ML080160268

Entergy'S Initial Statement of Position on Pilgrim Watch Contention 1

ML080160268
Person / Time
Site:	Pilgrim
Issue date:	01/08/2008
From:	Gaukler P Entergy Nuclear Generation Co, Entergy Nuclear Operations, Pillsbury, Winthrop, Shaw, Pittman, LLP
To:	Atomic Safety and Licensing Board Panel
SECY/RAS
References
50-293-LR, ASLBP 06-848-02-LR, RAS 14909
Download: ML080160268 (182)

Text

&A§ L~Or~ January 8, 2008 DOCKETED UNITED STATES OF AMERICA USNRC NUCLEAR REGULATORY COMMISSION January 9, 2008 (8:00am)

Before the Atomic Safety and Licensing Board Panel OFFICE OF SECRETARY RULEMAKINGS AND In the Matter of ) ADJUDICATIONS STAFF

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR (Pilgrim Nuclear Power Station) ))

ENTERGY'S INITIAL STATEMENT OF POSITION

• "- ON PILGRIM WATCH CONTENTION 1 Pursuant to 10 C.F.R. § 2.1207(a) and the Atomic Safety and Licensing Board's

("Board") December 19, 2007 Order revising the schedule for submissions, Entergy Nuclear Generation Company and Entergy Nuclear Operations, Inc. (collectively, "Entergy") hereby submit their Initial Statement of Position ("Statement") on Pilgrim Watch Contention 1 ("PW Contention 1"). This Statement is supported by the "Testimony of Alan Cox, Brian Sullivan, Steve Woods, and William Spataro, 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" ("Entergy. Dir.") and Entergy's exhibits thereto that are being filed simultaneously with this Statement.

I. INTRODUCTION As admitted by the Board, PW Contention I reads:

[t]he 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.

4 Seey~c

Memorandum and Order, LBP-06-23, 64 N.R.C. 257, 315 (2006). Further, in ruling on Entergy's motion for summary disposition of this Contention, the Board clarified that:

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 license renewal period - or, put another way, whether Pilgrim's 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.

Memorandum and Order, LBP-07-12, 66 N.R.C. _, slip op. at 17 (Oct. 17, 2007).

PW Contention I has no merit. As testified to by the Entergy witnesses, only six systems at the Pilgrim Nuclear Power Station ("PNPS") contain buried pipes and tanks within the scope of PNPS license renewal. Entergy Dir. at Al18. Only one of those six systems - the Condensate Storage System ("CSS") - contains radioactive liquids and thus falls within the scope of PW Contention 1. The discharge piping for the Salt Service Water ("SSW") system could also contain some radioactivity in the highly unlikely event that cross-contamination of the SSW system were to occur, but there are design features, monitors and alarms, and surveillance procedures in place to prevent such cross-contamination from occurring. Entergy Dir. at A18.

For both the CSS and SSW system, PNPS has aging management programs ("AMPs") that are in place to protect against the loss of material due to corrosion and other aging related effects so as to provide reasonable assurance that the buried pipes in those systems will remain capable of performing their intended functions during the period of extended operation. Entergy Dir. at A18.

Also, as requested by the Board's Order of December 19, 2007, there are procedures that are part of routine operation that provide reasonable assurance that there is no leakage occurring 2

that might endanger the ability of the CSS and SSW system buried pipes to accomplish their intended safety functions.I In addition to the AMPs, PNPS employs surveillance tests for the CSS and SSW system which routinely demonstrate that the systems are capable of performing their intended functions. Entergy Dir. at Al 8. Indeed, using monitoring wells to detect leakage would not be nearly as effective as the AMPs and the surveillance programs in place and credited under the plant's Technical Specifications for ensuring that the CSS and the SSW system will perform their intended functions. Entergy Dir. at Al 8.

II. APPLICABLE LEGAL STANDARDS 10 C.F.R. § 54.21 (a)(3) requires that a license renewal application demonstrate, for each component within the scope of the license renewal rules, that the effects of aging are being adequately managed so that the intended functions will be maintained consistent with the current licensing basis during the period of extended operation. The standard for this demonstration is one of "reasonable assurance." See 10 C.F.R. § 54.29(a). See also Nuclear Power Plant License Renewal Final Rule, 60 Fed. Reg. 22,461, 22,479 (1995) ("... the [license renewal] process is not intended to demonstrate absolute assurance that structures or components will not fail, but rather that there is reasonable assurance that they will perform such that the intended functions..

. are maintained consistent with the CLB").

10 C.F.R. § 54.4(a) defines the plant systems, structure, and components functions that are within the scope of license renewal as follows:

(a) Plant systems, structures, and components within the scope of this part are -

Among the items requested by the Board in its December 19, 2007 Order were "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."

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(1) safety related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 C.F.R. 50.49 (b)(1)) to ensure the following functions -

(i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it in a safe shut-down condition; or (iii) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in § 50.34(a)(1), § 50.67(b)(2), or § 100.11 of this chapter as applicable (2) All non-safety-related systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1) (i), (ii), or (iii) of this section.

(3) All systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 C.F.R. 50.48), environmental qualification (10 C.F.R. 50.49), pressurized thermal shock (10 C.F.R. 50.61),

anticipated transients without scram (10 C.F.R. 50.62), and station blackout (10 C.F.R. 50.63).

Of these systems, structures, and components that fall within. the scope of the license renewal, the license renewal rules define the systems, structures, and components that are subject to aging management review as those that (i) perform an intended function, as described in § 54.4, without moving parts or without a change in configuration or properties; and (ii) are not subject to replacement based on a qualified life or specified time period. 10 C.F.R. § 54.21 (a)(1). The license renewal rules define "intended function(s)" as "those functions that are the bases for including them within the scope of license renewal, as specified in 10 C.F.R. § 54(a)(1)-(3). 10 C.F.R § 54.4(b). As the Board has correctly recognized, groundwater protection is not a function within the scope of 10 C.F.R. § 54.4.2 2Indeed, the Commission specifically denied a petition for rulemaking that would have revised the scope of license renewal to cover "liquid and gaseous radioactive waste management systems." 66 Fed. Reg. 65,141 (Dec. 18, 2001). The Commission denied the petition because (1) "liquid and gaseous radioactive waste management systems are not involved in design and licensing basis events considered for license renewal," and (2) "the existing 4

III. ENTERGY'S STATEMENT OF POSITION ON FACTUAL ISSUES A. Entergy's witnesses and evidence Entergy's testimony on PW Contention 1 will be presented by a panel of the following four experts:

(1) Alan Cox, who is the Technical Manager, License Renewal with Entergy, has over 30 years of experience in the nuclear industry. Mr. Cox was involved in preparing the license renewal application and developing aging management programs for the PNPS license renewal project. Entergy Dir. at A2. Mr. Cox is knowledgeable of the function and purpose of the AMPs that are described in the PNPS license renewal application, and he managed the technical staff responsible for preparing the license renewal application. Entergy Dir. at Al 5.

(2) Brian Sullivan, who is the Engineering Director for PNPS with over 24 years of experience in the nuclear industry, 19 of which have been at, PNPS. Entergy Dir. at A5, A6. Mr. Sullivan is knowledgeable of the intended functions for license renewal components and of the aging management programs credited for buried pipes and tanks for PNPS license renewal. Entergy Dir. at A5.

(3) Steven Woods, who is the Manager, Programs and Engineering Components for PNPS and has over 26 years of engineering experience. Entergy Dir. at A8, A9. In his current position, Mr. Woods is knowledgeable of the AMPs that are described in the PNPS license renewal application and will support the development of procedures to implement the AMPs. Entergy Dir. at A15. In addition, from May 1992 to July 1993, Mr. Woods was employed by an industry contractor and worked at PNPS as the Mechanical Project Engineer dedicated to the "Salt Service Water Pipe Replacement" project, where he was responsible for the engineering and installation of the titanium piping for the SSW inlet line.

regulatory process is acceptable for maintaining the performance of the radioactive waste systems throughout the period of extended operation in order to keep exposures to radiation at the current levels below regulatory limits consistent with the conclusions made in the applicable regulations." Id.

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Entergy Dir. at A9. Thus, he is familiar with the installation of buried piping at PNPS.

(4) William Spataro, who until December 31, 2007 was the Senior Staff Engineer-Corporate Metallurgist with Entergy. Entergy Dir. at Al1. In that capacity, he provided technical support in metallurgy, corrosion, welding and forensic investigation in support of Entergy's operation of its nuclear power plants.

Entergy Dir. at A 11. He has nearly 40 years of experience in the fields of metallurgy, welding, corrosion, and forensic investigation, including 27 years of service with Entergy and the New York Power Authority, the former owner and operator of Entergy's Fitzpatrick and Indian Point,3 nuclear plants. Entergy Dir.

at A12. Mr. Spataro is knowledgeable of the technical requirements in his fields of expertise that apply to the AMPs described in the PNPS license renewal application. Entergy Dir. at A15. In addition, Mr. Spataro was the primary author of the Entergy fleet-wide procedure for the inspection of buried piping and tanks at Entergy's nuclear power plants, the Buried Piping and Tanks Inspection Monitoring Program Procedure, No. EN-DC-343, Rev. 0 which will be used to implement the AMP for buried pipes and tanks at PNPS. Entergy Dir. at A15.

The testimony and opinions of the Entergy witnesses on PW Contention 1 are based on both their technical expertise and their personal knowledge of the issues raised in PW Contention

1. By contrast, a review of the curriculumvitae of PW's witnesses on this contention, Messrs.

David P. Ahlfeld and Arnold Gundersen, shows that neither has any experience or familiarity with the issues central to PW Contention 1. For example, neither has experience with the systems within the scope of license renewal, with buried pipes and tanks that contain radioactive liquid, or the AMPs employed at PNPS to provide reasonable assurance that those buried pipes and tanks will perforin their intended functions. See November.29, 2007 "Pilgrim Watch Witness List - Docket No. 50-293" and attachments thereto.

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The evidence provided by the Entergy witnesses demonstrates that the PNPS AMPs provide reasonable assurance that the buried piping within the scope of license renewal and PW Contention 1 will remain capable of performing their intended functions. In addition, PNPS employs surveillance tests for the CSS and SSW system, which regularly demonstrate that the systems are capable of performing their intended functions.

B. Only the CSS and SSW system have buried pipes and tanks within the scope of license renewal that contain or may radioactive liquids Of the six systems at PNPS with buried pipes and tanks that meet the scoping criteria of 10 C.F.R. § 54.4,3 the only system that contains radioactive liquid is the CSS. The CSS contains buried piping that runs for two 275,000 gallon condensate storage tanks ("CSTs") to the reactor core isolation cooling ("RCIC") pump and the high pressure coolant injection ("HPCI") pump.

One line of piping runs from each CST to the CST concrete vault where the two pipes connect to a header. The header runs from the vault underground to the reactor building auxiliary bay. The buried potion of the piping runs approximately sixty-four feet before entering the reactor building auxiliary bay. Entergy Dir. at A24. There are no buried tanks within this system.

The CSS has two license renewal intended functions. Regarding 10 C.F.R. § 54.4(a)(1),

the CSS supplies water to the suction of the RCIC pump and the HPCI pump. This same function is also credited under 10 C.F.R. § 54.4(a)(3), because the HPCI and RCIC systems are credited in the 10 C.F.R. 50 Appendix R safe shutdown analysis for fire protection. Entergy Dir.

at A27.

3 The six systems are (1) the CSS; (2) the Fire Protection water system; (3) the Fuel Oil system; (4) the SSW system; (5) the Standby Gas Treatment system ("SGTS"); and (6) the Station Blackout Diesel Generator system. Entergy Dir. at A24 7

It is also possible that the water in the SSW discharge piping could contain radioactively contaminated water, although design features and other measures make this highly unlikely.

Entergy Dir. at A24, A32. The SSW system also contains buried inlet piping, but that piping draws water from the Cape Cod Bay and would not contain radioactivity. Entergy Dir. at A33.

There are two loops of buried SSW system discharge piping. Loop A buried discharge piping runs 240 feet from the reactor building auxiliary bay to the discharge canal that runs into Plymouth Bay. Loop B buried discharge piping runs 225 feet from the reactor building auxiliary bay to the discharge canal that runs into Plymouth Bay. There are no buried SSW system tanks.

Entergy Dir. At A24 The SSW system has two license renewal intended functions. Regarding 10 C.F.R. § 54.4(a)(1), the SSW provides a heat sink for the RBCCW system under transient and accident conditions. The same is also credited under 10 C.F.R. § 54.4(a)(3) because the SSW is credited in the 10 C.F.R. Part 50 Appendix R safe shutdown analysis for fire protection (10 C.F.R. § 50.48). Entergy Dir. at A30.

None of the four remaining systems with buried pipes and tanks within the scope of the license renewal rule contain radioactive liquid. Entergy Dir. at A24.

C. PNPS License Renewal AMPs Pilgrim implements multiple programs to manage the effects of aging on buried piping and tanks that are within the scope of license renewal and subject to aging management review.

Entergy Dir. at A35. The applicable AMPs for in-scope buried pipes and tanks containing or potentially containing radioactive liquid are (1) the Buried Piping and Tanks Inspection Program

("BPTIP"); (2) the Water Chemistry Control-BWR Program; (3) the Service Water Integrity Program; and (4) the One-Time Inspection Program. Entergy Dir. at A35. The BPTIP manages 8

loss of material due to external corrosion of buried pipes, while the other AMPs manage loss of material due to internal corrosion of buried pipes. Entergy Dir. At A35.

These AMPs comport with the guidance in the Generic Aging Lessons Learned

("GALL") Report, NUREG-1801. At the Commission's direction and to improve the efficiency and effectiveness of license renewal reviews, the NRC Staff prepared the GALL Report4 to compile aging management programs that have been determined to be acceptable through a systematic NRC Staff evaluation of operating experience and program attributes. To further the NRC's objectives, a Board should accept conformance with the GALL Report as substantial evidence that an aging management program is adequate.

1. PNPS BPTIP The Buried Piping and Tanks Inspection Program ("BPTIP") manages the effects of aging on the external surfaces of buried components, specifically, the potential loss of material (i.e., the effect of aging caused by corrosion) from the external surfaces of components buried in soil. Entergy Dir. at A36. The BPTIP includes (1) preventive measures to protect against corrosion the external surfaces of buried pipes and tanks exposed to soil; and (2) inspections to manage the effects of external surface corrosion on the pressure-retaining capability of buried metal components. Entergy Dir. at A36.

The preventive measures that PNPS employs to protect against corrosion include (1) metals and cured in place linings that are corrosion resistant; (2) protective coal tar or epoxy 4 In SECY-99-148, Credit for Existing Programs for License Renewal (June 3, 1999), the Staff recommended focusing Staff review guidance in the Standard Review Plan for License Renewal (SRP-LR) on areas where existing programs should be augmented. According to the Staff, this option provided "an effective integrated review of programs being relied upon to manage aging for license renewal" and "would reduce unnecessary burden by focusing the staff review on augmented programs for license renewal" (SECY-99-149 at 7). By SRM dated August 27, 1999, the Commission approved the Staff's recommendation and directed the Staff to develop the GALL report to document its evaluation of generic existing programs.

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coatings for buried piping; and (3) procedures and precautions that ensure piping structures are installed in non-corrosive soil and are excavated and handled in a manner that does not damage the coating. Entergy Dir. at A37.

The CSS buried piping is made of stainless steel. Stainless steel is resistant to corrosion in soils. Entergy Dir. at A38, A39. PNPS engineering practice, however, is to apply protective coatings even to corrosion resistant piping such as those made of stainless steel or titanium.

The SSW discharge piping is made of carbon steel and is coated in accordance with PNPS specifications to prevent external degradation. Entergy Dir. at A42. In addition, the discharge lines are lined internally with cured in place pipe ("CIPP") to protect against internal corrosion of the piping. Entergy Dir. at A42. The expected life of the cured in place lining installed in 2001 and 2003 is 35 years, which would extend beyond the license renewal period.

Entergy Dir. at A43. The SSW inlet piping (which would not contain radioactively contaminated water) is made of titanium, which is immune to corrosion in soils (but is nevertheless protectively coated). Entergy Dir. at A40, A41.

The external coatings specified for the CSS and SSW buried piping forms a chemically resistant barrier that is permanently bonded to the outer surface of the pipe creating a waterproof sealant. Experience shows that as long as this protective coating remains in place the buried piping is protected from external degradation. Entergy Dir. at A47. This external coating is also applied to the joints where pipe segments are joined together in the field. Entergy Dir. at A49, A50.

The coatings are inspected, pursuant to PNPS procedure, at every stage of the process to ensure that there are no places on the piping exposed to the soil. The inspections include visual 10

inspections as well as using a high-voltage "holiday" detector to identify any voids in the coating. Entergy Dir. at A5 1, A52.

As stated in the GALL Report, "[o]perating experience shows" that a program of protective coatings and opportunistic and periodic inspections to confirm that the coatings are intact is effective in managing the "corrosion of external surfaces of buried steel piping and tanks." Entergy Dir. at A72. Extensive operating experience indicates that a protective coating on the outer surface the pipe, properly applied and not damaged during installation, will protect the piping from external soil degradation. Entergy Dir. at A71. See also Entergy Dir. at A66, A67, A68, A69, A70. Entergy experience during the excavation and examination of buried SSW discharge pipe further illustrates that a protective coating on the outer surface of the pipe, properly applied and not damaged during installation, will protect the piping from external soil degradation. Entergy Dir at A74 The BPTIP inspection program confirms that the protective coatings remain intact so that they continue to protect the exterior surface of the piping against degradation. Entergy Dir. at A75. The BPTIP requires a minimum of two inspections for buried PNPS pipes and tanks subject to the BPTIP:

• Buried components will be inspected when excavated during maintenance;

• Prior to entering the period of extended operation, plant operating experience will be reviewed to verify that an inspection occurred within the past ten years. If not, an inspection will be performed prior to entering the period of extended operation; and

• A focused inspection will be performed within the first 10 years of the period of extended operation, unless an opportunistic inspection (or an inspection via a method that allows an assessment of pipe condition without excavation) occurs within this ten-year period. Entergy Dir. at A75.

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These inspections provide reasonable assurance of the continued integrity of the buried piping systems at PNPS to perform their intended functions during the period of extended operation.

Entergy Dir. at A77.

2. The Water Chemistry Control-BWR Program The Water Chemistry Control-BWR Program optimizes the water chemistry in the CSS (among other plant systems) by limiting the level of contaminants in those systems to minimize the potential for loss of material and cracking due to internal corrosion of the systems. Entergy Dir. at A91, A92. The Water Chemistry Control-BWR Program used Electric Power Research Institute ("EPRI") guidelines, as specified in the GALL report. Entergy Dir. at A94.

The Water Chemistry Control-BWR Program is an existing program at PNPS that has been confirmed effective at managing the effects of aging on the CSS as documented in the operating experience review described in the license renewal application. Entergy Dir. at A93.

The program's effectiveness has also been confirmed by industry operating experience and the GALL Report. Entergy Dir. at A94.

3. The Service Water Integrity Program The Service Water Integrity 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. Entergy Dir. at A95. The components of the SSW system are routinely inspected for internal loss of material and other aging effects that can degrade the SSW system. The inspection program includes provisions for visual inspections, eddy current testing of heat exchanger tubes, ultrasonic testing, radiography, and heat transfer capability testing of the heat exchangers. The periodic visual inspections include inspections by robotic devices. Entergy Dir. at A96. This 12

program has proven effective at detecting degradation of the internal rubber lining in the original SSW system carbon steel piping so as to allow corrective action prior to the loss of SSW system intended function. Entergy Dir. at A97.

4. The One-Time Inspection Program The One-Time Inspection Program confirms the absence of significant aging effects for the internal surfaces of piping. This program ensures the effectiveness of the Water Chemistry Control Program by confirming that unacceptable cracking, loss of material, and fouling is not occurring. Entergy Dir. at Al 00. The One-Time Inspection Program accomplishes its purpose by inspecting a representative sample of interior piping surfaces prior to the start of the period of extended operation. The inspection locations will be chosen based on identifying locations most susceptible for aging related degradation. Entergy Dir. at A101. The One-Time Inspection Program comports with guidance contained in the GALL report. Entergy Dir. at A 102.

D. Additional Surveillance Programs for the CSS and SSW System The AMPs described above are in addition to the regular surveillance and other monitoring programs implemented at PNPS to ensure the integrity and capability of the CSS and the SSW system to perform their intended functions. Entergy Dir. at A105.

1. Monitoring of the Integrity of the CSS While not credited as an AMP, each CST is equipped with a level indicator which is monitored every four hours. Entergy Dir. at A106. Any significant leakage in the buried CSS piping would therefore be directly detectable. It should be noted that the water level in the CST are maintained so as to be above 30 feet, only eleven feet of water is credited for the HPCI and RCIC function. Thus, the CSTs would have to lose on the order of 20 feet of water before their source of water from the CSTs would be impaired. Such a large loss would be readily apparent.

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Furthermore, the CSTs are not the assured source of water credited for HPCI and RCIC.

Under the current licensing basis, the assured source of water for HPCI and RCIC at PNPS is the suppression pool.

Another way PNPS ensures the continuing integrity of the CSS buried piping is monitoring the water flow from the HPCI and RCIC system pumps. Entergy Dir. at Al 17. The flow rates from the HPCI and RCIC pumps are tested every quarter and once each operating cycle. Entergy Dir. at A 118. If the minimum flow rates are not met, the systems are declared inoperable, and the system will not be returned to operability until a repair is completed, the malfunctioning component is replaced, or an analysis is performed demonstrating that the condition does not impair operability of the system. Entergy Dir. at Al 18.

These quarterly and once per operating cycle tests would detect a leak in the CSS buried system piping sufficiently large enough to prevent the HPCI or RCIC systems from performing their intended function. As long as the pump tests meet the required flow rates, they will perform their intended function. Entergy Dir. at A 120.

The CST level monitoring and the quarterly and once per operating cycle flow rate tests provide a far more direct means of detecting leakage for CSS buried piping than a groundwater monitoring program. The CST level monitoring and flow rate tests are direct, frequent, and establish the capability of the buried pipes to perform their intended functions on a real time basis. Entergy Dir. at A121.

2. Monitoring the Integrity of the SSW System Buried Piping PNPS monitors the integrity and functioning of the SSW system buried discharge piping by performing a monthly flow rate test on the seawater flow through the SSW system. Entergy Dir. at A122. Specifically, the flow rate of the SSW system water that flows through the 14

RBCCW heat exchanger is tested each month. Entergy Dir. at A 123. The flow rate test is to make sure is adequate water flow through the heat exchangers and confirms that if there were any leak, it would not be large enough to prevent the system from satisfactorily performing its intended function. Entergy Dir. at A124.

A monitoring well would not be more effective in detecting a leak in the SSW system buried piping than the monthly flow rate tests. Unlike a monitoring well, the SSW flow rate tests are a direct check on the water that flows through the precise buried piping system that is within the scope of license renewal. Entergy Dir. at A127. Furthermore, the SSW system does not normally and would be very highly unlikely to contain radiation. Therefore, monitoring wells, for radioactivity would not be expected to provide any indication of a leak in the SSW piping.

Further, the discharge piping is over 200 feet long, and attempting to use monitoring wells to detect leakage from such a span would be difficult and inefficient. Moreover, even assuming there was radioactive leakage from the SSW piping, a monitoring well could not distinguish a leak in the buried SSW piping from any other underground leak, or may even fail to detect a leak in the buried piping.

IV. CONCLUSION The AMPs for those buried components within the scope of license renewal containing radioactive liquids at PNPS are programs that have been shown to be effective by operating experience and the GALL Report, and thus provide reasonable assurance that such components will continue to perform their intended functions during the period of extended operation.

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Furthermore, these AMPs are in addition to regular monitoring and surveillances than continually confirm the ability of the components to perform their intended functions.

Respectfully Submitted, David R. Lewis Paul A. Gaukler PILLSBURY WINTHROP SHAW PITTMAN LLP 2300 N Street, N.W.

Washington, DC 20037-1128 Tel. (202) 663-8000 Counsel for Entergy Dated: January 8, 2008 16

January 8, 2008 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

Testimony of Alan Cox, Brian Sullivan, Steve Woods, and William Spataro 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 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

Testimony of Alan Cox, Brian Sullivan, Steve Woods, William Spataro on Pilgrim Watch Contention 1, Regarding Adequacy of Aging Management Program for Buried Pipes and Tanks and Potential Need for Monitorin2 Wells to Supplement Program I. WITNESS BACKGROUND Alan B. Cox ("ABC")

Qi. Please state your full name.

Al. (ABC) My name is Alan B. Cox.

Q2. By whom are you employed and what is your position?

A2. (ABC) I am the Technical Manager, License Renewal with Entergy Nuclear

("Entergy"). In that capacity, I was involved in preparing the license renewal application and developing aging management programs for the Pilgrim Nuclear Power Station ("PNPS" or "Pilgrim") license renewal project.

Q3. Please summarize your educational and professional qualifications.

A3. (ABC) My professional and educational experience is summarized in my curriculum vitae, which is attached to my declaration supporting this testimony.

Briefly summarized, I hold a Bachelors degree in nuclear engineering from the University of Oklahoma and a Masters of Business Administration from the University of Arkansas at Little Rock. I have 30 years of experience in the I

nuclear power industry, having served in various positions related to engineering and operations of nuclear power plants. I have held reactor operator and senior reactor operator licenses issued by the NRC for the operation of Arkansas Nuclear One, Unit 1. I have been licensed as a registered professional engineer in the State of Arkansas.

Since 2001, 1 have worked full-time on license renewal supporting the integrated plant assessment and license renewal application development for Entergy license renewal projects, as well as projects for other utilities. I am a member of the Nuclear Energy Institute ("NEI") License Renewal Task Force and have been a representative on the NEI License Renewal Mechanical Working Group and the NEI License Renewal Electrical Working Group. As a member of the Entergy license renewal team, I have participated in the development of seven license renewal applications. In addition, I have participated in industry peer reviews of at least eleven additional license renewal applications.

Brian R. Sullivan ("BRS")

Q4. Please state your full name.

A4. (BRS) My name is Brian R. Sullivan.

Q5. By whom are you employed and what is your position?

A5. (BRS) Since April 2007, I have held the position of Engineering Director for PNPS. In this capacity, I am responsible for providing engineering support at PNPS. My specific duties include maintaining the PNPS design bases; maintaining plant systems through predictive programs and system monitoring; maintaining equipment reliability through preventive maintenance optimization; resolving plant system issues through troubleshooting and problem solving support; providing modifications in support of plant needs; overseeing procedures and documentation which govern and control plant engineering activities; developing and implementing departmnent procedures and corporate 2

level policies; and developing, planning and coordinating or implementing special projects, corrective action plans, or improvement programs to address particular plant or regulatory issues.

During the preparation of the PNPS license renewal application I was the Manager, Engineering Programs and Components for PNPS. hi this position I was knowledgeable of the development of the aging management programs credited for buried pipes and tanks.

Q6. Please summarize your educational and professional qualifications.

A6. (BRS) My professional and educational experience is summarized in my curriculum vitae, which is attached to my declaration supporting this testimony.

Briefly summarized, I hold a Bachelor of Science Degree in Marine Engineering from the Massachusetts Maritime Academy. I have over 24 years of experience in the nuclear power industry, 19 of which have been at PNPS where I have served in various positions since 1988, including Senior Engineer, Control Room Supervisor, Shift Manager, AOM Shift, Outage Manager, AOM Support, Programs and Components Manager, Systems Engineering Manager, and now Engineering Director. I was a licensed Senior Reactor Operator and held a United States Coast Guard License as a Second Assistant Engineer.

