc to pcrfonn, s a f q functions. Othcr safety rckrtcd componcnls which could be affccccd by c~nrtruclion activities arc pratcctcd by structures d a i p c d to Class 11 o\\,cr Class I crircria, Dig ssfc m w r a bavc includcd cs~cnsivo dn&g scarchcs to identic buricd wmponcnB. Ground d c ~ i o n n&r h;ls ban emp10p~I to augncnt this cRbrt. Holcs for augcr drilltq \\rill bc lbc~tcd by sunq and individually app~ovcd prior to drillins. 7hcsc rnmurcs cannot gunmtcc all burid componcnls h v c bccn idcntificd a d prcciscly Iwtcd. imcc thcrc is somc potcnzinl h t unidcntificd itcm could bc dma~crf during drilling and cstxr~qon adsilia. Nc~crthclcss, msonablc assumcc is protidcd d J ssTL.1~ rclaed componcnts, aid componcnts csscnlid 10 powwr gcr~cration, wi!\\ nor bc afftctcd.

E?tuvarcd maccrials ~s-ill tx controlled in accordance with dialogical proccdums. hI;rtCriais d l 1 bc nockpilcd in a manner consistent jwi\\ilh Security considcmtions. Exa\\a~cd soil wtcrids \\till hc rcplaccd in accordurcr: \\\\j&

spceifiwtions for controlled S ~ N C ~ U ~

bilckfill.

G. M I

A PF I

r Bjckfilling around and ovcr rcpl~ccmcnt SSW pipc shall not bc prmittcd to p r w d until completion ofncccsssry pipc installntion inspections ~s m y bc mquircd by thc associated niod~fic;l~icn packngc.

I Testing of mtcrkls for Class 1 bcddil~g and backfill under. uound and above rr.placcrncnt SSN' pipc sIta13 bc

~crfonncd in ~ccordmcc with ttx GEI Sixxifiation and BECo Contn~trcin\\ Gtadc 11cm (CGI) documcm a.5 r ' Flmvablc fill (A con~rollcd dcnsity fill) uscd for backfill sllnll bc inspcctod in sccordutu: \\vith thc rquircmcnrs offic appliablc CGI, If a conflict csists b c n r m Ihc GEI Spccifiwtia~ and Lhc BECo CGI. thc hucr shalt ha\\% prcccdcncc, 11c pipc shall bc properly mchorcd to prrymf floution. CGI dcdiclltion for flooctblc fill u s d for Class I applications sltdl bc rcrififd by Quality Conlrol pcrsonncl.

Soil backfill shall rc-ttsc cscnatcd matcrids, and In thc scquuncc spreificd in 111~ "Plm for Ibdiologicnl Controls" (Xantiyc Paragraph I.). Thc bcdding maunaI providing supper( lo thc imrn af tftc pipo shll comp~crcd 10 thc rcquiromcnls OT~IIC GEi Spccificntion for Zonc A mtcrial lo h c cstcnt ncccssar)' based on dislurbvrm of tlic subgndc. All odlcr soil backfill around.uld abo\\'c thc pipc sltall bc compactd ta thc rquircmcnrs of tllc GEI Spcdfimion for Zone rnatcnal. Comp~nion tuling for soils uscd for Clss I applications sllall bc wrificd by Quality Control pcrsonncl.

Soil retaining strucrurcs dcsigncd to s~rpprl tlic wcavanon wmlls md cons~dcrcd Chss 11. hlmagcmcnr Q. sldl hc hspcc~cd ro cnsurc rq~tircrncnts orllu: d n ~ i n g s and spcctfic~t~ons arc follo\\vcd. In-proccss sun~cillancc inspction on a saniplo basis shdl bc pcrfomlcd. No s~scial tcstlng 6 roqu~rtd Inspection of Clss I[. Son SaTctylblalcd work is not rcqu~rd if FXJhfPOSEh'T NUhIUEKINC!.5:j~N,GJ n;r I

,\\l,.l.&hj>~SJF>~K.iu:~;

XI:\\ Th~s \\sark 1s being pzrionncd aursrdc tlrc RCA

J.

WPUT FOR MAINTENANCE WORK PLAN

~ s c a ~ ~ t i a n Plan The. cxca\\arion conlnctor shall &\\rlop a propscd plan for BECO approval, for Lhc location a d configuration of stdpilcs of cxcawtcd m3rcrids. hhtckd stockpiles shall bc Iocatcd a d controlled in a m c r which prceludcs rhc possibility of dmging cornponcnts asociatcd wirh Tunponty Modification 99-35, or othcr wmponcnts in thc arm. Lincs of sight rquired by Sccuric). sMl bc prcscrved to h maximum cxtcnt possible. Thc plan shall include pro\\isions to idcntie thc lmrions of cvisting paving joinrs asociatcd with prcviour repairs. This data likcly indiurcr buricd utilities 5vhich if not already show5n on BECo csm~!ion drawings, rniiy rcquirc tcst pits to pcrmii idcntifiwtion.

Hola to bc augcrcd for soldicr pilcs sMl bc locatcd by r sun.c?: Each holc location shlt bc nppru\\d by Engineering prior to bcing drilled. Test pits sW1 bc dug by h d \\vhm dinclcd by tltc Engineering as n c c c s q to loci-& potaual drilling obrtructions. Escas;~tcd mtcriaIs sU1 be controlled in acwrdiuacc \\vith tho ndiologiiul requirements. Soils sldl be rc-uscd during thc backfilling!~~~tantioa phase W thc maximurn extcnt p i b l c. As dctcrmincd by Enginaring, no l a ~ c rocks shdI be pcrmittcd lo be placcd in contact w~ith undcqmund quipmcnt during backfilling activities. Thc miximum sizc of gravcl in thc backfill \\\\ithin onc foot of thc pipc should bc no lager than abaul2".

Plan for Radiological Controls Radiological considcntions uill rcquirt c x a n t d matcrials lo bc scgrcptcd a d controlled in a prcscribcd fyhion.

n i s plm for cornrol my bc modified in-proccss at ~ h c direction of Ihc RPM or dcsipatcd rcprcscntativc. Thc follodng definitions arc applied lo lqcrs of mtcrials to bc cscatcd:

h m

Pcscriuiion Laycr A Bituminous ssphjl~ pawing mtcrinls h y c r B Thc 6" soil Iaycr immcdratcly bcncath Laycr A Lycr C Thc 6" soil h!.cr immcdiaccly bcncath kycr B kycr D All orhcr soils bcn~th L?cr C L y c r X paving matcrials shall be sockpilid in a scgrcgatcd ara for prc-rchc radiolcgid sunw prior to disposal o r silc. 'l'l~c mcthod of mavation ~vould prcfcrably rcsult in intnct picca or paving, minimizing thc mounts of lwsc imtcgatu \\\\%ich is mow cxpmnsivc to proccss for disposal.

Lysr B, C md D soil matcri;Lf~ shall be srmliiilcd in diffcml lodons during tic c?rw\\~tion procuss. 71csc marcrials shall bc propcrly idcntificd a d contmllcd to prcvcnt from bcing miscd togcthcr. Thc backfilling squcncc shall bc is followvs: Laycr D soil rna~crinls shall bt rcplnccd first, iollo\\trd by Laycr C. followed by Lqcr B.

Stccl pila shall bc cut ofT approsinmtc.ly Z R. bclow finish grdc and abmdoncd-in-placc. Prcsn~rc t m t d tinlbcr shcathmg rng. bc sbandnncd-ill-placc. tin~hcr slm~hing no1 prcssurc ~rccltcd.'shall bc rcn~ovcd prior to backfilling.

Rcplaccrn~n~

of csca\\atcd soils stlnll bc ;lccomplisl~cd in accordvlcc wit11 *IC following scqucncc: LI)IL.T D soil mntcrinls shall bc rcplaccd first, up to lu p~vious clwation. followvcd by hycr C. follo\\~cd by Laycr B.

ChLT: ION: For rnrioos rcasons, n 1s cspcctcd thcrc \\will bc csta Lycr D niatcrial mailling nfkcr il lras bccn rrslorsd to prcsscavatlon clcvmio~rr Ttlls is acccptablc and dwirablr: sincs thcrc niust bc a surticic~n \\.olanrc to rtplacc a11 Laycr C and U nlatcrmls In thclr original locarions in tBc csca~ation.

thckfill shall bc conlpnctsd as rcquircd b! BIG spccificntion. IVIrlrcrc. conditions may prcclridc accomplislmvn~ of h'i'3.2O Rcv. I

NRC STAFF EXHIBIT 8

required by 10 CFR 54.21 (d).

3.'0.3.1.13 Water Chemistry Control - BWR Proglim Summary of Technical Information in the Application. LRA Section 6.1.32.2; 'Water Chemistry, Control - BWR," describes the existing Water Chemistry Control-BWR Program as consistent with GALL AMP XI.M2, "Water Chemistry."

To manage aging effects.caused by corrosion and cracking mechanisms the program relies on monitoring and control of water chemistry based on EPRl Report 1008192 (Boiling Water Reactor Vessel and lnternals Project (6WRVIP)-130). BWRVIP-130 has three sets of guidelines: for primary water; for condensate and feedwater; and for control rod drive (CRD) mechanism cooling water. EPRl guidelines in BWRVIP-130 also include recommendations for controlling water chemistry in the torus, condensate storage tanks, demineralized water storage tanks, and spent fuel pool. The Water Chemistry Control - BWR Program optimizes the primary water chemistry to minimize potential loss of material and cracking by limiting causative '

contaminant levels in the reactor coolant system. Additionally, the applicant has instituted hydrogen water chemistry to limit the potential for intergranular stress corrosion cracking (IGSCC) through the reduction of dissolved oxygen in the treated water.

Staff Evaluation. During its audit and review, the staff confirmed theapplicant's claim of consistency with the GALL Report and documented a detailed evaluation of this AMP in Audit and Review Report Section. 3.0.3.1.. 13.

GALL AMP XI.M2 recommends that for 'susceptible locations" a one-time inspection program verification program may be appropriate. 'The staff asked the applicant whether it intended to implement a one-time inspection program for this water chemistry control program and, if so, why this intent is not included in the UFSAR supplement, Appendix A.

In response, the applicant stated that the One-Time lnspection Program described in LRA Section 8.1.23 includes inspections to verify the effectiveness of the water chemistry control AMPS by confirming that' unacceptable cracking, loss of material, and fouling has not occurred.

The discussions in LRA Section 3, Table 1 link the One-Time lnspection Program and water chemistry control programs for susceptible components; however, for clarity, in its.response dated July 19, 2006, the applicant stated that the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water Programs is confirmed by the One-Time lnspection Program.

With the change to Appendix A the staff finds the applicant's response'acceptable.

'The staff finds the applicant's Water Chemistry - BWR Program acceptable as consistent with the recommended GALL AMP XI.M2, "Water Chemistry."

Operating Experience. LRA Section 8.1.32.2 states that from 1998 through 2004 after several condition reports of adverse trends in parameters monitored by the Water Chemistry Control - BWR Program the applicant acted within the corrective action program to preclude unacceptable parameter values. Continuous confirmation of water quality and corrective actions taken before adverse trends reach control limits provide evidence that the program effectively manages component aging effects. From 1998 through 2004, after several condition reports of 3-34

parameters monitored by the Water Chemistry Control - BWR Program were outside administrative limits but still within EPRl acceptance criteria and the applicant acted within the corrective action program to preclude violations of EPRl acceptance criteria. Continuous confirmation of water quality and corrective action before parameters reach control limits provide evidence that the program effectively manages component aging effects.

From 1998 through 2004, there were two incidents in which.parameters monitored by the Water Chemistry Control-BWR Program were outside of EPRl acceptance criteria:

(1)

Following a power outage on March 29, 2002, dissolved oxygen measurement from the B high-pressure feedwater (HPFW) train was -28 ppb below the minimum required reading of 30 ppb (EPRI action level 1). Dissolved oxygen measured from the A HPFW train and condensate demineralizer effluent (CDE) were acceptable (- 70 to 80 ppb). The root cause was B HPFW sample line contamination, not actually low oxygen in the feedwater. The B HPFW sample line was replaced.

(2)

On October 28, 2002, HPFW and CDE dissolved oxygen levels spiked to 400 to 500 ppb for about 15 minutes before returning to normal. EPRl action level 1 for HPFW dissolved oxygen is 200 ppb. The root cause was inadequate filling of the D demineralizer prior to its return to service. The procedure states, "It is EXTREMELY important that all air is vented from a Cond Demin before it is placed in service to prevent air injection into the Feedwater System." Procedural steps were emphasized for proper venting to mitigate elevated oxygen levels in the feedwater system.

The applicant further stated that continuous confirmation of water quality and timely corrective action provide evidence that the program effectively manages component aging effects. QA audits in 2000 and 2002 revealed no issues or findings with impact on program effectiveness. A QA audit in 2004 revealed that reactor coolant sodium and 1ithium.analyses had not been weekly during the first half of 2004. The applicant took corrective action to replace the analysis

'instrument and to complete the analyses as required. A corporate assessment in 2003 found areas for improvement in administrative controls but no issues or findings with impact on program effectiveness.

The staff also reviewed the operating experience presented in the LRA and interviewed the applicant's technical personnel to confirm that the plant-specific operating experience revealed no degradation not bounded by industry experience.

The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10.'The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A.2.1.37, the applicant provided the UFSAR supplement for the Water Chemistry Control - BWR Program. The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21(d).

conclusion. On the basis of its audit and review of the applicant's Water Chemistry Control - BWR Program, the staff finds all program elements consistent with the GALL Report.

The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by A0 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2 AMPS That Are consistent with the GALL Report with Exceptions and/or Enhancements In LRA Appendix B, the applicant stated that the following AMPS are, or will be, consistent with the GALL Report with exceptions or enhancements:

Buried Piping and Tanks lnspection Program BWR CRD Return Line Nozzle Program BWR Feedwater Nozzle Program BWR Penetrations Program BWR Stress Corrosion Cracking Program BWR Vessel ID Attachment Welds Program BWR Vessels lnternals Program Diesel Fuel Monitoring Program

'Fatigue Monitoring Program Fire Protection Program Fire Water System Program Metal-Enclosed Bus lnspection Program Oil Analysis Program Reactor Head Closure Studs Program Reactor Vessel Surveillance Program Service Water Integrity Program Structures Monitoring Program Water Control Structures Monitoring Program Water Chemistry Control - Closed Cooling Water Program For AMPS that the applicant claimed are consistent with the GALL Report, with exception(s) andlor enhancement(s), the staff performed an audit and review to confirm that those attributes or features of the program for which the applicant claimed consistency were indeed consistent.

The staff also reviewed the exception(s) andlor enhancement(s) to the GALL Report to determine whether they were acceptable and adequate. The results of the staffs audits and reviews are documented in the following sections.

3.0.3.2.1 Buried Piping and Tanks lnspection Program Summary of Technical Information in the Application. LRA Section 8.1.2; 'Buried Piping and Tanks Inspection," describes the new Buried Piping and Tanks lnspection Program as consistent, with exception; with GALL.AMP XI.M34, "Buried Piping and Tanks Inspection."

This program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and titanium components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are

NRC STAFF EXHIBIT 9

Based on its review, the staff finds the response acceptable because'the applicant will review plant-specific operating experience against the industry experience described in the GALL Report., With additional operating experience lessons learned, the applicant can adjust the program elements.

On the basis of its review of the operating experience and discussions with the applicant's technical personnel, the staff concludes that the applicant's Non-EQ lnsulated Cables and Connections Program will adequately manage the aging effects for which this AMP is credited.

The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section ~.2.1.23, the applicant provided the UFSAR supplement for the Non-EQ lnsulated Cables and Connections Program. In a letter dated September 13, 2006, the applicant stated that it will implement the Non-EQ lnsulated Cables and Connections Program as described in LRA Section B.1.21 before the period of extended operation (Commitment No. 17).

The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Non-EQ lnsulated Cables and Connections Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.8 One-Time lnspection Program Summary of Technical Information in the Application. LRA Section B.1.23, "One-Time Inspection," describes the new One-Time lnspection Program as consistent with GALL AMPS XI.M32, "One-Time Inspection," and ~ 1. ~ 3 5,

"0nG~ime lnspection of ASME Code Class I Small-Bore Piping."

The One7Tirne lnspection Program will be implemented prior to the period of extended operation. The one-time inspection activity for small-bore piping in the reactor coolant system and systems that form the reactor coolant pressure boundary will be comparable to GALL AMP. XI.M35 and verify the effectiveness of the AMP to confirm the absence of aging effects.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of consistency with the GALL Report and documented a detailed evaluation of this AMP in Audit and Review Report Section 3.0.3.1.a.

During the audit and review, the staff asked the applicant how the sample of piping welds four inches and smaller will be selected for nondestructive examination.