Steven P. Woods ("SPW")

Q7. Please state your full name.

A7. (SPW) My name is Steven P. Woods.

Q8. By whom are you employed and what is your position?

A8. (SPW) I am the Manager, Engineering Programs and Components for PNPS.

In that position, I am responsible for developing and maintaining engineering programs and standards as well as monitoring plant components and replacement parts. My specific duties include overseeing code programs, plant programs, predictive maintenance and valve programs; maintaining equipment 3

reliability through preventive maintenance; ensuring replacement parts and components meet safety standards and technical specifications; managing and coordinating engineering work activities; overseeing procedures and documentation which govern and control plant programs, components, and engineering activities; and interfacing with regulatory and industry representatives on behalf of station activities.

Q9. Please summarize your educational and professional qualifications.

A9. (SPW) My professional and educational experience is summarized in my curriculum vitae, which is attached to my declaration supporting this testimony.

Briefly sumnarized, I hold a Bachelor of Science Degree in Marine Engineering from the Massachusetts Maritime Academy. I have over 26 years of experience applying engineering methods and capabilities to various projects and engineering disciplines, including repairing and maintaining marine and nuclear facilities, designing and preparing modifications for new and existing systems, implementing effective and efficient nuclear power plant procedures, and analyzing mechanical components and piping systems.

I have been employed by Entergy at PNPS since May 2000 and previously held the position of Supervisor Code Programs, Engineering Programs &

Components. Prior to that position, I was the Senior Engineer, Design Engineering for the Mechanical/Civil/Structural group, where I performed all facets of design engineering, including nuclear changes and field support.

Prior to joining Entergy, I worked for several industry contractors providing engineering services at nuclear power plants throughout the country. I worked at PNPS on several occasions prior to joining Entergy. Specifically, and relevant to my testimony here today, from May 1992 to July 1993, I was the Site Mechanical Project Engineer dedicated to the "Salt Service Water Pipe Replacement" project. In that role, I was responsible for the site engineering and installation of the titanium piping for the salt service water inlet line, 4

including excavation, shoring of the trenches, interferences, construction of concrete vaults, installation and assembly of pipe, and backfilling of excavation.

William H. Spataro ("WHS")

Q10. Please state your full name AlO. (WHS) My name is William H. Spataro.

Qll. By whom are you employed and what is your position?

All. (WHS) Until December 31, 2007 (at which time I retired), I was the Senior Staff Engineer-Corporate Metallurgist with Entergy Nuclear ("Entergy"). In that capacity, I provided technical support in metallurgy, corrosion, welding, and forensic investigation in support of Entergy's operation of its nuclear power plants. Prior to Entergy's purchase of the Fitzpatrick and Indian Point Unit 3 plants, I was Director of Materials Engineering - Consulting Metallurgist for the New York Power Authority ("NYPA"). In that capacity I managed metallurgical and chemical engineers supporting the operation of NYPA's nuclear, fossil fueled, pumped storage, and hydroelectric power projects and its transmission lines and under-water cables.

Q12. Please summarize your educational and professional qualifications.

A12. (WHS) My professional and educational experience is sunmmarized in my curriculum vitae, which is attached to my declaration supporting this testimony.

Briefly summarized, I hold a Bachelor of Engineering (in Metallurgy) degree firom New York University. I have nearly 40 years of experience in the fields of metallurgy, welding, corrosion, and forensic investigation; including 27 years of service with Entergy and the NYPA. I am a Registered Professional Engineer in Connecticut and New York, an American Welding Society Certified Welding Inspector and Certified Welding Educator, as well as a National Board Registered Certified Nuclear Safety Related Coating Engineer.

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Q13. Please explain the requirements for becoming a National Board Registered Certified Nuclear Safety Related Coating Engineer.

A13. (WHS) To become a National Board Registered Certified Nuclear Safety Related Coating Engineer one must: 1) have at least 10 years experience with nuclear related coatings; 2) pass an eight hour written exam; 3) pass a practical evaluation exam; 4) complete a one week course; and 5) be a registered professional engineer.

II. OVERVIEW Q14. What is the purpose of your testimony?

A14. (ABC, WHS, BRS, SPW) The purpose of our testimony is to address, on behalf of Entergy, Contention 1 submitted by Pilgrim Watch ("PW") in this proceeding. As admitted by the Atomic Safety and Licensing Board ("Board"),

PW Contention 1 reads:

"[t]he 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."

Memorandum and Order, LBP-06-23, 64 N.R.C. 257, 315 (2006). In addition, the scope of PW Contention 1 has been clarified recently by the Board, which has ruled that:

"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 license renewal period - or, put another way, whether Pilgrim's existing AMPs have elements that provide appropriate assurance as required under relevant NRC regulations that the buried pipes 6

and tanks will not develop leaks so great as to cause those pipes and tanks to be unable to perform their intended safety functions."

Memorandum and Order, LBP-07-12, 66 N.R.C. _, slip op. at 17 (Oct. 17, 2007).

Q15. What has been your role in the PNPS license renewal project as it relates to PW Contention 1?

A15. (ABC) In my capacity as Technical Manager, License Renewal, I am knowledgeable of the function and purpose of the aging management programs

("AMPs") that are described in the PNPS license renewal application. I have been the manager of the technical staff responsible for preparing the license renewal application. In that capacity, I have reviewed and provided input to aging management reviews and AMP development for PNPS.

(BRS) In my capacity as Engineering Director, I am knowledgeable of the AMPs that are described in the PNPS license renewal application.

(SPW) In my capacity as the PNPS Manager, Engineering Programs and Components, I am knowledgeable of the AMPs that are described in the PNPS license renewal application, and I will support development of new procedures to ensure that aging management programs are properly implemented.

(WHS) I am knowledgeable of the technical requirements in my fields of expertise that are attendant to the aging management programs that are described in the PNPS license renewal application ("LRA"). Also, in my capacity as Senior Staff Engineer-Corporate Metallurgist, I was the primary author of the Buried Piping and Tanks Inspection Monitoring Program Procedure, EN-DC-343, Rev. 0, an Entergy fleet-wide procedure for the inspection of buried piping at Entergy's nuclear power plants that will be used for implementing the AMP for buried piping and tanks at PNPS.

Q16. What will your testimony cover?

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A16. (ABC) I will testify on the function and purpose of license renewal AMPs, the buried piping and tanks at PNPS that potentially contain radioactive liquids which are within the scope of PNPS license renewal, and the adequacy of the PNPS AMPs to assure the performance of the intended functions of in-scope buried piping and tanks through the license renewal period of extended operation. My testimony will encompass the conformance of those AMPs to the programs described in NUREG 1801, Generic Aging Lessons Learned

("GALL") Report, Rev. 1 (Sept. 2005), and discussion of applicable operating experience supporting the adequacy of those programs.

(BRS) I will testify on (1) the license renewal intended functions and the design and operation of the condensate storage system ("CSS") buried piping, which include the reactor core isolation cooling ("RCIC"), high pressure coolant injection ("HPCI"), and fire protection safe shutdown functions; (2) the license renewal intended functions and the design and operation of the salt service water ("SSW") system; (3) the design features that preclude radioactive liquids from entering the SSW system and the high degree of assurance that the SSW will not contain radioactive liquids; (4) the license renewal intended functions and design and operation of the standby gas system treatment ("SGTS"); and (5) the differentiation between the SGTS and the condenser off-gas system. In addition, my testimony will describe (1) periodic surveillance tests and regularly documented observations to ensure that the CSS and SSW system are capable of performing their intended functions (including discussion of tests and observations ensuring the HPCI, RCIC, and fire protection functions of the CSS); and (2) the capability of these systems to perform their intended functions even if some leakage occurs.

(SPW) I will testify on (1) the specifications for the protective coating and wrapping of buried piping and tanks used at PNPS to protect against external degradation, (2) the installation of buried piping in accordance with these specifications and other measures taken at PNPS to protect against the external degradation of buried piping and tanks, (3) the operating experience at PNPS 8

with buried coated piping, (4) the Service Water Integrity Program, and the demonstrated capability of that program to identify SSW system degradation prior to the loss of its intended function, and (5) the replacement and upgrading of the buried piping for the SSW system.

(WHS) I will testify on (1) the corrosion resistance of the materials used for the buried CSS and SSW system piping at PNPS, (2) the general industry practice for protective coating and wrapping of buried piping and tanks to protect against external degradation, (3) the general industry practice for the installation of buried piping and the examination of protective coatings prior to burial, (4) the industry operating experience concerning the use of buried coated piping, (5) compatibility of the corrosion controls with soil conditions at PNPS, and (6) the Buried Piping and Tanks Inspection Program and the capability of that program to manage the effects of aging on buried piping to prevent the loss of intended function.

Q17. Do you agree with the assertion in PW Contention 1 that the "[t]he 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?"

A17. (ABC, BRS, SPW, WHS) No.

Q18. What is the basis for your disagreement?

A18. (ABC, WHS, BRS, SPW) Only six systems contain buried pipes and tanks within the scope of the PNPS license renewal. Only two of those six systems contain or could contain radioactive liquid: (1) the CSS, which contains radioactive liquid, and (2) the SSW system, which, although highly unlikely, could contain radioactive liquid. For both the CSS and SSW system, Pilgrim has developed aging management programs ("AMPs") that will maintain the pressure boundary of the buried pipes and tanks in those systems to provide 9

reasonable assurance that the CSS and SSW system will perform their system intended functions. The AMPs will protect against the loss of material due to corrosion and other aging effects in a manner sufficient to provide reasonable assurance that the buried pipes in those systems will remain capable of performing their intended functions.

In addition, Pilgrim employs surveillance testing for the CSS and SSW system.

These surveillance tests periodically demonstrate that the systems are capable of perforning their intended functions. Therefore, monitoring wells are not necessary to ensur6 that the CSS and SSW system do not develop leaks that would impair the performance of their intended functions. Indeed, monitoring wells to detect leakage would not be nearly as effective as the AMPs and the surveillance programs in place and credited under the plant's technical specifications for ensuring that the CSS and the SSW system will perform their intended functions.

II. DISCUSSION A. Function and Purpose of the PNPS License Renewal AMPs Q19. Please describe the function and purpose of the PNPS license renewal AMPs.

A19. (ABC) 10 C.F.R. Part 54 governs the matters that must be considered in a license renewal proceeding. 10 C.F.R. §§ 54.21 and 54.29(a) focus on the management of the effects of aging on certain systems, structures, and components defined in the license renewal rule. PNPS has identified AMPs to provide reasonable assurance that the effects of aging during the renewed license term are managed for the systems, structures, and components that are within the scope of license renewal. The purpose of the AMPs identified in the PNPS license renewal application is to manage the effects of aging so that the intended function(s) of systems, structures, and components will be maintained consistent with the current licensing basis for the period of extended operation in accordance with 10 C.F.R. §54.21(a)(3).

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The PNPS license renewal AMPs manage the effects of aging on buried piping and tanks that are within the scope of license renewal and subject to aging management review. The objective of the aging management programs as applied to buried pipes and tanks is to maintain the pressure boundary of the buried pipes and tanks so as to provide reasonable assurance that the systems containing the buried pipes and tanks can perform their system intended functions in accordance with 10 C.F.R. §§ 54.4(a)(1), (a)(2) or (a)(3).

Q20. How are the systems, structures, and components within the scope of license renewal identified?

A20. (ABC) The scoping criteria for license renewal set forth in 10 C.F.R. § 54.4(a) dictate the plant systems, structures, and components that are within the scope of 10 C.F.R. part 54. This provision reads in full as follows:

(a) Plant systems, structures, and components within the scope of this part are -

(1) Safety related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 C.F.R. 50.49 (b)(1)) to ensure the following functions -

(i) the integrity of the reactor coolant pressure boundary; (ii) the capability to shut down the reactor and maintain it in a safe shut-down condition; or (iii) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in § 50.34(a)(1), § 50.67(b)(2), or § 100.11 of this chapter as applicable (2) All non-safety-related systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1) (i), (ii), or (iii) of this section.

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(3) All systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 C.F.R. 50.48),

environmental qualification (10 C.F.R. 50.49), pressurized thermal shock (10 C.F.R. 50.61), anticipated transients without scram (10 C.F.R. 50.62),

and station blackout (10 C.F.R. 50.63).

Thus, 10 C.F.R. §§ 54.4(a)(1 )-(3) define both the safety-related and non-safety-related systems, structures, and components that are within the scope of license renewal and the functions of the systems, structures, and components that are intended to be assured by the AMPs. Of these systems, structures, and components that fall within the scope of license renewal, 10 C.F.R. § 54.21(a)(1) defines the systems, structures, and components that are subject to aging management review as those that (i) perform an intended function, as described in § 54.4, without moving parts or without a change in configuration or properties; and (ii) are not subject to replacement based on a qualified life or specified time period.

Q21. With respect to the systems, structures and components within the scope of the license renewal rule, what must the applicant demonstrate to obtain a renewed license?

A21. (ABC) Pursuant to 10 C.F.R. § 54.21(a)(3), an applicant must demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the licensing basis for the period of extended operation. As reflected in 10 C.F.R. § 54.29, these actions to manage aging must provide reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis.

An applicant must also evaluate time-limited aging analyses, but there are no such analyses relevant to PW Contention 1.

Q22. W\hat are "intended functions"?

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A22. (ABC) Pursuant to 10 C.F.R. § 54.4(b), intended functions that these systems, structures, and components must be shown to fulfill in § 54.21 are those functions that are the bases for including them within the scope of license renewal as specified in 10 C.F.R. § 54.4(a)(1)-(3).

B. License Renewal Buried Pipes and Tanks That Contain or Potentially Contain Radioactive Liquids and Their Function and Purpose

1. License Renewal Buried Pipes and Tanks Containing or Potentially Containing Radioactive Liquids Q23. What PNPS systems with buried pipes and tanks are within the scope of license renewal?

A23. (ABC) For PNPS, there are six systems with buried piping or tanks that meet the scoping criteria of 10 C.F.R. § 54.4: (1) the CSS; (2) the fire protection water system; (3) the fuel oil system; (4) the SSW system; (5) the standby gas treatment system ("SGTS"); and (6) the station blackout diesel generator system.

Q24. Of those PNPS buried pipes and tanks within the scope of license renewal, which have the potential for containing radioactive liquids?

A24. (BRS, SPW) The only system within the scope of license renewal with buried pipes or tanks that contain radioactive liquid is the CSS. In a boiling water reactor facility, such as PNPS, the CSS contains radioactively contaminated water. At PNPS, the CSS includes buried piping, but no buried tanks.

Specifically, buried CSS piping made of stainless steel (which is generally resistant to soil induced corrosion) runs from the concrete vault for the two 275,000 gallon condensate storage tanks ("CSTs") to the reactor building auxiliary bay where the piping then supplies water to the reactor core isolation cooling ("RCIC") pumps and the high pressure coolant injection ("HPCI")

pumps. One line of piping runs from each CST to the CST concrete vault where the two pipes connect to a header. The header runs from the vault underground to the reactor building auxiliary bay. The buried potion of the piping runs 13

approximately sixty-four feet before entering the reactor building auxiliary bay, and is approximately seven to ten feet below grade. Once inside the reactor building auxiliary bay, the piping connects to a header from which water is supplied to both the HPCI and RCIC systems.

Entergy Exhibit 1-A from Plant Reference Drawing C-8 shows the general PNPS plant layout with the CSTs and the reactor building auxiliary bay.

Entergy Exhibit 1-B shows the layout of the buried CSS piping running from the CST concrete vault wall to the reactor building auxiliary bay wall. The CSTs themselves are not buried and, therefore, are not within the scope of the license renewal AMP for buried pipes and tanks.

It is possible, but highly unlikely, that the SSW system cooling water discharged by PNPS through buried SSW discharge piping could contain radioactively contaminated water. There are two loops of buried SSW system discharge piping. Loop A buried discharge piping runs 240 feet from the reactor building auxiliary bay to the discharge canal that runs into Plymouth Bay. Loop B buried discharge piping runs 225 feet from the reactor building auxiliary bay to the discharge canal that runs into the bay. Both loop A and loop B are buried approximately ten feet below grade. Entergy Exhibit 1-A shows both loops of buried discharge piping running from the reactor building auxiliary bay to the discharge canal (as well as the SSW system inlet buried piping running from the intake structure to the reactor building auxiliary bay).

There are no buried SSW system tanks.

The SGTS would, during accident conditions, remove particulates and radioactively contaminated gases from the reactor building's ventilation exhaust air system. However, the SGTS is a gas system and does not contain radioactively contaminated water.

The buried pipes and tanks for the Fire Protection water system, the Fuel Oil system, and the Station Blackout Diesel Generator system do not contain 14

radioactive materials; nor do they interact with systems that contain radioactivity.

Thus, only two systems with buried pipes or tanks within the scope of license renewal contain or potentially contain radioactive liquids.

Q25. What is the "off gas system"?

A25. (BRS) The offgas and augmented offgas system removes, processes and disposes of non-condensable gases from the condenser. All such gases from the unit are routed to the main stack for dilution and elevated release to the atmosphere.

Q26. Does the offgas system contain buried pipes and tanks within the scope of license renewal?

A26. (ABC) No. The offgas and augmented offgas system has no intended function under 10 C.F.R. §§ 54.4(a)(1) or (a)(3). The buried piping in this system does not meet the scoping criterion of 10 C.F.R. § 54.4(a)(2) because failure of the buried piping cannot prevent satisfactory accomplishment of any of the functions identified in 10 C.F.R. § 54.4(a)(1)(i), (ii), or (iii).

2. Intended Function of the CSS and SSW System Buried Pipes

a. Intended Function of the CSS Buried Pipes Q27. What is the intended function of the CSS?

A27. (BRS, ABC) The CSS has two license renewal intended functions. Regarding 10 C.F.R. § 54.4(a)(1), the CSS supplies water to the suction of the RCIC pumps and the HPCI pumps, which is performed by safety-related piping and valves that interface with RCIC and HPCI. Regarding 10 C.F.R. § 54.4(a)(3),

the CSS provides a source of water to the HPCI and RCIC systems, which are credited in the 10 C.F.R. 50 Appendix R safe shutdown analysis for fire protection. The buried piping in this system does not meet the scoping criterion of 10 C.F.R. § 54.4(a)(2) because failure of the buried piping cannot prevent 15

satisfactory accomplishment of any of the functions identified in 10 C.F.R. § 54.4(a)(1)(i), (ii), or (iii).

Q28. What do the RC1C and HPCI systems do?

A28. (BRS) The RCIC system provides makeup water to the reactor vessel following reactor vessel isolation in order to prevent the release of radioactive materials to the environment as a result of inadequate core cooling. The RCIC system is capable of delivering 400 gallons per minute ("GPM") to the reactor vessel over a range of reactor pressures. The RCIC system pump is normally lined up to the two 275,000 gallon CSTs. Each CST has a 75,000 gallon reserve dedicated to the HPCI and RCIC systems. In other words, the inlet suction points from other systems that draw water from the CSTs are located sufficiently high in the CSTs so as not to draw on the 75,000 gallon reserve in either CST. The assured supply of cooling water for the RCIC system is the suppression pool (torus). If the water is unavailable from the CST, the safety function of the RCIC system is accomplished by using water from the torus.

The HPCI system is provided to ensure that the reactor core is adequately cooled to limit fuel clad temperature in the event of a small break in the nuclear system which does not result in rapid depressurization of the reactor vessel.

The HPCI system is designed to maintain sufficient reactor vessel water inventory until the reactor vessel is depressurized to the point at which the low pressure coolant injection system operation or core spray system operation maintain core cooling. The HPCI system is designed to pump water into the reactor vessel over a wide range of pressures in the reactor vessel. The Pilgrim accident safety analysis requires the HPCI system to deliver 4250 GPM to the reactor vessel over a range of reactor pressures. Like the RCIC system, the HPCI system initially draws from the two 275,000 gallon CSTs. If water is unavailable from the CSTs, the safety function of the HPCI system is accomplished by using water from the torus.

Q29. What is the overall objective of the AMPs with respect to the buried CSS piping?

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A29. (ABC) The overall objective of the AMPs with respect to the CSS buried piping is to preserve the piping's capability to provide a source of water to the HPCI and RCIC systems so as to avoid the loss of license renewal intended functions.

b. Intended Function of the SSW System Buried Pipes Q30. What is the license renewal intended function of the SSW system?

A30. (ABC, BRS) The SSW system has two license renewal intended functions.

Regarding 10 C.F.R. § 54.4(a)(1), the SSW provides a heat sink for the reactor building closed cooling water ("RBCCW) system under transient and accident conditions. The same is also credited under 10 C.F.R. § 54.4(a)(3) because the SSW is credited in the 10 C.F.R. Part 50 Appendix R safe shutdown analysis for fire protection (10 C.F.R. § 50.48). The buried piping in this system does not meet the scoping criterion of 10 C.F.R. § 54.4(a)(2) because failure of the buried piping cannot prevent satisfactory accomplishment of any of the functions identified in 10 C.F.R. § 54.4(a)(1)(i), (ii), or (iii).

Q31. How does the SSW system work?

A31. (BRS) The SSW system operates as the ultimate heat sink to transfer heat from safety-related plant equipment and non-safety-related plant equipment. The SSW system cools the RBCCW system, which in turn cools safety-related equipment. The SSW system draws in ocean water from Cape Cod Bay through the intake structure and pumps this water through the RBCCW heat exchangers, which cool the RBCCW system water. The SSW system then discharges the cooling water back into the Bay.

Q32. Please explain why it is possible, but highly unlikely, that the SSW system could contain radioactively contaminated water.

A32. (BRS) The SSW system is designed to function as the ultimate heat sink for all the systems cooled by the RBCCW system in all operating states by continuously providing adequate cooling water flow to the secondary side of the 17

RBCCW heat exchangers. The RBCCW system provides required cooling to equipment located in the reactor building during normal planned station operations and provides a barrier between the systems containing radioactively contaminated water (e.g., the reactor coolant system) and the SSW system. It is possible, but unlikely, that the RBCCW system could become contaminated by leakage from a system that it cools. It is therefore possible, but even more unlikely, that the SSW system, which cools the RBCCW system, could become contaminated. PNPS conducts weekly sampling of the RBCCW system water to detect any potential radioactivity in the RBCCW system and, furthermore, the

.interfacing RBCCW system is continuously monitored for radioactivity by radiation detectors. Should the radiation alarms be triggered, the alarm response procedure calls for obtaining a sample of the RBCCW system water and initiating actions to identify and isolate the source of any leak.

Additionally, water from the SSW system is sampled at least once per week to monitor for radioactivity. Further, Pilgrim performs periodic inspection, maintenance, and testing of the RBCCW heat exchangers to prevent potential leakage and cross contamination between the RBCCW and SSW systems. The heat exchanger inspection, maintenance, and testing includes perfonnance testing, visual examinations, eddy current testing, and periodic cleaning.

(ABC) In addition, water chemistry control programs based on EPRI guidelines are in place for the RBCCW system and the radioactive systems that it cools to protect against corrosion and cracking that could cause leakage of radioactive fluid into the SSW system. The EPRI guideline documents have been developed based on plant experience and have been shown effective over time throughout the nuclear power industry.

(BRS, ABC) In sum, the SSW system is designed to contain only raw, non-radioactive cooling water from the ocean. However, it is possible, although highly unlikely, that radioactive contamination could occur in the SSW system, and therefore possible, although highly unlikely, that SSW system cooling water 18

being discharged into Plymouth Bay through the SSW discharge buried piping could be radioactively contaminated.

Q33. What are the buried piping and/or tanks in the SSW system?

A33. (BRS, SPW) The SSW system does not contain buried tanks. As described above, the SSW system includes two loops of buried discharge piping, loop A and loop B, running from the reactor building auxiliary bay to the discharge canal. This buried discharge piping is made of carbon steel and is coated in accordance with Pilgrim specificationis to prevent external degradation of the piping as described later in this testimony.

The two loops of the SSW inlet piping are also buried. The SSW inlet piping is made of titanium and is coated in accordance with Pilgrim specifications. The inlet piping draws water from the bay and therefore does not contain radioactively contaminated water.

Q34. What is the overall objective of the AMPs with respect to the SSW System?

A34. (ABC) The overall objective of the AMPs with respect to the SSW system is to manage the effects of aging to preserve its capability to provide cooling for plant equipment.

C. PNPS License Renewal AMPs Q35. What are the AMPs for the in-scope buried pipes and tanks containing or potentially containing radioactive liquid?

A35. (ABC) Pilgrim implements multiple programs to manage the effects of aging on buried piping and tanks that are within the scope of license renewal and subject to aging management review. The applicable AMPs for in-scope buried pipes and tanks containing or potentially containing radioactive liquid are (1) the Buried Piping and Tanks Inspection Program ("BPTIP"); (2) the Water Chemistry Control-BWR Program; (3) the Service Water Integrity Program; and (4) the One-Time Inspection Program. These AMPs are set forth in Appendix B 19

to the LRA and are provided in Entergy Exhibit 2, which contains relevant excerpts from the LRA.

The objective of the AMPs as applied to buried pipes and tanks is to maintain the pressure boundary of the buried pipes and tanks in a manner providing reasonable assurance that the associated systems can perform their system intended functions. The BPTIP manages loss of material due to external corrosion of buried pipes, while the other AMPs manage loss of material due to internal corrosion of buried pipes.

1. PNPS BPTIP Q36. Please describe the BPTIP.

A36. (ABC) The Buried Piping and Tanks Inspection Program ("BPTIP") manages the effects of aging on the external surfaces of buried components, specifically, the potential loss of material (i.e., the effect of aging caused by corrosion) from the external surfaces of components buried in soil. As explained in the PNPS LRA, it includes (1) preventive measures to inhibit the corrosion of external surfaces of buried pipes and tanks exposed to soil, such as selection of corrosion resistant materials and/or application of protective coatings, and (2) inspections to manage the effects of external surface corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and titanium components. See PNPS LRA at Appendix B, Section B. 1.2, p. B-17-18 (Entergy Exhibit 2).

a. Preventive Measures for CSS and SSW Buried Piping Q37. What preventive measures does PNPS employ for in-scope buried pipes for the CSS and the SSW system?

A37. (SPW) PNPS employs several preventive measures to protect against the degradation of buried pipes in the CSS and SSW system (which do not contain buried tanks).

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" First, the buried CSS and SSW inlet piping use corrosion resistant metals (stainless steel and titanium, respectively). Further, the SSW discharge liner is protected by a cured in place liner.

" Second, PNPS coats buried piping with a coal-tar or epoxy protective coating to create a barrier between the pipe and the external environment.

" Third, PNPS has in place procedures to make certain that buried piping is installed, excavated, and handled in a manmer that does not damage the protective corrosion resistant coatings.

(1) Use of corrosion resistant materials in the CSS and SSW system buried piping Q38. What materials are used for the buried CSS piping to prevent corrosion?

A38. (SPW) The buried CSS piping is made of stainless steel. Additionally, in accordance with the PNPS specification for buried piping, described below, it has been the practice of PNPS to coat stainless steel piping, although unnecessary.

Q39. Please describe the corrosion resistance properties of stainless steel piping buried in soil.

A39. (WHS) Stainless steels are generally resistant to corrosion in soils. Depending on the grade of stainless steel used, pitting corrosion of stainless steel can occur under certain conditions involving high temperatures, high concentrations of chlorides (generally greater than 500 ppm), and low pH (generally less than 4.5, acidic conditions). However, PNPS has taken steps to prevent soil conditions, discussed below, that could cause corrosion of stainless steel. Further, notwithstanding their corrosion resistance, it has been PNPS practice to apply protective coatings to corrosion resistant piping like the stainless steel CSS piping (and the titanium SSW inlet piping).

Q40. What materials are used in the SSW inlet piping to prevent corrosion?

A40. (SPW) The SSW inlet piping, originally made of wrapped carbon steel, was replaced in 1993 with titanium piping.

Q41. Please describe the corrosion resistance of titanium piping in soil.

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A41. (WHS) Titanium is immune to corrosion in soils. Titanium and its alloys are fully resistant to all natural waters and steam to temperatures in excess of 6000F.

Titanium alloys exhibit negligible corrosion rates in seawater to temperatures as high as 500'F. A stable, substantially inert oxide film provides the material with its outstanding resistance to corrosion in a wide range of aggressive media.

Whenever titanium is exposed to the atmosphere, or to any environment containing oxygen, including water, it immediately reacts with the oxygen creating a thin film of titanium oxide. It is the presence of this surface film that confers on the material its corrosion resistance.

The protective coatings applied to the buried titanium piping, discussed below, provide additional assurance that the titanium inlet piping will not suffer external degradation by corrosion from the soil.

Q42. What materials are used in the SSW discharge piping to prevent corrosion?

A42. (SPW, BRS) As stated, the SSW discharge piping consists of two loops of buried piping, loop A 240 feet in length and loop B 225 feet in length. This buried discharge piping is made of carbon steel and was wrapped in accordance with PNPS specifications to prevent external degradation. In 1999, PNPS replaced two forty-foot sections of the SSW discharge piping (one from each discharge loop). PNPS applied a protective epoxy coating to both the internal and external surfaces of the replaced pipe.

In addition, in 2001, during refueling outage 13, PNPS lined the entire length of the loop B discharge pipe with Cured-In-Place-Pipe ("CIPP") to protect against internal corrosion of the piping. In 2003, during refueling outage 14, PNPS lined the entire length of the loop A discharge pipe with CIPP liner.

Q43. Please describe the CIPP liner installed in the SSW discharge piping.

A43. (SPW, BRS) The CIPP liner material consists of a nonwoven polyester felt tube that is saturated with a resin and catalyst system in loop A, and an epoxy resin and hardener system in loop B, with a polyurethane or polyethylene inner 22

membrane. The liner has a nominal V2" thickness. The resulting configuration is a rigid resin composite pipe within the original pipe. Based on the service conditions and the design of the CIPP liner, the expected life of the CIPP is approximately thirty-five years.

Q44. Did the carbon steel SSW discharge piping as originally installed have any internal lining of the piping?

A44. (SPW, BRS) Yes. The original SSW discharge piping had an internal rubber liner which was not cured in place with an expected life of about 20 years. The integrity of the SSW system rubber liner was monitored under the Service Water Integrity Program, described below, and the CIPP was installed upon identifying degradation of the internal rubber liner.

Q45. Please describe the corrosion resistance of the CIPP lined SSW carbon steel piping at PNPS.

A45. (WHS) The 1/2" thick CIPP liner, consisting of polyester felt material with a resin and catalyst system or an epoxy resin and hardener system, forms a smooth, hard surface that resists moisture intrusion and abrasion, and is resistant to most chemicals and all waters. The CIPP liner is superior to the rubber liner since it is an epoxy and polyester thermosetting resin that cures in place with a smooth hard surface that is resistant to biofouling and other forms of degradation. Such an impervious membrane fonns an excellent protective barrier protecting the carbon steel from internal corrosion.

(2) External Coatings Q46. How are the buried CSS and SSW pipes protected from the soil environment?

A46. (SPW) Specification No. 6498-M-306, "Specification for External surface Treatment of Underground Metallic Pipe for Unit No. 1 Pilgrim Station No. 600 Boston Edison Company" (Entergy Exhibit 3) specifies the application of 23

permanent coating to the outside of buried piping. This specification applied to the original SSW buried piping as well as to the CSS buried piping.

In addition, the two forty-foot sections of the SSW discharge piping (one from each discharge loop) that were replaced in 1999 were coated with an epoxy coating applied to the external surface of the piping. Also, although titanium is immune to soil induced corrosion, PNPS applied a coal-tar coating to the replacement SSW system inlet titanium piping installed in 1993.

Q47. How do these external coatings act to protect the piping from the environment?

A47. (WHS) The coatings form a moisture and chemically resistant barrier that is permanently bonded to the outer surface of the pipe creating a waterproof barrier between the soil and the pipe. As long as the protective coating remains in place, the buried piping is protected from external degradation. As discussed below, this is confirmed by extensive industry experience.

Q48. Please describe the content of Specification No. 6498-M-306.

A48. (SPW) Specification No. 6498-M-306 provides procedures for installing and inspecting coatings applied in the shop as well as for coatings applied in the field (e.g., at pipe joints). With respect to coatings applied in the shop, the specification requires the following steps:

• The pipe is cleaned of all dirt, grease, mill scale, or any loose debris using some mechanical means, e.g., impact wheel or wire brush;

" Following cleaning of the pipe, a layer of primer is painted onto the exterior of the cleaned pipe;

• Following application of the primer, a coal-tar enamel coating is applied to the clean dry surface of the pipe at the correct temperature to ensure the primer bonds with the enamel to form a coating which cannot be peeled from the pipe;

• The enamel is then visually inspected for uniformity; 24

• Before the enamel cools, a fiber-glass pipe wrapping is applied over the enamel in a uniform wrap to cover the entire outside surface of the enamel;

" Thereafter, an additional layer of coal-tar enamel is applied;

" The second layer of enamel is followed by an outerwrap of insulation; and

• A final layer of heavy Kraft paper completes the process.

Q49. Please describe Specification No. 6498-M-306 requirements for the field application of protective coatings used on PNPS buried piping.

A49. (SPW) Specification No. 6498-M-306 provides specific instructions for field applications of coatings, which would occur at the joints where pipe segments are joined. Specification No. 6498-M-306 requires the following steps in-the-field application of coatings:

• Cleaning of the piping by wire brushing to remove and rust, scale, dust, or dirt; oil or grease is removed with a solvent; o Following cleaning of the pipe, a layer of primer is applied to the exterior of the cleaned pipe and allowed to dry;

• Coal tar tape is applied to the primed surface. The coal tar tape is a 35-millimeter cold-applied tape coating consisting of a 7-millimeter polyethylene film backing and 28 millimeters of adhesive.

Q50. Please describe how the pipe sections are joined together before they are wrapped as you described above.

A50. (SPW) Pipe sections consist of straight length pipe, elbows, and end flanges that are welded together and coated in the shop or in the field. The flanges and elbows are made of the same material as the pipe. In the field, the end flanges of the individual pipe sections are bolted together to create the installed system.

Once bolted together, the flange joints are field wrapped as described above, and tested, as described below, for complete coverage prior to back filling the excavation.

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Q51. What steps are undertaken to ensure that coatings have been properly applied to ensure that there are no places on the buried pipe exposed to the soil?

A51. (SPW, WHS) In accordance with established industry practices, the coatings are inspected at every stage in the process. Specification No. 6498-M-306 requires that all shop applied coatings be inspected in accordance with Specification AWWA C-203 before shipment. This would involve visual inspection of the coated piping for any misapplication of the coatings followed by an electrical inspection of the pipe coating by a high-voltage "holiday" detector to identify any voids in the coating.

In the field, the pipes are visually inspected upon receipt to ensure that no damage occurred during shipment. Finally, after pipes are fully joined and assembled in place and the field joints are wrapped, and before covering them with soil, the entire pipe is again tested for voids using a high voltage holiday detector to assure the field joints were properly wrapped and that the shop applied coatings were not damaged during installation.

Q52. Please describe the high-voltage "holiday" test of the pipe coating.

A52. (WHS, SPW) An inspector uses a calibrated high-voltage holiday detector to identify any voids or imperfections in the coatings. The inspector drags a coil-spring or brush type electrode along the entire surface of a coated pipe. The electrode is electrically charged at a very high voltage so that if there are any voids in the pipe's coating, electricity will arc from the electrode to the metal pipe surface creating a bright flash and audible noise. If the test finds any defects, they are marked and repaired, then the pipe is retested to assure the repairs are acceptable.

Q53. Please describe the coatings used on the two forty-foot sections of SSW discharge piping that were replaced in 1999.

A53. (SPW, WHS) The coatings used on the two forty-foot section of SSW discharge piping that were replaced in 1999 utilized a aliphatic amine epoxy 26

coating with excellent corrosion resi'stance properties. A minimum of two coats were applied to each length of piping in the shop to achieve a dry thickness of at least 30 millimeters, and all coated areas were holiday tested after the curing was complete. The joints between two forty-foot sections and the existing pipe were coated in the field.

Q54. Please describe the protective coating applied to the replacement SSW system inlet titanium piping installed in 1993.

A54. (SPW, WHS) The replaced titanium SSW system inlet piping was not coated in the shop, but wrapped in the field with a coal tar tape in accordance with the field application for PNPS coatings as described above.

Q55. Based on your experience, what is the industry standard for protecting buried piping used in nuclear applications?

A55. (WHS) Standard industry practice depends on the metal being buried.

Typically, stainless steel and titanium are not coated or wrapped since both are generally resistant to corrosion caused by soil environments. Carbon steel, however, is subject to corrosion from the soil environment and is coated before burial. Standard industry practice for coatings requires that the pipe be cleaned and primed before any coatings are applied. Additional layers of wrapping, such as insulation, epoxy, coal tar, or bonded asbestos wrap paper depend on the pipes function and the soil conditions. Notably, standard industry practice for buried pipes applies to not only the nuclear industry, but the coal, oil, gas industries as well as fossil fueled and hydroelectric power facilities.

Q56. What specifications dictate the industry standard?

A56. (WHS) All industries rely on several common specifications for corrosion resistant coatings that are developed by industry organizations, including:

American Water Works Association (AWWA), National Association of Corrosion Engineers (NACE), American National Standards Institute (ANSI),

ISO, National Association of Pipe Coating Applicators, (NAPCA), American 27

Petroleum Institute (API), Society for Protective Coatings (SSPC), and ASTM International.

Q57. How do PNPS coatings for the CSS and SSW systems buried piping compare to industry standards?

A57. (WHS) PNPS coatings exceed industry standards in two major respects. First, PNPS has generally double wrapped its buried piping. As described earlier, Specification No. 6498-M-306 provided for double wrapping of buried pipe consisting of a permanent protective coal-tar coating, fiberglass wrapping, another layer of coal-tar, a layer of insulation, and a final layer of heavy Kraft paper. The standard industry practice, as set forth in AWWA C-203, requires a single wrapping for buried piping under normal soil conditions. AWWA C-203 does provide for double wrapping of pipe but only for unusual or severe conditions, such as when pipes are submerged under water. The coal-tar enamel permanent coating and bonded double outerwrap used at PNPS is specifically designed for use on submerged lines, river crossings, or similar installations involving aggressive environments, or where trench conditions are extraordinarily severe, conditions that do not apply at PNPS.

Second, it has been the practice at PNPS to wrap titanium and stainless steel buried piping, although neither is susceptible to corrosion caused by soil conditions. This is not the standard practice for the industry, which typically buries titanium and stainless steel pipe with no protective coatings because of their inherent corrosion resistance.

(3) Precautions taken in burying PNPS piping to prevent corrosion Q58. Please describe your experience in the field installation of buried piping at PNPS.

A58. (SPW) As stated above, from May 1992 to July 1993, I was the Site Mechanical Project Engineer dedicated to the "Salt Service Water Pipe Replacement" project. In that role, I was responsible for the site engineering 28

and installation of the titanium piping for the SSW inlet line including excavation, shoring of the trenches, interferences, construction of concrete vaults, installation and assembly of pipe, and backfilling of excavation. Also, I am generally knowledgeable of the procedures for the installation of buried piping at PNPS and the industry generally.

Q59. Based on your experience what methods does PNPS use when installing buried piping to ensure that the pipes will not corrode?

A59. (SPW) Several measures are taken at PNPS to ensure that no corrosion occurs on buried piping. These include dig safe measures, safe handling procedures, control of the soil surrounding the pipe, and compaction testing.

Q60. Please describe the dig safe measures.

A60. (SPW) Dig safe measures includes extensive drawing searches and the use of ground detection radar to identify buried components. As an added precaution, once excavation depths near the pipe depths, all digging must occur by hand to avoid damaging piping. All digging requires engineering approval to assure that existing buried systems are not damaged.

Q61. Please describe the safe handling procedures.

A61. (SPW) At all times, coated pipes must be handled with non-abrasive canvas or leather straps or nylon belts. Chains and other abrasive items are prohibited.

This is required by Specification No. 6498-M-306.

Q62. Please describe control of the soil and compaction testing.

A62. (SPW) PNPS excavates the soil in layers. Once a layer of soil is excavated, it is stockpiled separately from the other layers. Layers can be as small as six inches. During backfilling, layers are replaced in the order in which they were removed. Generally, soils are replaced and compacted every six inches, and after twelve inches of backfill is added, the soil is tested to ensure the soil is sufficiently compact.

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Q63. What other precautions are taken in the installation of buried piping?

A63. (SPW, WHS) The CSS and SSW system buried piping installed at PNPS was buried in a maimer to protect the pipe from structural damage and from a corrosive environment. The installation instructions required the pipe to be placed on a bed of sand or specially engineered fill, which consists mostly of fine aggregate sand and specified amounts of fly ash and cement, of approximately 6 inches. The pipe is then covered with sand or specially engineered fill material before being covered by the contaminate-free, controlled soil. The sand and the engineered fill material compared to other forms of soil, such as silt or clay, do not retain water but allow water to percolate through the soil and therefore maintain very high soil resistivity.

Q64. What is the importance of soil resistivity?

A64. (WHS) Soil resistivity is an important property that determines the soil's corrosive nature. Corrosion is largely an electrochemical phenomenon whereby metal is destroyed by electrochemical or chemical reactions. For corrosion to occur, there must be a transfer of electrons between the metal and its soil environment, i.e., there must be an electric current, for which there must be an electrolyte. Soil resistivity measures the degree to which the soil opposes an electric current through it. Highly resistive soil contains minimal water, which limits the electrolytic capabilities of the soil, and inhibits current flow thereby preventing corrosion.

Q65. How do the PNPS installation methods compare to standard industry practice?

A65. (WHS) Standard industry practice for installation requires that the owner take care and precaution in excavating and re-burying piping to assure a defect-free coating or wrap is maintained. PNPS meets or exceeds standard industry practice. AWWA C203 requires that a layer of screened earth or sand, at least three inches in thickness, be placed in the bottom of the trench prior to installation of the pipe. As described above, the PNPS requirements exceed the 30

industry standard because PNPS utilized sand or a special backfill material that is a minimum of 6 inches thick in the bottom of the trench prior to installation of the pipe.

b. Industry experience for buried piping Q66. Mr. Spataro, what is your experience with industrial coatings used on buried pipes for corrosion resistance?

A66. (WHS) I have extensive experience in industrial coatings used to protect buried piping from corrosion since I began my professional engineering career with Ebasco Services, Inc. in 1968. As an engineer at Ebasco, I worked on projects where I evaluated and compared applied coatings on the market at the time, and I evaluated the coatings' ability to protect the piping's exterior from corrosion.

A special assignment occurred during the July to December 1972 time period during which I was assigned to the refurbishment of many miles of a live 600 pound pressure gas transmission line in the countryside surrounding Newburgh, NY. The team inspected excavated piping and evaluated the conditions of the coatings, performed weld sleeve attachment to areas where degradation had occurred because of damage to the coatings, recoated the repaired areas, electrically tested the new and existing coatings, and supervised the backfill operation to assure that the coatings were not damaged.

Since then, I have worked extensively with applied coatings. I have written application procedures used in the power industry, including hydroelectric, nuclear, fossil, oil, and gas facilities as well as transmission towers, and I have evaluated the effectiveness of coatings that have been in service for many years.

I have worked on projects requiring the specification of coatings and the excavation, analysis, recoating, and re-burying of piping used in the nuclear industry. I have been involved with the construction of at least 30 nuclear power stations in the United States and overseas where I specified and evaluated corrosion resistant coatings for use on buried piping.

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Q67. Does industry experience show that properly wrapped and installed buried piping is sufficient to protect the piping from external corrosion?

A67. (WHS) Yes. Industry experience demonstrates that if, 1) there is a coal tar or epoxy coating on the outer surface, 2) the coating was properly applied, and 3) the coating was not damaged during installation, the protective coating will protect piping from exterior degradation. The consensus standards based on this industry experience have been in existence for many decades with only minor changes. Such durability attests to the validity of the procedures specified in the standard and used in the industry.

Q68. Can you give us some examples of the capability of external coatings to protect buried piping?

A68. (WHS) Yes, I can. As I stated, while a welding engineer at Ebasco Services I assisted in the excavation and analysis of a buried piping gas transmission line which had been coated with coal-tar epoxy in accordance with the industry practice for buried piping as described above. At the time of excavation, the piping had been in service for 25 years. Upon excavation, I personally evaluated the pipe and the coating and found that where the coating had been properly applied and not damaged, not only were there no indications of corrosion, but both the pipe and coatings were essentially in the same condition as when the pipe was buried. Because of the lack of any visible degradation of properly applied coatings over 25 years of service, the coatings as repaired were left in service.

Q69. Can you cite further examples where you have examined coatings that have met or exceeded engineering expectations?

A69. (WHS) Yes. In 1996, as Consulting Metallurgist at NYPA, I assisted in modifications of the 40 ft. wide x 80 ft. tall hydroelectric dam spill gates at the St. Lawrence Seaway Power Project. The spill gates are employed at dams to release the water behind the dam so it can be channeled through the water 32

wheels to produce electricity. Thus, the gates are either completely submerged when closed or partially submerged when open in a flowing river water environment. The gates are coated with the same type of coal-tar that is used on buried pipes to prevent corrosion. In the case of the dam, however, the coating is applied to protect the spillway gates from, not just corrosion, but erosion from the water flow and impact damage caused by solid objects, such as trees and ice floes hitting the gate itself.

The gates had been in service for 40 years when the modifications were planned. Upon my initial inspection, I found the protective coating on the gates to be in substantially original condition. The applicable work procedures, however, required removal of the coating in those areas requiring modification by cutting and welding. After two weeks of vigorous removal efforts with mechanical tools, including chisels and jackhammers, the coating was barely removed from the areas requiring work because it had adhered so tightly to the steel. After inspection and consultation with the coating manufacturer, NYPA elected to leave the original coatings on the remaining gates not requiring modification, and to recoat the modified areas with the same protective coating.

Since the gates were in excellent condition and the coating manufacturer stated that the existing coating was good for another 40 years, NYPA put the spill gates back in service with their original protective coating.

Q70. Is other industry data available regarding the capability of properly coated buried piping to resist external degradation?

A70. (WHS, ABC) Yes. NUREG/CR-6876, "Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants" (2005) describes the research performed to assess the effects of age-related degradation of buried piping at nuclear power plants. The report refers to operating experience of buried pipes at 12 nuclear power plants that have undergone license renewal.

This experience shows that properly applied coatings will protect the pipe from external corrosion. For example:

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• In 1996, portions of four buried pipelines were inspected at the Calvert Cliffs nuclear power plant. The pipe wrap (trade name, "TRU COAT," an extruded polyvinyl coating covered with a black tape) was discovered to have been slightly damaged during construction, but the piping was in pristine condition after 20 years of operation.

" During the 2000 outage of the Catawba Nuclear Power Station, Units 1&

2, the nuclear service water system piping was cleaned to remove fouling buildup. After excavation, an examination of the piping's external coating revealed that the coating had been cut during construction allowing the underground environment to contact the pipe surface. Except for the cut, the external coating was in good shape.

• At North Anna Power Station, Units 1 & 2, a small hole in a branch line pipe was observed. The hole was caused by galvanic or pitting corrosion at a pinhole void. The root cause of the local galvanic cell was due to a void in the protective coating.

NUREG/CR-6876 also refers to NUREG-1522, published in June 1995, which contains descriptions of age-related degradation that were obtained from many different sources, including site visits at six older nuclear plants that had been licensed before 1977. The report stated that internal coating degradation of buried piping had been observed at three of the six plants, but no external degradation was reported.

Q71. What do you conclude after reviewing the operating experience described in NUREG/CR-6876 and NUREG- 1522?

A71. (WHS) This operating experience shows that properly applied coatings will protect buried piping from external corrosion for many years. This is in accord with well established industry experience to which I have previously referred.

That experience indicates that properly applied coatings will prevent the aging of components buried in the soil for extended periods of time, absent damage to the coatings during installation or maintenance. Thus, I conclude that the external surface of buried piping will not corrode during the life of a nuclear power plant if 1) there is a protective coating on the outer surface, 2) the coating was properly applied, and 3) the coating was not damaged during installation.

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My familiarity with the Pilgrim specifications and review of the soil and groundwater chemistry reports, the backfill material composition, and the piping installation records lead me~to conclude that the buried piping at PNPS will perform their intended functions for the license renewal period.

Q72. Is this operating experience reflected and confirmed elsewhere?

A72. (ABC) Yes. This operating experience is reflected and confirmed by the "Operating Experience" review for buried piping and tanks in NUREG 1801, Generic Aging Lessons Learned ("GALL") Report, Vol. 2, Rev. 1. The GALL Report states that "[o]perating experience shows" that a program of protective coatings and opportunistic and periodic inspections to confirm that the coatings are intact is effective in managing the "corrosion of external surfaces of buried steel piping and tanks." GALL Report,Section XI.M34, at XI M-1 12 (excerpts included in Entergy Exhibit 4).

As reflected in the GALL Report in the XI.M34 Operating Experience review at XI M-1 12, the NRC has determined that the operating experience at nuclear power plants shows that an AMP for the exterior surfaces of buried pipes and tanks consisting of protective coatings (such as those used at PNPS) and opportunistic and periodic inspections (such as those set forth in the PNPS AMP for buried pipes and tanks, discussed below) is effective in managing the corrosion of external surfaces of buried pipes and tanks.

Q73. Please describe the genesis of the GALL Report.

A73. (ABC) The GALL Report is referenced as the technical basis document for NUREG- 1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants." The GALL report identifies AMPs that have been determined by the NRC to be acceptable programs to manage the effects of aging on systems, structures and components within the scope of license renewal as required by 10 C.F.R. Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." The NRC Staff developed the 35

GALL report at the direction of the Commission to provide a basis for evaluating the adequacy of aging management programs for license renewal.

The GALL report is based on a systematic compilation of plant aging information and evaluation of program attributes for managing the effects of aging on systems, structures and components for license renewal. GALL Report at 1-3, Entergy Exhibit 4.

Q74. Has the effectiveness of the external coatings to protect buried piping been confirmed at PNPS?

A74. (SPW) Yes. The effectiveness of properly applied coatings at PNPS has been confirmed by operating experience at PNPS during the excavation of buried piping for maintenance and modification activities. PNPS had the opportunity to examine external buried piping coatings on the two forty-foot sections of SSW system discharge piping (one from each discharge loop) that were replaced in 1999, more than 25 years after the plant had become operational.

The exterior surface of the piping was wrapped with reinforced fiberglass wrapping and coal tar saturated felt and heavy Kraft paper in accordance with the PNPS specification for the external wrapping of pipes that I described previously. The exterior wrappings of the pipes were found to be in good condition and no external corrosion of the pipes was observed. PNPS examined the removed piping after its wrapping was removed and found the outside surface of the piping in original, pristine condition.

(ABC) Thus, evaluation of the PNPS operating experience, as called for by Section XI.M34 of the GALL report, demonstrates the effectiveness of the protective coatings used at PNPS.

c. PNPS periodic and opportunistic inspection program for the aging management of buried piping and tanks Q75. Please describe the inspections that are part of the PNPS license renewal BPTIP.

A75. (ABC) The PNPS license renewal BPTIP provides for inspection as follows:

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0 Buried components will be inspected when excavated during maintenance.

a Prior to entering the period of extended operation, plant operating experience will be reviewed to verify that an inspection occurred within the past ten years. If not, an inspection will be performed prior to entering the period of extended operation.

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

Thus, the PNPS licensing renewal BPTIP requires a minimum of two inspections for buried PNPS pipes and tanks subject to the BPTIP.

Q76. What is the purpose of the inspection program that is employed as part of the PNPS license renewal BPTIP?

A76. (ABC, WHS) The purpose of the inspection program is to confirm continuing integrity of the protective coatings so as to ensure protection of the exterior surface of the piping against degradation. As discussed previously, as long as the protective coatings remain intact, the piping will be protected from external degradation caused by the soil. Therefore, as long as the inspections show that the protective coatings are not degrading and are remaining in place as designed and intended to protect the piping, inspection occurring more frequently would serve no purpose, and in fact would create the potential for damage to the protective coatings on the pipes. If degradation of the coatings is identified, however, then further analysis and evaluation would be required with potentially additional, more frequent inspections of the buried piping.

Q77. In your professional opinion, are the inspections provided for by the BPTIP sufficient to provide reasonable assurance of the continued integrity of the buried piping systems at PNPS to perform their intended functions during the period of extended operation?

A77. (ABC, WHS) Yes. The BPTIP provides for two inspections of the buried piping between 2002 (within ten years prior to entering the period of extended operation) and 2022 (within the first 10 years of the period of extended 37

operation). Both the industry experience and the PNPS experience discussed above shows that properly applied coatings would not be expected to degrade so as to impair the integrity of the buried piping, particularly during the limited time span between inspections as provided for by the PNPS BPTIP inspection regime Thus, the inspections are complimentary and provide additional assurance. As stated, if the inspections were to identify degradation of the coatings, then further analysis and evaluation would be required with potentially additional inspections of the buried piping.

Q78. Have any procedures been developed by which the PNPS license renewal BPTIP will be implemented?

A78. (ABC, WHS) Yes. Entergy has developed a fleet-wide procedure, EN-DC-343, Rev. 0, Buried Piping and Tanks Inspection and Monitoring Program

("BPTIMP Procedure" or "the Procedure"), which is provided as Entergy Exhibit 5. The BPTIMP Procedure implements the PNPS license renewal AMP for the inspection of buried pipes and tanks, but also implements additional inspections beyond the scope of the license renewal rules.

Q79. What are the inspection methods specified in the BPTIMP Procedure?

A79. (WHS, ABC) Section 5.12 of the Procedure specifies the inspection methods by which the inspections of buried pipes are to be accomplished. It provides for visual inspection and holiday testing of the exterior of the pipes for degradation of coatings or corrosion of the pipe as well as for non-destructive testing of the pipes.

Q80. What additional inspections beyond the scope of license renewal rules are provided for by the BPTIMP Procedure?

A80. (ABC, WHS) Additional inspections beyond the scope of the LRA are based on a corrosion risk evaluation that accounts for impact factors such as soil resistivity, pipe materials, coatings, and drainage that affect the susceptibility of the piping to corrosion. The more susceptible the piping is to soil induced 38

corrosion, the greater the fi-equency of the inspections provided by the BPTIMP Procedure.

Q81. What is known about the susceptibility of the CSS and SSW system buried piping to soil induced corrosion.