The applicant responded that the 0ne:~ime Inspection Program will inspect small-bore piping in the reactor coolant system and systems that form the reactor coolant,pressure boundary. This inspection will include a statistically significant sample of welds of each material and environment combination in Class I piping equal to.or less than 4-inch nominal pipe size (NPS).

The initial population will include all Class.I small-bore piping, and.actual locations will be selected for physical location, exposure levels, nondestructive examination (NDE) techniques, and locations specified in NRC Information Notice (IN) 97-46, "Un-lsolable Crack'in High-Pressure Injection Piping.".The staff further asked the applicant to clarify whether it uses volumetric examinations to detect cracking in butt welds.

In its response, the applicant revised the program evaluation report to state:

Combinations of non-destructive examinations (including VT-1, enhanced VT-1, ultrasonic, and surface techniques) will be performed by qualified personnel following procedures that are consistent with Section XI of ASME Code and 10CFR50. Appendix B. Volumetric examinations are used to detect cracking in butt welds. Actual inspection locations will be based on physical accessibility, exposure levels, NDE techniques and locations identified in NRC IN 97-46, "Un-isolable Crack in High-Pressure Injection piping."

Based on the above, the staff found the response acceptable.

During the audit and review, the staff asked the applicant how it will handle the aging of small piping socket welds.

I The applicant responded that during the fourth inservice inspection (ISI) interval it plans both VT-2 and penetrant testing (PT) examinations, at a minimum, of socket welds in accordance with the fourth interval IS1 program plan. The one-time inspection of small-bore piping does not exclude locations based on geometry. 'Therefore, Class 1 small-bore piping socket welds will be selected for one-time inspection based on physical location and exposure levels.

In a letter dated September 13, 2006, the applicant stated that the One-Time lnspection Program will also include destructive or nondestructive examination of one socket-welded connection using techniques proven by past industry experience to be effective for the identification of cracking in small-bore socket welds. Should an inspection opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or nondestructively prior to entering the period of extended operation,Since small-bore piping socket-weld connection will be either destructively or nondestructively examined at least once, the staff found the applicant's response acceptable.

Upon further discussions the staff concluded that the destructive or nondestructive examination of one or more socket welds would not contribute significant additional information on the condition of socket welds.,Socket welds fail by vibrational fatigue with cracks initiating from their inside surfaces. The time required for fatigue crack initiation is very long compared to the time to'.

propagate through a wall. Therefore, a surface examination or destructive examination of a socket weld is unlikely to detect problems. In addition, there is no history of significant socket weld failures. The staff presented this information 'to the Advisory Committee on Reactor Safeguards (ACRS) Subcommittee on the Oyster Creek License Renewal on January 18,2007, and it accepted the staff conclusions on socket welds.

In a letter dated February 23, 2007, the applicant amended Commitment No. 20 to remove references to socket welds.

The staff reviewed those portions of the applicant's One-Time lnspection Program for which the applicant claimed c,onsistency with GALL AMP XI.M32 and GALL AMP XI.M35 and found that they are consistent'with these GALL AMPS. On the basis of its review, the staff concludes that the applicant's One-Time lnspection Program provided assurance that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect the intended function of the component or structure. The staff finds the applicant's One-Time lnspection Program acceptable because it conforms to the recommended GALL AMP XI.M32, "One-Time Inspection" and GALL AMP.XI.M35, "One-Time lnspection of ASME Code Class 1 Small-Bore Piping."

Operating Experience. LRA section 6.1.23 states that there is no operating experience for the new One-Time lnspection Program. Industry and plant-specific operating experience will be considered appropriately in the development of this program.

As this program is new, the staff reviewed the License Renewal Project Operating Experience Review Report in general for small-pipe issues. 'This report provides information from condition reports and program owner interviews and covers the last five years. The staff determined that the applicant has a good corrective action program that promptly detects a'ge-related degradation.

The staff confirmed that the "operating experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.

c -

UFSAR Supplement. In LRA Section A.2.1.25, the applicant provided the UFSAR supplement for the One-Time lnspection Program'. During the audit and review, the staff noted that the applicant's description of the One-Time lnspection Program in the UFSAR supplement in LRA Appendix A did not include, as a commitment, implementation of the new program Nor did it indicate that this.program is new. The applicant was asked to justify why LRA Appendix A did not include a commitment for the new program.

In its response dated September 13, 2006, the applicant included Commitment No. 20 for implementation of this new program. Commitment No. 20 also includes the one-time destructive or nondestructive examination of small-bore socket weld connections.

As a result of the staff's presentation to the ACRS on January 18, 2007, the applicant has since amended Commitment No. 20 to remove references to socket welds.

The staff reviewed this section and determined that the information in the UFSAR supplement is an adequate summary,description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's One-Time lnspection Program, the staff finds all program elements consistent with the GALL Report. The staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3)..The staff also reviewed the

UFSAR supplement for this AMP and concludes that it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.9 Selective Leaching Program Summary of Technical Information in the Application. LRA Section 8.1.27, "Selective Leaching,"

describes the new Selective Leaching Program as consistent with GALL AMP XI.M33, "Selective Leaching of Materials."

The Selective Leaching program will ensure theintegrity of components made of cast iron, bronze, brass, and other alloys exposed to raw water, treated water, or groundwater that may cause selective leaching. The program will include a one-time visual inspection and hardness measurement of selected components that may be susceptible to determine whether loss of material due to selective leaching has occurred and whether the loss will affect component ability to perform intended functions for the period of extended operation. The program will start prior to the period of extended operation.

Staff Evaluation. During its audit and review, the staff confirmed' the applicant's claim of consistency with the GALL Report and documented a detailed evaluation of this AMP in Audit and Review Report Section 3.0.3.1.9.

Based on its review, the staff finds the Selective Leaching Program consistent with GALL AMP XI.M33,"Selective Leaching of Materials," including the operating experience attribute.

Operating Experience. LRA Section 8.1 -27 states that there is no operating experience for the new Selective Leaching Program.

During the audit and review, the staff requested operating experience with circulating water pump replacement due to selective leaching. The applicant responded that it had replaced P-105A ("A" circulating sea water pump) in RFO 15 (April 2005) when the vendor (Flowserve) informed it that a cast iron circulating water pump failure had occurred at the New Boston Fossil Station in 2004 due to graphitization. That pump was of a design similar to that of the PNPS pump with six additional years of submerged operation in salt water. Six core samples of the pump casing were sent out to a materials laboratory for analysis, and the results confirmed graphitization. The applicant plans to replace P-105B in RFO 17 based on the core sample analysis from P-105A columns. The applicant also has purchased columns for P-105B overhaul/replacement onsite. The new pump columns are cast iron enhanced with the addition of 3 to 5 percent nickel to improve strength and graphitization resistance. The original columns were ASTM A48 CL 35 with 1.75-to 2.25-percent nickel.

The staff confirmed that the 'operating experiencen program element satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A.2.1.29, the applichnt provided the UFSAR supplement for '

the Selective Leaching Program. The description in LRA Appendix A did not indicate that this program is new nor did it include a commitment to implement it. The applicant was asked why LRA Appendix A did not include a commitment for the new program.

NRC STAFF EXHIBIT 10

Entergy Nuclear Operations, Inc.

Pllgr~m Stat~on 600 Rocky Hill Road Plymouth. MA 02360 William J. Rlggs D~recta, Nuclear Assessment December 6,2002 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555-0001

SUBJECT:

Entergy Nuclear Operations, Inc.

Pilgrim Nuclear Power Station Docket No. 50-293 License No. DPR-35 Pilgrim Nuclear Power Station Fourth Ten-Year lnserveice Testing (IST)

Program and Request for Approval of IST Relief Requests LETTER NUMBER: 2.02.109

Dear Sir or Madam:

Entergy Nuclear Operations, Inc. (Entergy) has revised the Pilgrim Nuclear Power Station (PNPS) Inservice Testing (IST) Program as required by 10CFR50.55a(f)(4)(ii) for the fourth 10-year interval starting December 7,2002.

This submittal dockets Pilgrim IST program, Procedure No. 8.1.1.I.

and requests NRC approval of IST relief requests, as described in this letter.

The revised IST Program complies with 1995 Edition through 1996 Addenda of the OM Code for Operation and Maintenance of Nuclear Power Plants, Section IST requirements with a few exceptions. These exceptions invoke 10CFR50.55a(f)(4)(iv), the use of portions of later approved ASME OM Code editions and 10CFR50,55a(f)(5)(iii) the notification that conformance with certain code requirements are impractical.

The NRC has recently approved 1998 Edition through 2000 Addenda of the OM Code for Operation and Maintenance of Nuclear Power Plants, (OMb Code - 2000). The following portions of the OMb Code - 2000 will be adopted into the revised IST Program (There are no other related requirements within the OMb Code - 2000 for these paragraphs):

Appendix 1-1390, Test Frequency, Class 2 and Class 3 Pressure Relief Devices that are Used for Thermal Relief Application.

Appendix 1-41 10(h) and Appendix 1-4130(g), Pressure Relief Devices - a minimum of 5-minute time elapse between successive openings.

Deletion ISTA 2.1, Inspection - Duties of,Inspector, Inspector Qualifications, and Access for Inspector.

A summary table of the IST Program Relief Requests requested for approval is enclosed (Attachment 1). This summary table provides a brief description of the impracticality or hardship requiring relief. The updated program Valve Relief Request No. 1 (VR-01) and No. 2 (VR-02) were recently reviewed and granted for ten years in a NRC Safety Evaluation Report (SER) dated September 17, 2002 and May 2, 2001, respectively.

Entergy Nuclear Operations, Inc.

Pilgrim Nuclear Power Station Letter Number: 2.02.109 Page 2 The details of the relief requests are specified in the IST Program Section 7.0 (Attachment 2) as purrlp and valve relief requests. A relief is requested where PNPS determined a non-conformance to certain Code requirement(s). The relief request provides either an alternative of acceptable level of quality and safety, an alternative since a hardship exists without a compensating increase in the level of quality and safety, or an alternative because it is an impractical requirement for the facility to meet.

PNPS has developed the following schedule plan for implementation of the updated program surveillance requirements:

Subsection ISTB, lnservice Testing of Pumps, will be implemented three months from December 7, 2002, with the exception of Reactor Building Closed Cooling Water (RBCCW) and High Pressure Coolant Injection (HPCI) pump testing, which will be implemented upon receipt of NRC approval of the pump relief requests. Until then Pilgrim will continue to comply with the third 10-year IST Interval program requirements for RBCCW and HPCI pumps.

Implementation of Subsection ISTC, lnservice Testing of Valves, will begin three months from December 7,2002.

Entergy requests timely NRC review and approval of IST Relief Requests in order to support implementation of the new program.

If you have any questions or require additional information, please contact Mr. Bryan Ford, Licensing Manager, at (508) 830-8403.

Attachments: 1. Relief Request Summary Table - 1 page

2. Procedure No. 8.1.1.1, "lnservice Pump and Valve Testing Program" - 178 pages cc:

Mr. Travis Tate, Project Manager Office of Nuclear Reactor Regulation Mail Stop: 0-86-1 U.S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike Rockville, MD 20852 U.S. Nuclear Regulatory Commission Region 1 475 Allendale Road King of Prussia, PA 19406 Senior Resldent Inspector

ATTACHMENT 2 PROCEDURE NO. 8.1.1.I, INSERVICE PUMP AND VALVE TESTING PROGRAM

1.0 PURPOSE AND SCOPE This Procedure encompasses and controls the PNPS lnservice Testing (IST) Program. It identifies the scope of components (pumps and valves) and testing requ~rements for compliance with 10CFR50.55a(f), lnservice Testing Requirements. This Procedure will be utllized for the IST Program submittal to satisfy ISTA 2.2.3 lnservice Test Interval and to identify rmpractical Code requirements in accordance with 10CFR50.55a(f)(5).

Impractical Code requirements are reviewed and disposltioned by the Nuclear Regulatory Commission (NRC) and documented in a Safety Evaluation Report authored by the Office of Nuclear Reactor Regulation as related to the lnservice Testing Program and Requests for Relief The NRC will grant program relief requests pursuant to IOCFR50.55a(a)(3)(i),

10CFR50 55a(a)(3)(ii), or IOCFR50.55a(f)(6)(1). Granting of relief ensures that the IST Program has satisfactorily demonstrated that either: 1) the proposed alternative provides an acceptable level of quallty and safety, 2) complrance would result in hardshlp or unusual difficulty without a compensating increase in the level of quality and safety, or 3) conformance with certain requirements of the applicable Code edition and addenda IS impractical for its facility.

The scccs of the IST Program lncfudes those safety-related pumps and valves which are prrt of the Reactor coolant pressure boundary and must meet the requirements appl~cable to components classified as ASME Code Class 1. Additionally, other safety-related pumps and valves that perform a functron to shut down the Reactor or malntarn the Reactor in a safe shutdown condltlon, mitlgate the consequences of an accident, or prov~de overpressure protection for safety-related systems meet the test requirements applicable to components which are classified as ASME Code Class 2 or Class 3. This scope is limited to those pumps and valves identified as meeting ASME Code Class 1, 2, or 3 in accordance with Regulatory Guide 1.26 classifications. The pumps and valves not performing a function as stated above or those meeting the excluston requirements of the OMa Code need not be tested, but the bases for a component's exclusion must be justified. TDBD-121, "Topical Design Basis Document for In-Service Testing (IST)", provides the bases information related to IST Program exclusions.

Non-ASME Code Class safety-related pumps and valves that perform a function to shut down the Reactor or maintain the Reactor in a safe shutdown condit~on, mitigate the consequences of an accident, or provlde overpressure protection for safety-related systems are to be tested under the requirements of 10CFR50 Appendix 6. The scope of the PNPS Appendix B Test Program includes those safety-related pumps and valves identified as non-ASME Code Class in accordance with Regulatory Guide 1.26 but would be considered ASME Code Class 1, 2, 3.

8.1.1.1 Rev. 15 Page 5 of 179

This Procedure details the followrng items: compliance requirements, general information, pump hydraulic circuits, and tables of the components (pumps and valves) tested. The last Section (7.0) contains Valve Justifications (i.e., cold shutdown, Refuel Outage, Disassembly Examination, and Series Valve Pairs) and Relief Requests. In addition, the Procedure references the Condition Monitoring Program for check valves.

The Procedure's pump and valve tables provide a cross-reference between a component test requirement and a Station Procedure implementing the test. Additional information is provided withrn this component Irsting: safety class, category, test frequency, test parameters, Relief Requests, justifications, and remarks. Newly incorporated componentltest requirements wrll have implementing Procedures identified for future incorporation. All newly identified componentltest requirements shall be initially tested during the next scheduled frequency (i.e.,

quarterly, cold shutdown, refueling interval, and 2 years) following Procedure approval date.

These newly incorporated component/test requirements will be identified by an asterisk (*) next to the implementing Procedure. When using (*) Procedures for postmaintenance testing, the current approved Procedure should be reviewed for applicability (i e, IS the new test requirement or component incorporated)

PNPS 8.1.1, "Administration of lnservice Pump and Valve Testmg", covers the adminrstrative requirements for the development, performance, and marntenance of the PNPS lnservice Test Program In accordance with the ASME OMa Code for Operation and Maintenance of Nuclear Power Plants, and includes the 1995 Edrtion through 1996 Addenda.

Station AURA practices have been considered when addressrng ASME Code test requlrernenrs wlih~n thrs Procedure. When test requrrements are added or revised, good ALARA practices should be incorporated to mrnrmlze personnel dose.

3.0 REFERENCES

[I]

10CFR5O Appendix B, Quality Assurance Criterra for Nuclear Power Plants and Fuel Reprocessing Plants

[2]

10CFR50 Appendix J, Primary Reactor Containment Leakage Testing

[3]

10CFR50.55a(b), Code and Standards, Reference Applicability

[4]

10CFR50.55a(f), lnservice Testing Requirements

[5]

ASME Code, Mandatory Appendix I, lnservice Testing of Pressure Relief Device in Light-Water Reactor Power Plants

[6]

ASME Code, Subsection ISTA, General Requirements 8.1.1.1 Rev. 15 Page 6 of 179

5.2.4 Core Spray (CS) Pumps

[I]

Test Group B - pumps that are not operated routinely except for testing.

[2]

Test FrequencyIMethod CS pumps are tested quarterly usirlg the Group B Test Method and b~ennially using the Comprehensive Test Method.

[3]

Hydraulic Test Path Each pump shall be tested by establishrng a flow path with suction from and discharge returning to the Torus. Using the CS Full Flow Test Valve for throttling, establish a flow rate in accordance with current Technrcal Specif~cations requirements. Pump discharge and suction pressures shall be recorded and the differential pressure will be calculated and compared to the established value.

[4]

Instrumentation (a)

Inlet Pressure (psrg) M&TE test gauges at PI-40A, PI-40B.

(b)

D~scharae Pressure (psrg) M&TE test gauges at PT-1460A, PT-1460B.