A81. (WHS) As already discussed, it is PNPS practice to coat buried piping with permanent protective coatings, which greatly reduce susceptibility to soil induced corrosion. In addition, the stainless steel employed in the buried piping of the CSS and the titanium piping employed for the SSW system intake piping are highly resistant to soil induced corrosion. Finally, as discussed below, based on available information, the corrosivity of the soil at PNPS is low. Therefore, the susceptibility of the CSS and SSW system buried piping to soil induced corrosion is low.

d. PNPS soil chemistry and corrosion environment Q82. What are the soil factors that affect the susceptibility of corrosion in buried piping?

A82. (WHS) Several factors affect the corrosivity of the soil to buried piping:

" Resistivity - Since corrosion is an electrochemical process, soil resistivity is a direct measurement of the properties of the soil in preventing or accelerating corrosion. Resistivity is a broad indicator the soil's electrolytic strength; high resistivity soil indicates that the soil has low electrolytic capability, thereby inhibiting corrosion. The resistivity of soil is largely a function of the soil's moisture content and ion concentration and it generally decreases with increasing moisture and concentrations of aggressive ions.

" Moisture - Soil moisture is a general indicator of the soil's propensity to carry current in the presence of aggressive ions. Soil with low moisture content provides essentially a non-corrosive environment even for carbon steel.

• pH - Soil pH is the measure of acidity or alkalinity of the soil water.

Normal soil pH is in the range of 4.5-8.0 whereas highly acidic soils, which can create an aggressive environment for certain metals if high concentrations of aggressive ions are present, have pH values less than 4.5.

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Ion Concentration - The presence of the chloride ion (CI), in excess of 500 ppm, in the soil can be harmful to stainless steel because it can cause pitting initiation. Other ions, such as sulphates, are considered less aggressive, but do contribute to the pH level of the soil water.

Q83. What is known about the soil environment at PNPS that would affect the corrosion of buried pipes?

A83. (SPW, WHS) Two major precautions have been taken at PNPS to ensure that piping is not buried in an aggressive soil environment. First, as discussed above, piping is placed on a bed of sand or specially engineered fill before it is covered by another layer of fill. The sand or special fill is very porous and allows water to percolate through. Thus, it does not retain moisture and generally has high resistivity to corrosion. Second, during construction of PNPS, the site was excavated for the construction of the various PNPS buildings. During excavation, all rocks over six inches, shrubs, and trees were removed from the soil. Rocks can cause physical damage to buried structures and plants, as they biodegrade, release compounds that may increase soil pH.

These two precautions serve to reduce the corrosivity of the soil environment experienced by the buried piping at PNPS. Additionally, as discussed below, the soil's pH of 6.2-6.82 and CI content of 210 - 420 ppm show that neither of these factors creates an aggressive soil environment.

Q84. Since moisture content of the soil affects corrosivity, what other steps, if any, has PNPS undertaken to ensure that the moisture content of the soil surrounding the pipe remains low.

A84. (SPW) In addition to surrounding buried pipe with sand or special fill material, as already described, two other important precautions are taken to prevent high levels of soil moisture from occurring: (1) when PNPS was erected, a storm drain system was installed to prevent the buildup of water; and (2) buried pipes are buried above the water table.

Q85. Please describe the PNPS storm drainage system.

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A85. (SPW) The storm drain system not only runs throughout the 90 acre PNPS site, but also along the border of the site. The purpose of the drain system is to carry away excess rainwater on the site and to divert rainwater runoff outside of the site away from the site.

Q86. Please describe the effect of burying pipes above the water table.

A86. (SPW, WHS) When it rains, water naturally percolates down through the soil.

Burying pipes above the water table ensures that the water percolates down, past the piping, and is taken away with the flow of the ground water instead of collecting and adding moisture to the soil creating an electrolyte next to the buried pipe. The water table at PNPS where the CSS and SSW system piping is buried is approximately 17 feet below the surface. The CSS and SSW system pipes are buried 7 to 10 feet below the surface, well above the water table. In addition to the sand or special fill material used at PNPS, burying the pipe above the water table ensures that the low moisture content of the soil surrounding the buried piping is maintained.

Q87. Mr. Spataro, have you reviewed any soil analysis reports for PNPS that would enable you to characterize the corrosivity of the soil at PNPS?

A87. (WHS) Yes. I reviewed the 1992 soil analysis taken near SSW system loop A and loop B and I have also reviewed an October 2005 analysis of the groundwater at PNPS which is a good indicator of the soil condition.

Q88. What did you find from your review?

A88. (WHS) The soil pH ranges from 6.2-6.82 which reflects a non-aggressive soil environment. The moisture content of the soil ranged from 5.5% to 8.1%,

which is a low moisture content and a non-aggressive environment. The chloride content is 210-420 ppm, which constitutes a low ion concentration, and non-aggressive environment. The low moisture and ion concentration along with the use of sand or specially engineered fill used in burying the pipe yields a high soil resistivity and results in a non-aggressive soil environment.

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Q89. Mr. Spataro, based on your experience, how aggressive is the PNPS soil?

A89. (WHS) The soil at PNPS is not aggressively corrosive at all. Considering the pH and high resistivity plus the low chloride concentration and low moisture content, in my expert opinion, at worst the soil is mildly corrosive.

e. Sufficiency of the PNPS BPTIP AMP Q90. Is the PNPS BPTIP sufficient to meet the requirements of 10 C.F.R. Part 54 for the buried piping systems to which it applies?

A90. (ABC, WHS. SPW) Yes. The PNPS BPTIP is consistent with one exception to the NUREG-1 801,Section XI.M34 Buried Piping and Tanks Inspection (which provides NRC guidance on aging management programs for the external surfaces of buried pipes and tanks) and is more than sufficient to meet the requirements of 10 C.F.R. Part 54. The one exception allows flexibility to use a more effective means than visual inspection, if available, to assess pipe condition. An effective method of performing piping assessment without excavation would minimize the potential for damage to the protective coating during excavation. Specifically, the BPTIP incorporates the following features that are consistent with regulatory guidance and meet the requirements of the regulations to provide reasonable assurance that the effects of aging on the external surfaces of the PNPS SSW system and the CSS buried piping will be managed such that the intended functions will be maintained consistent with the current licensing basis throughout the period of extended operation.

" The CCS and SSW system buried piping utilizes corrosion resistant materials, titanium, stainless steel, and wrapped carbon steel with internal cured in place linings.

• The buried piping utilizes coal tar or epoxy coatings that generally exceed industry standards.

• The BPTIP provides for inspections to confirm continuing integrity of the protective coatings.

42

" Because of the precautions taken at PNPS, the corrosivity of the soil surrounding the buried piping is low.

• The PNPS operating experience demonstrates the sufficiency of the protection provided by the protective coatings used on buried pipes at PNPS, consistent with industry experience, which demonstrates that properly applied coatings will ensure the protection of buried piping from soil induced corrosion.

2. The Water Chemistry Control-BWR Program Q91. What is the purpose of the Water Chemistry Control BWR Program?

A91. (ABC) The Water Chemistry Control-BWR Program optimizes the water chemistry in the CSS (among other plant systems) to minimize the potential for loss of material and cracking due to internal corrosion of the system.

Q92. How does the Water Chemistry Control BWR Program accomplish its purpose?

A92. (ABC) The Water Chemistry Control BWR Program operates by limiting the levels of contaminants in the CSS that could cause loss of material and cracking.

Q93. Has the effectiveness of the Water Chemistry Control BWR Program been confirmed at PNPS?

A93. (ABC) Yes. This is an existing program at PNPS that has been confirmed effective at managing the effects of aging on the CSS as documented by the operating experience review. See PNPS LRA at Appendix B, Section B. 1.32.2,

p. B-106-07. The continuous confirmation of water quality and timely corrective actions taken to address water quality issues ensure that the program is effective in managing corrosion for applicable components.

Q94. Does the Water Chemistry Control BWR Program comport with the guidance contained in the GALL Report?

A94. (ABC) Yes. The program uses EPRI BWR water chemistry guidelines, as specified in the GALL Report, which include chemistry recommendations for 43

condensate storage tanks. The program's effectiveness has also been confirmed by industry operating experience as described in the GALL Report. GALL Report at XI M-12, M-13, Entergy Exhibit 4.

3. The Service Water Integrity Program Q95. What is the purpose of the Service Water Integrity Program?

A95. (SPW) The Service Water Integrity Program includes surveillance and control techniques to manage the effects of aging on the SSW system or structures and components serviced by the SSW system.

Q96. How does the Service Water Integrity Program accomplish its purpose?

A96. (SPW) Under the program, the components of the SSW system are routinely inspected for internal loss of material and other aging effects that can degrade the SSW system. The inspection program includes provisions for visual inspections, eddy current testing of heat exchanger tubes, ultrasonic testing, radiography, and heat transfer capability testing of the heat exchangers. The periodic inspections include direct visual inspections and video inspections accomplished by inserting a camera-equipped robotic device into the SSW system piping. In addition, chemical treatment using biocides and chlorine and periodic cleaning and flushing of infrequently used loops are methods used under this program.

Q97. Has the effectiveness of the Service Water Integrity Program been confirmed at PNPS?

A97. (SPW) This program has been effective in detecting degradation of the internal rubber lining in the original SSW system carbon steel piping. As a result, the inlet pipes were replaced with titanium pipe, and portions of the discharge pipes were replaced with carbon steel piping coated internally and externally with an epoxy coating, and the entire lengths of the discharge pipes were internally lined with cured-in-place pipe linings. Thus, this program has been successfully implemented at PNPS to manage SSW system degradation from loss of material 44

due to internal corrosion prior to the loss of its intended function. See PNPS LRA at Appendix B, Section B. 1.28, p. B-92-93 (Entergy Exhibit 2).

Q98. Please describe how the Service Water Integrity Program was used to identify the internal degradation of the original internal rubber lining in the SSW discharge piping.

A98. (SPW) PNPS monitored the integrity of the original rubber lining as part of the in-service inspection requirements for the SSW developed in response to Generic Letter 89-13. As part of this monitoring, PNPS undertook increasingly intensive inspections as the original rubber lining approached the end of its expected life. In 1995, PNPS visually inspected the rubber liner using a robot crawler fitted with a camera and found minor age related degradation. The rubber liner was re-inspected using this same method in 1997, which identified additional degradation. Consequently, in 1999 PNPS undertook more intensive inspections by sending an inspector into the pipe to do both visual and ultrasonic examinations with the intent to make any necessary replacements or repairs. Based on the findings of this inspection, PNPS replaced the two forty-foot sections of the carbon steel SSW discharge pipe, as discussed above, and made other repairs. This action was then followed up with the installation in 2001 and 2003 of the CIPP throughout the entire length of both discharge loops A and B as discussed above.

Similarly, the Service Water Integrity Program will be used to monitor the newly installed CIPP. As the CIPP approaches the end of its expected life, increased inspections will be undertaken of the CIPP. The in-service inspection program for the SSW currently requires PNPS to undertake a complete ultrasonic or visual examination of the CIPP, analogous to those undertaken for the original rubber lining, after the CIPP has been in service for 20 years, well before the end of its expected 35 year life.

Q99. Does the Service Water Integrity Program comport with the guidance contained in the GALL Report?

45

A99. (ABC, SPW) Yes. The Service Water Integrity Program is consistent with the program described in NUREG-1 801 with two minor exceptions. One is that not all of the PNPS SSW components are coated internally (e.g., the titanium inlet piping) while the NUREG-1 801 program states that system components are lined or coated. In practice, systems are lined or coated based on whether the coating is necessary to protect specific materials in the service water environment. This practice is standard throughout the industry. PNPS conservatively identified this as an exception because for some component materials, such as the titanium inlet piping, internal linings or coatings are not necessary and were not provided. (As discussed above, all of the carbon steel discharge piping is lined with CIPP.) The second exception is an exception to the frequency specified for tests and inspections. NUREG-1801 specifies testing and inspections annually and during refueling outages. Since some inspections and tests are not feasible during plant operation, the PNPS program entails inspections and testing during refueling outages, not annually. Since aging effects are manifest over several years, the difference in inspection and testing frequency is insignificant.

4. The One-Time Inspection Program Q100. What is the purpose of the One-Time Inspection Program?

A100. (ABC) The One-Time Inspection Program includes activities to confirm the absence of significant aging effects for the internal surfaces of piping. In essence, the One-Time Inspection Program ensures the effectiveness of the Water Chemistry Control-BWR Program, which minimizes the potential for loss of material due to internal corrosion of the CSS, by "verify[ing] the effectiveness of the water chemistry control [AMPs] by confirming that unacceptable cracking, loss of material, and fouling is not occurring." PNPS LRA at Appendix B, Section B. 1.23, p. B-76 (Entergy Exhibit 2).

Q101. How does the One-Time Inspection Program accomplish its purpose?

46

A101. (ABC) The One-Time Inspection Program is an inspection of a representative sample (based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience) of the interior piping surface, which will be performed prior to the period of extended operation. The inspection locations will be chosen based on identifying locations most susceptible to aging degradation.

Q102. Does the One-Time Inspection Program comport with the guidance contained in the GALL Report?

A102. (ABC) Yes. The PNPS One-Time Inspection Program comports with the NRC Staff guidance set forth in the GALL Report for such inspection programs. See GALL Report at XI M-105 (Entergy Exhibit 4).

5. Summary of the AMPs Q103. Is it your opinion that the AMPs described above will provide reasonable assurance that the CSS and SSW system will perform their intended safety function during the license renewal term?

A103. (ABC, WHS, BRS, SPW) Yes.

Q104. Please summarize the basis for your opinion.

A104. (ABC, WHS, BRS, SPW) These AMPs will provide reasonable assurance that the effects of aging on the PNPS SSW system and the CSS will be managed such that the intended functions will be maintained consistent with the current licensing basis throughout the period of extended operation. The AMPs described above are either (i) programs proven effective through industry operating experience or (ii) new programs that rely on proven methods to effectively manage the effects of aging.

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D. Additional Surveillance Programs for the CSS and SSW System Q105. In addition to the AMPs described above, does PNPS undertake any additional surveillance or otherwise monitor the integrity and functioning of the CSS and SSW system?

A105. (BRS, SPW) Yes, PNPS employs surveillance and other monitoring programs to ensure the integrity and capability of the CSS and the SSW system to perform their intended functions. The monitoring and surveillance programs consist of frequent monitoring of plant indicators and testing of plant systems.

1. Monitoring of the Integrity of the CSS Q106. Please describe the additional surveillance and other monitoring that PNPS undertakes to ensure the integrity and functioning of the CSS.

A106. (BRS) PNPS ensures the continuing integrity and functioning of the CSS in two ways. First, a water level indicator in each of the two condensate storage tanks

("CST") is monitored every four hours. Second, the water flow rates from the HPCI and RCIC pumps are tested on a quarterly basis which serves to confirm adequate flow rates through the buried CSS piping.

a. CST Monitoring Q107. Regarding the monitoring of the water level in the CSTs, how are those tanks related to the in-scope CSS system buried piping?

A107. (BRS) The CSS system buried pipes draw water from the CST tanks and carry that water to the HPCI and RCIC system pumps.

Q108. How does monitoring the water level of the CSTs assist PNPS in verifying the integrity of the CSS system buried piping?

A108. (BRS) A significant change (i.e., outside the nornal parameters) in the water level in the CSTs would indicate that there was a significant leak in one of the components of the CSS.

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Q109. Why would a significant change in the water level in the CSS tanks indicate that there was a significant leak somewhere in the system?

A109. (BRS) Condensate water is part of the overall condensate and feedwater system. PNPS monitors the water level in the CSTs to ensure that the system is operating within normal parameters. If there were a significant drop in the level of water in the CSTs, we would know that there was a significant leak in the system, and would take appropriate action to identify and fix the leak.

Q110. Please describe the CSS tanks and the measures for monitoring the water level of the tanks.

All0. (BRS) Each of the two CSS tanks holds 275,000 gallons of water. The water level in each tank is maintained such that the level of the water in the tanks does not drop below 30 feet. The control room personnel monitor and record the water level in each tank every four hours to ensure that the water level in the CSTs is maintained.

Q111. What, if any, corrective action would be taken if the water level went below that normal range?

A111. (BRS) Any abnormal usage of water by the plant would require corrective action. Due to normal usage, personnel have to periodically add water to the CSTs. The need for excessive amounts of added water would indicate that there was a leak and would require corrective action. If there was no visible leak in the CSTs and connected systems, we would know that the leak is in the CSS buried piping connected to the CST which provide water to the HPCI and RCIC systems and would take the action necessary to fix the leak.

Q112. Assuming the CST water level was dropping below the normal level, is there a CST water level at which the HPCI and RCIC systems would no longer work?

A112. (BRS) As long as the water levels in the CSTs remain at or above 11 feet, the HPCI and RCIC systems would be able to draw sufficient water from the CSTs 49

to perform their intended functions. (As I noted previously, each CST has a 75,000 gallon reserve dedicated to the HPCI and RCIC systems which equates to 11 feet of water in the CSTs.) Moreover, the HPCI and RCIC intended functions can be accomplished using water from the torus. Thus, even if the CST water level drops below 11 feet, the HPCI and RCIC systems are able to perform their intended functions.

Q113. Is it correct that you would have to lose roughly 20 feet of water from the CSTs before the capability of the HPCI and RCIC to perform their system functions using water solely from the CSTs would be impaired?

Al13. (BRS) That is correct.

Q114. Would you notice and respond to such a drop in the CST water level?

A114. (BRS) Yes. Such a large drop in the CST water level would indicate a major leak in the CSS and prompt corrective action would taken to identify and remedy the source of the leak.

Q115. Can the plant still operate without the HPCI and RCIC systems?

A115. (BRS) Based on the plant's technical specifications, if one of the two systems is inoperable, you have 14 days to fix the system before you have to shut the plant down. If both systems are inoperable, you would have to shut down the plant within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Q116. Would a monitoring well be more effective in detecting a leak in the CSS buried piping than the CST water level monitoring program?

A116. (BRS) No. The CST water level check is performed every four hours, which is substantially more frequent than a sampling program for monitoring wells.

Further, depending on the location of the leak, it might take additional time for the radioactivity to reach and be detectible in a monitoring well. In addition, the CST water level check would directly detect any leak significant enough to 50

impair the intended functions of the CSS. It is a check on the water that flows into the precise buried piping system that is within the scope of license renewal.

b. HPCI and RCIC system pump water flow monitoring Q117. How does monitoring the water flow from the HPCI and RCIC system pumps assist PNPS in verifying the integrity of the CSS system buried piping providing water to the HPCI and RCIC systems?

A117. (BRS) The pumps must meet a minimum flow rate in order to perform their intended functions. If, when tested, the required minimum water flow rate out of the HPCI and RCIC system pumps is not met, we would declare the affected systems inoperable. If one or both systems are inoperable, we would take corrective action because, as I previously testified, we would have to shut down within 14 days if one system was inoperable, or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if both systems are inoperable.

Q118. Please describe the measures for monitoring the water flow rate from the HPCI and RCIC system pumps.

A118. (BRS) The Pilgrim plant safety analysis requires that the HPCI system maintain a water flow rate of 4,250 ("GPM"). The Pilgrim plant safety analysis requires that the RCIC system maintain a water flow rate of 400 gallons per minute.

Pursuant to 10 C.F.R. §§ 50.55a(f)-(g) and the technical specification surveillance requirements, PNPS undertakes in-service testing of the HPCI and RCIC systems to confirm the system capability to deliver the minimum required water flows. Specifically, the HPCI and RCIC systems are tested quarterly to prove operability in accordance with the PNPS Technical Specifications and the ASME Code. In other words, these quarterly tests ensure that the required water flow rates of 4,250 gallons per minute and 400 gallons per minute, respectively, are met.

In addition, the flow rates for the HPCI and RCIC systems are confirmed during system testing once every operating cycle following each refueling outage. The 51

HPCI and RCIC systems are also tested once every two years to verify the capability to operate the systems from the Alternate Shutdown Panel ("ASP").

These tests are in addition to the quarterly tests.

Q119. What consequences result, if any, should the specified flow rates not be achieved?

A119. (BRS) If any of the acceptance criteria for the flow rate tests are not met, corrective actions will be taken.

Q120. Would these quarterly flow rate inspections detect a leak in the CSS system piping large enough to prevent the HPCI or RCIC systems from performing their intended function?

A120. (BRS) Yes. A sufficiently large leak in the buried piping would cause the acceptance criteria not to be met. In other words, a potential cause of a failure to meet either the required 4,250 GPM or 400 GPM flow rates could be a leak in the buried pipe from the CSTs. As long as the quarterly testing meets the required flow rates, the HPCI or RCIC systems will perform their intended functions. However, a leak that could prevent satisfactory accomplishment of the flow tests is much larger than the size of a leak that will be readily detected through routine monitoring of the CST levels.

Q121. Would a monitoring well be more effective in detecting a leak in the CSS buried piping running to the HPCI and RCIC system pumps than the quarterly flow rate tests?

A121. (BRS) No. The flow rate tests on the HPCI and RCIC system pumps occur once every quarter, once per operating cycle, and once every two years.

Therefore, the RCIC and HPCI pumps would be checked at least as frequently as ground water in a monitoring well program. In addition, a monitoring well program could not distinguish a leak in the CSS buried piping leading to the HPCI and RCIC pumps from any other underground leak. Conversely, the quarterly flow rate tests check the water flow from the HPCI and RCIC system pumps connected to the CSS buried piping. It is a check on the water flow rate through the precise buried piping system within the scope of license renewal.

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W

2. Monitoring the Integrity of the SSW System Buried Piping Q122. Does PNPS monitor the integrity and functioning of the SSW system buried piping?

A122. (BRS) Yes. PNPS performs, on a monthly basis, a flow rate test of the seawater flow through the SSW system.

Q123. Please describe the program for monitoring the water flow rate.

A123. (BRS) Each month, PNPS tests the flow rate of the SSW system through the RBCCW heat exchanger. The minimum required flow for the test is 4500 GPM.

Q124. What does this test show?

A124. (BRS) The test is performed to make sure that there is adequate water flow through the heat exchangers and piping. It confirms that a leak, if any, from the buried piping is not large enough to prevent the system from satisfactorily performing its intended function.

Q125. What consequences result should the specified flow rates not be achieved?

A125. (BRS) If the acceptance criteria for the flow rate test are not met, corrective action will be taken - the problem will be investigated and fixed.

Q126. Are small leaks in the SSW system discharge lines a concern to the operability of the SSW system?

A126. (BRS, SPW) No. A small leak in the SSW system discharge line would not impair the operability of the SSW system. After all, the discharge line discharges the water into the bay. Therefore, a leak in and of itself does not impair the operability of the system. Only if the flow through the discharge system were impaired would system operability be affected. Should that occur, the SSW flow would decrease and pump discharge pressure would increase.

These parameters are continuously monitored in the control room by plant operators.

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Q127. Would a monitoring well be more effective in detecting a leak in the SSW system buried piping than the monthly flow rate tests of the SSW system?

A127. (BRS) No. The flow rate tests on the SSW system occur every month, which is more frequent than sampling from a monitoring well. In addition, the SSW system does not normally and would be very unlikely to contain radioactivity, so monitoring groundwater wells for radioactivity would not be expected to provide any indication of a leak in the SSW piping. Indeed, the only indicator would be salt water, but the SSW runs near the intake embayment and into the discharge canal, both of which contain salt water, so it would be difficult to discern whether salt levels in a monitoring well are attributable to a leak rather than the influences of the adjacent water bodies. In addition, the SSW discharge lines are each over 200 feet long, and attempting to use monitoring wells to detect leakage from this span would be difficult and inefficient. Further, sampling from a monitoring well could not distinguish a leak in the SSW system buried piping from any other leak. Conversely, the monthly SSW system flow rate tests check the water flow through the SSW buried piping. It is a check on the water that flows through the precise buried piping system within the scope of license renewal.

E. Monitoring Wells are Not Necessary to Detect Leakage Sufficiently Large Enough to Prevent the CSS Buried Piping and the SSW System Buried Discharge Piping from Performing their Intended Safety Functions Q128. Is it your opinion that monitoring wells, through which sampling would monitor the radiation levels in the ground water in and around the Pilgrim site, are necessary in order to detect a leak in the buried CSS piping or the SSW system discharge piping?

A128. (ABC, WHS, BRS, SPW) No.

Q129. Why not?

A129. (ABC, WHS, BRS, SPW) Monitoring wells would not be as effective at detecting significant leaks from either the CSS or SSW system as the periodic surveillance tests summarized above. Sampling for radioactivity in the 54

N 11

.

monitoring wells would not likely detect a leak from the SSW system because it is highly unlikely that the discharge piping would contain any radioactive water.

In addition, the flow rate testing for the SSW system confinrs on a monthly basis that that system is capable of performing its intended function.

For the CSS, which does contain radioactive liquid, monitoring confirms every four hours that the water level in the two CSTs is within the normal operating range. CST water level within normal range indicates that there is no leak in CSS system piping large enough to compromise the ability of those pipes to perform their intended function of providing water to the HPCI and RCIC systems.

Furthermore, the HPCI and RCIC system pump flow rate tests confirm on a quarterly basis that the HPCI and RCIC system pumps, which are fed by the in-scope CSS buried piping, are performing at the water flow rates required under the technical specifications. The daily monitoring and quarterly testing of the systems using in-scope buried piping provide a more precise indication of whether the in scope buried piping is leaking sufficient liquid such that the piping could not perform its intended function than monitoring wells.

Even if monitoring wells detected radioactivity, such a measurement could not indicate, with anywhere near as much precision, the origin of the leak.

Furthermore, monitoring wells would likely not be monitored more than once every quarter. This is no more frequent than the quarterly surveillance program for the HPCI and RCIC system piping and less frequent than the monthly program for the SSW system piping, and is significantly less frequent than the daily monitoring of the CST water level.

IV. CONCLUSION Q130. What is your conclusion regarding the sufficiency of the AMPs discussed above to provide reasonable assurance that components within the scope of license renewal containing radioactive liquids at PNPS will continue to perform their intended functions during the period of extended operation?

55

, . )

A130. (ABC, BRS, SPW, WHS) The AMPs for those buried components within the scope of license renewal containing radioactive liquids at PNPS are programs that have been shown to be effective by PNPS operating experience and the GALL Report, and thus provide reasonable assurance that such components will continue to perform their intended functions during the period of extended operation. Further, these AMPs are in addition to regular monitoring and surveillances that continually confirm the ability of the components to perform their intended functions.

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-t January 8, 2008

• UNITfED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and licensing Board Panel In the Matter of

)

Entergy Nuclear Generation Company and' ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

DECLARATION OF WILLIAM H. SPATARO IN SUPPORT OF ENTERGY'S PRE-FILED TESTIMONY ON PILGRIM WATCH CONTENTION I 1, William H. Spataro, do hereby state the following-.

Untir-December 3 1,'2007,'l was the Senior StaffEngineer-:Corporate'Metallurgist With Entergy Nuclear. My personal address is 2 Burning Brush Court, Pomona, NY 10970. In that position, 1 provided technical support in metallurgy, corrosion, welding, and forensic investigation in support of Entergy's operation of its nuclear plants. I am a National Board Registered Certified Nuclear Safety Related Coating Engineer and have extensive experience in the coating and corrosiQraot buried pipes. A statement of.my professional qualifications is attached.

I provide this declaration in support of Entergy's pre-filed testimony on Pilgrim Watch Contention I pursuant to the December 19, 2007 Atomic Safety and Licensing Board Order.

I attest to the accuracy of those statements attributed to me (that material. marked by my initials in Entergy's pre-filed testimony), support them as my own, and endorse their introduction into the record of this proceeding. I declare under penalty of petjury that those statements, and

my.statements in this declaration, are true and correct to the best of my knowledge, information, and belief Executed- January. 8, 2007 William I- Spat'go i(I 2

2 Burning Brush Court WILLIAM H. SPATARO, P.E. Professional Engineer - CT, NY Pomona, N.Y. 10970-2015 CONSULTING SPECIALIST NBR Certified Coatings Engineer Phone (845) 304-6482 METALLURGY WELDING CORROSION AWS Certified Welding Inspector Fax (845) 362-4946 AWS Certified Welding Educator Email whspataro@optonline.net FORENSIC ANALYSIS CONSULTANT Forty-five years of practical welding experience, thirty-nine years of professional engineering experience in welding, corrosion and metallurgical engineering. Expertise in welding and repair welding specification development, nondestructive examination, corrosion and materials evaluation, root cause determination, forensic failure analysis and supervision of on-site fabrication, installation and repair methods and techniques. Applications performed for nuclear, fossil fuel and hydroelectric power plants, electric transmission systems, steam, water and gas transmission pipelines, wastewater treatment and industrial manufacturing facilities, especially during outages.

Of special note, during steam generator installation, determined the cause of nozzle mock-up weld lack of fusion, developed solution and presentation to plant personnel and NRC; vessels installed without incident of weld defects. Received EPRI Innovators Award for reduction of nondestructive examination requirements for socket welds resulting in $995,000 estimated savings.

Currently hold or have held certifications in shielded metal arc (SMAW), gas tungsten arc (GTAW),

gas metal arc (GMAW), flux-cored arc (FCAW) and oxy-acetylene welding, brazing, soldering, plasma and flame spray overlay processes.

COURSE DESIGN AND DELIVERY Thirty-six years of experience as guest lecturer, course author and presenter at utilities, architect-engineering firms, manufacturing facilities, professional seminars, conferences and symposia.

Entergy Nuclear Northeast (New York Power Authority,) White Plains, NY Developed and delivered five-day Welding Metallurgy Course, three-day Forensic Metallurgical Failure Root Cause Evaluation Course and two-day Material Science Course. Each course delivered twice yearly. Each presentation saves an estimated $10,000-50,000/presentation over outsourcing.

(1980 - Present)

Garlock Sealing Technologies, Palmyra, NY Guest Lecturer, Regional and on-site Nuclear Applications Seminars. (2004 - Present)

Electric Power Research Institute, Charlotte, NC Guest Lecturer, Visual Examination and Advance Welding Technology Courses. (1988 - 1991)

American Association of Performance Engineers New York State Convention - Keynote Speaker, Topic "The Role of Metallurgy in Failure Analysis." (1987.)

ASM, NACE and AWS Guest lecturer at local chapter meetings (1984-1987.) Guest Lecturer - "Interaction Between Welding and Corrosion Control," NACE Northeast Region Conference September 1988.

Burns & Roe, Incorporated, Paramus and Oradell, NJ Developed and delivered five-day Practical Metallurgy For Engineers Course at Bums & Roe Corporate Office and at "Washington Public Power Supply System, Hanford, WA"; "Northeast Utilities, Millstone, Waterford, CT"; "General Public Utilities, Toms River, NJ" and "William F.

Wyman Fossil Plant, Falmouth, ME." Savings - $20,000/presentation. (1973 -1980) 1

2 Burning Brush Court WILLIAM H. SPATARO, P.E. Professional Engineer - CT, NY Pomona, N.Y. 10970-2015 CONSULTING SPECIALIST NBR Certified Coatings Engineer Phone (845) 304-6482 METALLURGY WELDING CORROSION AWS Certified Welding Inspector Fax (845) 362-4946 AWS Certified Welding Educator Email whspataro@optonline.net PROFESSIONAL EXPERIENCE ENTERGY NUCLEAR NORTHEAST (NEW YORK POWER AUTHORITY)

Director Materials Engineering - Consulting Metallurgist (1980 - Present)

Manage metallurgical and chemical engineers supporting the operation of the company's nuclear, fossil fueled, pumped storage and hydroelectric power projects and its transmission lines and under-water cables. Develop and present engineering support personnel training courses in Material Science, Welding Metallurgy, and Root Cause Forensic Metallurgical Failure Evaluation. Received Employee of the Quarter Award twice, Excellence In Engineering Performance Award twice, and EPRI Innovators Award.

BURNS & ROE, INCORPORATED, ORADELL, NJ Senior Metallurgist (1973 - 1980)

EBASCO SERVICES, INCORPORATED, NEW YORK, NY Welding Engineer (1968 - 1973)

EDUCATION AND DEVELOPMENT B.E. Metallurgy - New York University Supervisory Development Program - Rutgers University Maintenance Coatings in Class I Areas of Nuclear Plants - National Bureau of Registration ASME Section IX Welding Qualifications Course ASME Section XI Inservice Inspection Course PROFESSIONAL AFFILIATIONS AND MEMBERSHIPS Registered Professional Engineer, Connecticut and New York AWS: Certified Welding Inspector, Certified Welding Educator NBR: Certified Nuclear Safety Related Coating Engineer American Welding Society, Life Member American Society for Metals International, 41-year member National Association of Corrosion Engineers, 28-year member Welding Research Council - Subcommittees on High Nickel Alloys, Corrosion and Weldability of Stainless Steel Toastmasters International - Able Toastmaster Bronze Award Union County Vocational Institute, Scotch Plains, NJ - Advisory Board Member and Guest Lecturer - 1970-1975 Rockland County Board of Cooperative Extension Services, Bardonia, NY - Advisory Board Member and Guest Lecturer - 1969-1976 PUBLICATIONS Analysis and Monitoring of Heat Transfer Tube Fouling, N.Zelver, J.R.Flandreau, W.H.Spataro, et. al. Presented at ASME Joint Power Generation Conference, Denver, CO, October 1982.

Avoiding SCC Failures in Steam Turbine Blades, W.H.Spataro. Welding Design & Fabrication.

October 1989.

2

2 Burning Brush Court WILLIAM H. SPATARO, P.E. Professional Engineer - CT, NY Pomona, N.Y. 10970-2015 CONSULTING SPECIALIST NBR Certified Coatings Engineer Phone (845) 304-6482 METALLURGY WELDING CORROSION AWS Certified Welding Inspector Fax (845) 362-4946 AWS Certified Welding Educator Email whspataro@optonline.net MAJOR ACCOMPLISHMENTS Nuclear Power Plants Pressure Vessel Shell Weld Failures and Repair Techniques Analyzed 3-1/2" thick pressure vessel shell weld failures. Determined the cause of failure to be improper post weld heat treatment of original fabrication weld repairs on quench & tempered material. Excessive residual stresses, acting on high hardened weld heat-affected zones, pitted By brackish water contamination, resulted in over 200 individual corrosion assisted fatigue cracks in each of four vessels. Developed repair techniques. Used the lessons learned to develop the specifications used to purchase new, competitively bid steam generators for $30,000,000, a savings of $10,000,000. During steam generator installation, determined the cause of nozzle mock-up weld lack of fusion, developed solution and presentation to plant personnel and NRC.

Low Pressure Turbine Blade Failure Evaluation and Manufacturing Modification Analyzed blade failures in low-pressure turbines. Determined improper welding caused recurring corrosion failures. The welding technique resulted in a heat-affected zone of extremely high hardness in which stress corrosion cracking initiated. Modified manufacturing sequence to add peening and ultrasonic testing as a crack preventative measure. Spindles operated without further blade cracking. Estimated savings: $850,000.

Condenser Tube/Tubesheet Weld Corrosion Failure Evaluation and Repair Analyzed condenser tube/tubesheet weld corrosion. Over 1000 welds had experienced pitting corrosion. The attack covered 1/4 -1/3 of the weld circumference. The position of the corrosion around the circumference varied in different areas and suggested the phenomenon was related to the weld procedure. Analysis showed a rapid cooling at the weld start/stop location caused microstructural segregation that was susceptible to intragranular galvanic corrosion and cavitation/erosion degradation. Developed repair procedure to weld rather than plug the tubes.

Designed a cathodic protection system to prevent further corrosion. Condenser operated without further corrosion. Deferred condenser replacement for an estimated $10,500,000 savings.

Isophase Bus Installation Procedure Development Evaluated aluminum isophase bus welds failures and determined that poor welding techniques caused brittle welds that cracked. Developed new installation welding and heat-treating procedures. The bus, installed in half the estimated time, has operated since 1983 without incident of cracking. Estimated savings two weeks outage time $120,000.

Hydroelectric Power Plants Discharge Tube Cracking Evaluation and Repair Evaluated cavitation repair failures and determined cause of cracking. The repair welds were made with carbon steel filler metal diluted by a previous stainless steel repair weld deposit resulting in a brittle weld that cracked from residual stress. Developed a repair method for sealing the four-foot long, through-wall (3-1/2") cracks using the back-step, alternate bead placement technique. The remaining fifteen 60MW units were repaired without incident. Estimated savings

$210,000/unit.

3

2 Burning Brush Court WILLIAM H. SPATARO, P.E. Professional Engineer - CT, NY Pomona, N.Y. 10970-2015 CONSULTING SPECIALIST NBR Certified Coatings Engineer Phone (845) 304-6482 METALLURGY WELDING CORROSION AWS Certified Welding Inspector Fax (845) 362-4946 AWS Certified Welding Educator Email whspataro@optonline.net MAJOR ACCOMPLISHMENTS Fossil Fueled Power Plants Metallurgical Analysis of Cracked Low Pressure Turbine Blades A prior turbine blade weld deposit, susceptible to fatigue failure, was removed and re-welded by the equipment supplier with a different material. The new welds failed. Determined fatigue failure of new welds caused by insufficient removal of prior precipitation hardened material that formed a metallurgical notch. Developed weld repair technique eliminating crack sensitive material. Spindles have operated since 1986 without blade cracking. Estimated savings:

$700,000.

Replacement Boiler Tube Process Development Boiler tube failures were caused by caustic cracking of sensitized and decarburized 304H stainless steel. The tubes, cold worked during bending prior to installation and exposed to 1100'F operating condition developed a susceptibility to corrosion and failed within two years.

Developed pre-installation, post-bend heat treatment. The tubes have been in service since 1982 without failure. Estimated savings $150,000.

High VoltageTransmission Towers Bolted Connection Failure Analysis and Repair Performed root cause evaluation of bolted connections on 765kV and 345kV weathering alloy steel towers. Corrosion product build-up in the bolted connections exerted a force that deformed the structural members creating a danger of imminent failure. Designed a coating system to prevent intrusion of moisture into the joint and still maintain current transfer across the connection. The program enabled the towers to be repaired without interruption of service.

There have been no further incidents of corrosion since 1984. Prevented a potential New York State blackout.

State of the Art Material Utilization Service Water System Heat Exchanger Failure Analyses and Repair Evaluated root cause of corrosion failures of copper-nickel material in brackish water after less than one year of service. Determined crevices in weld joint design and susceptible material caused the failures. The material was unsuitable for low flow rate (less than 2 fps) conditions.

Anaerobic bacteria under silt deposits rapidly pitted the material. Designed new system utilizing crevice free joints of 904L/AL6X material that has operated successfully since 1981 without failure. Estimated savings of four replacements, one every five years at $5,500,000 each.

Service Water System Piping and Component Failure Analyses and Repair Utilized latest corrosion resistant materials: 347SS, 904L, Alloy 20, AL6XN, 254SMO and Titanium. Corrosion degradation eliminated in many systems handling brackish water or corrosive media. Evaluated these materials with emphasis on the effect of stagnant or low flow, crevice, galvanic, and microbiologically influenced corrosion mechanisms.

4

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

• )

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

$ )

(Pilgrim Nuclear Power Station) )

DECLARATION OF STEVEN P. WOODS IN SUPPORT OF ENTERGY'S PRE-FILED TESTIMONY ON PILGRIM WATCH CONTENTION I 1, Steven P. Woods, do hereby state the following:

I am the Manager, Programs & Engineering Components for Pilgrim Nuclear Power Station ("PNPS"). My business address is 600 Rocky Hill Road, Plymouth, MA 02360. I knowledgeable of the PNPS aging management program for buried pipes and tanks and was responsible for site engineering to install buried salt service water inlet piping at PNPS in 1993.

A statement of my professional qualifications is attached.

I provide this declaration in support of Entergy's pre-filed testimony on Pilgrim Watch Contention I pursuant to the December 19, 2007 Atomic Safety and Licensing Board Order.

I attest to the accuracy of those statements attributed to me (that material marked by my initials in Entergy's pre-filed testimony), support them as my own, and endorse their introduction into the record of this proceeding. I declare under penalty of perjury that those statements, and my statements in this declaration, are true and correct to the best of my knowledge, information, and belief.

Executed on January 8, 2008 Steven P. Woods

STEVEN P. WOODS RESUME OF QUALIFICATIONS 24 Winter Street Telephone: (781) 826-2076 Hanover, MA 02339 e-mail: woodsie24@comcast.net

SUMMARY

OF QUALIFICATIONS EXPERIENCE Over twenty six years experience applying engineering methods and capabilities to various projects and engineering disciplines ... employing management and supervisory skills ... repairing and maintaining marine and nuclear facilities ... identifying technical discrepancies ... solving engineering problems ... designing and preparing modifications for new and existing systems ...

implementing effective and efficient nuclear power plant procedures...designing and developing specifications for various equipment and systems ... analyzing mechanical components and piping systems to ASME, AWS, ANSI and AISC codes utilizing conventional methods and computer programs including MATHCAD, SUPERPIPE, GT Strudl and CDC Baseplate II, ... highly motivated and capable of working independently or as a member of an integrated team.

EMPLOYMENT HISTORY ENTERGY CORP. - PILGRIM NUCLEAR POWER STATION, Plymouth, Massachusetts 7/07 To Present Manager, Engineering Programs & Components. Responsible for budgets, schedules, resource allocation for emergent activities as well as long term plans including outages and license renewal.

1/06 To 7/07 Supervisor Code Programs, Eng. Programs & Components. Responsible for code program activities such as budgets, schedules, resource allocation, long term plans, and license renewal.

Acting EP&C manager.

5/00 To 1/06 Senior Engineer, Design Engineering - Mechanical / Civil / Structural group. Performing all facets of design engineering including nuclear changes and field support.

9/99 To 5/2000 ALTRAN CORPORATION, Boston, Massachusetts Engineering Consultant, Indian Point Unit 2 and Pilgrim Nuclear Power Stations Project Manager / Engineer to resolve design problems via generic modifications / component replacements to support IP2's outage. Staff augmentation to Mechanical / Structural Engineering Group at Entergy's PNPS for plant design changes.

3/96 To 9/99 PROTO-POWER CORPORATION, Groton, Connecticut Senior Engineer, Structural / Applied Mechanics Group, Millstone Unit 2 Nuclear Power Station Engineering Consultant assigned to lead the mechanical section of the Rapid Response Group in resolving "hot items" critical to plant operations. Performed analysis of structural and mechanical components initiated by Non-Conformance Reports, Condition Reports and Plant Design Changes.

Provide Motor Operated Valve (MOV) engineering support to MOV Group.

8/93 To 2/96 ALTRAN CORPORATION, Boston, Massachusetts Engineering Consultant, Millstone Units 1, 2, 3 & Connecticut Yankee Nuclear Power Stations and Fitzpatrick Nuclear Plant Lead Project Engineer performing Weaklink structural analysis of components for MOV's in accordance with the NRC's GL89-10 program. Developing design modifications for overstressed MOV's to return valves to original design basis.

5/92 - 7/93 CYGNA ENERGY SERVICES, Boston, Massachusetts Engineering Consultant, Boston Edision's Pilgrim Nuclear Power Station Mechanical Project Engineer dedicated to the "Salt Service Water Pipe Replacement" project.

Generated calculations to qualify design modifications during each phase of the project including excavation, underground concrete vault construction, titanium pipe fabrication and installation.

1/92 - 3/92 ALTRAN CORPORATION, Boston, Massachusetts Engineering Consultant, Millstone Units 1, 2, 3 & Connecticut Yankee Nuclear Power Stations

STEVEN P. WOODS RESUME OF QUALIFICATIONS Performed Erosion / Corrosion analysis for operability of piping systems enabling plant restart.

Page Two 12/88 - 12/91 ABB IMPELL CORPORATION, Framingham, Massachusetts Lead Senior Engineer, Engineering Mechanics Division Mechanical Engineering Consultant for Nine Mile Units 1 & 2 and Pilgrim Nuclear Station.

Performed pipe stress analysis and calculations. Mechanical Maintenance Project Engineer for Reactor Recirc Pumps Replacement and Modification controlling part replacements, rebuilding; identified and procured vendor specialty services; identified and designed special tools to facilitate field conditions. Resolved critical path engineering discrepancies in preparation for plant restart. Develop program and staff for material availability / substitution.

6/88 - 11/88 IMPELL CORPORATION, Fort Worth, Texas Senior Engineer Consultant, Structural Mechanics Division, Comanche Peak Nuclear Plant.

Lead Engineer for the Post Construction Hardware Validation Program. Evaluated and controlled critical path items; verified support calculations for structural integrity.

1/88 - 5/88 GILBERT/COMMONWEALTH, Chattanooga, Tennessee Senior Engineer Consultant, Hixson Office.

Verifier, Checker and Originator of calculations for analysis of pipe supports on Sequoyah Nuclear Plant Calculation Regeneration Program.

12/85 - 9/87 IMPELL CORPORATION, Knoxville, Tennessee Principal Engineer, Watts Bar Nuclear Plant.

The Design Engineering Department interface for system modifications and special tasks per request by the client. Field verified and analyzed structural and mechanical components, including load generation and support qualification, utilizing conventional methods and computer programs. Performed constructability reviews.

12/81 - 10/85 TELEDYNE ENGINEERING SERVICES, Waltham, Massachusetts Project Engineer. Turkey Point Nuclear Plant, Nine Mile Point Nuclear Plant, Fitzpatrick Nuclear Plant, Pilgrim Nuclear Station and Watts Bar Nuclear Plant.

Liaison engineer coordinating uninterrupted construction of all mechanical activities, making on-the-spot decisions for effective work flow. Performed structural and mechanical component analysis on new and existing systems.

1980-1981 U.S. MERCHANT MARINES Third Assistant Engineering Officer aboard cargo vessels.

Engineering Officer-On-Watch. Responsible for power plant operations and maintenance including supervision of extensive repair / testing of power plant components such as turbines, gears, pumps, valves, heat exchangers, boilers, I&C systems and electric motors.

1977-1980 MASSACHUSETTS MARITIME ACADEMY Summer training cruises (3) aboard Academy vessels. Performed all engine room tasks.

CLEARANCES Unescorted access to all nuclear plant sites assigned to.

EDUCATION Bachelor of Science Degree, Marine/Mechanical Engineering, Massachusetts Maritime Academy, Buzzards Bay, Massachusetts, 1980 U.S. Coast Guard Third Assistant Engineer of Steam and Motor Vessels for Unlimited Horsepower. License No. 513413.

DATE OF BIRTH CITIZENSHIP USA

STEVEN P. WOODS RESUME OF QUALIFICATIONS REFERENCES Av~ailable upon request.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

DECLARATION OF BRIAN R. SULLIVAN IN SUPPORT OF ENTERGY'S PRE-FILED TESTIMONY ON PILGRIM WATCH CONTENTION I I, Brian R. Sullivan, do hereby state the following:

I am the Engineering Director for Pilgrim Nuclear Power Station ("PNPS"). My business address is 600 Rocky Hill Road, Plymouth, MA 02360. I am currently responsible for engineering support at PNPS and I am knowledgeable of the intended functions for license renewal components and of the aging management programs credited for buried pipes and tanks for PNPS license renewal. A statement of my professional qualifications is attached.

I provide this declaration in support of Entergy's pre-filed testimony on Pilgrim Watch Contention 1 pursuant to the December 19, 2007 Atomic Safety and Licensing Board Order.

I attest to the accuracy of those statements attributed to me (that material marked by my initials in Entergy's pre-filed testimony), support them as my own, and endorse their introduction into the record of this proceeding. I declare under penalty of perjury that those statements, and my statements in this declaration, are true and correct to the best of my knowledge, information, and belief.

Executed on January 8, 2008 Brian'. SullivI

Brian R. Sullivan Pilgrim Nuclear Power Station 600 Rocky Hill Road Plymouth, MA 02360 EDUCATION 1980 - BSME - Massachusetts Maritime Academy Senior Operator License Number 11780 Operator Docket Number 55-62007 2 nd Assistant Engineers License - USCG EXPERIENCE 1988 - Present Various positions of increased responsibility at Pilgrim Nuclear Power Station

• Senior Engineer

• Control Room Supervisor

• Shift Manager

• AOM Shift

• Outage Manager

• AOM Support

• Programs and Components Manager

• Systems Engineering Manager

• Engineering Director

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board Panel In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

DECLARATION OF ALAN B. COX IN SUPPORT OF ENTERGY'S PRE-FILED TESTIMONY ON PILGRIM WATCH CONTENTION 1 I, Alan B. Cox, do hereby state the following:

I am the Technical Manager, License Renewal for Entergy Nuclear. My business address is 1448 State Road 333, Russelville, AR 72801. I was involved in preparing the license renewal application and developing aging management programs for the Pilgrim Nuclear Power Station license renewal project and have extensive experience and knowledge in the preparation of license renewal applications. A statement of my professional qualifications is attached.

I provide this declaration in support of Entergy's pre-filed testimony on Pilgrim Watch Contention 1 pursuant to the December 19, 2007 Atomic Safety and Licensing Board Order.

I attest to the accuracy of those statements attributed to me (that material marked by my initials in Entergy's pre-filed testimony), support them as my own, and endorse their introduction into the record of this proceeding. I declare under penalty of perjury that those statements, and my statements in this declaration, are true and correct to the best of my knowledge, information, and belief.

Executed on (Date)

Alan B. Cox

• • En.tergy RESUME Alan B. Cox EDUCATION B.S., Nuclear Engineering, University of Oklahoma, 1977 M.B.A., University of Arkansas at Little Rock, 1999 EXPERIENCE June 2001 - Enterqv License Renewal Team - Manacger, License Renewal Present Project manager and technical lead for license renewal services supporting both Entergy and non-Entergy license renewal projects. Entergy representative on various license renewal related industry groups.

1996-2001 Entergy Operations - Supervisor, Design Engineering Responsible for NSSS systems including supervision of engineers responsible for ANO-1 license renewal project. Served as member of expert panel responsible for review of license renewal application. Also provided design engineering support for plant modifications, corrective action tasks, major projects and plant operations associated with Arkansas Nuclear One.

1993-1996 Enterav Operations - Senior Staff Enaineer Provided design engineering support for plant modifications, corrective action tasks, major projects and plant operations associated with Arkansas Nuclear One. Principal mechanical engineering reviewer for improved Technical Specifications for ANO-1.

1990-1993 Entergy Operations - Technical Assistant to Plant Manager Provided technical support associated with management of Arkansas Nuclear One, Unit 1. Served as Entergy representative on the B&W Owners Group steering committee.

1986-1989 Arkansas Power & Liqht Company - Manager, Operations Responsible for the day to day operations of Arkansas Nuclear One, Unit 1. -

1977-1986 Arkansas Power & Light Company - Engineer At Arkansas Nuclear One, served in various capacities associated with the operation of Unit 1 and the startup and operation of Unit 2. Included assignments in plant performance monitoring, outage planning and scheduling, reactor engineering, and operations technical support. Qualified as shift technical advisor for both units of Arkansas Nuclear One.

CERTIFICATIONS " Professional Engineer; Registered in Arkansas (currently inactive)

• Previously held RO and SRO licenses at Arkansas Nuclear One, Unit 1

)ROFESSIONAL " Member, American Nuclear Society (ANS)

AFFILIATIONS Page 1 of I May 2007 2007 Page 1 of 1

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

Entergy Exhibits to Testimony of Alan Cox, Brian Sullivan, Steve Woods and William Spataro 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 Exhibit Document 1A Plant Layout Diagram 1B Condensate Storage System Sketch 2 License Renewal Application - Appendix B (Excerpts) 3 Specification No. 6498-M-306, "Specification for External Surface Treatment of Underground Metallic Pipe for Unit No.1 Pilgrim Station No. 600 Boston Edison Company' 4 NUREG 1801, Generic Aging Lessons Learned ("GALL") Report, Vol. 2, Rev. 1 (Excerpts) 5 Procedure No. EN-DC-343, Rev. 0, Buried Piping and Tanks Inspection and Monitoring Program Exhibit table.doc

EXHIBIT IA

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EXHIBIT 2 Pilgrim Nuclear Power Station License Renewal Application Technical Information Administrative Controls PNPS quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B.

The Entergy Quality Assurance Program applies to PNPS safety-related structures and components. Administrative (document) control for both safety-related and nonsafety-related structures and components is accomplished per the existing document control program. The PNPS administrative controls are consistent with NUREG-1801.

B.0.4 OPERATING EXPERIENCE Operating experience for the programs and activities credited with managing the effects of aging was reviewed. The operating experience review included a review of corrective actions resulting in program enhancements. For inspection programs, reports of recent inspections, examinations, or tests were reviewed to determine if aging effects have been identified on applicable components. For monitoring programs, reports of sample results were reviewed to determine if parameters are being maintained as required by the program. Also, program owners contributed evidence of program success or weakness and identified applicable self-assessments, QA audits, peer evaluations, and NRC reviews.

B.0.5 AGING MANAGEMENT PROGRAMS The following aging management programs are described in the sections listed of this appendix.

Programs are identified as either existing or new. The programs are either comparable to programs described in NUREG-1801 or are plant-specific. The correlation between NUREG-1801 programs and PNPS programs is shown in Table B-2, with plant-specific programs listed near the end.

Table B-1 Aging Management Programs

1) Boraflex Monitoring Program B. 1.1 existing

2) Buried Piping and Tanks Inspection B.1.2 new Program

3) BWR CRD Return Line Nozzle Program B.1.3 existing

4) BWR Feedwater Nozzle Program B.1.4 existing

5) BWR Penetrations Program B.1.5 existing

6) BWR Stress Corrosion Cracking Program B.1.6 existing

7) BWR Vessel ID Attachment Welds B.1.7 existing Program Appendix B Aging, Management Programs and Activities Page B-3

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-1 Aging Management Programs (Continued)

8) BWR Vessel Internals Program B.1.8 existing

9) Containment Leak Rate Program B.1.9 existing

10) Diesel Fuel Monitoring Program B.1.10 existing

11) Environmental Qualification (EQ) of B.1.11 existing Electric Components Program

12) Fatigue Monitoring Program B.1.12 existing

13) Fire Protection - Fire Protection Program B.1.13.1 existing

14) Fire Protection - Fire Water System B.1.13.2 existing Program

15) Flow-Accelerated Corrosion Program B.1 .14 existing

16) Heat Exchanger Monitoring Program B.1.15 new

17) Inservice Inspection - Containment B.1.16.1 existing Inservice Inspection (CII) Program

18) Inservice Inspection - Inservice Inspection B.1.16.2 existing (ISI) Program

19) Instrument Air Quality Program B.1.17 existing

20) Metal-Enclosed Bus Inspection Program B.1.18 new

21) Non-EQ Inaccessible Medium-Voltage B.1.19 new Cable Program

22) Non-EQ Instrumentation Circuits Test B.1.20 new Review Program

23) Non-EQ Insulated Cables and B.1.21 new Connections Program

24) Oil Analysis Program B.1.22 existing

25) One-Time Inspection Program B.1.23 new

26) Periodic Surveillance and Preventive B.1.24 existing Maintenance Program Appendix B Aging Management Programs and Activities Page B-4

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-1 Aging Management Programs (Continued)

27) Reactor Head Closure Studs Program B.1.25 existing

28) Reactor Vessel Surveillance Program B.1.26 existing

29) Selective Leaching Program B.1.27 new

30) Service Water Integrity Program B.1.28 existing

31) Structures Monitoring - Masonry Wall B.1.29.1 existing Program

32) Structures Monitoring - Structures B.1.29.2 existing Monitoring Program

33) Structures Monitoring - Water Control B.1.29.3 existing Structures Monitoring Program

34) System Walkdown Program B.1.30 existing

35) Thermal Aging and Neutron Irradiation B.1.31 new Embrittlement of Cast Austenitic Stainless Steel (CASS) Program

36) Water Chemistry Control - Auxiliary B.1.32.1 existing Systems Program

37) Water Chemistry Control - BWR Program B.1.32.2 existing

38) Water Chemistry Control - Closed Cooling. B.1.32.3 existing Water Program Appendix B Aging Management Programs and Activities Page B-5

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.0.6 CORRELATION WITH NUREG-1801 AGING MANAGEMENT PROGRAMS The correlation between NUREG-1 801 programs and PNPS programs is shown below. For the PNPS programs, links to appropriate sections of this appendix are provided.