(c)

Flow rate, Q (GPM) Flow Indicators F1-1450-4A (Loop A) and FI-1450-46 (Loop 6) or EPIC Computer Po~nts CSP002 (Loop A) and CSP004 (Loop B).

5 2.5 H~gh Pressure Coolant lnjectlon (HPCI) Pump

[I]

Test Group B - a pump that IS not operated routrnely except for test~ng

[2]

Test FrequencyIMethod The HPCl pump (reference PR-02) is tested quarterly using the Group B Test Method and b~enn~ally using the Comprehensive Test Method when adequate steam pressure is available.

131 Hydraulrc Test Path The HPCI pump (mainlbooster Integral unit) shall be tested by establishing a flow path with suction from and discharge returning to the CST. Using the HPCl Full Flow Test Valve for throttling, establish the speed and flow rate In accordance w~th current Technical Specifications requirements. Pump discharge and suction pressure shall be recorded. The differential pressure will be calculated and compared to the established value 8.1.1.1 Rev.15 Page 17 of 179

[4]

Instrumentation (a) lnlet Pressure (psrg). PI-2340-1 or M&TE test gauge at PI-2381 (Quarterly Group B Test). M&TE test gauge at PI-2381 (Biennial Comprehensive Test).

(b)

Discharqe Pressure (psrg). M&TE test gauge at PI-2357 (c)

Flow rate, Q (GPM). Fl-2340-1.

(d)

Speed, N (RPM): M&TE tachometer.

5 2.6 Reactor Core Isolation Cool~ng (RCIC) Pump

[I] Test Group B - a pump that IS not operated rout~nely except for testing.

[2]

Test FrequencyIMethod The RClC pump is tested quarterly using the Group B Test Method and biennially using the Comprehensive Test Method when adequate steam pressure is available.

[3]

Hydraulic Test Path The RClC pump shall be tested by establ~shing a flow path from and returning to the CST. Us~ng the full flow test valve for throttling, establish the speed and flow rate in accordance wlth current Technical Soec~ficatrons requirements Pump discharge and suctron pressures shall be recorded. The differenttal pressure wrll be calculated and compared to the established value (a)

Inlet Pressure (psig): PI-1340-2 or M&TE gauge at 1360-20 (Quarterly Group B Test). M&TE test gauge at 1360-20 (B~ennial Comprehensive Test).

(b)

Dlscharae Pressure (psig): M&TE test gauge at PI-1 360-5 (c)

Flow rate, Q (GPM): FI-1340-1.

(d)

Speed, N (RPM): M&TE tachometer.

8.1.1.1 Rev. 15 Page 18 of 179

NRC STAFF EXHIBIT 11

LIMITING CONDITIONS FOR OPERATION 3.5 CORE AND CONTAINMENT COOLING SYSTEMS C.

HPCl Svstem

1. The HPCI system shall be operable whenever there is irradiated fuel in the reactor vessel, reactor pressure is greater than 150 psig., and reactor coolant temperature is greater than 365"F, except as specified in 3.5.C.2 below.

2. From.and after the date that the HPCl system is made or found to be inoperable for any reason, continued reactor opefation is permissible only during the succeeding 14 days unless such system is sooner made operable, providing that during such 14 days all active components of the ADS system, the RClC system, the LPCl system and both core spray systems are operable.

3. If the requirements of 3.5.C cannot be met, an orderly shutdown of the reactor shall be initiated and the

. reactor shall be in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILL4NCE REQUIREMENTS 4.5 CORE AND CONTAINMENT Cool-ING SYSTEMS C.

HPCl System

1.

HPCl system testing shall be as follows:

a.

Simulated Once/

Automatic Operating Actuation Cycle Test

b.

Pump When tested Operability as specified in 3.1 3, verify that the HPCl pump delivers at least 4250 GPM for a system head corresponding to a reactor pressure of 1000 psig.

c.

Motor As Specified in Operated 3.13 Valve Operability

d.

Flow Rate at Once1 150 psig.

operating cycle, verify that the HPCI pump delivers at least 4250 GPM for a system head corresponding to a reactor pressure of 150 psig.

The HPCl pump shall deliver at least 4250 GPM f ~ r a system head corresponding to a reactor pressure of 1000 to 1 50 psig.

u Amendment No. 1 7 6

LIMITING CONDITIONS FOR OPERATION 3.5 CORE AND-CONTAINMENT COOLING SYSTEMS

0. Reactor Core Isolation Cooling IRCIC) System

1.

The RClC system shall be operable whenever there is irradiated fuel in the reactor vessel, reactor pressure is greater than 150 psig, and reador coolant temperature is greater than 365'F, except as specified in 3.5.0.2 below.

From and after the date that the RClC system is made or found to be inoperable for any reason, continued reactor operation is permissible on\\y during the succeeding 14 days unless such system is sooner made operable, providing that during such 14 days the HPCIS is operable.

3.

If the requirements of 3.5.0 cannot be met, an orderly shutdown of the reactor shall be initiated and the reactor shall be in the Cold

. Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.5 SYSTEMS D. Reactor Core Isolation cool in^ (RCIC)

System

1.

HPCI system testing shalt be as follows:

a.

Simulated Once/

Automatic Operating Actuation Test Cycle

b. Pump When tested as Operability specified in 3.13, verify that the RClC pump delivers at least 400 GPM at a system head corresponding to a reactor pressure of 1000 psig.

c.

Motor As Specified Operated in 3.13 Valve Operability Flow Rate at Once/

1 50 psig.

operating cycle verify that the RClC pump delivers at least 400 GPM at a system head corresponding to a reactor pressure of 50 psig.

The RClC pump shall deliver at least 400 GPM for a system head corresponding to a reactor pressure of 1000 to 150 psig.

Amendment No. 176

NRC STAFF EXHIBIT 12

PNPS - FSAR 11.9 CONDENSATE STORAGE SYSTEM 11.9.1 Power Generation Objective The power generation objective is t o provide condensate for system makeup needs, and t o take system "rejectn surges.

11.9.2 Power Generation Design Basis The condensate storage system shall provide station system makeup, receive system reject flow, and provide condensate for any continuous service needs and intermittent batch type services.

The t o t a l stored design quantity shall be based on the demand requirements during refueling for f i l l i n g the dryer separator pool and the reactor well.

Two tanks shall be used for reasons of operational f l e x i b i l i t y so that a plant shutdown w i l l not be required when one tank is being maintained.

11.9.3 Description The two 275,000 gal condensate storage tanks supply the various station requirements as shown on Figure 11.9-1.

The tanks are of coated carbon s t e e l with a l l i n l e t and outlet lines, overflows, vents, and instrument lines located a t the tank bottom or toward the tank center to prevent freezing problems.

The condensate storage system also consists of the two condensate transfer pumps, a

jockey pump, and associated piping and valves.

The condensate tanks provide the preferred supply t o the HPCI and RCIC systems.

The torus water storage provides the backup emergency HPCI and RCIC systems supply.

A l l other suctions are located above the HPCI and RCIC suctions t o provide a 75,000 gal reserve i n each tank for these systems.

NRC STAFF EXHIBIT 13

PNPS-FSAR 1.10 QUALITY ASSURANCE PROGRAM 1.10.1 Introduction Boston Edison Company, as original owner and operator of Pilgrim Nuclear Power Station, assumed full responsibility and authority for facility operation and has taken appropriate action to ensure the station is designed, modified, operated, and maintained in accordance with sound engineering principles and safe operating practices. The Boston Edison Company Quality Assurance Program for operation of PNPS was defined in the Boston Edison Quality Assurance Manual Volume I1 (BEQAM).

The owhership and operation of PIWS was transferred From Boston Edison Company to the Entergy Nuclear Generation Company (EBGC),

effective July 13, 1999.

The ENGC Quality Assurance Program for operation of PNPS was defined in the Pilgrim Quality Assurance Manual (FQAM), which was the governing document for quality related activities relating to Pilgrim Station until May 5, 2002, when the NRC approved ENGC1s transfer of plant operating responsibility to Ehtergy Nuclear Operations Inc. (ENOI).

At this time the PQAM was replaced by adopting the Entergy QA Program Manual (QAPM), as the QA program description for PNPS.

The requirements in the QAPM, and its Predecessors (BEQAM and PQAM),

were established to comply with the requirements of 10 CFR 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants."

1.10.2 QA Program Objectives The quality assurance program' s objectives are to ensure compliance with regulatory requiranents, company co~tments, and established practices for efficient design, modification, maintenance, testing, and operation of Pilgrim Station. The program requires every person involved in quality assurance program related activities to comply with the provisions of the program.

1.10.3 QA Program Organization

\\

The function of the Pilgrim Quality Assurance Organization established by Entergy is to monitor the quality oriented activities I of all organizations involved in the design, modification, operation, and maintenance of Pilgrim Station and report the results of such monitoring activities to the appropriate levels of management.

The site quality assurance organization reports off-site to the mtergy Director, Oversight. The Director, Oversight through the VP, Oversight r.eports to the President, Planning, Development and Oversight and the Chief Executive Officer.

This reporting relationship ensures the appropriate organizational freedom required by 10 CFR 50 Appendix B, Criteria I as needed for the site QA organization to effectively perfom their assigned functions.

1.10.4 Quality Control and Assurance Measures 1.10-1 Rev 26 - Oct 2007

PNPS-FSAR The degree to which guality control and assurance measures are assigned is a direct function of the safety and operating requirements of the various structures, systems, and components.

Essential equipment.and nuclear systems are emphasized; however, nonessential and non-safety related systems and components may be included in the Quality Assurance Program to the extent necessary to assure reliability of station operation.

The quality assurance organization has developed an integrated system of planned audits, reviews, surveillances, inspections, and assessments in order to fulfill its responsibility for monitoring of QA Program implementation. The system has been designed to meet or exceed applicable regulatory, license, and national code or standard requirements. The audits, reviews, and surveillances are scheduled to provide comprehensive oversight and verification of all aspects of the QA Program and to provide management of the affected areas with continuous assessments of facility operation.

In addition to the conn-nitrnents to NRC Regulatory Guides and ANSI Standards described in the Ehtergy QAPM, the following Regulatory Guides and associated ANSI Standards will be applied to construction related activities associated with major modifications during the operational phase that are comparable in nature and extent to related activities occurring during initial plan design and construction:

Regulatory Guide 1.54, Rev. 0, 1973.

"QA Requirements for Protective Coating ~pplied to Water-Cooled Nuclear Power Plants. "

Regulatory Guide 1. S S, Rev. 0, 1973. "Concrete Placement in Category I Structures."

ANSI N45.2.16, "Requirements for the Calibration and Control of Measuring and Test Equipment Used in the construction and Maintenance of Nuclear Power Generating Stations."

UFSAR, Appendix D describes the quality assurance program for the initial design and construction phase of Pilgrim Station.

1.10.5 Quality Records and Documentation Documentation to support quality assurance is essential to the safe operation, integrity and proper maintenance of Pilgrim Station. It is compiled and maintained throughout the life of the plant.

In general, the minimum requirements for documentation for PNPS are those requirements imposed by the QAPM.

Refer to Section 13.7.5 relative to records retention.

1.10.6 Quality Program Review Periodic, independent reviews of the QA Program policies and implementation are conducted to evaluate the continued adequacy and effectiveness of the program.

1.10-2 Rev 26 - Oct 2007

1.10.7 QA Program Update The QA Program applied to operation and modification of Pilgrim Station is set forth in the QAPM.

Rev 26 - Oct 2007

NRC STAFF EXHIBIT 14

Entergy Nuclear Operations, Inc.

Pilgrim Station 600 Rocky Hill Road Plymouth, MA 02360 Stephen J. Bethay Director. Nuclear Assessment June 2 9, 2005 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Entergy Nuclear Operations, Inc.

Pilgrim Nuclear Power Station Docket No. 50-293 License No. DPR-35 Pilgrim Fourth Ten-Year lnservice lnspection Program Plan, and the Associated Relief Requests for NRC Approval

Dear Sir or Madam:

By this letter Entergy submits the attached Pilgrim Nuclear Power Station (PNPS) Fourth Ten-Year lnservice lnspection (ISI) Program Plan (PNPS-RPT-05-001, Rev. 0) pursuant to 10 CFR 50.55a(a)(g)(4)(ii) and requests NRC approval of associated relief requests pursuant to 10 CFR 50,55a(a)(3).

PNPS Fourth Ten-Year IS1 Interval will commence on July 1,2005 and ends on June 30,201 5.

This IS1 Program Plan is developed in accordance with the 1998 Edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI with the 2000 Addenda. The IS1 Program Plan is divided into five major sections:

1.0 Introduction and Plan Description 2.0 IS1 System / Component Exemptions & Examination Development 3.0 Code Compliance lnservice lnspection Program Summary 4.0 lnservice lnspection Components & Schedule 5.0 Appendices The IS1 Program Plan contains the Second Ten-Year IWE Containment lnspection program and Second Ten-Year Risk Informed IS1 program. Both programs have been aligned with the regular IS1 program interval schedule.

Entergy Nuclear Operations, Inc.

Pilgrim Nuclear Power Station Letter Number: 2.05.045 Page 2 The Code of Record for the Fourth Ten-Year IS1 Interval, the Second IWE Containment lnspection interval, and the Second RI-IS1 interval will be the ASME Section XI Code, 1998 Edition with 2000 Addenda. Accordingly, this letter requests NRC acceptance for these programs to be based upon the aforementioned EditiodAddenda.

Fourth Ten-Year IS1 Relief Reauests for NRC A~Droval:

The relief requests associated with the Fourth Ten-Year IS1 Program Plan and any precedent are contained in Section 5, Appendix B of the Program Plan. There are thirteen (1 3) relief requests. Two (2) relief requests PRR-28 (MB6074) and PRR-39 (MC2496) were previously approved for use during the 4' interval are included for information. In addition, three (3) requests related to the use of subsequent editions and addenda of Section XI of the ASME Code are included in Appendix D.

Entergy requests NRC review and approval of the IS1 Relief Requests as soon as possible, preferably by July 1,2006.

This submittal represents IS1 Program Plan and does not contain any regulatory cornmltments.

If you have any questions on this transmittal, please contact Mr. Bryan Ford, Licensing Manager at 508-830-8403.

Sincerely, Stephen J. Bethay

@T

Attachment:

1. PNPS Fourth Ten-Year IS1 Program Plan, including IWE Containment lnspection Program (PNPS-RPT-05-001, Rev. 0) cc:

Regional Administrator, Region 1 W/O U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Mr. James Shea, Project Manager Project Directorate I Mail Stop: 0-8B-1 Division of Licensing Project Management Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Senior Resident Inspector Pilgrim Nuclear Power Station

Nuclear Northeast Entergy Nuclear Getzcratiorl Conrpalzy PILGRIM NUCLEAR POWER STATION (PNPS)

Plymouth, Massachusetts ASME B&PV CODE SECTIONX FOURTH TEN-YEAR INSPECTION INTER VAL INSER VICE INSPECTION (IS') PROGRAM PLAN July 1,2005 to June 30,2015 Commercial Service Date:

June 8,1972 NRC Docket Number:

50-293 Facility Operating License:

DPR-35 Document Number:

PNPS-RPT-05-00 1 Revision Number:

0 Document Date:

July 1,2005 Prepared by:

Enterm? Nuclear Northeast 440 Hanrilton Avenue WJlite Plains, New York 10601

One ofthe tasks required to complete theThird Interval IS1 Progam Update at the Pilgrim Nuclear Powver Station wvas to perform a review of the classification boundaries for inservice inspections.

This wm documented under Vectra Report 0025-0024 1-00 1. Vectta documented the information and decisions in developing recommended and required revisions to the IS1 boundaries for clarification purposes.

Entw&

Nuclcar Northcast 1.3.1 Code of Federal Rceulrtions (10CFRSD)

Sections 50.55a(c), (d) and (e), reference 10CFR50.2, and Regulatory Guide 1.26 for the classification of Quality Group A, and Quality Groups B and C components, respectively.

Footnote 9 of 10CFR50.55a specifically invokes Regulatory Guide 1.26. IOCFR50.2 provides criteria for the classification of Quality Group A components.

Pilgrim Nuclear Power Station ASME S E n I O N XI FOURTI1 TLWYEAR INTERVAL INSERVICE INSPECTION PROGRARI PLAN In accordance with 10CFR50,55a(c), the Class I boundaries are described in 10CFRS02 which defmes the reactor coolant boundary as follows:

PNPS-RPT-05-001 Rev. 0 "All those pressure-containing components of boiling and pressurized water-cooled nuclear power reactors such as pressure vessels, piping, pumps, nnd valves, which are:

(1)

Pan of the reactor coolant system, or (2)

Connected to the reactor coolant system, up to and including any and all of the follow;ing:

(i)

The outermost containment isolation valve in system piping which penetrates primary reactor containment, (ii)

The second of two valves normally closed during normal reactor operation in system piping which does not penetrate primary reactor containment, (iii)

?he reactor coolant system safety and relief valves.

For nuclear power reactors of the direct cycle boiling water type, the reactor coolant system extends to and includes the outermost containment isolation valve in the main steam and feedwter piping!'

This is the definition which is used for Class I systems at Pilgrim Station.

10CFR50.55n does not specifically defrne the boundaries for Class 2 and 3 piping systems, but in Footnote 9 it refers to Regulatory Guide 126 and NUREG-0800, Section 3.22 for y idance. For Pilgrim Station, guidance is taken from Regulatory Guide 1.26 which provides genenl boundary definitions for systems containing water, steam or radioactive waste. It should be noted that Regulatory Guide 1.26 specifically states that it does not address other systems such as

"...instrument and service air, diesel engine and its genemtors and auxiliary support system, diesel fuel, emergency and n o m l ventilation, fuel handling, and radioactive waste management systems".

13.3 ASME Section XI In accordance with 10CFR50.55a, the inservice inspection of Class 1,2 and 3 piping and components will be governed by ASME Section XI. When applying the criteria ofASME Section

XI, one of the main considerations is the exemption criteria presented in Paragraphs IWB-1220, IWC-1220 and IWD-1220 for Class I, 2 and 3 systems respectively. These parapphs state specific criteria for the exemption ofcomponents due to various factors including line size, system function and opemting conditions. One exemption which requires particular attention is the exemption of Class 1 components due to make-up flow capacity as pmmted in IWF3-122qa). As addressed in BE&

Boundary Study Document NED 90-300, attached NLJTECH Lctter No. BOS-06-01 1, and its associated make-up capacity calculation, Class I piping in uater systems with an inside diameter of 1.10" or less, ond pipiing in steam systems uith an inside diameter of 220" or less qualify for the make-up capacity exemption of IWB1220(a).

Entw#

LI Nuclcar Northcast ASME Section XI Examination Categories B-F and B-J currently contain the requirements for the nondestructive examination (NDE) of Class 1 piping components. The alternative RI-IS1 program for piping is described Section 1.5.2.1 of this IS1 Program Plan.

The RI-IS1 Program will be substituted for the Section XI program for Class 1 piping in accordance with IOCFR50,55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. Other non-related portions of the ASME Section XI Code will be unaffected. For example, existing pressure testing requirements and Class 2 piping inspection requirements remained unchanged. EPRI TR-I 12657 provides the methodology for defining the relationship between the RI-IS1 program and the remaining unaffected portions of ASME Section XI.

1.3.4 Updated Final Safetv Analvsis Report lFSAR)

Pilgrim Nuclcar Power Station AShlE SECTION XI FOURTI, TEN-YEAR IKTERVAL INSERVICE INSPECTION PROGRAM PLAN In general, the PNPS Updated Final Safety Analysis Report (FSAR) provides limited references to irwrvice inspection requirements. There nre numerous references to inservice inspections interspersed throughout the FSAR, but most are inconsequential discussions on accessibility or testing requirements. FSAR Appendix K addresses the general requirements of Pilgrim's IS1 Program, but it only covers the First Interval IS1 Program. The PNPS FSAR does not establish any additional commitments which must be incorporated into the IS1 Program.

PNPS-RPT-05-00 1 Rev. 0 1.3.5 NRC Commitments In general, Pilgrim Station was designed and constructed prior to many of the Code and Regulatory documents becoming mandatory. The augmented examination requirements which have been issued since the stilrt ofplant operation are currently being performed at Pilgrim Station under PNPS Procedure No. NE 15.08, "Conrrof ofAtigmenredExclminationZ'. Although the documents listed in this procedure provide augmented examination requirements, they do not affect the inservice inspection boundaries.

1.3.6 IS1 Clnssification & Flow Diaerams The Inservice Inspection classification process described above resulted in system classifications indicating ASME Class 1.2.3, and MC components. Class boundaries were developed and are shown on the IS1 flow diagrams (IS1 P&IDs) listed in Appendix E Table E.1.

For ASME Class 1 components, the requirements of Subsection I\\VB apply, for ASME Class 2 components, the requirements of Subsection IWC apply, for ASME Class 3 components, the rules of Subsection IWD apply; and for ASME Class MC components, the requirements of Subsection IWE apply. The rules of Subsection IWF for component supports apply to ASME Classes 1.2.3, and MC.

1.4.4 The ASME Section XI Repair I Replacement Program will be implemented and maintained in accordance with separate plant site procedures. Repair and replacement requirements for Class MC components (Code Subsection 11VE) are included within the site'sSection XI Repair I Replacement Progmm.

Entw e

Nuclear Northeast 1.5 Aaernented and Alternative TnscnSce Tnspection Reauiremcnts 1.5.1 Al~emented lnsenlce TnspectIon Reauirements Pilgrim Nuclear Power Station ASME SECTION XI,,TI1 TEN-YEAR INTERVAL INSERVICE INSPECTION PROCRAnI PLAN Augmented inservice inspection requirements are those examinations that are specified by documents other than the ASME Section XI Code. Augmented examina~ions will be performed as required by 10CFR5OS55a, the NRC, Response to RAls, or as deemed necessary by the IS1 Program. The augmented inservice inspections performed at the Pilgrim Nuclear Powzr Station are documented in controlled PNPS Procedure No.

NE15.08, "Control ofAugnrented Examinations", latest revision. Current augmented examination programs include:

PNPS-RPT-05-001 Rev. 0 1.5.1.1 pip in^ Flow-Accelerated Corrosion (FAC) Monitoring Flow accelerated corrosion (FAC) examinations arc performed in accordance within the separate and independent PNPS FAC Program under Specification M577. The PNPS FAC Program satisfies NRC G.L. 89-08 using the guidelines developed by MJMARC and EPRI. Credit is taken for 8 of the 71 RI-IS1 components under the FAC Program. Coordination between the FAC Program and h e RI-IS1 Program is described in the PNPS RI-IS1 Template and in Inservice Engineering Report No.

PNPS-O2Q-402. The FAC Program is relied upon to manage the flow accelerated corrosion damage mechanism in Class 1 piping, but is not othenvise affected or changed by the RI-IS1 program.

The following table summarizes the relationship between the FAC and RI-IS1 examinations. Note that some of the welds in this table are in carbon steel piping segments that are evaluated for FAC, but the welds a n not selected for examination per the FAC Program. In these instances. welds selected for examination per the RI-IS1 Pro-will require volumetric examination like any other weld.

FAC VS. RI-IS1 EXAhlINATIONS

FAC VS. Rl-ISI EXAMINATIONS t

I I

I I

EWlINATION(S) REQUIRED PNPS-RPT-05-00 1 Rev. 0 Nuclear Northeast

• The FAC Program examination is credited for lhese 8 RI-IS1 components.

Pilgrim Nuclear Power Station ASME SECTIOXXI FOURTII TEN-YEAR INTERVAL IKSERVICE INSPECTION PROCRAhl PLAN Routine inspection, mainvnance, and test requirements for the PNPS Salt Service Water (SSW) System piping and heat exchanger inspections, along with the associated acceptance criteria, are included in Specification M591 for compliance with NRC G.L.

89-13. These inspections are separate from, but supplement, the Section XI Class 3 IS1 component inspections listed in Table 4.1-1 8. Implementation of SSW System inspections is via PNPS Nuclear Organization Procedure NOPOZEl "Service Water Inspections, Maintenance, and Testing in Response to Generic Letter 89-13".

1.5.1.3 Class I Pressure Boundarv Onlv (PBO) Pinine & Com~onents Augmented lns~ectioq Procram 1.5.1.3.1 Background & Purpose During 1998 it UQS identified that there uas not an adequate basis for the IS1 boundary change h m Class 3 to Class 0 at the Nonnally-Open RBCClVNon-Essential loop isolation valves. The RBCCW Non-Essential heat trnnsfer components perform no active safety function but arc categorized.ns PNPS Class 1 "Pressure Boundary Only" (PBO) and the non-essential piping, pipe supports, and components are "MQW per the PNPS Q-list. The

Pressure testing following repairlreplacement activities performed on Class MC items will be in accordance with IWE-5000.

Entw a

Nuclear Northeast 1.1 1.2 Pcriodic Ssstcm Prcsst~rc Testing 1.1 1.2.1 General Pilgrim Nuclear Pollrer Station ASME S E n l O N XI FOURTH TEN-YEAR INTER\\'AL 1NSERVICE INSPECTION PROGRAM PLAN Periodic system pressure tests are performed by plant procedures in accordance with the requirements of Article IWA-5000 for the following components:

PNPS-RPT-05-00 1 Rev. 0 P Class 1 Pressure Retaining Components (Examination Category B-P) 0 Class 2 Pressure Retaining Components (Examination Category C-H) 0 Class 3 Pressure Retaining Components (Examination Category D-B)

The requirements of IWA-5000 are not applicable to Class MC components, except for repairlreplacement activities. Article 1WA-5000 System Pressure Tests are also not applicable to Subsection IWF component supports.

Test boundaries will be determined in accordance with IWA-5220.

The required visual examinations (VT-2) will be performed by personnel qualified and certified in accordance with Subarticle IWA-2300. Guidance for the PNPS IS1 Inspectors when performing VT-2 visual inspections for leaknge during the Class 1, Class 2, and 3 system pressure tests is provided by PNPS Procedure No. 2.1.8.3, "Vislml Exnmfnation for Leakage During System Pressure Testing".

Tests will be documented by plant procedures and made available to an ANII inspector and a Plant NDE Level 111 inspector for review.

1.1 1.2.2 System Leakage Testing In accordance with IOCFRS0.55a(b)(2)(xx) "System Leakage Tests", when performing system leakage tests per IIVA-5213(a), 2000 Addenda, a 10-minute hold time after attaining test pressure is required for Class 2 and Class 3 components that are not in use during normal operating conditions, and no hold time is required for the remaining Class 2 and Class 3 components provided that the system has been in operation for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for insulated components or 10 minutes for uninsulated components.

Class 1 System Leakage Testing shall be performed after every reactor refueling outage has been completed prior to plant startup.

Class 2 and Class 3 System Leakage Testing shall be performed once each Inspection Period.

The leakage observations shnll be made by qualified VT-2 examiners. VT-2 Visual Examination Reports shall be generated and reviewed by site personnel in

accordance with site procedures. Such reports are available for review by regulatory personnel.

1.1 1.2.3 Hydrostatic Testing PNPS-RPT-05-00 1

Rev. 0 Entw a

Nuclear Northeast Class 1 (IWB) and Class 2 (IWC) components do not require hydrostatic testing under Examination Categories B-P and C-H, respectively.

Pilgrim Nuclcar Power Station ASME SEflION XI FOURTI1 TEN-YEAR INTERVAL INSERVICE INSPECTION PROCRAB1 PLAN Class 3 (IWD) components under ;he 1998 Code, 2000 Addenda, require 10 Yr.

System Hydrostatic Tests (Exam. Cat. D-B, Item No. D2.20) to be conducted at or near the end of the Inspection Interval or during the same Inspection Period as the Third Interval. These System Hydrostatic Tests may be conducted while the plant is either in operation or shutdown. Houvever, per 10CFR50.55a Request Number PIL 05-R-003 included within Appendix D, the 2001 Edition, through the 2003 Addendn will be used in place of the 1998 Edition, 2000 Addenda. Class 3 system hydrostatic test requirements have been deleted in their entirety from the 2001 Edition, 2003 Addenda.

1.12 Calibration Blocks 1.12.1 Calibration blocks shall meet the material, surface finish and calibration reflector configuration requirements in effect at the time of the calibration block fabrication. Where this differs from the current edition of ASME Section XI, the differences shall be noted in the UT examination procedure.

1.12.2 Calibration blocks shall be used to establish a reference sensitivity level from which subsequent examinations may be compared. The calibration block design may be the Basic Calibration Block described in Section XI Appendix I11 (i.e., 111-3400) or the design may be the Alternative Calibration Block described in ENN NDE procedures. During Section XI Appendix VIII performance demonstration for ultrasonic examinations, alternate calibration blocks may be used.

1.12.3 A detailed list of all IS1 calibration blocks to be employed during the Fourth Intern1 is provided in Appendix C of this Program Plan. Per PDI procedures, calibration blocks fabricated to an edition of Section XI earlier than the 1998 Edition with 2000 Addenda may be used in the 4' Interval without reconciliation.

NRC STAFF EXHIBIT 15

ATTACHMENT 71 11 1.07 INSPECTABLE AREA: Heat Sink Performance CORNERSTONES:

Initiating Events Mitigating Systems Barrier Integrity INSPECTION BASES: Heat exchangers and heat sinks are required to remove decay heat, and provide cooling water for operating equipment.

Degradation in performance can result in failure to meet system success criteria, and lead to increased risk primarily due to common cause failures. This inspectable area verifies aspects of the associated cornerstones for which there are no indicators to measure performance.

LEVEL OF EFFORT:

The effort of this procedure consists of the review of a sample of one or two heat exchangerslheat sinks, on an annual basis, in accordance with the requirements specified in Section 02.01. On a biennial basis, review a sample of two or three heat exchangerslheat sinks in accordance with the requirements in Section 02.02.

71 11 1.07-01 INSPEC-I-ION OBJECTIVES 01.01 To verify that any potential heat exchanger deficiencies which could mask degraded performance are identified. Applies to all heat exchangers connected to safety related service water systems.

01.02 To verify that any potential common cause heat sink performance problems that have the potential to increase risk are identified, i.e., icing at circulating and service water intake structures.

01.03 To verify that the licensee has adequately identified and resolved heat sink performance problems that could result in initiating events or affect multiple heat exchangers in mitigating systems and thereby increase risk, i.e., component cooling water heat exchanger performance affected by corrosion, fouling, or silting.

71 11 1.07-02 INSPECTION REQUIREMENTS When scheduling this inspection, inspectors should consider refueling outage and at-power maintenance schedules. The review sho~~ld be to identify opportunities to observe infrequent activities associated with risk significant heat exchangers or service water inspectionsltesting (heat exchanger inspections and testing, internal service water pipe inspections).

02.01 Annual Review. Verify the readiness and availability of a sample of one or two heat exchangerslheat sinks by monitoring licensee programs, or invoking industry standards, and also, if necessary, checking critical operating parameters, andlor maintenance records.

The readiness and availability of the sample of heat exchangerslheat sinks may be verified by one of the items a. through d. below. Items e. and f. may be performed as additional assurance of,the heat exchanger(s) operability.

Issue Date: 05/25/06

a.

Observe actual performance tests for heat exchangerlheat sinks or review the dataireports for those tests for any obvious problems or errors.

b.

Verify the licensee utilizes the periodic maintenance method outlined in EPRl NP-7552.

c.

Observe licensee's execution of biofouling controls.

d.

Observe the licensee's heat exchanger inspections and the state of cleanliness of their tubes.

e.

Check, by either a walkdown or the review of operations data, any or all of the following:

1.

The heat exchanger's inlet and/or outlet temperatures.

2.

Primary or secondary side fluid flow.

3.

If there are any evident leaks.

4.

If licensee believes the heat exchanger can perform its safety related function and whether supporting documentation or inspections support the licensee's position.

f.

Determine if heat exchanger is correctly categorized under the Maintenance Rule and verify if it is receiving the required maintenance.

02.02 Biennial Review

a.

Select a sample of 2-3 heat exchangers for systems that are ranked high in the plant specific risk assessment. This includes all heat exchangers directly or indirectly connected to the safety-related service water system.

b.

For the selected heat exchangers that are also directly connected to the service water system, verify that testing, inspection/maintenance, or monitoring of biotic fouling controls are singularly or in combination adequate to ensure proper heat transfer.

1.

Review the method and results of heat exchanger performance testing or equivalent methods to verify performance. Verify the following items, as applicable:

(a)

The selected test methodology is consistent with accepted industry practices, or equivalent.

(b)

Test conditions (e.g., differential temperatures, differential pressures, and flows) are consistent with the selected methodology.

(c)

Test acceptance criteria (e.g., fouling factors, heat transfer coefficients) are consistent with the design basis values.

(d)

Test results have appropriately considered differences between testing conditions and design conditions (functional testing at design heat removal rate may not be practical).

Issue Date: 05/25/06

(e)

Frequency of testing based on trending of test results is sufficient (based on trending data) to detect degradation prior to loss of heat removal capabilities below design basis values.

(f)

Test results have considered test instrument inaccuracies and differences.

(g)

Tube and shell side heat loads are equal if adequate information is available in test results to calculate these two values.

2.

For inspectionlcleaning, review the methods and results of heat exchanger performance inspections or observe the actual inspection1 cleaning. Verify the following first three steps ((a)-@)) if conducting the review and the last step (d) only if actually observing the inspectionlcleaning:

(a)

Methods used to inspect heat exchangers are consistent with expected degradation.

(b)

Established acceptance criteria are consistent with accepted industry standards, or equivalent, including acceptability of the cleaning interval.