Table B-2 PNPS AMP Correlation with NUREG-1801 Programs NUREG-1801 NUREG-1801 Program PNPS Program Number Environmental Qualification (EQ) Environmental Qualification (EQ) of of Electric Components Electric Components Program [B.1.11]

X.M1 Metal Fatigue of Reactor Coolant Fatigue Monitoring Program [B.1.12]

Pressure Boundary Concrete Containment Tendon X.S1 Prestress Not applicable ASME Section XI Inservice See plant-specific Inservice Inspection XI.M1 Inspection, Subsections IWB, - Inservice Inspection (ISI) Program IWC, and IWD [B.1.16.2]

Water Chemistry Control - BWR XI.M2 Water Chemistry Program [B.1.32.2]

XI.M3 Reactor Head Closure Studs Reactor Head Closure Studs Program

[..5

[B. 1.25]

Xi.M4 BWR Vessel ID Attachment Welds BWR Vessel ID Attachment Welds Program [B.1.7]

XI.M5 BWR Feedwater Nozzle BWR Feedwater Nozzle Program

[B.1.4]

BWR Control Rod Drive Return BWR CRD Return Line Nozzle Line Nozzle Program [B. 1.3]

BWR Stress Corrosion Cracking XI.M7 BWR Stress Corrosion Cracking Program [B.1.6]

XI.M8 BWR Penetrations BWR Penetrations Program [B.1.5]

XI.M9 BWR Vessel Internals BWR Vessel Internals Program [B.1.8]

Appendix B Aging Management Programs and Activities Page B-6

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-2 PNPS AMP Correlation with NUREG-1801 Programs (Continued)

NUREG-1801 NUREG-1801 Program PNPS Program Number XI.M10 Boric Acid Corrosion Not applicable XI.M11 Nickel-Alloy Nozzles and Not applicable Penetrations Nickel-Alloy Penetration Nozzles XI.M11A Welded to the Upper Reactor Not applicable Vessel Closure Heads of Pressurized Water Reactors Thermal Aging Embrittlement of XI.M12 Cast Austenitic Stainless Steel Not applicable (CASS)

Thermal Aging and Neutron Thermal Agingofand Neutron Embrittlement Cast Austenitic XI.M13 Irradiation Embrittlement of Cast Staless t (CAs) rora Austenitic Stainless Steel (CASS) [8.1.31]

XI.M14 Loose Part Monitoring Not applicable XI.M15 Neutron Noise Monitoring Not applicable XI.M16 PWR Vessel Internals Not applicable Flow-Accelerated Corrosion Program XI. MI7 Flow-Accelerated Corrosion[B114 [B. 1. 14]

XI.M18 Bolting Integrity Not applicable XI.M19 Steam Generator Tube Integrity Not applicable XI.M20 Open-Cycle Cooling Water Service Water Integrity Program System [B. 1.281 XI.M21 Closed-Cycle Cooling Water Water Chemistry Control - Closed System Cooling Water Program [B. 1.32.3]

XI.M22 Boraflex Monitoring Boraflex Monitoring Program [B.1.1]

Appendix B Aging Management Programs and Activities Page B-7

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-2 PNPS AMP Correlation with NUREG-1801 Programs (Continued)

NUREG-1801 NUREG-1801 Program PNPS Program Number Inspection of Overhead Heavy XI.M23 Load and Light Load (Related to Not applicable Refueling) Handling Systems XI.M24 Compressed Air Monitoring Not applicable XI.M25 BWR Reactor Water Cleanup Not applicable System XI.M26 Fire Protection Fire Protection Program [B.1.13.1]

XI.M27 Fire Water System Fire Water System Program [B. 1.13.2)

XI.M28 Buried Piping and Tanks Not applicable Surveillance XI.M29 Aboveground Steel Tanks Not applicable Diesel Fuel Monitoring Program XI.M30 Fuel Oil Chemistry [B.1.10]

Reactor Vessel Surveillance Program XI.M31 Reactor Vessel Surveillance [..6

[6.1.26]

XI.M32 One-Time Inspection One-Time Inspection Program [B.1.23]

XI.M33 Selective Leaching of Materials Selective Leaching Program [B.1.27]

Buried Piping and Tanks Buried Piping and Tanks Inspection Inspection Program [B.1.2]

XI.M35 One-time Inspection of ASME One-Time Inspection Program [B.1.231 Code Class 1 Small-Bore Piping XI.M36 External Surfaces Monitoring System Walkdown Program [B.1.30]

XI.M37 Flux Thimble Tube Inspection Not applicable Appendix B Aging Management Programs and Activities Page B-8

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-2 PNPS AMP Correlation with NUREG-1801 Programs (Continued)

NUREG-1801 NUREG-1801 Program PNPS Program Number Inspection of Internal Surfaces in XI.M38 Miscellaneous Piping and Ducting Not applicable Components XI.M39 Lubricating Oil Analysis Oil Analysis Program [B.1.22]

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Non-EQ Insulated Cables and Environmental Qualification Connections Program [B.1.21]

Requirements Electrical Cables and Connections Not X Subject to nvirotuectal 10 CFR toa10 50.49 50.4Non-EQ Instrumentation Circuits Test icFR XlI.E2 Environmental Qualification Rve rga B .0 Requirements Used in Review Program [B.1.20]

Instrumentation Circuits Inaccessible Medium-Voltage Cables Not Subject to 10 CFR Non-EQ Inaccessible Medium-Voltage 50.49 Environmental Qualification Cable Program [B.1.19]

Requirements Metal-Enclosed Bus Inspection XI.E4 Metal Enclosed Bus Program Porm[..8 [B.1.18]

XI.E5 Fuse Holders Not applicable Electrical Cable Connections Not XI.E6 Subject to 10 CFR 50.49 Environmental Qualification Not applicable Requirements See plant-specific Inservice Inspection XI.S1 ASME Section Xl, Subsection IWE - Containment Inservice Inspection (CII) Program [B.1.16.1]

XI.S2 ASME Section Xl, Subsection IWL Not applicable Appendix B Aging Management Programs and Activities Page B-9

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-2 PNPS AMP Correlation with NUREG-1801 Programs (Continued)

NUREG-1801 NUREG-1801 Program PNPS Program Number See plant-specific Inservice Inspection XI.S3 ASME Section XI, Subsection IWF - Inservice Inspection (ISI) Program

[B.1.16.2]

XI.S4 10 CFR 50, AppendixJ Containment Leak Rate Program

[B19

[B.1.9]

Structures Monitoring - Masonry Wall XI.S5 Masonry Wall Program Program [B. 1.29.1]

Structures Monitoring - Structures XI.S6 Structures Monitoring Program Monitoring Program [B.1.29.2]

RG 1.127, Inspection of Water- Structures Monitoring - Water Control XI.S7 Control Structures Associated with Structures Monitoring Program Nuclear Power Plants [B.1.29.3]

XI.S8 Protective Coating Monitoring and Not applicable Maintenance Program Plant-Specific Programs Heat Exchanger Monitoring Program NA Plant-specific program [B. 1.15]

Inservice Inspection - Containment NA Plant-specific program Inservice Inspection (CII) Program

[B.1.16.1]

Inservice Inspection - Inservice NA Plant-specific program Inspection (ISI) Program [B.1.16.2]

Instrument Air Quality Program NA Plant-specific program [B. 1.17]

Periodic Surveillance and Preventive NA ' Plant-specific program Maintenance Program [B.1.24]

Water Chemistry Control - Auxiliary NA Plant-specific program Systems Program [B.1.32.1]

Appendix B Aging Management Programs and Activities Page B-10

Pilgrim Nuclear Power Station License Renewal Application Technical Information PNPS programs have been compared to the NUREG-1801 programs with the results being shown in Table B-3 as

• programs consistent with NUREG-1 801;

• programs with enhancements;

• programs with exception to NUREG-1801;

• not comparable to NUREG-1 801 (plant-specific)

Table B-3 PNPS Program Consistency with NUREG-1801 NUREG-1801 Comparison Programs Consistent Programs Plant Programs with with Program Name Specific with Enhancements Exceptions to NUREG- NUREG-1801 1801 Boraflex Monitoring Program X Buried Piping and Tanks X Inspection Program BWR CRD Return Line Nozzle X Program BWR Feedwater Nozzle X Program BWR Penetrations Program X BWR Stress Corrosion Cracking X X Program BWR Vessel ID Attachment X Welds Program BWR Vessel Internals Program X X Containment Leak Rate X Program Diesel Fuel Monitoring Program X X Environmental Qualification (EQ) X of Electric Components Program Appendix B Aging Management Programs and Activities Page B-11

Pilgrim Nuclear Power Station

• License Renewal Application Technical Information Table B-3 PNPS Program Consistency with NUREG-1801 (Continued)

NUREG-1801 Comparison Programs Consistent Programs Plant Programs with with Program Name Specific with Enhancements Exceptions to NUREG- NUREG-1801 1801 Fatigue Monitoring Program X Fire Protection - Fire Protection X X Program Fire Protection - Fire Water X X System Program Flow-Accelerated Corrosion. X Program Heat Exchanger Monitoring X Program Inservice Inspection - X Containment Inservice Inspection (CII) Program Inservice Inspection - Inservice X Inspection (ISI) Program Instrument Air Quality Program X Metal-Enclosed Bus Inspection X Program Non-EQ Inaccessible Medium- X Voltage Cable Program Non-EQ Instrumentation Circuits X Test Review Program Non-EQ Insulated Cables and X Connections Program Oil Analysis Program X X One-Time Inspection Program X Appendix B Aging Management Programs and Activities Page B-12

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-3 PNPS Program Consistency with NUREG-1801 (Continued)

NUREG-1801 Comparison Programs Consistent Programs Plant Programs with with Program Name Specific with Enhancements Exceptions to NUREG- NUREG-181l 1801 Periodic Surveillance and X Preventive Maintenance Program Reactor Head Closure Studs X Program Reactor Vessel Surveillance X X Program Selective Leaching Program X Service Water Integrity Program X Structures Monitoring - Masonry X Wall Program Structures Monitoring - X X Structures Monitoring Program Structures Monitoring - Water X X Control Structures Monitoring Program System Walkdown Program X Thermal Aging and Neutron X Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program Water Chemistry Control - X Auxiliary Systems Program Water Chemistry Control - BWR X Program Appendix B Aging Management Programs and Activities Page B-13

Pilgrim Nuclear Power Station License Renewal Application Technical Information Table B-3 PNPS Program Consistency with NUREG-1 801 (Continued)

NUREG-1801 Comparison Programs Consistent Programs Plant Programs with with Program Name Specific with Enhancements Exceptions to 1801 NUREG-1801 Water Chemistry Control - X Closed Cooling Water Program Appendix B Aging Management Programs and Activities Page B-14

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.2 BURIED PIPING AND TANKS INSPECTION Proaram Description The Buried Piping and Tanks Inspection Program at PNPS is comparable to the program described in NUREG-1 801,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 opportunistic inspection (or an inspection via a method that allows assessment of pipe condition without excavation) occurs within this ten-year period.

NUREG-1801 Consistency 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 one exception.

Exceptions to NUREG-1801 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 Exception

4. Detection of Aging Effects Inspections via methods that allow assessment of pipe condition without excavation may be substituted for inspections requiring excavation solely for 1

the purpose of inspection.

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 B Aging Management Programs and Activities Page B-17

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

Conclusion Implementation of the Buried Piping and Tanks Inspection 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.

Page B-18 B

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

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.16 INSERVICE INSPECTION Regulation 10 CFR 50.55a, imposes inservice inspection (ISI) requirements of ASME Code,Section XI, for Class 1, 2, and 3 pressure-retaining components, their integral attachments, and supports in light-water cooled power plants. Inspection, repair, and replacement of these components are covered in Subsections IWB, IWC, IWD, and IWF respectively. The program includes periodic visual, surface, and volumetric examination and leakage tests of Class 1, 2, and 3 pressure-retaining components, their integral attachments and supports.

Inservice inspection of supports for ASME piping and components is addressed in Section XI, Subsection IWF. ASME Code Section XI, Subsection IWF constitutes an existing mandated program applicable to managing aging of ASME Class 1, 2, 3, and MC supports for license renewal.

Additionally, 10 CFR 50.55a imposes inservice inspection requirements of ASME Code Section XI for class MC and class CC containment structures. Subsection IWE contains inspection requirements for class MC metal containments and class CC concrete containments. The scope of IWE includes steel liners for concrete containment and their integral attachments; containment hatches and airlocks; moisture barriers; and pressure-retaining bolting.

The program uses nondestructive examination (NDE) techniques to detect and characterize flaws. Three different types of examinations arevolumetric, surface, and visual. Volumetric examinations are the most extensive, using methods such as radiographic, ultrasonic or eddy current examinations to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws.

Three levels of visual examinations are specified. VT-1 visual examination is conducted to assess condition of the surface of the part being, examined, looking for cracks and symptoms of wear, corrosion, erosion or physical damage. It can be done with either direct visual observation or with remote examination using various optical/video devices. The VT-2 examination is conducted specifically to locate evidence of leakage from pressure retaining components (period pressure tests). While the system is under pressure for a leakage test, visual examinations are conducted to detect direct or indirect indication of leakage. The VT-3 examination is conducted to determine the general mechanical and structural condition of components and supports and to detect discontinuities and imperfections. For containment inservice inspection, general visual and detailed visual examinations are used in addition to VT examinations as allowed by 10 CFR 50.55a to include applicable relief requests.

The inservice inspection programs are discussed in more detail in the following subsections

• Containment Inservice Inspection (CII)

• Inservice Inspection (ISI)

Appendix B Aging Management Programs and Activities Page B-55

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.16.2 INSERVICE INSPECTION Program Description The PNPS Inservice Inspection (ISI) Program is a plant-specific program encompassing ASME Section XI, Subsections IWA, IWB, IWC, IWD and IWF requirements.

The ISI Program is based on ASME Inspection Program B (IWA-2432), which has 10-year inspection intervals. Every 10 years the program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in 10 CFR 50.55a. On July 1, 2005 PNPS entered the fourth ISI interval. The ASME code edition and addenda used for the fourth interval is the 1998 Edition with 2000 Addenda. The current program ensures that the structural integrity of Class 1, 2, and 3 systems and associated supports is maintained at the level required by 10 CFR 50.55a.

Evaluation

1. Scope of Program The ISI Program manages cracking, loss of material, and reduction of fracture toughness of reactor coolant system piping, components, and supports. The program implements applicable requirements of ASME Section XI, Subsections IWA, IWB, IWC, IWD and IWF, and other requirements specified in 10 CFR 50.55a with approved NRC alternatives and relief requests. Every 10 years the ISI Program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in 10 CFR 50.55a.

ASME Section XI inspection requirements for Reactor Vessel Internals (Subsection IWB, Categories B-N-1 and B-N-2) are not in the ISI Program, but are included in the BWR Vessel Internals Program.

2. Preventive Actions The ISI Program is a condition monitoring program that does not include preventive actions.

3. Parameters Monitored/Inspected The program uses nondestructive examination (NDE) techniques to detect and characterize flaws. Volumetric examinations such as radiographic, ultrasonic or eddy current examinations are used to locate surface and subsurface flaws. Surface examinations, such as magnetic particle or dye penetrant testing, are used to locate surface flaws.

Appendix B Aging Management Programs and Activities Page B-59

Pilgrim Nuclear Power Station License Renewal Application Technical Information Three levels of visual examinations are specified. VT-1 visual examination is conducted to assess the condition of the surface of the part being examined, looking for cracks and symptoms of wear, corrosion, erosion or physical damage. It can be done with either direct visual observation or with remote examination using various optical and video devices. VT-2 visual examination is conducted specifically to locate evidence of leakage from pressure retaining components (period pressure tests).

While the system is under pressure for a leakage test, visual examinations are conducted to detect direct or indirect indication of leakage. VT-3 visual examination is conducted to determine general mechanical and structural condition of components and supports and to detect discontinuities and imperfections.

4. Detection of Aging Effects The ISI Program manages cracking and loss of material, as applicable, for carbon steel, low alloy steel and stainless steel/nickel based alloy subcomponents of the reactor pressure vessel using NDE techniques specified in ASME Section Xl, Subsections IWB, IWC, and IWD examination categories.

The ISI Program manages cracking, loss of material, and reduction of fracture toughness, as applicable, of reactor coolant system components using NDE techniques specified in ASME Section X1, Subsections IWB, IWC and IWD examination categories.

The ISI Program manages loss of material for ASME Class MC and Class 1, 2, and 3 piping and component supports and their anchorages by visual examination of components using NDE techniques specified in ASME Section XI, Subsection IWF examination categories.

No aging effects requiring management are identified for lubrite sliding supports.

However, the ISl Program will confirm the absence of aging effects for the period of extended operation.

5. Monitoring and Trending Results are compared, as appropriate, to baseline data and other previous test results. If indications are accepted for continued use by analytical evaluation, the areas containing such flaws are monitored during successive inspection periods.

ISI results are recorded every operating cycle and provided to the NRC after each refueling outage via Owner's Activity Reports prepared by the ISI Program Coordinator. These detailed reports include scope of inspection and significant inspection results.

Appendix B Aging Management Programs and Activities Page B-60

Pilgrim Nuclear Power Station License Renewal Application Technical Information

6. Acceptance Criteria A preservice, or baseline, inspection of program components was performed prior to startup to assure freedom from defects greater than code-allowable. This baseline data also provides a basis for evaluating subsequent inservice inspection results.

Since plant startup, additional inspection criteria for Class 2 and 3 components have been imposed by 10 CFR 50.55a for which baseline and inservice data has also been obtained. Results of inservice inspections are compared, as appropriate, to baseline data, other previous test results, and acceptance criteria of the ASME Section XI, 1998 Edition, 2000 Addenda, for evaluation of any evidence of degradation.

7. Corrective Actions If a flaw is discovered during an ISI examination, an evaluation is conducted in accordance with articles IWA-3000 and IWB-3000, IWC-3000, IWD-3000 or IWF-3000 as appropriate. If flaws exceed acceptance standards, such flaws are removed, repaired, or the component is replaced prior to its return to service. For Class 1, 2, and 3, repair and replacement is in conformance with IWA-4000. Acceptance of flaws which exceed acceptance criteria may be accomplished through analytical evaluation without repair, removal or replacement of the flawed component if the evaluation meets the criteria specified in the applicable article of the code.

8. Confirmation Process This attribute is discussed in Section B.0.3.

9. Administrative Controls This attribute is discussed in Section B.0.3.

10. Operating Experience Intergranular stress corrosion cracking was discovered during RFO06 in the thermal sleeve at nine of the ten recirculation supply nozzles. GE has performed an evaluation to demonstrate no further crack growth with hydrogen water chemistry protection.

A scheduled ISI surface examination in 1997 detected an indication adjacent to a welded pipe support lug. The lug was removed and the indication was repaired by welding. A scheduled ISI visual examination in 1999 detected a snubber with restricted movement and cold piston setting out of tolerance. The restriction was re-worked and the cold piston setting was accepted by evaluation. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects.

Appendix B Aging Management Programs and Activities Page B-61

Pilgrim Nuclear Power Station License Renewal Application Technical Information 142 scheduled ISI (ASME Section XI Subsections IWB, IWC, IWD, and IWF) examinations were performed on-line (between RFO13 and RFO14) and during RFO14 (April 2003). Results show that one spring hanger support in the residual heat removal system required rework because ISI visual inspection determined that bolting was loose. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects.

194 scheduled ISI (ASME Section XI Subsections IWB, IWC, IWD, and IWF) examinations were performed on-line (between RFO14 and RFO15) and during RFO1 5 (April 2005). Results show that cracked welds on four steam dryer tie-bars were repaired, loose bolting on a hanger was reworked, a UT exam indication on a standby liquid control system weld was repaired, and a number of RPV safe-end welds were accepted by evaluation because they had wall thickness less than the screening criteria, but not less than design minimums. Identification of degradation and corrective action prior to loss of intended function provide evidence that the program is effective for managing aging effects.

A QA audit and an NRC inspection in spring 2005 revealed no issues or findings that could impact effectiveness of the program.

Conclusion The ISI Program has been effective at managing aging effects. The ISI Program provides 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 B-62

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.23 ONE-TIME INSPECTION Program Description The One-Time Inspection Program at PNPS is a new program that will be implemented prior to the period of extended operation. The program will be comparable to the program described in NUREG-1801,Section XI.M32, One-Time Inspection. The one-time inspection activity for small bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary, will also be comparable to the program described in NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping. The PNPS program will be consistent with the program elements described in NUREG-1801.

The program will include one activity to verify effectiveness of an aging management program and activities to confirm the absence of aging effects as described below.

Water chemistry control programs One-time inspection activity will verify the effectiveness of the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

Internal surfaces of buried carbon steel One-time inspection activity will confirm pipe on the standby gas treatment system that loss of material is not occurring or is so discharge to the stack insignificant that an aging management program is not warranted.

Internal surfaces of compressed air and One-time inspection activity will confirm emergency diesel generator system that cracking (EDG system) and loss of components containing untreated air material (compressed air and EDG systems) are not occurring or are so insignificant that an aging management program is not warranted.

Internal surfaces of stainless steel One-time inspection activity will confirm radioactive waste and sanitary soiled that loss of material is not occurring or is so waste and vent system components insignificant that an aging management containing untreated water program is not warranted.

Small bore piping in the reactor coolant One-time inspection activity will confirm system and associated systems that form that cracking and reduction of fracture the reactor coolant pressure boundary toughness are not occurring or are so insignificant that an aging management program is not warranted.

Appendix B Aging Management Programs and Activities Page B-76

Pilgrim Nuclear Power Station License Renewal Application Technical Information RV flange leakoff line One-time inspection activity will confirm that cracking is not occurring or is so insignificant that an aging management program is not warranted.

Main steam flow restrictors (CASS) One-time inspection activity will confirm that loss of material, cracking, and reduction of fracture toughness are not occurring or are so insignificant that an aging management program is not warranted.

The elements of the program include (a) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; and (d) evaluation of the need for follow-up examinations to monitor the progression of any aging degradation.

When evidence of an aging effect is revealed by a one-time inspection, routine evaluation of the inspection results will identify appropriate corrective actions.

The inspection will be performed within the 10 years prior to the period of extended operation.

NUREG-1801 Consistency The One-Time Inspection Program will be consistent with the program described in NUREG-1801,Section XI.M32, One-Time Inspection. The one-time inspection activity for small bore piping in the reactor coolant system and associated systems that form the reactor coolant pressure boundary, will also be consistent with the program described in NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

Exceptions to NUREG-1801 None Enhancements None Appendix B Aging Management Programs and Activities Page B-77

Pilgrim Nuclear Power Station License Renewal Application Technical Information Operating Experience The One-Time Inspection Program is a new program for which there is no operating experience.

Industry and plant-specific operating experience will be considered in development-of this program, as appropriate.

Conclusion Verification of the effectiveness of the Water Chemistry Control programs and confirmation of the absence of aging effects on specific standby gas treatment, compressed air, emergency diesel generator, radioactive waste, sanitary soiled waste and vent, and reactor coolant system components will be undertaken in the One-Time Inspection Program to ensure component intended functions can be maintained in accordance with the current licensing basis (CLB) during the period of extended operation.

Appendix 3 Aging Management Programs and Activities Page B-78

Pilgrim Nuclear Power Station License Renewal Application Technical Information B.1.28 SERVICE WATER INTEGRITY Program Description The Service Water Integrity Program at PNPS is comparable to the program described in NUREG-1801,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-1801 Consistency The Service Water Integrity Program at PNPS is consistent with the program described in NUREG-1801,Section XI.M20, Open-Cycle Cooling Water System with exceptions.

Exceptions to NUREG-1801 The Service Water Integrity 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 Exceptions

2. Preventive Actions NUREG-1 801 states that system components are lined or coated.

Components are lined or coated only where necessary to protect the underlying metal 1

surfaces.

5. Monitoring and Trending NUREG-1801 states that testing and inspections are performed annually and during refueling outages. The PNPS program requires tests and inspections 2

each refueling outage.

Exception Notes

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.

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 Operating Experience 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.

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.

Conclusion The Service Water Integrity Program has been effective at managing aging effects. The Service Water Integrity 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

Pilgrim Nuclear Power Station License Renewal Application Technical Information Conclusion The Water Chemistry Control - Auxiliary Systems Program has been effective at managing loss of material for components exposed to treated water. The Water Chemistry Control - Auxiliary Systems Program provides 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.

B.1.32.2 WATER CHEMISTRY CONTROL - BWR Program Description The Water Chemistry Control - BWR Program at PNPS is comparable to the program described in NUREG-1801,Section XI.M2, Water Chemistry.

The objective of this program is to manage aging effects caused by corrosion and cracking mechanisms. The program relies on monitoring and control of water chemistry based on EPRI Report 1008192 (BWRVIP-130). BWRVIP-130 has three sets of guidelines: one for primary water, one for condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water. EPRI 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 the potential for loss of material and cracking. This is accomplished by limiting the levels of contaminants in the RCS that could cause loss of material and cracking. Additionally, PNPS has instituted hydrogen water chemistry (HWC) to limit the potential for IGSCC through the reduction of dissolved oxygen in the treated water.

NUREG-1801 Consistency The Water Chemistry Control - BWR Program is consistent with the program described in NUREG-1801,Section XI.M2, Water Chemistry.

Exceptions to NUREG-1801 None Enhancements None Appendix B Aging Management Programs and Activities Page B-105

Pilgrim Nuclear Power Station License Renewal Application Technical Information Operatina Experience During the period from 1998 through 2004, several condition reports were initiated due to adverse trends in parameters monitored by the Water Chemistry Control - BWR Program.

Corrective actions were taken within the Corrective Action Program to preclude reaching unacceptable values for the parameters. Continuous confirmation of water quality and corrective action prior to reaching control limits provide evidence that the program is effective in managing aging effects for applicable components.

During the period from 1998 through 2004, several condition reports were initiated due to parameters monitored by the Water Chemistry Control - BWR Program outside of administrative limits, but still within EPRI acceptance criteria. Corrective actions were taken within the Corrective Action Program to preclude violating EPRI acceptance criteria. Continuous confirmation of water quality and corrective action prior to reaching control limits provide evidence that the program is effective in managing aging effects for applicable components.