(c)

As found results are appropriately dispositioned such that the final condition is acceptable.

(d)

If observing the inspectionlcleaning then perform the following:

(1.) Prior to cleaning, inspect the extent of fouling and blockage of tubes.

(2.)

Inspect the condition of the cleaned surfaces.

(3.)

Verify that the number of plugged tubes are within the limit of operability of the heat exchanger and are appropriately accounted for in heat exchanger performance calc~~lations.

3.

When implemented, verify that chemical treatments, tube leak monitoring, methods used to control biotic fouling corrosion (such as shells, seaweed, corbicula, and microbiological induced corrosion), and methods to control macrofouling (silt, dead mussel shells, debris, etc.) are sufficient (e.g.,

appropriate acceptance criteria) to ensure required heat exchanger performance.

For the selected heat exchangers either directlv or indirectlv connected, except as noted, to the service water system, verify the following:

1.

Condition and operation are consistent with design assumptions in heat transfer calculations, e.g. for tube plugging.

2 Licensee has evaluated the potential for water hammer in those heat exchangers and undertaken appropriate measures to address it.

3.

The heat exchangers do not exhibit excessive vibration during operation that could potentially damage their tubes or tubesheets based on direct observation or issues identified in corrective-action documents.

Issue Date: 05125106 71111.07

4.

For heat exchangers indirectly connected to the service water system, that the water chemistry is being adequately controlled to discourage corrosion, e.g. stress corrosion cracking, in its metallic sub-components.

5.

Redundant and infrequently used heat exchangers are flow tested periodically at maximum design flow.

d.

Verify the performance of ultimate heat sinks (UHS) and their subcomponents like 1

piping, intake screens, pumps, valves, etc. by tests or other equivalent methods.

For heat sinks, the issue is their availability and accessibility to the in-plant cooling water systems.

I The inspector should check at least two of the following for heat sinks and their subcomponents as applicable. (For plants that have dams or other containment devices for the UHS, items 1 or 2 below must be checked every other biennial assessment.)

1.

For an above-ground UHS encapsulated by embankments, weirs or excavated side slopes:

a.

The toe of the weir or embankment should be checked for seepage of water and the crest of the dam should be checked for settlement.

b.

The rip rap protection placed on excavated side slopes should be in place. Ensure that if vegetation is present along the slopes that it is trimmed, maintained and is not, or has not, adversely impacted the embankment.

c.

If available, review the licensee or third party dam inspections that monitor the integrity of the heat sink.

d.

Verify sufficient reservoir capacity.

I

2.

For underwater UHS weirs or excavations, perform or verify visual or other inspections have been performed to check for:

a.

Any possible settlement or movement indicating loss of str~~ctural integrity and/or capacity.

b.

Sediment intrusion that may reduce capacity.

3.

Review design changes to the ultimate heat sink.

I

4.

Free from clogging due to macrofouling (silt, dead mussel shells, debris, etc.)

and aquatic life such as fish, algae, grass or kelp.

I

5.

Licensee has in place adequate controls for biotic fouling.

6.

Functionality during adverse weather conditions, e.g. icing or high temperatures.

7.

Performance tests for pumps and valves in service water system.

e.

Review, if available, eddy current summary sheets, ultrasonic testing results, and visual inspections to determine the structural integrity of the heat exchanger.

Issue Date: 05/25/06

02.03 Identification and Resolution of Problems. Verify that the licensee has entered significant heat exchangerlsink performance problems in the corrective action program.

As it relates to degraded heat exchangerlsink performance including issues related to silting, corrosion, fouling, and heat exchanger testing then verify that licensee corrective actions are appropriate. See lnspection Procedure 71 152, "Identification and Resolution of Problems," for additional guidance.

71 11 1.07-03 INSPECTION GUIDANCE General Guidance Refer to the table below for selecting inspection activities to achieve each cornerstone objective and to those activities that have a risk priority i.e., those common-cause failures with a reasonable probability of occurring should be targeted by inspection to determine impact on cornerstones.

Specific Guidance Cornerstone Initiating Events Mitigating System sl Barrier Integrity 03.01 Annual Review This inspection should encourage the timely identification of heat exchangerlheat sink performance problems so the licensee may take prompt corrective actions.

Inspection Objective Evaluate events, issues, or conditions involving the degradation or loss of both the normal and ultimate heat sinks.

Evaluate any potential degraded performance of heat exchangers1 containment fan coolers The heat exchangers should be in a system that is directly or indirectly cooled by the safety-related service water system or the credited water system cooled by the ultimate heat sink, and that is ranked high in the plant specific risk assessment.

The inspection activities in some cases may be the same as those in Section 02.02 but the inspection should not be conducted at the same level of detail or depth.

Risk Priority Common-cause issues affecting heat removal capabilities.

Heat exchanger selection should focus on the potential for common-cause failures or on potentially high risk heat exchangers with a low margin to their design point or the high potential for fouling.

lnspection results are appropriately categorized against pre-established engineered acceptance criteria, and are acceptable.

Example Icing of a circulating water and service water intake structure.

Degraded containment cooling or component cooling water heat exchanger performance due to corrosion, fouling, silting, etc.

Frequency of testing or inspection is sufficient (given the potential for fouling) to detect degradation prior to loss of heat removal capabilities below design basis values.

Issue Date: 05125106 71111.07

a.

These tests should be those typically sanctioned by industry. The heat exchangers should be in a system that is directly cooled by the safety-related service water system or the credited water system cooled by the ultimate heat sink. Test acceptance criteria and results have appropriately considered differences between testing conditions and design conditions (functional testing at design heat removal rate may not be practical); and the test results have appropriately considered test instrument inaccuracies and differences.

b.

No specific guidance

c.

The licensee should have an acceptance criteria for its bio-fouling controls that is based on an industry standard, supportive program results, or the recommendation of the appropriate vendors.

d.

Primarily focus on whether the number of tubes plugged affects the heat exchanger's operability and not the biofilm on the inside of tubes which should be covered in the biennial inspection by a specialist. The licensee should have an acceptance criteria that indicates the maximum number of tubes that may be clogged for a specific heat excharrger and a basis for that acceptance criteria.

03.02 Biennial Review

a.

There is no limitation on the type and size of heat exchangers that can be selected as long as they are cooled by the safety-related service water system or the credited water system cooled by the ultimate heat sink and they are ranked high in the plant specific risk assessment. The credited water source is the one relied on in accident analyses in the licensee's safety analysis report. The selection of the heat exchanger also should consider results from previous annual inspection and heat exchangers with past history of problems/extensive corrective actions.

b.

For this requirement, if possible, focus on the credited water source as defined in 03.02a. above. Of the heat exchangers selected only those directly cooled by the safety-related service water system should be reviewed or evaluated for this inspection requirement in accordance with Generic Letter 89-1 3.

1.

No specific guidance (a - c)

No specific guidance (d).

Test results need to be extrapolated to the heat exchanger design conditions.

(e)

Trending of the results of heat exchanger performance tests should not have abrupt step changes without the licensee providing some valid justification as to the reason for the deviation..

( f 1 Test instruments should be calibrated and set on appropriate range for the parameters to be measured, otherwise small measurement errors could affect the test results. The required accuracy of the instruments depends on the margins available between the calculated parameter based on the test results and the limiting design condition.

(9)

No specific guidance

2.

No specific guidance Issue Date: 05/25/06

3.

No specific guidance

c.

This inspection requirement should target those design and operational requirements other than those evaluated by performance testing or inspection/cleaning.

1.

The inspector can refer to either design assumptions in calculations or also parameters on design data sheet that can be evaluated by observation not testing.

2.

No specific guidance

3.

No specific guidance

4.

This inspection requirement is or~ly applicable to those heat exchangers cooled by safety-related service water or the credited water source as defined above in 03.02a. and which are also in closed loop systems.

5.

No specific guidance For this requirement focus on the credited water source as defined in 03.02a.

above. The inspector should assess whether the ultimate heat sink and its subcomponents are capable of performing their intended safety functions. Only two of the listed parameters which are applicable for the respective plant should be reviewed on a biennial basis. For plants that have dams or other containments for the UHS, the inspection frequency is no longer always optional. This is based on findings concerning capacity and structural integrity on a facility with an UHS dam. Consideration for more frequent inspection should be made if there is known or suspected degradation. If the UHS is not licensee owned, ensure advance notice is provided to allow preparations for visual inspection if desired.

1.

lnspection of above ground UHS embankments, where they exist, should identify:

a.

Erosion which could lead to loss of structural integrity.

b.

Loss of shoreline protection can lead to a changing shoreline resulting in UHS capacity that is less than the design. Large vegetation, such as tree roots or burrowing animals can weaken the integrity of,the embankments. Similarly, decayed tree roots can allow formation of a water channel in the embankment that weakens the integrity.

c.

If available, review licensee or third party dam inspections for integrity of heat sink.

d.

Changing shore lines or sedinient intrusion can reduce UHS capacity.

Lessons learned from plant inspections include: degradation of the shoreline by vegetation growth can cause compacted clay to degrade and slump into the heat sink reducing capacity, also an insufficient number of measurements taken of the depth of water may not identify significant debris or sediment build-up in the UHS.

2.

lnspection of underwater UHS structures should identify settlement or movement indicating loss of structural integrity and/or capacity. The height of water over the crest of the weir should be constant in cases where the licensee takes these measurements to verify capacity.

Issue Date: 05/25/06 71111.07

3.

Review of changes or modifications should ensure that key design basis requirements were considered as inputs and maintained. Consideration may be given to reviewing planned modifications as well as age-related changes that have the potential to adversely impact the LlHS design basis including intake structures, reservoir and dam material conditions.

4.

This requirement can be satisfied by test results, observation, or other equivalent methods that verify ultimate heat sink and subcomponents can accommodate maximum system flow. Operating experience in 2004 and 2005 indicates a number of events involving foreign material intrusion into the systems.

These events include clogging of system piping, heat exchangers and strainers due to overpopulation of small fish that are pulled into the system, underwater grasses and kelp that break off or die, and sediment intrusion. Generic Letter 89-1 3 recommended once per refueling outage visual inspection for macroscopic biological fouling, sediment and corrosion and removal of accumulation. Some licensees have made commitments pursuant to Generic Letter 89-1 3 to minimize the potential for clogging equipment.

5.

Best verified by checking conformance with the acceptance criteria adopted I

by the licensee for checking the adequacy of the licensee's biotic fouling controls.

6.

This inspection requirement should determine whether licensee has procedures to deal with adverse weather conditions.

Coordinate the performance of this step with the inspection requirements of IP 71 11 1.01, "Adverse Weather Protection." Also, this inspection should verify that the LlHS water temperature is monitored and has not exceeded licensing or design basis.

7.

No specific guidance.

I

e.

No specific guidance 03.03 ldentification and Resolution of Problems The inspector should focus on events or conditions that could cause the loss of a heat exchangerlsink due to events such as heat transfer problems, improper cleaning, ice buildup, grass intrusion, or blockage of pipes and components. The inspector should determine whether the licensee has appropriately considered common-cause failures. If any loss of heat exchangerlsink events have occurred, these should receive the priority for review. Review the corrective actions to determine if actions were sufficient to prevent recurrence of the problem. Refer to IP 71 152, "ldentification and Resolution of Problems,"

for further guidance in this area.

This inspection procedure is estimated to take, on average, 5 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> for an annual review and 34 to 46 hours5.324074e-4 days <br />0.0128 hours <br />7.60582e-5 weeks <br />1.7503e-5 months <br /> for a biennial review at a site regardless of the number of units at that site. These estimates depend on the number of heat exchangerslsinks tested by the licensee during the inspection period.

Issue Date: 05125106

71 11 1.07-05 PROCEDURE COMPLETION lnspection of the minimum sample size will constitute completion of this procedure in the Reactor Programs Systems (RPS). That minimum sample size will consist of one sample, on an annual basis, to verify the readiness/availabilityof one heat exchangerlheat sink per Section 02.01, and two samples, on a biennial basis, to verify the heat exchangerlheat sink performance in accordance with Section 02.02.

71 1 11.07-06 REFERENCES EPRl NP-7552 Heat Exchanger Performance Monitoring Guidelines (Call the NRC Technical Library to get a copy of this if needed.)

ASME OM-SIG Part 21 lnservice Performance Testing of Heat Exchangers in Light-Water Reactor Power Plants NLIREG 1275 Vol. 3 Operating Experience Feedback Report-Service Water System Failures and Degradations NUREGICR-5865 Generic Service Water System Risk-Based lnspection Guide NUREGICR-0548 Ice Blockage of Water Intakes Generic Letter 89-13 Service Water System Problems Affecting Safety-Related Equipment IN 2004-07 Information Notice: Plugging of Safety Injection Pump Lubrication Oil Coolers with Lakeweed RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants See the following web links for reference documents:

I http:llwww.internal.nrc.~ov/lRMILlBRARYlstandards/ihs.htm http://www.internal.nrc.qov/lRM/LIBRARY/Iibrarv. htm END Issue Date: 05/25/06

ATTACHMENT 1 Revision Historv for IP 71 1 11.07 lssue Date: 05/25/06 71 11 1.07, Att 1 Commitment Tracking Number Training Completion Date N/A N/A Issue Date 05/25/06 05/25/06 Comment Resolution Accession Number NIA ML061290102 Description of Change Researched commitments back four years - none found.

Revised to incorporate lessons learned from AN0 inspection regarding UHS dam integrity (report number 2005008); FB-937.

Inspections of the UHS water reservoir is required every other biennial inspection.

Also, addressed FB-996 regarding inspections to prevent clogging of UHS equipment with sediment.

Other minor editorial comments also included.

Training Required None None

NRC STAFF EXHIBIT 16

May 12,2006 Mr. Michael A. Balduzzi Site Vice President Entergy Nuclear Operations, Inc.

Pilgrim Nuclear Power Station 600 Rocky Hill Road Plymouth, MA 02360-5508

SUBJECT:

PILGRIM NUCLEAR POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000293/2006002

Dear Mr. Balduzzi:

On March 31, 2006, the US Nuclear Regulatory Commission (NRC) completed an inspection at your Pilgrim reactor facility. 'The enclosed integrated inspection report documents the inspection findings, which were discussed on April 6, 2006, with Mr. Dietrich and members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents one finding of very low safety significance (Green), which involved a violation of NRC requirements. However, because of the very low safety significance and because the issue has been entered into your corrective action program, the NRC is treating the issue as a non-cited violation (NCV), in accordance with Section VI.A.l of the NRC's Enforcement Policy. Additionally, a licensee-identified violation that was determined to be of very low safety significance is listed in Section 40A7 of this report. If you contest any NCV in this report, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at Pilgrim.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosures will be available electronically for public inspection in the NRC Public Document

Michael Balduzzi 2

Room or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.aov/readinq-rmladams.html (the Public Electronic Reading Room).

Sincerely, IRA by Tracy Walker for Clifford Anderson1 Clifford Anderson, Chief Projects Branch 5 Division of Reactor Projects Docket No.

50-293 License No.

DPR-35

Enclosure:

Inspection Report 50-293106-02 wl

Attachment:

Supplemental Information cc wlencl:

G. J. Taylor, Chief Executive Officer, Entergy Operations M. Kansler, President, Entergy Nuclear Operations, Inc.

J. T. Herron, Senior Vice President and Chief Operating Officer C. Schwarz, Vice-President, Operations Support S. J. Bethay, Director, Nuclear Safety Assessment

0. Limpias, Vice President, Engineering J. F. McCann, Director, Licensing C. D. Faison, Manager, Licensing M. J. Colomb, Director of Oversight, Entergy Nuclear Operations, Inc.

B. S. Ford, Manager, Licensing, Entergy Nuclear Operations, Inc.

T. C. McCullough, Assistant General Counsel S. Lousteau, Treasury Department, Entergy Services, Inc.

R. Walker, Department of Public Health, Commonwealth of Massachusetts The Honorable Therese Murray The Honorable Vincent deMacedo Chairman, Plymouth Board of Selectmen Chairman, Duxbury Board of Selectmen Chairman, Nuclear Matters Committee Plymouth Civil Defense Director D. O'Connor, Massachusetts Secretary of Energy Resources J. Miller, Senior Issues Manager Office of the Commissioner, Massachusetts Department of Environmental Protection Office of the Attorney General, Commonwealth of Massachusetts Electric Power Division, Commonwealth of Massachusetts R. Shadis, New England Coalition Staff D. Katz, Citizens Awareness Network Chairman, Citizens Urging Responsible Energy J. Sniezek, PWR SRC Consultant M. Lyster, PWR SRC Consultant

1 R07 Heat Sink Performance (IP 71 11 1.078)

a.