During the period from 1998 through 2004, the following two incidents were found in which parameters monitored by the Water Chemistry Control - BWR Program were outside of EPRI acceptance criteria.

Following a downpower 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). Root cause was B HPFW sample line contamination, not actual low oxygen in the feedwater. The B HPFW sample line was replaced.

On October 28, 2002, HPFW and CDE dissolved oxygen levels spiked to 400 to 500 ppb for about 15 minutes before returning to normal. EPRI action level 1 for HPFW dissolved oxygen is 200 ppb. Root cause was determined to be 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 that will insure proper venting and mitigate elevated oxygen levels in the feedwater system.

Continuous confirmation of water quality and timely corrective action provide evidence that the program is effective in managing aging effects for applicable components.

QA audits in 2000 and 2002 revealed no issues or findings that could impact effectiveness of the program.

A QA audit in 2004 revealed that reactor coolant sodium and lithium analyses were not being performed weekly during the first half of 2004. Corrective action was taken to replace the analysis instrument and ensure required analyses are performed. Confirmation of water quality Appendix B Aging Management Programs and Activities Page B-106

Pilgrim Nuclear Power Station License Renewal Application Technical Information and timely corrective actions provide evidence that the program is effective in managing aging effects for applicable components.

A corporate assessment in 2003 identified areas for improvement in administrative controls, but revealed no issues or findings that could impact effectiveness of the program.

Conclusion The Water Chemistry Control - BWR Program has been effective at managing aging effects.

The Water Chemistry Control - BWR Program at PNPS provides 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 0peration.

B.1.32.3 WATER CHEMISTRY CONTROL- CLOSED COOLING WATER Program Description The Water Chemistry Control - Closed Cooling Water Program at PNPS is comparable to the program described in NUREG-1 801,Section XI.M21, Closed-Cycle Cooling Water System.

This program includes preventive measures that manage loss of material, cracking, and fouling for components in closed cooling water systems (reactor building closed cooling water, turbine building closed cooling water, emergency diesel generator cooling water, station blackout diesel cooling water, security diesel generator cooling water, and plant heating). These chemistry activities provide for monitoring and controlling'closed cooling water chemistry using PNPS procedures and processes based on EPRI guidance for closed cooling water chemistry.

NUREG-1801 Consistency The Water Chemistry Control - Closed Cooling Water Program is consistent with the program described in NUREG-1 801,Section XI.M21, Closed-Cycle Cooling Water System, with one exception.

Exceptions to NUREG-1801 The Water Chemistry Control - Closed Cooling Water Program is consistent with the program described in NUREG-1 801,Section XI.M21, Closed-Cycle Cooling Water System, with the following exception.

Attributes Affected Exception

4. Detection of Aging Effects The PNPS Water Chemistry Control -

Closed Cooling Water Program does not 1

include performance and functional testing.

Appendix B Aging Management Programs and Activities .Page B- 107

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EXHIBIT 4 NUREG-1 801, Vol.I, Rev. 1 Generic Aging Lessons Generic Aging Lessons Learned (GALL) Report Summary Manuscript Completed: September 2005 Date Published: September 2005 Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

/1

INTRODUCTION NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," is referenced as a technical basis document in NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR). The GALL Report identifies aging management programs (AMP) that were determined to be acceptable to manage aging effects of systems, structures and components (SSC) in the scope of license renewal, as requiredby 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

The GALL Report is comprised of two volumes. Volume 1 summarizes the aging management reviews that are discussed in Volume 2. Volume 2 lists generic aging management reviews (AMRs) of SSCs that may be in the scope of license renewal applications (LRAs) and identifies GALL AMPs that are acceptable to manage the aging effects.

If an LRA references the GALL Report as the approach used to manage aging effect(s), the.

NRC staff will use the GALL Report as a basis for the LRA assessment consistent with

.guidance specified in the SRP-LR.

BACKGROUND Revision 0 of the GALL Report By letter dated March 3, 1999, the Nuclear Energy Institute (NEI) documented the industry's views on how existing plant programs and activities should be credited for license renewal. The issue can be summarized as follows: To what extent should the staff review existing programs.

relied on for license renewal in determining whether an applicant has demonstrated reasonable assurance that such programs will be effective in managing the effects of aging on the functionality of structures and components during the period of extended operation? In a staff paper, SECY-99-148, "Credit for Existing Programs for License Renewal," dated June 3, 1999, the staff described options for crediting existing programs and recommended one option that the staff believed would improve the efficiency of the license renewal process.

By staff requirements memorandum (SRM), dated August 27, 1999, the Commission approved the staffs recommendation and directed the staff to focus the staff review guidance in the Standard Review Plan for License Renewal (SRP-LR) on areas where existing programs should be augmented for license renewal: The staff would develop a "Generic Aging Lessons Learned (GALL)" report to document the staffs evaluation of generic existing programs. The GALL Report would document the staff s basis for determining which existing programs are adequate without modification and which existing programs should be augmented for license renewal. The GALL Report would be referenced in the SRP-LR as a basis for determining the adequacy of existing programs.

This report builds on a previous report, NUREG/CR-6490, "Nuclear Power Plant GenericAging Lessons Learned (GALL)," which'is a systematic compilation of plant aging information. This report extends the information in NUREG/CR-6490 to provide an evaluation of the adequacy of.

aging management programs for license renewal. The NUREG/CR-6490 report was based on information in over 500 documents: Nuclear Plant Aging Research (NPAR) program reports sponsored bythe Office of Nuclear Regulatory Research, Nuclear Management and Resources Council (NUMARC, now NEI) industry reports addressing license renewal for major structures and components, licensee ev.ent reports (LERs), information notices, generic letters, and September 2005 I NUREG-1801 Vol. 1, Rev. I

bulletins. The staff has also considered information contained in the reports provided by the Union of Concerned Scientists (UCS) in a letter dated May 5, 2000.

Following the general format of NUREG-0800 for major plant sections except for refueling water, chilled water, residual heat removal, condenser circulating water, and condensate storage system in pressurized water reactor (PWR) and boiling water reactor (BWR) power plants, the. staff has reviewed the .aging effects on components and structures, identified the relevant existing programs, and evaluated program attributes to manage aging effects for license renewal. This report was prepared with the technical assistance of Argonne National Laboratory and Brookhaven National Laboratory. As directed in the SRM, this report has the benefit of the experience of the staff members who conducted the review of the initial license renewal applications. Also, as directed in the SRM, the staff has sought stakeholders' participation in the development of this report. The staff held many public meetings and workshops to solicit input from the public. The staff also requested comments from the public on the draft improved license renewal guidance documents, including the GALL Report, in the Federal Register Notice, Vol. 65, No. 170,. August 31, 2000. The staffs analysis-of stakeholder comments is documented in NUREG-1 739. These documents can be found on-line at:

http://www.nrc.gov/reading-rm/doc-collections/.

Revision I of the GALL Report The GALL Report has been referenced in numerous license renewal applications (LRA) as a basis for aging management reviews to satisfy the regulatory criteria contained in 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," Section 54.21, "Contents of application - technical information." Based on lessons learned from these reviews, and other public input, including industry comments, the NRC staff proposed changes to the GALL Report to make the GALL Report more efficient. A preliminary version of Revision I of the GALL Report was posted on the NRC public web page on September 30, 2004. The draft revisions of GALL Vol. 1 and Vol. 2 were further refined and issued for public comment.on January 31, 2005. In addition, the staff also held public meetings with stakeholders to facilitate dialog and to discuss comments. The staff subsequently took into consideration comments received (see NUREG-1 832) and incorporated its dispositions into the, September 2005 version of the GALL Report..

OVERVIEW OF THE GALL REPORT EVALUATION PROCESS The results of the GALL effort are presented in a table format in the GALL Report, Volume 2.

The table column headings are: Item, Structure and/or Component; Material, Environment; Aging Effect/Mechanism; Aging Management Program (AMP); and Further Evaluation. The staff's evaluation of the adequacy of each generic aging management program in managing certain aging effects for particular structures and components is based on its review of the following 10 program elements in each agingmanagement program:

AMP Element Description

1. Scope of the program The scope of the program should include the specific structures arid components subject to an aging management review.

2. Preventive actions Preventive actions should mitigate or prevent the applicable aging effects.

3. Parameters monitored or Parameters monitored or inspected should be linked to the inspected effects of aging on the intended functions of the particular NUREG-1801 Vol. 1, Rev. 1 2 September 2005

AMP Element Description structure and component.

4. Detection of aging effects Detection of aging effects should occur before there isa loss of any structure and component intended function. This includes aspects such as method or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data collection and timing of hew/one-time inspections to ensure timely detection of aging effects.

5. Monitoring and trending Monitodring and trending should provide for prediction of the extent of the effects of aging and timely corrective or mitigative actions.

6. Acceptance criteria Acceptance criteria, against which the need for corrective action will be evaluated, should ensure that the particular structure and component intended functions are maintained under all current licensing basis (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 The confirmation process should ensure that preventive actions are adequate and appropriate corrective actions have been completed and are effective.

9. Administrative controls Administrative controls should provide a formal review and approval process.

10. Operating experience Operating experience involving the aging management program, including past corrective actions resulting in program enhancements or additional programs, should provide objective evidence to support a determination that the effects of aging will be -adequately managed so that the structure and component intended functions will be maintained during the period of extended operation.

If,on the basis of its evaluation, the staff determined that a program is adequate to manage certain aging effects for a particular structure or component without change, the "Further Evaluation"'entry would indicate that no furth.er evaluation is recomrmended for license renewal.

Chapter XI of the GALL Report, Volume 2, contains the staffs evaluation of generic aging management programs that are relied on in the GALL Report, such as the ASME Section XI inservice inspection, water chemistry, or structures monitoring program.

APPLICATION OF THE GALL REPORT The GALL Report is a technical basis document to the SRP-LR, which provides the staff with guidance.in reviewing a license renewal application. The GALL Report should be treated in the same manner as an approved topical report that is generically applicable. An applicant may reference the GALL Report in a license renewal application to demonstrate that the programs at the applicant's facility correspond to those reviewed and approved in the GALL Report.

Ifan applicant takes credit for a program in GALL, it is incumbent on the applicant to ensure that the plant program contains all the elements of the referenced GALL program. In addition, the conditions at the plant must be-bounded by the conditions for which the GALL program was evaluated. The above verifications must be documented on-site in an auditable form. The applicant must include a certification in the license renewal application that the verifications have been completed.

September 2005 3 NUREG-1801 Vol. 1, Rev. 1

The GALL Report contains one acceptable way to manage aging effects for license renewal. An applicant may propose alternatives for staff review in its-plant-specific license renewal application. Use of the GALL Report is not required, but its use should facilitate both preparation of a license renewal application by an applicant and timely, uniform. review by the NRC staff.

In addition, the GALL Report does not address scoping of structures and components for license renewal. Scoping is plant specific, and the results depend on the plant design and current licensing basis. The inclusion of a certain structure or component in the GALL Report does not mean that this particular structure or component is within the scope of license renewal for all plants. Conversely, the omission of a certain structure or component in the GALL Report does not mean that this particular structure or component is not within the scope of license renewal for any plants.

The GALL Report contains an evaluation of a large number of structures and components that may be in the scope of a typical LRA. The evaluation results documented in the GALL Report indicate that many existing, typical generic aging management programs are adequate to manage aging effects for particular structures or components for license renewal without change. The GALL Report also contains, recommendations on specific areas for which generic existing programs should be augmented (require further evaluation) for license renewal and documents the technical basis for each such determination. In addition, the GALL Report identifies certain SSCs that may or may not be subject to particular aging effects, and for which industry groups are developing generic aging management programs or investigating whether aging management is warranted. To the extent the ultimate generic resolution of such an issue

) will need NRC review and approval for plant-specific implementation, as indicated in a plant-specific FSAR supplement, and reflected in the SER associated with a particular LR application, an amendment pursuant to 10 CFR 50:90 will be necessary.

In the GALL Report, Volume 1, Tables 1 through 6 are summaries of the aging management review. These tables contain the same information as Tables 3.1-1 to 3.6-1, respectively, in the SRP-LR. These tables also include additional seventh and eighth columns that identify the related generic item and unique item associated with each structure and/or component (i.e.,

each row in the AMR tables contained in Volume 2 of the GALL Report). A locator for the plant systems evaluated in Volume 2 is also provided in the Appendix of Volume 1.

The Appendix of Volume 2 of the GALL Report addresses quality assurance (QA) for aging management programs. Those aspects of the aging management review process that affect the quality of safety-related structures, systems, and components are subject to the QA requirements of Appendix B to 10 CFR Part 50. For nonsafety-related structures and components subject to an aging management review, the existing 10 CFR Part 50, Appendix B, QA program may-be used by an applicant to address the elements of the corrective actions, confirmation process, and administrative controls for an aging management program for license renewal.

The GALL Report provides a technical basis for crediting existing plant programs and recommending areas for program augmentation and further evaluation. The incorporation of the GALL Report information into the SRP-LR, as directed by the Commission, should improve the efficiency of the license renewal process and better focus staff resources.

NUREG-1 801 Vol. 1, Rev. 1 4 .September 2005

NUREG-1 801, Vol. 2, Rev. 1 Generic Aging Lessons Generic Aging Lessons Learned (GALL) Report Tabulation of Results Manuscript Completed: September 2005 Date Published: September 2005 Division of Regulatory. Improvement Programs Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

XI.M2 WATER CHEMISTRY Program Description The main objective of-this program is to mitigate damage caused by corrosion and stress corrosion cracking (SCC). The water chemistry program for boiling water reactors (BWRs) relies on monitoring and control of reactor water chemistry based on industry guidelines such asthe boiling water reactor vessel and internals project (BWRVIP)-29 (Electric Power Research Institute [EPRI] TR-103515) or later revisions. The BWRVIP-29 has three sets of guidelines: one for primary water, one for condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water, The water chemistry program for pressurized water reactors (PWRs) relies on monitoring and control of reactor water chemistry based on industry guidelines for primary water and secondary water chemistry such as EPRI TR-105714, Rev. 3 and TR-102134, Rev. 3 or later revisions.

The water chemistry programs are generally effective in removing impurities from intermediate and high flow areas. The Generic Aging Lessons Learned (GALL) report identifies those circumstances in which the water chemistry program is to be augmented to manage the effects of aging for license renewal. For example, the water chemistry program may not be effective in low flow or stagnant flow areas. Accordingly, in certain cases as identified in the GALL Report, verification of the effectiveness of the chemistry control program is undertaken to ensure that significant degradation is not occurring and the component's intended function will be maintained during the extended period of operation. As discussed in the GALL Report for these specific cases, an acceptable verification program is a one-time inspection of selected components at susceptible l6cations in the system.

Evaluation-and Technical Basis

1. Scope of Program:The program includes periodic monitoring and control of known detrimental contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate concentrations below the levels known to result in loss of material or cracking.

Water chemistry control is in accordance with industry guidelines such as BWRVIP-29 (EPRI TR- 03515) for water chemistry in BWRs, EPRI TR-1 05714 for primary water chemistry in PWRs, and EPRI TR-102134 for secondary water chemistry in PWRs;

2. PreventiveActions: The program includes specifications for chemical species, sampling and analysis frequencies, and corrective actions for control of reactor water chemistry.

System water chemistry is controlled to minimize contaminant concentration and mitigate loss of material due to general, crevice and pitting corrosion and cracking caused by SCC.

For BWRs, maintaining high water purity reduces susceptibility to SCC.

3. ParametersMonitored/Inspected:The concentration of corrosive impurities listed in the EPRI guidelines discussed above, which include chlorides, fluorides (PWRs only),

sulfates, dissolved oxygen, and hydrogen peroxide, are monitoredto mitigate degradation of structural materials. Waterquality (pH and conductivity) is also maintained in accordance with the guidance. Chemical species and water quality are monitored by in-process methods or through sampling. The chemical integrity of the samples is maintained and verified to ensure that the method of sampling and storage will not cause a change in the concentration of the chemical species in the samples.

NUREG-1801, Rev. 1 XAM-1 0 September. 2005

N BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-1 03515) for BWR reactor water recommend that the concentration of chlorides, sulfates; and dissolved oxygen are monitored and kept below the recommended levels to mitigate corrosion. The two impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend that the coolant conductivity and ECP are also monitored and kept below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI guidelines in BWRVIP-29 (TR-1 03515) for BWR feedwater, condensate, and control rod drive water recommend that conductivity, dissolved oxygen level, and concentrations of iron and copper (feedwater only) are monitored and kept.below the recommended levels to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include recommendations for controlling water chemistry in auxiliary systems: torus/pressure suppression chamber, condensate storage tank, and spent fuel pool.

PWR PrimaryWater Chemistry:The EPRI guidelines (EPRI TR-105714), for PWR primary water chemistry recommend that the concentration of chlorides, fluorides, sulfates, lithium, and dissolved oxygen and hydrogen are monitored and kept below the recommended levels to mitigate SCC of austenitic stainless steel, Alloy 600, and Alloy 690 components. TR-1 05714 provides guidelines for chemistry control in PWR auxiliary

• systems such as the boric acid storage tank, refueling water storage tank, spent fuel pool, letdown purification systems, and volume control tank.

PWR Secondary Water Chemistry:The EPRI guidelines (EPRI TR-102134), for PWR secondary water chemistry recommend monitoring and control of chemistry parameters (e.g., pH level, cation conductivity, sodium, chloride, sulfate, lead, dissolved oxygen, iron, copper, and hydrazine) to mitigate steam generator tube degradation caused by denting, intergranular attack (IGA), outer diameter stress corrosioncracking (ODSCC), or crevice and pitting corrosion. The.monitoring and control of these parameters, especially the pH level, also mitigates general (for steel components), crevice, and pitting corrosion of the steam generator shell and the balance of plant materials of construction (e.g., steel, stainless steel, and copper).

4. Detection of Aging Effects: This is a mitigation program and does not provide for detection of any aging effects.

In certain cases as identified in the GALL Report, inspection of select components is to be undertaken to -verify the effectiveness of the chemistry control program and to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation.

5. Monitoring and Trending: The frequency of sampling water chemistry varies (e.g.,

continuous, daily, weekly, or as needed) based on -plant operating conditions and the EPRI water chemistry guidelines. Whenever corrective actions are taken to address an abnormal chemistry condition, increased sampling is utilized to verify the effectiveness of these actions.

6. Acceptance Criteria: Maximum levels for various contaminants are maintained below the system specific limits as indicated by the limits specified in the corresponding EPRI water chemistry guidelines. Any evidence of aging effects or unacceptable water chemistry results is evaluated, the root cause identified, and the condition corrected.

September 2005 XI M-1 1 NUREG-1801, Rev. 1

7. Corrective Actions: When measured water chemistry parameters are outside the specified range, corrective actions are taken to bring the pararheter back within the acceptable range and within the time period specified in the EPRI water chemistry guidelines. 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:Following corrective actions, additional samples are taken and analyzed to verify that the corrective actions were effective in returning the concentrations of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen,.and hydrogen peroxide to within the acceptable ranges. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process.

9. Administrative Controls: 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 B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.

10. OperatingExperience: The EPRI guideline documents have been developed based on plant experience and have been shown to be effective over time with their widespread use. The specific examples of operating experience are as follows:

BWR: Intergranular stress corrosion cracking (IGSCC) has occurred in small- and large-diameter BWR piping made of austenitic stainless steels and nickel-base alloys.

Significant cracking has occurred in recirculation, core spray, residual heat removal (RHR) systems, and reactor water cleanup (RWCU) system piping welds. IGSCC has also occurred in a number of vessel internal components, including core shroud, access hole cover, top guide, and core spray spargers (Nuclear Regulatory Commission [NRC]

Bulletin 80-13, NRC Information Notice [IN] 95-17, NRC Generic. Letter [GL] 94-03, and NUREG-1544). No occurrence of SCC in piping and other components in standby liquid control systems exposed to sodium pentaborate solution has ever been reported (NUREG/CR-6001).

PWR PrimarySystem: The primary pressure boundary piping of PWRs has generally not been found to be affected by SCC because of low dissolved oxygen levels and control of primary water chemistry. However, the potential for SCC exists due to inadvertent introduction of contaminants into the. primary coolant system from unacceptable levels of contaminants in the boric acid, introduction through the free surface of the spent fuel pool (which can be a natural collector of airborne contaminants), or introduction of oxygen during cooldown (NRC IN 84-18). Ingress of demineralizer resins into the primary system has caused IGSCC of Alloy 600 vessel head penetrations (NRC IN96-11, NRC GL 97-01). Inadvertent introduction of sodium thiosulfate into the primary system has caused IGSCC of steam generator tubes. The SCC has occurred in safety injection lines (NRC INs 97-19 and 84-18), charging pump casing cladding (NRC INs 80-38 and 94-63),

instrument nozzles in safety injection tanks (NRC IN91-05), and safety-related SS piping systems that contain oxygenated, stagnant, or essentially stagnant borated coolant (NRC IN 97-19). Steam generator tubes and plugs and Alloy 600 penetrations have experienced primary water stress corrosion cracking (PWSCC) (NRC INs 89-33, 94-87, 97-88, 90-10, and 96-11; NRC Bulletin 89-01 and its two supplements).

NUREG-1801, Rev. 1 Xf M-12 September 2005

PWR Secondary System:.Steam generator tubes have experienced ODSCC, IGA, wastage, and pitting (NRC IN 97-88, NRC GL 95-05). Carbon steel support plates in steam generators have experienced general corrosion. The steam generator shell has experienced pitting and stress corrosion cracking (NRC INs 82-37, 85-65, and 90-04).

Such operating experience has provided feedback to revisions of the EPRI water chemistry guideline documents.

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

BWRVIP-29 (EPRI TR-103515), BWR Water Chemistry Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 1994.

BWRVIP-79, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, March 2000.

BWRVIP-130, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, October 2000.

EPRI TR-1 02134, PWR Secondary Water Chemistry Guideline-Revision 3, Electric Power Research Institute, Palo Alto, CA, May 1993.

EPRI TR-105714, PWR PrimaryWater Chemistry Guidelines-Revision 3, Electric Power Research Institute, Palo Alto, CA, Nov. 1995.

EPRI TR-1002884, PWR Primary Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, October 2003.

NRC Bulletin 80-13, Cracking in Core Spray Piping, U.S. Nuclear Regulatory Commission, May 12,1980.

NRC Bulletin 89-01, Failure of Westinghouse Steam GeneratorTube Mechanical Plugs, U.S. Nuclear Regulatory Commission, May 15,1989.

NRC Bulletin 89-01, Supplement 1, Failureof Westinghouse Steam Generator Tube Mechanical Plugs, U.S. Nuclear Regulatory Commission, November 14,1989.

NRC Bulletin 89-01, Supplement 2, Failureof Westinghouse Steam Generator Tube Mechanical Plugs, U.S. Nuclear Regulatory Commission, June 28, 1991.

NRC Generic Letter 94-03, IntergranularStress Corrosion Cracking of Core Shrouds in Boiling Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994.

NRC Generic'Letter 95-05, Voltage-Based Repair Criteriafor Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress CorrosionCracking, U.S. Nuclear Regulatory Commission, August 3,1995.

September 2005 X.1M-1 3 NUREG-1801, Rev. 1

N XLM32 ONE-TIME INSPECTION Program Description The program includes measures to verify the effectiveness of an aging management program (AMP) and confirm the insignificance of an aging effect. Situations in which additional confirmation is appropriate include (a) an aging effect is not expected to occur but the data is insufficient to rule it out with reasonable confidence; (b) an aging effect is ex'pected to progress very slowly in the specified environment, but the local environment may be more adverse than that generally expected; or (c) the characteristics of the aging effect include a long incubation period. For these cases, there is to be confirmation that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly so as not to affect the component or structure intended function during the period of extended operation.

A one-time inspection may also be used to provide additional assurance that aging that has not yet manifested itself is not occurring, or that the evidence of aging shows that the aging is so insignificant that an aging management program is not warranted. (Class 1 piping less than or equal to NPS 4 is addressed in Chapter Xl. M35, One Time Inspection of ASME Code Class I Small Bore-Piping)

One-time inspections may also be used to verify the system-wide effectiveness of an AMP that is designed to prevent or minimize aging to the extent that it will hot cause the loss of intended function during the period of extended operation. For example, effective control of water chemistry can prevent some aging effects and minimize others. However, there may be locations that are isolated from the flow stream for extended periods and are susceptible to the gradual accumulation or concentration of agents that promote certain aging effects. This program provides inspections that either verifies that unacceptable degradation is not occurring or trigger additional actions that will assure the intended functionof affected components will be..

maintained during the period of extended-operation' The elements of the program include (a) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; arid (d) evaluation, of the need for follow-up examinaions to monitor the progression of aging if age-related degradation is found that could jeopardize an intended function before the end of the period of extended operation.

When evidence of an aging effect is revealed by a one-time inspection, the routine evaluation of the inspection results would identify appropriate corrective actions.

As set forth below, an acceptable verification program may consist of a one-time inspection of selected components and susceptible locations in the system. An alternative acceptable program may include routine maintenance or a review of repair or inspection records to confirm that these components have been inspected for aging degradation and significant aging degradation has not occurred. One-time inspection, or any other action or program, created to verify the effectiveness of an AMP and confirm the absence of an aging effect, is to be reviewed by the staff on a plant-specific basis.

September 2005 XI M-105 NUREG-1801, Rev. 1

Evaluation and Technical Basis

1. Scope of Program:The program includes measures to verify that unacceptable degradation is not occurring, thereby validating the effectiveness of existing AMPs or confirming that there is no need to manage aging-related degradation for the period of extended operation. The structures and components for which one-time inspection is spedified to verify the effectiveness of the AMPs (e.g., water chemistry control, etc.) have been identified in the Generic Aging Lessons Learned (GALL) Report. Examples include the feedwater system components in boiling water reactors (BWRs) and pressurized water reactors (PWRs).

2. Preventive Actions: One-time inspection is an inspection activity independent of methods to mitigate or prevent degradation.

3. ParametersMonitored/Inspected:The program monitors parameters directly related to the degradation of a component. Inspection is to be performed by qualified personnel following procedures consistent with the requirements. of the American Societyof Mechanical Engineers (ASME) Code and 10 CFR 50, Appendix B, using a variety of nondestructive examination (NDE) methods, including visual, volumetric, and surface techniques.

4. Detection of Aging Effects: The inspection includes a representative sample of the system population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin.

The program will rely on established NDE techniques, including-visual, ultrasonic, and surface techniques that are performed by qualified personnel following procedures consistent with the ASME Code and 10 CFR Part 50, Appendix B.

The inspection and test techniques will have a demonstrated history of effectiveness in detecting the aging effect of concern. Typically, the one time inspections should be performed as indicated in the'following table.

NUREG-1801, Rev. 1 X1 M-106 September 2005

Examples of Parameters Monitored or Inspected And Aging Effect for Specific Structure or Component9 Aging Aging Parameter Inspection Effect Mechanism Monitored Method1" Loss of Crevice Wall Thickness Visual (VT-1 or equivalent) and/or Material Corrosion Volumetric (RT or UT)

Loss of Galvanic Wall Thickness Visual (VT-3 or equivalent) and/or I,,

Material Corrosion Volumetric (RT or UT)

Loss of General Wall Thickness Visual (VT-3 or equivalent) and/or' Material Corrosion Volumetric (RT or UT)

Loss of MIC. Wall Thickness Visual (VT-3 or equivalent) and/or Material Volumetric (RT or UT)

Loss of Pitting Wall Thickness Visual (VT-1 or equivalent) and/or Material Corrosion Volumetric (RT or UT)

Loss of Erosion Wall Thickness Visual (VT-3 or equivalent) and/or Material Volumetric (RT or UT)

Loss of Fouling Tube Fouling Visual (VT-3 or equivalent) or Heat Enhanced VT-1 for CASS Transfer Cracking SCC or Cyclic Cracks Enhanced Visual (VT-I or equivalent, Loading and/or Volumetric (RT or UT)

Loss of Thermal Loosening of Visual (VT-3 or equivalent)

Preload Effects, Components Gasket Creep and Self-loosening.