Inspection Scope (4 samples)

Based on a plant specific risk assessment, past inspection results, and recent operational experience, the inspectors selected a sample of four safety-related heat exchangers (HXs) for review: the B Reactor Building Closed Cooling Water (RBCCW)

HX, the B Residual Heat Removal (RHR) room cooler, the High Pressure Coolant Injection (HPCI) room cooler, and the Reactor Core Isolation Cooling (RCIC) room cooler. The Salt Service Water (SSW) system, which provides cooling to the RBCCW HXs, was also reviewed, as was the RBCCW system, which provides cooling to the safety-related room cooler heat exchangers.

Enclosure

The inspector reviewed performance tests, periodic cleaning, eddy current inspections, chemical control methods, tube leak monitoring, the extent of tube plugging, potential water hammer analysis, operating procedures, maintenance practices. The inspector also confirmed that controls for the selected components conformed to Entergy's commitments to Generic Letter 89-1 3, "Service Water System Problems Affecting Safety-Related Equipment." The inspector compared the inspection results to the established acceptance criteria to verify that the results were acceptable and that the HXs operated in accordance with design. The inspector walked down the systems, structures, and components, and monitored a performance test of the B RBCCW HX. The inspectors reviewed system health reports and interviewed applicable system engineers.

The inspector confirmed that potential common cause heat sink performance problems that had the potential to increase risk were identified and corrected by Entergy. The inspector closely examined potential macro fouling (silt, debris, etc.) and biotic fouling issues. The inspector walked down the Salt Service Water intake, chlorination system, and other support and sub components of the Salt Service Water system to assess the material condition of these systems and components.

The inspector reviewed a sample of condition reports (CRs) related to the RBCCW HXs, the safety-related room coolers, and the SSW system to ensure that Entergy was appropriately identifying, characterizing, and correcting problems related to these systems and components. The documents that were reviewed are listed in the attachment to the report.

b.

Findinas No findings of significance were identified.

1 R11 Licensed Operator Requalification (71 11 1.1 1)

.I Licensed Operator Simulator Traininq

a.

Inspection Scope (1 sample)

The inspector observed an evaluated licensed operator simulator training exercise on January 23, 2006. The training was performed using scenarios SES-148 and involved both operational transients and design basis events. The inspector evaluated both the crew's performance and evaluators' assessments in-terms of the crew meeting the scenario objectives, accomplishing the critical tasks, proper use of abnormal and emergency operating procedures, command and control, effective communication, and the crew's ability to implement the emergency plan in-terms of event classification and notification. The inspector reviewed the post-scenario critique and confirmed lessons learned and items for improvement were discussed with the crew to enhance future performance.

Enclosure

NRC STAFF EXHIBIT 17

PNPS-FSAR 10.7 SALT SERVICE WATER SYSTEM 1 0. 7. 1 S a f e t y Objective The s a f e t y o b j e c t i v e of t h e S a l t S e r v i c e Water (SSW) System is t o provide a h e a t s i n k f o r t h e Reactor Building Closed Cooling Water (RBCCW) System under t r a n s i e n t and a c c i d e n t conditions.

10.7.2 S a f e t y Design Basis

1.

The system is designed w i t h s u f f i c i e n t redundancy s o t h a t no s i n g l e a c t i v e system component f a i l u r e can prevent t h e system from achieving its s a f e t y o b j e c t i v e.

2.

The system is designed t o continuously provide a supply of cooling water t o t h e secondary s i d e of t h e RBCCW h e a t exchangers adequate f o r t h e requirements o f t h e RBCCW under t r a n s i e n t and a c c i d e n t c o n d i t i o n s.

10.7.3 Power Generation Objective The power g e n e r a t i o n o b j e c t i v e o f t h e SSW System is t o provide a h e a t s i n k f o r t h e RBCCW System and t h e Turbine Building Closed Cooling Water (TBCCW)

System d u r i n g planned operations i n a l l o p e r a t i n g s t a t e s.

10.7.4 Power Generation Design B a s i s The system is designed t o f u n c t i o n a s t h e u l t i m a t e heat s i n k f o r a l l t h e systems cooled by t h e RBCCW and TBCCW during a l l planned o p e r a t i o n s i n a l l o p e r a t i n g s t a t e s by continuously providing adequate cooling water flow t o t h e secondary s i d e s of t h e RBCCW and TBCCW heat exchangers.

10.7.5 Description The e n t i r e SSW System shown on Figure lo.--; is designed i n accordance w i t h C l a s s I c r i t e r i a, and t h e r e is 20 C l a s s I1 Seismic piping i n t h e system.

See Appendix C and Section 1 2.

The Service Water System c o n s i s t s of f i v e v e r r ~ x l s e r v i c e water pumps located i n t h e i n t a k e s t r u c t u r e,

and associated piping,

valving, and instrumentation.

The pumps disckarge t o a common header from which independent p i p i n g s u p p l i e s each of t h e tldo cooling water loops, each loop c o n s i s t i n g of cne Xeactor Building and one Turbine Building cooling water keaz

-:-changers.

Tw'2 d i v i s i o n valves are included i n t h e common

s:harge header r2 permit t h e SSW System t o be operated a s two i ~ d e ~ e ~ d e n t loops.

The water then r e t u r n s t o t h e bay from t h e s l ~ r l e r of the heac exchangers.

The heat exchangers a r e valved s.i-5 :hat they can be i n d i v i d u a l l y backwashed without i n t e r r u p t i n g sys:en operation.

>my marine growth occurring i n t h e h e a t exchangers x111 be controlled by hypochlorination based upon r e s i d u a l c h l o r i n e csntent measured I n t h e discharge headers.

Xev 2 1 - Oct 1937

PNPS-FSAR Sample valves have been i n s t a l l e d i n each of t h e independent cooling water loops, between t h e pumps and t h e h e a t exchangers.

These valves a r e t o be used f o r t h e following purposes:

1.

To obtain a g r a b sample of service water.

2.

To provide access t o t h e header f o r venting 1

Each service water pump has an automatic a i r v e n t t o prevent water h m e r.

Pump bearings a r e marine c u t l a s s type, s u i t a b l e f o r s e a water a p p l i c a t i o n and a r e l u b r i c a t e d by water a s it rises through t h e pump column.

The following number of pumps w i l l be used during each of t h e indicated modes:

Normal Operations

~ c c i d e n t -

Conditions (LOCA)

Shutdown Conditions Number o f Pumps 1 t o 4 The number of pumps required f o r normal o p e r a t i o n is s e l e c t e d based on p l a n t cooling needs and SSW i n l e t temperature.

Pressure t r a n s m i t t e r s mounted a t t h e discharge header provide i n d i c a t i o n i n the c o n t r o l room t o allow o p e r a t o r s t o monitor SSW pump performance.

Plant Technical S p e c i f i c a t i o n s o r i g i n a l l y described t h e minimum required SSW pump performance a s 2700 gprn a t 55 f t. TDH.

Actual SSW pump r a t e d performance is 2700 gpm a t 95 f t TDH and minimum required performance f o r in-service t e s t i n g is defined a s 2700 gpm a t 87.5 f t TDH.

These TDH values a r e f o r t h e pump bowl not including t h e 40 f t v e r t i c a l pump column.

The 55 f t value r e p r e s e n t s the minimum required pressure, i n f e e t, measured a t t h e c e n t e r l i n e of t h e pump discharge piping (EL 23.9 f t ) f o r a pump bowl operating a t 2700 GPM a t 87.5 f t TDH.

The s e a water t i d e l e v e l used i n accident anal:/sis c a l c u l a t i o n s is 7.1 f t below msl, t h e yearly astronomical miniinn low t i d e.

This is t h e value used f o r t h e design b a s i s a n a l y s i s of t h e minimum SSW system performance required t o perform t h e emergency containment cooling function.

This low t i d e occurs f o r s k o r t periods of t i m e during t h e semidiurnal t i d a l v a r i a t i o n s once every year.

For t h e SSW system performance a n a l y s i s, t h i s lowest t i d e l e v e l is assumed t o be constant, thereby y i e l d i n g a conservatively low SSW system flow r a t e during accident analyses t h a t span a several day period.

The SSW pumps a r e a l s o assumed t o be operatl-g a t t h e i r minimum performance thereby providing only t h e r e q i l r e d 4500 gprn t o the RBCCW heat exchanger.

Rev 22 - Ocr 1999

PNPS-FSAR The minimum sea water level for maintaining SSW pump rated performance is I approximately 13 feet 9 inches below msl. This represents the lowest sea water at which a SSW pump bowl operating at its rated performance of 95 feet TDH at 2700 gpn will produce a discharge head of 55 feet at 2700 gpn as measured at EL 23.9 feet. The lowest postulated instantaneous sea water level is 10.1 feet below msl (Section 2.4.4.2) caused by a hurricane producing 110 mph winds blowing directly offshore during the same critical hour at which the yearly astroncanical low tide occurs. At this lowest water lwel, the pumps are capable of maintaining rated performance which implies that they have adequate NPSH and suhnergence (to prevent vortexing).

It is not appropriate to assume that this condition will exist long enough to require that it be the design basis for the long term emergency cooling function of the SSW system for which these pumps are assumed to be at their rninimuxn required performance level.

The buried portions of the 22" nominal diameter discharge piping from the last flange connections in the Auxiliary Building piping vault to the end of the discharge pipes at the Seal Well opening have been provided with a Cured-In-Place-Pipe (CIPP) lining. The 240 ft total length Loop "A" lining was installed in RFO-14 and the 225 ft total length "B" lining was installed in RFO-13. The CIPP liner material consists of a tube composed of nonwoven polyester felt material that is saturated with either an isophthalic polyester resin and catalyst system (Loop "An) or epoxy resin and hardener system (Loop "Bu) with a polyurethane or polyethylene inner membrane surface. The liner has a nominal 1/2" installed thickness. The resulting configuration is a rigid resin composite pipe within the original pipe with no requirements for bonding between the pipes.

The Salt Service Water System is designed to provide a heat sink for the Reactor Building Closed Cooling Water System under accident and transient conditions.

Section 14.5 describes the Containment Cooling System analysis for a design basis loss of coolant accident (LQCA) at both a salt water inlet t ~ r a t u r e of 659 and 759.

To ensure that the safety design basis in Section 10.7.2 is achieved, flow condition is improved by the addition of baffle plates in the west side service water bay and a rear sluice gate allows maintenance and operational flexibility. The gate is normally closed and does provide a barrier to c m o n mode failures.

It does not provide a separation function as the salt service water pump bay is a single bay. It was not sized to allow supply of a seawater pump.

To ensure that sufficient seawater flow is maintained through the RBCCW heat exchangers (minimum of 4500 gpn for each heat exchanger), rnotor-operated butterfly valves on the TBCCW heat exchanger outlets will automatically adjust to preset throttling positions and the RBCCW outlet valves will simultaneously open.

Autamatic adjustment of the outlet valves occur following a loss of coolant accident (LOCA) with a coincident Loss of Offsite Power (LLX3P), or a LOCA with degraded voltage on the safety buses while being supplied from the startup transformer.

If a LOCA occurs without a LLX3P or degraded voltage condition, the heat exchanger outlet valves remain as-is. Manual adjustments of the outlet valves will be made by operators to achieve adequate cooling water flow.

The loss of AC power will trip all service water pumps and will close one of the two division valves in the cammon pump discharge header, effectively dividing the service water system into two independent loops. Two pumps would be connected to each loop. The two division valves are arranged to permit the fifth (middle) pump to be operated on either loop. The operator preselects the division valve to be closed and thereby determines which loop will be connected to the middle punp?. Either valve can also be closed by a hand switch.

For the limiting design basis emergency condition, the Circulating Water System pumps (Section 11.6) are not operating.

This assumption is based on the need for the containment heat removal function of the SSW System versus the Circulating Water System when the Main Condenser is not being used as the heat sink. For either emergency containment heat removal or normal shutdown cooling, the SSW System is the main heat sink for the reactor core decay heat only after the discharge of steam to the Main Condenser has stopped.

For the bounding design basis LOCA (Section 14.51, it is only the RHR, RBCCW, and SSW Systems that provide containment heat removal.

To maximize the containment heat removal frcnn a single loop of these systems, when required, the circulating water pumps are secured so that the lwel in the SSW pumps bay(s) will be equal to the ocean tide level and unaffected by operation of the Circulating Water

.,System.

There are a number of single failures that can result in a SSW System configuration where one SSW pump will be supplying flw to both trains of SSW during the first ten minutes of an accident.

Should this occur, operators are then m t e d to align the SSW System for optimal performance by starting additional pumps and/or

.closing division valves as required. This mode of operation has been analyzed and determined to be acceptable.

The pumps are separated into two loops electrically. In the went of the loss of the preferred AC power source, the two SSW pumps on loop A are powered by diesel generator A. They provide cooling to RBCCW loop A (also powered by diesel generator A) which provides cooling to all Core Standby Cooling System components loaded on diesel generator A. The two salt service water pumps on loop B have the same relationship, both to their standby AC power source, diesel generator B, and to RBCCW Loop B. The fifth pump is loaded on a c m o n emergency service bus which can be powered fram either standby AC power source.

PNPS-FSAR I n i t i a t i o n of standby AC power following l o s s of t h e p r e f e r r e d AC power source w i l l automatically s t a r t a t l e a s t one pump i n each loop during normal conditions.

Following a LOCA and l o s s - o f - o f f s i t e power one and only one pump w i l l s t a r t i n each loop because of d i e s e l load l i m i t a t i o n s.

Additional pumps a r e s t a r t e d manually by t h e operator as a d d i t i o n a l cooling loads a r e e s t a b l i s h e d and d i e s e l c a p a c i t y is made available.

10.7.6 Safety Evaluation The SSW System is designed with s u f f i c i e n t redundancy s o t h a t no s i n g l e a c t i v e system component f a i l u r e nor any s i n g l e a c t i v e component f a i l u r e i n any o t h e r system can prevent it from achieving its s a f e t y o b j e c t ~ v e. Two independent closed loops with f u l l heat t r a n s f e r capacity on each loop are provided.

The existence of s i n g l e f a i l u r e s which place t h e SSW system i n t h e mode o f one pump supplying both t r a i n s of heat exchangers f o r the f i r s t t e n minutes of an accident has been analyzed and found t o be acceptable.

Operator a c t i o n is c r e d i t e d a f t e r t e n minutes t o r e a l i g n t h e system f o r optimal performance.

The 22 inch discharge headers leave t h e Reactor Building a t an e l e v a t i o n of 15 f t 7 i n msl.

The two p a r a l l e l l i n e s run approximately para;;.,~l t o t h e s h o r e l i n e wicl: a 2.8 percent slope.

At a point approxvnately i n l i n e with t h e edge of t h e intake s t r u c t u r e t h e l i n e s t u r n and then p a r a l l e l t h e c e n t e r l i n e of t h e discharge s t r u c t u r e with a 1.98 percent slope.

At an e l e v a t i o n of

-6 1/2 f t m s l t h e two discharge l i n e s t u r n and e n t e r t h e s i d e of the discharge s t r u c t u r e sealwell.

Detection of leakage i n t h e Reactor Building a u x i l i a r y bay is provided by two water l e v e l d e t e c t o r s mounted i n each a r e a.

The d e t e c t o r s provide control room personnel with e a r l y i n d i c a t i o n of flooding such t h a t personnel can be dispatch&

t o t h e a r e a t o i d e n t i f y the source and e f f e c t i s o l a t i o n.

Dewatering of a major pipe rupture is accomplished by two 1 4 inch d r a i n l i n e s i n each a r e a which d i r e c t the water t o t h e torus compartment.

The discharge of t h e d r a i n l i n e s is submerged i n a water trough t o ensure t h a t a s u f f i c i e n t water s e a l e x i s t s between t h e t o r u s compartment and t h e Reactor Building a ~ u i l i a r y bay.

The drain l i n e dewatering capacity is sized on t h e maximum possible flooding r a t e which r e s u l t s from a s i n g l e f a i l u r e i n any one l i n e.

Numerous small diameter f l o o r d r a i n s i n t h e R X Z H compartments a r e plugged t o prevent chloride and n i t r a t e i n t r, s i c. n s i n radwaste.

Therefore, normal leakage can accumulate t o a le-:sl of f o u r inches before overflowing t h e l i p around t h e fourteen inch dewatering l i n e s located i n each of t h e RBCCW compartments.

1 s a f e t y r e l a t e d equipment i n t h e RBCCW compartments w i l l be unaffected by flooding four inches above t h e f l o o r l e v e l.

Normal lzakage w i l l not prevent s a f e t y r e l a t e d systems o r components from performing t h e i r intended s a f e t y functions.

Rev 22 - Oct I999

PNPS-FSAR A major pipe break i n t h i s area w i l l not r e s u l t i n a l o s s of both I

RBCCW and TBCCW Systems because t h e redundant portions of each system a r e separated by a watertight b a r r i e r.

The watertight b a r r i e r consists of a watertight door and a spray barrier.

The spray b a r r i e r is located i n t h e pipeway immediately above t h e watertight door. Position switches provide s t a t i o n personnel with s t a t u s information f o r t h e watertight door at a l l times.

In order t o evaluate Pilgrim S t a t i o n ' s s u s c e p t i b i l i t y t o damage due t o a major o i l s p i l l i n Cape Cod Bay near t h e Pilgrim Nuclear Power Station, previous o i l s p i l l s have been examined r e l a t i v e t o power plant and i n d u s t r i a l proximity t o t h e s p i l l and t h e e f f e c t s observed.

Additionally, the various mechanisms by which s p i l l e d o i l can be transported i n water have been analyzed r e l a t i v e t o t h e s t a t i o n design.

The b a s i s f o r these comparisons was Systems Study of O i l Cleanup Procedures (Dillingham Corporation, 1969) and t h e American Petroleum I n s t i t u t e (API) Conference on Prevention and Control of O i l S p i l l s (December 1969).

Floating o i l would be prevented from entering t h e i n t a k e s t r u c t u r e by various devices.

The primary o i l containment device of t h e intake s t r u c t u r e is its entrance skimmer wall, which functions a s a submerged b a f f l e.

M i n h submergence of the b a f f l e is 5 f t a t I design low water l e v e l.

A secondary o i l containment device is a concrete b a f f l e wall inside t h e intake s t r u c t u r e, downstream from t h e t r a s h racks and upstream of t h e traveling screens and pumps.

This b a f f l e provides 2.2 f t submergence a t m l w l e v e l.

The f i n a l and most e f f e c t i v e o i l containment devices i n t h e intake s t r u c t u r e a r e t h e s l u i c e gates through which t h e service water pump s u c t i o n water must flow.

The s l u i c e gates a r e designed t o allow i s o l a t i o n and dewatering of e i t h e r c i r c u l a t i n g water bay.

Positioning of t h e gates halfway closed would allow e f f e c t i v e b a f f l i n g t o a submergence of 5 f t a t design low water l e v e l.

In the unlikely event of some o i l penetratin:

,he aforementioned b a r r i e r s, the minimum submergence a t design 12,d water level of the service water pumps of 11 f t would prevent tb.e ;il from being drawn i n t o the pump suction.

Should s l i g h t amounts of emulsified o i l reach z?.e s a l t s e r v i c e water pump suction t h e observable e f f e c t s would ce Limited t o a small decrease i n pumping efficiency and higher s y s t e ~

head l o s s e s due t o s l i g h t l y increased f l u i d viscosity.

Rev 2 1 - O c t 1997

PNPS-FSAR 10.7.7 Inspection and Testing Testing is performed on the SSW punps, safety related check valves, and all safety related motor and air operated valves in the ssw system in accordance with the 1n-Service Testing (IST) program. The testing is performed per the ASME code as required by 10 Cm

50. S5a(f),

to demonstrate compliance with plant technical specifications for the SSW pumps. Operational performance testing is also conducted on the SSW system to verify that the system meets design criteria.

maminations are conducted on SSW system components in accordance with the In-Service Inspection (ISI) program.

10.7.8 Nuclear Safety Requirements for Plant Operation General This section represents the nuclear safety requirements for the SSW System for each BWR operating state which result from the stationwide BWR systems analysis of Appendix G.

The following referenced portions of the safety analysis report provide important information justifying the entries in this section:

Rev 24 - Oct 2003

PNPS-FSAR r"

Ref erenca Informatl on Provl ded Descrlptlon of the SSW System hardware

2.

Statlon Nuclear Identl fl es condl tlons and Safety Operatl onal events f o r whlch SSW System Anal ys 1 s, Append1 x G actlon I s requlred Each detal l e d requl rement I n the f o l low1 ng analysl s I s referenced, i f possible, t o the most slgnlflcant statlon condltlon orlglnatlng the need f o r the requlrement by Identifying a matrlx block on Table 6.5-3.

The matrix block references are given I n parentheses beneath the detal l e d requirements i n the "minlmum required f o r action" section.

The matrix block references I d e n t i f y the BWR operating state, the event number and the system number.

For example, F39-99, I d e n t i f i e s BWR operation state F, event (row) No.

39, and system (column) No. 99, on Table 6.5-3.

The SSW System provides a heat sink f o r the RBCCW System.

N umber Provided bv Deslan This system conslsts o f two open loops.

Each loop has two pumps (plus a comnon spare),

p i ping, val vlng, lnstrumentatlon, and controls as necessary t o provlde coolant t o one RBCCW heat exchanger and one TBCCW heat exchanger on each loop.

Hi n i mum Reaul red f o r Act1 on BWR Operating States A, B, C, D, E, & F:

Two pumps w i t h associated controls and Instrumentation on one loop must be operable and the following valves on that loop operable:

1.

One TBCQJ heat exchanger o u t l e t valve unless valve I s t h r o t t l e d

2.

One RBCCW heat exchanger o u t l e t valve unless valve I s open 10.7-5 Revision 14 - June 1992

PNPS-FSAR

3.

One discharge header valve (for loop separation unless valve r

\\

i s f u l l y closed C

10.7.9 Current Technical Specifications I

The current 1 i m i ting conditions for operation, survei 11 ance requirements, and t h e i r bases are contained i n the Technical Speci fi cations referenced i n Append1 x 0.

10.7-6 Revision 12 - Jan 1991

NRC STAFF EXHIBIT 18

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555 November 7, 1991 1

.a TO:

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 t o be included i n Part 9900, Technical Guidance, of the NRC Inspection Manual.

The f i r s t is, "Resolution o f Degraded and Nonconforming Conditions."

The second is, "Operabl e/Operabi 1 i ty:

Ensuring the Functional Capability o f a System o r Component."

Copies o f the additions t o the NRC Inspection Manual (enclosure) are provided f o r information only.

No specific 1 i censee actions are required.

'The additions t o the NRC Inspection Manual are based upon previously issued guidance.

However, because o f the compl exi t y involved i n operabi 1 i t y determinations and the resol u t ion o f degraded and nonconforming conditions, there have been differences i n application by NRC s t a f f during past inspection activities.

Thus, the ' purpose o f publishing t h i s guidance i s t o ensure consistei~cy i n appl ication o f t h i s guidance by the NRC.

Regional.inspection personnel have been briefed on t h i s guidance.

The NRC w i l l conduct further training on these topics t o ensure uniform s t a f f understanding.

The use o f t h i s guidance by inspectors may raise backfitting issues f o r specific 1 i censees. The NRC backf i t t i n g procedures apply i n such cases.

L i cen'sees should consult with the Regional o f f i c e regarding the application o f specific staff positions i n the guidance.

Please contact the appropriate NRC Project Manager i f you have any questions regarding t h i s matter.

f o r Projects ff ice o f Nuclear Reactor Regulation

Enclosure:

As stat

NRC STAFF EXHIBIT 19

UNITED STATES NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION WASHINGTON, DC 20555-0001 September 26, 2005 NRC REGULATORY ISSUE

SUMMARY

2005-20:

REVISION TO GUIDANCE FORMERLY CONTAINED IN NRC GENERIC LElTER 91-18, "INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL SECTIONS ON RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY99 ADDRESSEES All holders of operating licenses for nuclear power reactors, including those who have permanently ceased operations and have certified that fuel has been permanently removed from the reactor vessel.

INTENT The U.S. Nuclear Regulatory Commission (NRC) is issuing this Regulatory Issue Summary (RIS) to inform licensees that it has revised the guidance contained in two sections of NRC Inspection Manual Part 9900, Technical Guidance, "OperableIOperability: Ensuring the Functional Capability of a System or Component" and "Resolution of Degraded and Nonconforming Conditions," and has combined these two documents into a single document.

The revised inspection guidance reflects relevant changes that have been made to NRC regulations, policies, and practices, and clarifies selected issues based on operating experience. This RIS requires no action or written response on the part of an addressee.

BACKGROUND INFORMATION The NRC staff inspection guidance contained in the two NRC lnspection Manual sections described above were initially provided to licensees in Generic Letter (GL) 91-18, issued on November 7,1991. The NRC staff revised the guidance in NRC lnspection Manual Part 9900, Technical Guidance, "Resolution of Degraded and Nonconforming Conditions," and issued it in Revision 1 of GL 91-18 on October 8, 1997. The purpose of Revision 1 of GL 91-18 was to more explicitly discuss the role of the 10 CFR 50.59 evaluation process in the resolution of degraded and nonconforming conditions.

In the summer of 2003, the NRC staff sought public comment on the technical guidance, which included holding a public workshop in August 2003. The staff revised the guidance based on the inputs received, and held a second public workshop to discuss it in August 2004.

Subsequently, the NRC staff met several times in 2005 with an industry task force formed by the Nuclear Energy Institute (NEI), and resolved the comments received from various stakeholders.

RIS 2005-20 Page 2 of 3

SUMMARY

OF ISSUE Attached is a revised NRC Inspection Manual, Part 9900, Technical Guidance, "Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety." This guidance supercedes the guidance previously provided in GL 91-18 and Revision 1 to GL 91-18.

The attached inspection manual section provides guidance to NRC inspectors for reviewing the actions of licensees pertaining to the operability of structures, systems, and components (SSCs) following the discovery of degraded and nonconforming conditions in SSCs. However, many licensees have found NRC's guidance to be very useful in developing their plant-specific processes, and therefore the NRC staff is communicating it to licensees as a RIS.

The NRC revised its inspection guidance to reflect ongoing regulatory changes, including implementation of the revised reactor oversight process, the requirement that licensees appropriately assess and manage risk related to proposed maintenance activities (10 CFR 50.65(a)(4)), and implementation of the revised change control process in 10 CFR 50.59, "Changes, Tests and Experiments." The revision also clarifies selected issues in the guidance based on operating experience and industry feedback.

In addition, the NRC concluded that the two inspection manual documents were closely related.

The NRC staff therefore combined the documents, and at the same time re-wrote them to make them clearer and more process-oriented. However, the NRC understands that licensees may collectively refer to the processes described in the revised Part 9900 as the "GL 91-18 process" or the "operability determination process (ODP)."

BACKFIT DISCUSSION This RIS requires no action or written response and, therefore, is not a backfit under 10 CFR 50.109. Consequently, the staff did not perform a backfit analysis.

FEDERAL REGISTER NOTIFICATION A notice of opportunity for public comment was published in the Federal Register on August 3, 2004 (69 FR 46599), to give interested parties an opportunity to suggest ways for improving the guidance. The staff concludes that this RIS and the attached NRC inspection guidance are informational and pertain to a staff position that does not represent a departure from current regulatory requirements and practices.

SMALL BUSINESS REGULATORY ENFORCEMENT FAIRNESS ACT OF 1996 This RIS is not a "rule" as defined in 5 U.S.C. 804 and therefore is not subject to the Congressional review provisions of the Small Business Regulatory Enforcement Fairness Action of 1996.

RIS 2005-20 Page 3 of 3 PAPERWORK REDUCTION ACT STATEMENT This RIS does not contain any information collections and, therefore, is not subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). The information collection requirements referenced in Manual Chapter 9900 are approved by the Office of Management and Budget approval number 3150-001 1 which expire February 28, 2007. The NRC may not conduct or sponsor, and a person is not required to respond to, an information collection unless the requesting document displays a currently valid OMB control number.

CONTACT Please direct any questions about this matter to the technical contacts listed below, or to the appropriate Office of Nuclear Reactor Regulation (NRR) project manager.

/RA/

Patrick L. Hiland, Chief Reactor Operations Branch Division of lnspection Program Management Office of Nuclear Reactor Regulation Technical Contacts: Carl S. Schulten, NRR James M. Trapp, (R-I) 301-415-1 192 61 0-337-51 86 E-mail: cssl @nrc.gov E-mail: jmtl @,nrc.gov Randall A. Musser, (R-ll)

Stephen C. Burton, Ill, (R-Ill) 91 9-362-0601 920-388-31 56 E-mail: rxml @nrc.qov E-mail: sxb3@nrc.aov Charles R. Stancil, Jr., (R-IV) 81 7-276-6532 E-mail: crsl @nrc.aov

Attachment:

NRC Inspection Manual Part 9900: Technical Guidance, "Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse To Quality or Safety" Note: NRC generic communications may be found on the NRC public website, http://www.nrc.aov, under Electronic Reading Room/Document Collections.

C.12 Operational Leakaqe From Code Class 1, 2, and 3 Components Leakage from the reactor coolant system, as specified in TSs, is limited to specified values in the TSs depending on whether the leakage is from identified, unidentified, or specified sources such as the steam generator tubes or reactor coolant system pressure isolation valves. If the leakage exceeds TS limits, the LC0 must be declared not met and the applicable conditions must be entered. For identified 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 on other components and materials.

Existing regulations and TSs require that the structural integrity of ASME Code Class 1, 2, and 3 components be maintained in accordance with the ASME Code.

In the case of specific typesof degradation, other regulatory requirements must also be met. If a leak is discovered in a Class 1, 2, or 3 component in the conduct of an inservice inspection, maintenance activity, or facility operation, corrective measures Issue Date: 09/26/05 C-9 9900, Operability Det Process

may require repair or replacement activities in accordance with IWA-4000 of Section XI. In addition, the leaking component should be evaluated for flaws according to IWB-3000, which addresses the analytical evaluation and acceptability criteria for, flaws.

The TSs do not permit any reactor coolant press[-lre bol-~ndary (RCPB) leakage. The operational leakage LC0 must be declared not met when pressure boundary leakage is occurring. Upon discovery of leakage from a Class 1, 2, or 3 pressure boundary component (pipe wall, valve body, pump casing, etc.), the licensee must declare the component inoperable.

Evidence of leakage from the press[-ire boundary indicates the presence of a through-wall flaw. It may be possible to use visual methods to determine the exterior dimension(s) and orientation of a through-wall flaw in a leaking component. When the outside surface breaking dimension of a through-wall flaw is small, the length and extent of the flaw inside the component wall may be quite long and potentially outside the lirr~its established by the Code.

For these reasons the component is declared inoperable while methods such as ultrasonic examination are performed to characterize the actual geometry of the through-wall flaw. However, after declaring inoperability for leakage from Class 3 moderate-energy piping, the licensee may evaluate the structural integrity of the piping by fully characterizing the extent of the flaw using volumetric methods and evaluating the flaw using the criteria of paragraph C.3.a of Enclosure 1 to GL 90-05.

If the flaw meets the criteria, the piping can subsequently be deemed operable but degraded until relief from the applicable Code requirement or requirements is obtained from the NRC. Alternatively, the licensee can evaluate the structural integrity of leaking Class 3 moderate-energy piping using the criteria of Code Case N-513, which is approved with limitations imposed by the NRC staff and incorporated by reference in 10 CFR 50.55(a)(b)(2)(xiii). The limitations imposed by the NRC staff are as follows:

a.

Specific safety factors in paragraph 4.0 of Code Case N-513 must be satisfied, and

b.

Code Case N-513 may not be applied to:

(1) components other than pipe and tubing, (2)

Leakage through a gasket, (3) threaded connections employing nonstructural seal welds for leakage prevention (through seal weld leakage is not a structural flaw, but thread integrity must be maintained), and (4) degraded socket welds.

Following the declaration of inoperability, the licensee may also decide to evaluate the structural integrity of leaking Class 2 or 3 moderate-energy piping using the criteria of Code Case N-513-1. The same limitations imposed by the NRC staff on Code Case N-513 apply to Code Case N-513-1.

Code Case N-513-1 has been reviewed and found acceptable by the NRC. However, Code Case N-513-1 has not yet been incorporated into RG 1.147 or the Code of Federal Regulations for generic use. Therefore, until Code Case N-513-1 is approved for generic use in either RG 1.147 or 10 CFR 50.55a,.the licensee must request relief and obtain NRC approval to use Code Case N-513-1.

9900, Operability Det Process C-I 0 Issue Date: 09126105

If,the piping meets the criteria of ASNlE Code Case N-513, continued temporary service of the degraded piping components is permitted. If the licensee decides to control the leakage by mechanical clamping means, the requirements of Code Case 523-2, *Mechanical Clamping Devices for Class 2 and 3 Piping Section XI, Division 1," may be followed, as referenced in 10 CFR 50.55a(b)(2)(xiii). This Code Case is to maintain the structural integrity of Class 2 and 3 piping which is 6 inches (nominal pipe size) and smaller and shall not be used on piping larger than 2 inches (nominal pipe size) when the nominal operating temperature or pressure exceeds 200°F or 275 psig. These and other applicable Code Cases which have been determined to be acceptable for licensee use without a request or authorization from the NRC are listed in RG 1.147. These Code Cases do not apply to Class 1 pressure boundary components.

The NRC has no specific guidance or generically approved alternatives for temporary repair of flaws (through-wall or non-through-wall) in Class 1, 2, or 3 high-energy system components, or for Class 2 or 3 moderate-energy system pressure boundary corr~ponents other than piping. Therefore, all such flaws in these components must be repaired in accordance with Code requirements, or relief from Code requirements must be requested of and approval obtained from the NRC.

C.13 Structural Requirements Structures may be required to be operable by the TSs, or they may be related support f~~nctions for SSCs in the TSs. Examples of structural degradation are concrete cracking and spalling, excessive deflection or deformation, water leakage, rebar corrosion, missing or bent anchor bolts, and degradation of door and penetration sealing. If a structure is degraded, the licensee should assess the structure's capability of performing its specified function. As long as the identified degradation does not result in exceeding acceptance limits specified in applicable design codes and standards referenced in the design basis documents, the affected structure is either operable or functional.

NRC inspectors, with possible headquarters support, should review licensees' evaluations of structural degradations to determine their technical adequacy and conformance to licensing and regulatory requirements.

END Issue Date: 09126105 9900, Operability Det Process

NRC STAFF EXHIBIT 20

combination of component type, material, environment, AERM, and AMP in LFW Table 2 with the GALL Report items. If there are no corresponding items in the GALL Report, the applicant leaves the column blank. In this way the applicant identified the AMR results in the LRA tables corresponding to the items in the GALL Report tables.

(8) Table 1 Item - The eighth column lists the corresponding summary item number from LFW Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with the GALL Report the Table 1 line item summary number should be listed in LFW Table 2.

If there is no corresponding item in the GALL Report, column eight is left blank. In this manner, the information from the two tables can be correlated.

(9)

Notes - The ninth column lists the corresponding notes used to identify how the information in each Table 2 aligns with the information in the GALL Report. The notes, identified by letters, were developedby an NEI work group and will be used in future LFWs. Any plant-specific notes identified by numbers provide additional information about the consistency of the lirie item with the GALL Report.

3.0.2 Staffs Review Process The staff conducted three types of evaluations of the AMRs and AMPs:

(I)

For items that the applicant stated were consistent with the 'GALL Report, the staff conducted either an audit or a technical review to determine such consistency.

(2)'

For items that the applicant stated were consistent with the GALL Report with exceptions, enhancements, or both, the staff conducted either an audit or a technical review of the item to determine such consistency. In addition, the staff conducted either an audit or a technical review of the applicant's technical justifications for the exceptions or the adequacy of the enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific GALL AMP elements; however, any deviation from or exception to the GALL AMP should be described and justified. Therefore, the staff considers exceptions as being portions of the GALL AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet all the program elements defined in the GALL AMP. However, the applicant may make a commitment to augment the existing program to satisfy the GALL AMP prior to the period of extended operation. Therefore, the staff considers these augmentations or additions to be enhancements. Enhancements include, but are not limited to, activities needed to ensure consistency with the GALL Report recommendations. Enhancements may expand, but not,reduce, the scope of an AMP.

(3) For other items, the staff conducted a'technical review to verify conformance with 10 CFR 54.21 (a)(3) requirements.

Staff audits and technical reviews of the applicant's AMPs and AMRs determine whether the aging effects on SCs can be adequately managed to maintain their intended function(s) consistent with the plant's current licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.

3.0.2.1 Review of AMPs For AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conducted either an audit or a technical review to verify the claim. For each AMP with one or more deviations, the staff evaluated each deviation to determine whether the deviation was acceptable and whether the modified AMP would adequately manage the aging effect(s) for which it was credited. For AMPS not evaluated in the GALL Report, the staff performed a full review to determine their adequacy. The staff evaluated the AMPs against the following 10 program elements defined in SRP-LR Appendix A.

(1)

Scope of.the Program - Scope of the program should include the.specific SCs subject to an AMR for license renewal.

(2)

Preventive Actions - Preventive actions should prevent or mitigate aging degradation.

(3)

Parameters Monitored or Inspected - Parameters monitored or inspected should be linked to the degradation of the particular structure or component.intended function(s).

(4)

Detection of Aging Effects - Detection of aging effects should occur before there is a loss of structure or component intended function(s). This includes aspects such as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and timing of newlone-time inspections to ensure timely detection of aging effects.

(5)

Monitoring and n rend in^ - Monitoring and trending should provide predictability of the extent of degradation, as well as timely corrective or mitigative actions.

(6)

Acceptance Criteria - Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the structure or component intended function(s) are maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions - Corrective actions, including root cause determination and prevention of recurrence, should'be timely.

(8)

Confirmation Process - Confirmation process should ensure that preventive actions are adequate and that appropriate corrective actions haye been completed and are effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and approval process.

(10) Operating Experience - Operating experience of the AMP, including past corrective actions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be adequately managed so that the SC intended function(s) will be maintained during the period of extended operation.

Details of the staffs audit evaluation of program elements (1) through (6) are documented in SER Section 3.0.3.

The staff reviewed the applicant's quality assurance (QA) program and documented its evaluations in SER Section 3.0.4. The staffs evaluation of. the QA program included assessment of the "corrective actions,"'"confirmation process," and "administrative controlsn program elements.

The staff reviewed the information on the "operating experiencen program element and documented its evaluation in SER Section 3.0.3.

3.0.2.2. Review of AMR Results Each LRA Table 2 contains information concerning whether or not the AMRs identified by the applicant align with the GALL AMRs. For a given AMR in a Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular system component type. Item numbers in column seven of the LRA, 'GALL Report Volume 2 Item,"

correlates to an AMR combination as identified in the GALL Report. The staff also conducted onsite audits to verify these correlations. A blank in.column seven indicates that the applicant was unable to identify an appropriate correlation in the GALL Report. The staff also conducted a technical review of combinations not consistent with the GALL Report. The next column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.

3.0.12.3 UFSAR Supplement Consistent with the SRP-LR, for the AMRs and AMPs that it reviewed, the staff also reviewed the UFSAR supplement, which summarizes the applicant's programs and activities for managing aging effects for the period of extended,operation, as required by 10 CFR 54.21 (d).

3.0.2.4 Documentation and Documents Reviewed In its review, the staff used the LRA, LRA amendments, the SRP-LR, and the GALL Report.

During the onsite audit, the staff also examined the applicant's justifications to verify that the applicant's activities and programs will'adequately manage the effects of aging on SCs. The staff also conducted detailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.

3.0.3.Aging Management Programs SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix 8. The table also indicates the SSCs that credit the AMPs and the GALL AMP with which the applicant claimed consistency and shows the section of this SER in which the staff's evaluation of the program is documented.

Table 3.0.3-1 PNPS Aging Management Programs

.';$:';.:jPNPS.AMP,::.;,,;:~.$

, (LRA sicaon).: ";.

.., ^... '.,;' "l;,:.,t

,;8'

.... :......?,cii~~ii~in~;:,,.;

'!;. :, : ~ ~ ~ ~ ~ ~ j ~ ~ ~ ',, ~ - :.,

Existing AMPS Boraflex Monitoring Program (B.1.1)

<i!sttie..'. ;.' ;:

~ ~ ~. & ~ t i b ~ i

,. G A L L

• R ~ ~ ~ o ~ ~ ' ~ :

.....':AMR=

'iP' <

LRI\\ spurns: or s t r ~ & i & '

".That ciedit-h& AMP'; "' r' :

Consistent 3.0.3.1.1 XI.M22 auxiliary systems

.:::~pjGi m p.:-,

. \\ ?...

.:.:.8(L.A S&ti&.,)

BWR CRD Retum Line Nozzle Program (B. 1.3)

BWR Feedwater Nozzle Program (8.1.4)

BWR Penetrations Program (B.1.5)

BWR Stress Corrosion Cracking Program (B.1.6)

BWR Vessel ID Attachment Welds Program (8.1.7)

BWR Vessels lntemals Program (B. 1.8)

Containment Leak Rate Program (B. 1.9)

Diesel Fuel Monitoring Program (B,l.lO)

Environmental Qualification (EQ) of Electric Components Program (6.1.1 1)

Fatigue Monitoring Program (B.1.12)

Fire protection Program (B.1.13.1)

Fire Water System Program (8.1:13.2)

FW.

$ i t. m. + s t ~ ~ ~ i ~ :i

..:. :' ". That Credlt the AMP. '

reactor vessel. internals, and reactor coolant system reactor vessel, internals. and reactor coolant system reactor vessel, internals, and reactor coolant system reactor vessel, intemals, and reactor coolant system reactor vessel, internals, and reactor coolant system reactor vessel, internals, and reactor coolant system engineered safety features systems I structures and component supports auxiliary systems electrical and instrumentation and controls reactor vessel,'internals, and reactor coolant system I engineered safety features systems / auxiliary systems /

steam and power conversion systems / structures and component supports auxiliary systems 1 structures' and component supports auxiliary systems I I,.:..

_ : ~ ~ ~ i s ~ ~

SER Sedtioii" 3.0.3.2.2 3.0.3.2.3 3.0.3.2.4 3.0.3.2.5 3.0.3.2.6 3.0.3.2.7 3.0.3.1.2 3.0.3.2.8 3.0.3.1.3 3.0.3.2.9 3.0.3.2:10 3.0.3.2.1 1

,:;GuL-R.~~~;~ ::;.:

,. :;.:.,c6,+iris&,,

Consistent with exceptions Consistent with exceptions Consistent with exceptions Consistent with exception and enhancement Consistent with exception Consistent with,

exceptions and enhancement Consistent Consistent with exceptions and enhancements Consistent '

Conslstent '

Consistent with exceptions and enhancements Consistent with exception and enhancements I

.,;GAL~:R~&~_

'?' AMP^..,:,:;,.

XI.M6 XI.M5 XI.M8 XI.M7 XI.M4 XI.M9 X1.S XI.M30 X.El X.Ml XI.M26 XI.M27

staff I.:

SER Section 3 0 3 1 4 3.0.3.3.2 3.0.3.3 3 3 0.3.3.4 3.0.3.2.13 3.0.3 3.5 3.0.3.2 14 3 0.3 2.15 3.0.3.2 16 3.0.3.1.10 3 0.3.2.17 3.0.3.2 18 3.0.3.1.1 1 L

-, PNPS AMP

,(LRA Section) v Flow-Accelerated Corrosion Program (B 1 14)

Conta~nment Inservice lnspectlon Program (B 1.16 1)

Inservice lnspect~on Program (8.1.16.2)

Instrument Alr Quality Program (B.1.17)

Oil Analysis Program (B 1.22)

Penodic Surveillance and Preventive Maintenance Program (B.1.24)

Reactor Head Closure Studs Program (8.1.25)

Reactor Vessel Surveillance Program (8.1 26)

Service Water Integrity Program (B 1.28)

Masonry Wall Program (8.1.29.1)

Structures Monitoring Program (0 1.29.2)

Water Control Structures Monitoring Program (B 1.29 3)

System Walkdown Program (8.1.30)

.LRA Systems or Structures "

That Credit the AMP reactor vessel, internals, and reactor coolant system I auxiliary systems I steam and power conversion systems structures and component supports reactor vessel, internals. and reactor coolant system I structures and component supports engineered safety features systems I auxil~ary systems engineered safety features systems I auxiliary systems engineered safety features systems I auxiliary systems I steam and power conversion systems I structures and component suppotts reactor vessel, internals, and reactor coolant system reactor vessel. intemals. and reactor coolant system auxiliary systems structures and component Supports structures and component supports structures and component supports reactor vessel, intemals, and reactor coolant system I engineered safety features systems 1 auxillary systems I steam and power conversion systems I

I

• . ; ~ ' ~ ~ e ~ o r t -

' Comparison Consistent Plant-specific Plant-speclfic Plant-specific Consistent mth exception and enhancements Plant-specific Consistent with exception Consistent with enhancement Consistent wth exceptions Consistent Consistent with enhancements Consistent with enhancement Consistent GALL Report AMPS :.

a XI MI7 XI.M39 XI.M3 XI.M31 XI.M20 XIS5 XI.S6 XIS7 XI.M36

Staff's '.,

SER Sectlon 3.0.3.3.6 3 0.3.1.13 3.0.3.2 19

% PNPS AMP.

(LRA Section)

Water Chemistry Control - Auxiliary Systems Program (8.1.32.1)

Water Chemistry Control - BWR Program (6.1.32 2)

Water Chem~stry Control - Closed Cooling Water Program (8.1.32.3)

GALL Report '

Comparison '

Plant-specific Consistent Consistent with exception New AMPS Buried Plplng and Tanks lnspect~on Program (8.1.2)

Heat Exchanger Monitoring Program (B.1.15)

Metal-Enclosed Bus Inspection Program (6.1.18)

Non-EQ Inaccessible Medium-Voltage Cable Program (B.l.19)

Non-EQ Instrumentation Circuits Test Revlew Program (8.1.20)

Non-EQ Insulated Cables and Connections Program (B.1.21)

One-T~me lnspect~on Program (6.1.23)

Selectwe Leaching Program (B 1.27)

"GALL ~ e p o r t

.",AMPS -

a XI M2 XI.M21 L w Systems or Structu~es,.

.,' 'That Credlt the AMP auxlliaty systems reactor vessel. internals, and reactor coolant system I eng~neered safety features systems I aux~l~ary systems I steam and power conversion systems reactor vessel. internals. and reactor coolant system I eng~neered safety features systems I auxiliary systems 3.0.3.2 1 3.0.3.3 1 3.0 3 2 12 3.0 3.1.5 3.0.3.1.6 3.0 3.1 7 3.0.3 1.8 3.0.3.1.9 Consistent with exception Plant-specific Consistent with exceptions Consistent Consistent Consistent Consistent Consistent XI.M34 XI.E4 XI.E3 XI.E2 XI.El XI.M32 XI.M35 XI.M33 engineered safety features systems 1 auxiliary systems I steam and power conversion systems engineered safety features systems I auxilrary systems electrical and instrumentatton and controls electrical and instrumentation and controls electr~cal and instrumentation and controls electrical and instrumentation and controls reactor vessel, internals, and reactor coolant system I eng~neered safety features systems I auxiliary systems engineered safety features systems I auxiliary systems I steam and power conversion systems

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of

)

)

ENTERGY NUCLEAR OPERATIONS, INC.

)

Docket No. 50-293-LR

)

(Pilgrim Nuclear Power Station)

)

ASLBP No. 06-848-02-LR

)

CERTIFICATE OF SERVICE I hereby certify that copies of NRC STAFF INITIAL STATEMENT OF POSITION ON PILGRIM WATCH CONTENTION 1, NRC STAFF TESTIMONY OF TERENCE L. CHAN AND ANDREA T. KEIM CONCERNING PILGRIM WATCH CONTENTION 1, NRC STAFF TESTIMONY OF DR. JAMES A. DAVIS REGARDING PILGRIM WATCH CONTENTION 1, CERTIFICATIONS of Terence L. Chan, Andrea T. Keim and Dr. James A. Davis and Exhibits 1 - 20 in the above-captioned proceeding have been served on the following by electronic mail and by deposit in the U.S. Nuclear Regulatory Commissions internal mail system as indicated by a single asterisk(*), or by electronic mail and by deposit in the U.S. Mail System, as indicated by a double asterisk (**) this 29th day of January, 2008.

Administrative Judge*

Richard F. Cole Atomic Safety and Licensing Board Panel Mail Stop: T-3F23 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: rfc1@nrc.gov Administrative Judge*

Paul B. Abramson Atomic Safety and Licensing Board Panel Mail Stop: T-3F23 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: pba@nrc.gov Administrative Judge*

Ann Marshall Young, Chair Atomic Safety and Licensing Board Panel Mail Stop: T-3F23 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: amy@nrc.gov Office of Commission Appellate

• Adjudication Mail Stop: O-16G4 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: OCAAMail@nrc.gov Sheila Slocum Hollis**

Duane Morris LLP 1667 K Street, NW, Suite 700 Washington, DC 20006 E-mail: sshollis@duanemorris.com Office of the Secretary*

Attn: Rulemaking and Adjudications Staff Mail Stop: O-16G4 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 E-mail: hearingdocket@nrc.gov Atomic Safety and Licensing Board*

Mail Stop: T-3F23 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Terence A. Burke, Esq.**

Entergy Nuclear 1340 Echelon Parkway Mail Stop: M-ECH-62 Jackson, MS 39213 Mary Lampert**

148 Washington Street Duxbury, MA 02332 E-mail: lampert@adelphia.net David R. Lewis, Esq.**

Paul A. Gaukler, Esq.

Pillsbury, Winthrop, Shaw, Pittman, LLP 2300 N Street, NW Washington, DC 20037-1137 E-mail: david.lewis@pillsburylaw.com paul.gaukler@pillsburylaw.com Chief Kevin M. Nord**

Fire Chief & Director Duxbury Emergency Management Agency 668 Tremont Street Duxbury, MA 02332 E-mail: nord@town.duxbury.ma.us Fax: 781-934-6530 Town Manager**

Town of Plymouth 11 Lincoln St.

Plymouth, MA 02360 E-mail: msylvia@townhall.plymouth.ma.us

/RA/

Kimberly A. Sexton Counsel for the NRC Staff