With respect to inspection timing, the population of components.inspected before the end of the current operating term needs to be sufficient to provide reasonable assurance that the aging effect will not compromise any intended function at any time during the period of extended operation. Specifically, inspections need to be completed early enough to ensure that the aging effects that may affect intended functions early in the period of extended operation are appropriately managed. Conversely, inspections need to be timed to allow the inspected components to attain sufficient age to ensure that the aging effects with long incubation periods (i.e., those that may affect intended functions near the end of the period of extended operation) are identified. Within these constraints, the applicant should schedule the inspection no earlier than 10 years prior to the period of extended operation, and in such a way as to minimize the impact on plant operations. As a plant will-have accumulated at least 30 years of use before inspections under this program begin,.

sufficient times will have elapsed for aging effects, if any, to be manifest.

9 The examples provided in the table rnay not be appropriate for all relevant situations. If the applicant chooses to use an alternative to the recommendations in this table, a technical justification should be provided as an exception to this AMP. This exception should list the AMR line-item component, examination technique, acceptance criteria, evaluation standard and a description of the justification.

10 Visual inspection may be used only when the inspection methodology examines the surface potentially experiencing the aging effect.

September 2005 XI M-107 NUREG-1801, Rev. 1

5. Monitoringand Trending: The program provides for increasing of the inspection sample size and locations in the event that aging effects are detected. Determination of the sample size is based.on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience. Unacceptable inspection findings are evaluated in accordance with the site corrective action process to determine the need for subsequent (including periodic) inspections and for monitoring and trending the results.

6. Acceptance Criteria:Any indication or relevant conditions of degradation detected are evaluated. For example, the ultrasonic thickness measurements are to be compared to predetermined limits, such as the design minimum wall thickness for piping.

7. CorrectiveActions: 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 B. 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, confirmation process, and administrative controls.

8. Confirmation Process:See Item 7, above.

9. Administrative Controls:See Item 7, above.

10. OperatingExperience: This program applies to potential aging effects for which there are currently no operating experience indicating the need for an aging management program. Nevertheless, the elements that comprise these inspections (e.g., the scope of the inspections and inspection techniques) are consistent with industry practice.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteriafor NuclearPower Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards; Office of the Federal Register,- National Archives and Records Administration, 2005.

ASME Section XI, Rules for Inservice Ihspection of Nuclear Power Plant Components, ASME Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, American Society of Mechanical Engineers, New York, NY.

NUREG-1801, Rev. 1 X1 M-108 Septernber.2005

_N 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 castiron, 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 mainitaining 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 element/attributes of detection of aging effects (regarding inspection frequency) and operating experience.

Evaluation and Technical Basis

1. 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 coversburied 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 polyolifin tape coating, or a fusion bonded epoxy coating to protect the piping from contacting the aggressive soil environment.

3. ParametersMonitored/Inspected: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 Xl M-111 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 peri6d.

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. CorrectiveActions: 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,

9. Administrative Controls:See Item 7, above.

10. OperatingExperience: 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 Criteriafor NuclearPower Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NUREG-1801, Rev. 1 XI M-1 12 September 2005

EXHIBIT 5 Procedure Contains NMM REFLIB Forms: YES IF] NO L_

Effective Procedure Owner: Oscar Limpias Governance Owner: Oscar Limpias Date

Title:

VP Engineering

Title:

VP Engineering 11/19/07 Site: HQN Site: HQN Exception Site Site Procedure Champion Title Date* ____________________

ANO Jamie McCoy Mgr, Prog & Comp N/A BRP GGNS William Parman Mgr, Prog & Comp IPEC Richard Burroni Mgr, Prog & Comp JAF Joseph Pechacek Mgr, Prog & Comp N/A PLP PNPS Steven Woods Mgr, Prog & Comp RBS Chris Forpahl Mgr, Prog & Comp VY George Wierzbowoski Mgr, Prog & Comp W3 Rex Putnam Mgr, Prog & Comp N/A NP HQN Karen Tom Mgr, Prog & Comp Site and NMM Procedures Canceled or Superseded By This Revision Process Applicability Exclusion: All Sites: FI Specific Sites: ANO [I BRP [I GGNS El IPEC-- JAF El PLP [L PNPS[1 RBS El VY [I W3 El NP El Change Statement Original Issue

• Requires justification for the exception

TABLE OF CONTENTS Section Title Page 1.0 PURPOSE ........................................................................................ 3

2.0 REFERENCES

................................................................................. 3 3.0 DEFINITIONS .................................................................................... 4 4.0 RESPONSIBILITIES ......................................................................... 5 5.0 DETAILS ........................................................................................ 7 6.0 INTERFACES ................................................................................. 16 7.0 RECORDS ...................................................................................... 17 8.0 OBLIGATIONS AND COMMITMENTS IMPLEMENTED BY THE PROCEDURE .................................................................................. 17 9.0 ATTACHMENTS .............................................................................. 18 ATTACHMENT 9.1 XI.M34 BURIED PIPING AND TANKS INSPECTION .................. 19 ATTACHMENT 9.2 ROADMAP FOR BURIED PIPING AND TANKS INSPECTION AND MONITORING PROGRAM ....................... q........................................... 21 ATTACHMENT 9.3 LIST OF AFFECTED BURIED PIPING SYSTEMS AS PER LRA,.. 22 ATTACHMENT 9.4 SAMPLE DATA TABLE ....................................................... 24 ATTACHMENT 9.5 SAMPLE LONG TERM INSPECTION PLAN .............................. 25 ATTACHMENT 9.6 CORROSION OF MATERIALS IN SOILS ................................... 26 ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEM PLATE .......................................................................................... 29

1.0 PURPOSE

[1] This procedure provides the requirements, for each site to develop its own site specific Buried Piping and Tanks Inspection and Monitoring Program Section (hereafter referred to as The Program). This procedure specifies the Program content, the scope, ranking methodology, priorities and inspection frequency of the buried piping and tanks. The Program consists of inspection and monitoring of selected operational buried piping and tanks for external corrosion, including crevice, general, microbiologically influenced corrosion (MIC), and pitting corrosion.

2.0 REFERENCES

[1] NUREG-1801, "Generic Aging Lessons Learned (GALL) Report", dated July 2001

[2] NUREG-6876, "Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants", dated June 2005

[3] 10 CFR 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants"

[4] 10 CFR 50, Appendix B "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants"

[5] ANSI N18.7-1976, "Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants"

[6] NUMARC 93-01 (1996), "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," April 1996

[7] NEI 95-10 (1996), "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 -The License Renewal Rule," March 1996

[8] NEI 07-07, "Industry Ground Water Protection Initiative", June 2007

[9] EPRI Report 1011829, "Condition Assessment of Large-Diameter Buried Piping, Phase 2: Vehicle Design and Construction"

[10] INPO Engineering Program Guide, "Underground Piping Reliability Management",

dated June 2006

[11] INPO Operating Experience Digest OED 2007-09, "External Degradation of Buried Piping", dated April 2007

[12] ASM Handbook, Volume 13A, "Corrosion: Fundamentals, Testing and Protection, ASM International", October 2003

[13] ASM Handbook, Volume 13B, "Corrosion: Materials,,ASM International", November 2005

[14] "Corrosion Resistance of Stainless Steels in Soils and in Concrete", by Pierre-Jean Cunat. Paper presented at the Plenary Days of the Committee on the Study of Pipe Corrosion and Protection, Ceocor, Biarritz, October 2001

[15] API Standard 570, "Inspection, Repair, Alteration, and Rerating of In-Service Systems Piping Systems", Second edition, Addendum 1, February 2000 3.0 DEFINITIONS

[1] Baseline Inspection - The inspection of a new or replaced component that has not previously been involved in plant operations.

[2] Buried Section - A buried portion of piping or tank in a plant system that is placed below grade either in soil or concrete, (generally categorized by P &ID)which has similar parameters; i.e. similar pressure, temperature and materials.

[3] Concrete Piping - Piping that is manufactured from concrete or cementitious material with or without metallic reinforcement. Concrete piping is generally used for large diameter lines such as the water intake piping from sources of cooling water (e.g.,

lakes, rivers, and reservoirs).

[4] Corrosion - The chemical or electrochemical reaction between a material, usually a metal, and its environment that produces a deterioration of the material and its properties. A common example is the oxidation of an iron-based alloy exposed to water (rusting).

[5] Crevice Corrosion - Localized corrosion that mayý occur in areas of stagnant solutions existing in crevices, joints, and contacts between metals or between metals and non-metals.

[6] Erosion - Deterioration of materials by the abrasive action of moving fluids or gases, usually accelerated by the presence of solid particles or gases in suspension. When corrosion occurs simultaneously, the term Erosion/Corrosion is often used.

[7] General (also called Uniform) Corrosion - This type'of corrosion attacks the entire un-protected surface in a uniform manner. Of all types of corrosion, this is the least damaging and easiest to determine or quantify the corrosion rate.

[8] Holidays - also known as pinholes, voids, discontinuities.

[9] Initial Operational Inspection - The first inspection of a component that has been in-service and has not been subjected to a baseline inspection.

[10] Inspection Program - A systematic evaluation of all buried components using various techniques [e.g., ultrasonic testing (UT), radiographic testing (RT), visual testing (VT), leak testing (LT), eddy current (ET)].

[11] Licensed Material - Any material for which a permit or license is issued for purposes of monitoring inventory, effluent limits or prevention of release [e.g. State Pollution Discharge Elimination System (SPDES)].

[12] Microbiologically Influenced Corrosion (MIC) - Corrosion caused by the presence and/or activities of microorganisms in biofilms on the surface of the material.

Microorganisms have been observed in a variety of environments that include seawater, natural freshwater (lakes, rivers, wells), soils, and sediment.

Microbiological organisms include bacteria, fungi, and algae.

[13] Pitting - A form of localized corrosion that results in the formation of small, sharp cavities in a metal.

[14] Quality Assurance Classification - For this purpose of this procedure Safety Class or QA Category used to designate safety classification. Refer to Attachment 9.8 of EN-DC-1 67 for a summary of the corresponding "legacy" classifications formerly used at each plant and how they are classified as safety related, augmented and non-safety related.

[15] Redox - of or relating to oxidation-reduction.

[16] Resistivity - the longitudinal electrical resistance of a uniform rod of unit length and unit cross-sectional area. The reciprocal of conductivity.

[17] Subsequent Re-inspection - The inspection of a component that has been previously subjected to a Baseline Inspection and/or an Initial Operational Inspection.

[18] Visual Inspection - The inspection of a component accessible for direct observation by inspectors or by the use of remote visual inspection devices.

4.0 RESPONSIBILITIES 4.1 Site Engineering Director is responsible for:

[1] Sponsoring all aspects of this Program at the station.

4.2 Manager Programs & Components is responsible for:

[1] Implementing all aspects of this Program at the station.

[2] Ensuring that all activities associated with this Program are performed in a timely and cost efficient manner commensurate with the risk and safety significance of the issue.

[3] Allocating adequate resources as necessary to implement this Program.

4.3 Supervisor Programs & Components is responsible for:

[1] Assigning a Program Owner to develop, implement and maintain the site's Program in accordance with this procedure.

[2] Ensuring the timely completion of inspections.

4.4 Program Owner is responsible for:

[1] Developing, implementing and maintaining a site specific Program in accordance with the requirements of this procedure and EN-DC-174.

[2] Developing controlled Program and inspection documents.

[3] Reviewing site maintenance records for designated buried piping/tanks to determine if previous maintenance and inspections can be credited for pre-extended period of operation inspection requirements contained in Attachment 9.1, XI.M34 (4) Detection of Aging Effects.

[4] Initiating Condition Reports (CRs) for inspected conditions that fail to meet the acceptance criteria.

[5] Interfacing with other discipline Engineers as required to implement this procedure.

4.5 Site Design Engineering is responsible for:

[1] Supporting Program Owner in developing and maintaining a site specific Program in accordance with this procedure.

[2] Developing Acceptance Criteria for buried piping and tanks.

[3] Supporting the review of inspection results and evaluations.

4.6 Site System Engineering is responsible for:

[1] Ensuring that the site Cathodic Protection System is evaluated for proper operation and that routine maintenance and surveillance testing is being performed. Verifying that proper acceptance criteria have been established for evaluation of the test results. Confirming that the Cathodic Protection System is periodically evaluated by a National Association of Corrosion Engineer certified specialist as recommended by INPO.

5.0 DETAILS 5.1 PRECAUTIONS AND LIMITATIONS

[1] The risk of a failure caused by corrosion, directly or indirectly, is probably the most common hazard associated with buried piping and tanks. The corrosion risk assessment, described herein, is organized into categories reflecting four factors that impact the degree of corrosion risk due to design and environmental conditions.

Table 2 contains the elements contributing to each type of environment and the suggested weighting factors.

[2] Building the risk assessment tool requires the following four steps:

(a) Sectioning: dividing a system into smaller sections. The size of each section shall reflect practical considerations of operation, maintenance, and cost of data gathering with respect to the benefit of increased accuracy.

(b) Customizing: deciding on a list of risk contributors and risk reducers and their relative importance.

(c) Data gathering: building a database by completing an evaluation for each section of the system.

(d) Maintenance: identifying when and how risk factors can change and updating these factors accordingly. (Reference 12)

[3] Each Program Owner shall evaluate the site excavating procedures/processes to take advantage of opportunistic inspections.

[4] Be aware that backfilling an excavated area could increase the corrosion susceptibility in that area of the buried piping or tank due to changing soil conditions.

[5] When the inspection of the pipe entails unearthing the pipe, caution should be used so as to not disturb the protective exterior coating or the cathodic protection system, as applicable.

[6] Piping used to convey petroleum products should be inspected by an authorized inspection agency in accordance with the provisions API 570.

[7] Work Orders involving excavation should be routed to the Program Owner.

5.2 Scope of Program

[1] The Program shall include the following piping and tanks described in [2], [3] and [4].

[2] The Program shall include all systems and that have been identified in the License Renewal Aging Management Program consistent with NUREG-1801, "Generic Aging Lessons Learned (GALL) Report" (Ref. 1),Section XI.M34, "Buried Piping and Tanks Inspection" (see Attachment 9.1).

[3] The Program shall include buried or partially buried piping and tanks that, if degraded, could provide a path for radioactive contamination of groundwater (See Reference 8).

Some examples are:

• Underground storage tanks e Outdoor tanks such as refueling water storage tanks and condensate storage tanks e Spent fuel pools

• Buried piping containing contaminated or potentially contaminated liquids 9 Discharge canals 9 Retention ponds or basins

[4] The Program shall include buried piping or tanks not included in [1] through [3] that may present a potential concern as noted in site specific or general industry Operating Experience (OE).

[5] The Program shall at least assess all other buried piping or tanks not included in steps 5.2[2]-5.2[4] for susceptibility and risk as described in this procedure.

[6] A roadmap of the major steps needed for the Program is shown in Attachment 9.2 5.3 Identification of Affected Systems

[1] The affected systems shall be identified in accordance with the requirements stated in Section 5.2. Attachment 9.3 provides a list of affected buried piping systems for those plants that have submitted a License Renewal Application (LRA). The Program shall include these systems and any additional systems as identified in accordance with Section 5.2.

5.4 Identification of Buried Piping and Tanks to be Inspected and Prioritized

[1] The Program Owner shall develop a list of all systems containing buried piping and tanks. The Program Owner shall identify those sections of the affected piping and tanks that are buried, collecting physical drawings, piping/tank installation specifications, piping design tables and other data needed to support inspection activities.

[2] The Program Owner should complete the above design information and input into Attachment 9.4 within 3 months after issuance of this procedure.

[3) The Program Owner shall perform the impact assessment for all buried piping and tanks within 6 months after issuance of this procedure using Table 1 and input into Attachment 9.4

[4] Any buried piping or tank identified by applicable OE is designated High Impact requiring prompt attention until evaluated and dispositioned otherwise.

Table I Impact Assessment High Medium Low Safety (Class per Safety Related Augmented QP and Non-Safety Related EN-DC-167) Fire Protection Radioactive Chemical/Oil Untreated Water Public Risk Contamination e.g. Treated System SW, Demin Water Tritium gases Economics (Cost of buried >$1M or Potential >$100K<$1M <$100K equipment failure to Shutdown plant)

Notes:

1. Any buried section with at least one High Impact rating gets an overall High Impact rating.

2. Any buried section with no High Impact Rating but at least one Medium Impact rating gets an overall Medium Impact rating.

3. Any buried section with all Low Impact ratings is to be rated as Low Impact.

5.5 Preparation of Corrosion Risk Assessment

[1] The Program Owner shall perform the corrosion risk evaluation (Tables 2 and 3) for all High Impact buried sections within 9 months of issuance of this procedure, 12 months for all Medium Impact buried sections and 18 months for all Low Impact buried sections and input the data into Attachment 9.4.

[2] The Corrosion Risk Tabulation (Table 3), must consider the following attributes contained in Table 2 using the following steps but note this is already factored into the table in Attachment 9.4:

(a) Step 1: Using Table 2, take the soil resistivity measurement results to determine the soil resistivity risk weight. This is the first weight number (1-10).

(b) Step 2: Using Table 2, determine the Drainage Risk Weight. This is the second weight number (1- 4)

(c) Step 3: Using Table 2, determine the Material Risk Weight. This is the third weight number (0.5- 2)

(d) Step 4: Using Table 2, determine the Cathodic Protection/Coating Risk Weight by considering the condition of both cathodic protection and coating. This is the fourth weight number (0.5- 2).

(e) Step 5: Next, multiply together all weights from steps 1 thru 4 to determine the final Corrosion Risk Assessment number (0.25 - 160).

[3] The data generated in sections 5.4 and 5.5 shall be input in Attachment 9.4 and included in the Program.

[4] The Program Owner shall develop a long term inspection plan and input the schedule into Attachment 9.5 after completion of the impact assessment (Table 1),

corrosion risk tabulation (Table 3) and inspection interval (Table 4). The inspection plan shall include a representative sampling of each section or tank within each of the High, Medium and Low inspection priorities in Table 4.

[5] The determination of the inspection locations may also consider:

0 Ease of access to inspection point, especially for buried locations, 0 Ability to insert/withdraw inspection tool(s) and/or "pigs",

• Limitations of inspection tools to navigate bends and elbows in piping, and, Ability to isolate section of piping/tank or to place piping/tank in an out-of-service condition.

Enrgy J NUCLEAR MANAGEMENT MANUAL QUALITY RELATED INFORMATIONAL USE EN-DC-343 PAGE REV.0 11 OF 34 Buried Piping and Tanks Inspection and Monitoring Program

[6] The determination of inspection points should consider the results of previous inspections. Prioritization of the inspections should be based on severity of the condition, risk implications, and whether an immediate repair would be required.

Following any inspection, the as-found conditions shall be applied to the, prioritization standards and determination made of next re-inspection requirement.

Table 2 Corrosion Risk Assessment Soil Resistivity Risk Soil Resistivity, 1"-cm (Note 1) Corrosivity Rating Weight

>20,000 Essentially Non-corrosive 1 10,001-20,000 Mildly Corrosive 2 5,001-10,000 Moderately Corrosive 4 3,001-5,000 Corrosive 5 1,000-3,000 Highly Corrosive 8

<1,000 Extremely Corrosive 10 Drainage Drainage Risk Weight Poor Continually Wet 4.0 Fair Generally Moist 2.0 Good Generally Dry 1.0 Material (Note 2) Material Risk Weight Carbon and Low Alloy Steel 2.0 Cast and Ductile Iron 1.5 Stainless Steel 1.5 Copper Alloys 1.0 Concrete 0.5 Cathodic Protection Coating CP/Coating Risk Weight No CP No Coating 2.0 No CP Degraded Coating 2.0 No CP Sound Coating 1.0 Degraded CP No Coating 1.0 Degraded CP Degraded Coating 1.0 Degraded CP Sound Coating 0.5 Sound CP No Coating 0.5 Sound CP Degraded Coating 0.5 Sound CP Sound Coating 0.5 Notes:

1. Soil resistivity measurements must be taken at least once per 10 years unless areas are excavated and backfilled or if soil conditions are known to have changed for any reason.

2. Attachment 9,6 gives further insight to the corrosion of materials in soils.

Table 3 Corrosion Risk Tabulation Corrosion Condition Risk Weight Points Soil Conditions Resistivity step 5.5 [2] (a) 1-10 Drainage step 5.5 [2] (b) 1-4 Materials Materials step 5.5 [2] (c) 0.5 -2 Component Protection Cathodic Protection/Coating step 5.5 [2] (d) 0.5 -2 Final Corrosion Risk Tabulation Multiply all weights together in steps 5.5 [2] (a) thru (d) 0.25 -160 High Corrosion Risk,61-160 pts Medium Corrosion Risk, 30-60 pts Low Corrosion Risk, 0-29 pts

Table 4 Inspection Intervals vs. Inspection Priority Impact-Corrosion Inspection Priority Initial Inspection Inspection Interval Risk (years) (years)

High-High High 5 8 High-Medium High 5 8 Medium-High High 5 8 High-Low Medium 8 10 Medium-Medium Medium 8 10 Low-High Medium 8 10 Medium-Low Low 10 15 Low-Medium Low 10 15 Low-Low Low 10 15 Notes:

1. High priority initial inspections shall be scheduled within 5 years. Subsequent High priority inspections shall be scheduled within 8 years.

2. Medium priority initial inspections shall be scheduled within 8 years. Subsequent Medium priority inspections shall be scheduled within 10 years thereafter.

3. Low priority initial inspections shall be scheduled within 10 years. Subsequent Low priority inspections shall be scheduled for all components within 15 years thereafter.

4. Regardless of the inspection schedule in Table 4 each plant site must ensure it complies with the commitments in License Renewal Application (LRA).

5. Once initial inspections are performed and conditions become known, a re-prioritization may maintain, decrease or increase a component future inspection priority.

5.6 Parameters to be Inspected 0 External coating and wrapping condition Pipe wall thickness degradation 0

Tank plate thickness degradation Cathodic Protection System Performance (if applicable) 5.7 Acceptance Criteria Acceptance criteria for any degradation of external coating, wrapping and pipe wail or tank plate thickness should be based on current plant procedures. If not covered by plant

procedures, new acceptance criteria should be developed based on applicable code and industry requirements. Acceptance criteria shall be developed prior to performing inspections.

5.8 Corrective Actions A Condition Report (CR) shall be written if acceptance criteria are not met. The corrective actions may include engineering evaluations, scheduled inspections, and change of coating or replacement of corrosion susceptible components. Components that do not meet the acceptance criteria shall be dispositioned by engineering.

5.9 Preventive Actions Newly installed piping and tanks should be coated as applicable during installation with a protective coating system, such as coal tar enamel with fiberglass wrap and a Kraft paper outer wrap, a polyolefin tape coating, or a fusion bonded epoxy coating to protect the piping and tanks from contacting the aggressive soil environment. As part of preventive measures, the existing Cathodic Protection system may be updated or a new Cathodic Protection system may be installed.

For plants with installed Cathodic Protection systems for buried piping and tanks, verify Preventive Maintenance tasks exist to verify proper operation of these systems at least semi-annually. Verify corrective maintenance tasks for CP system identified deficiencies are corrected on a schedule commensurate with the safety significance of the system/component being protected.

° CP System degradation affecting Safety Related SSC, recommended repair within the Work Week T process

• CP System degradation affecting Non-Safety Related SSC, recommended for repair within 6 months of identification.

5.10 Monitoring, Trending and Frequency of Inspections The Program Owner shall prepare and implement a long-term inspection plan per Table 4 and Attachment 9.5.

5.11 Administrative Controls

[1] This procedure dictates how to develop the Program, what design information must be obtained, how to evaluate the overall scope and inspection frequency and the format for the Program.

[2] The Program Owner shall develop the Program per EN-DC-174 and the template in Attachment 9.7 of this procedure. The Program (which is actually a site engineering procedure (SEP) program section number) shall use the nomenclature of SEP-CBT-XXX where the site will assign a unique number for XXX. The Program includes all

the site specific references, commitments, scope of program and long term inspection plan with tables in Attachment 9.4 and 9.5 filled in for each buried section.

[3] The Program Owner shall document all inspection results, associated data, inspection testing and analysis results and any engineering evaluations performed, in an Engineering Report per EN-DC-147. The Program Owner shall maintain the record of all inspection results in an Engineering Report.

5.12 Inspection Methods and Technologies/Techniques

[1] Visual Inspection Buried piping and tanks: Visually inspect the "as-found" conditions and document as necessary. Personnel performing inspections shall be qualified as applicable per ANSI/ANS 3.1-1978, "Selection and Training of Nuclear Power Plant Personnel" or equivalent. Pictures should be taken to visually compare with the previous inspections.

These picture files are to be maintained for future reference in a Program notebook.

(a) Any time a buried section is opened or removed; it should be examined to quantify deposit accumulation, corrosion mode and localized wall loss and those results documented.

(b) Perform general visual inspection of exterior surface coatings for cracking, peeling, blistering, holidays (pinholes) or other coating failures. Look for signs of damaged coatings or wrapping defects such as coating perforation, holidays, or other damage that indicates possible corrosion damage to the external surface of the piping.

(c) The interior of piping may be examined using divers, remote cameras, robots or moles when appropriate.

(d) Use holiday tester to check excavated areas of piping for coating defects.

(e) If the visual inspection shows that the coatings or wrappings are intact, no further inspection is required. However, if any evidence of coating/wrapping damage is observed or if the component is uncoated, the components will be further inspected for evidence of degradation/loss of material due to corrosion (e.g., crevice, general, MIC, and pitting corrosion) and determination made as to repair.

(f) Inspect inaccessible below-grade concrete for indications of cracking, loss of material,. and change in material properties (rust discoloration or white chalky deposits).

(g) A CR shall be initiated if the acceptance criteria are not met.

[2] Non-Destructive Testing (NDT)

There are several NDT methods that are applicable to buried piping inspections.

These are:

(a) Ultrasonic Testing (UT) - Automatic Scanning: Automated Scanning UT measures thickness variations in the scanned area for reliable wall loss sampling.

(b) Electromagnetic (ET) - Automated Scanning: This technique provides a "map" of thickness variations in the scanned area of the piping.

(c) Radiographic Testing (RT): This involves creating an image by use of x-rays or gamma-rays. The image is recorded on film or viewed on a monitor.

(d) Torsional Guided Wave: The torsional guided wave (T-wave, G-scan) technique is a non-destructive technique performing a volumetric inspection, suitable for use on buried piping.

(e) Ultrasonic C-Scan: The UT C-scan is used to detect and locate anomalies in the external coating of a buried pipe. Anomalies as small as 1 sq. mm are detectable.

(f) Instant Off Close Interval Survey - monitors for proper operation and coverage of Cathodic Protection Systems (g) Direct Current Voltage Gradient - indirect monitoring of pipeline for degradation to external pipe wrap/coatings similar to C-Scan.

(h) Pressure Testing - direct method of monitoring an isolable section of piping for the presence of active leakage.

(i) Leak Testing (LT) - A method for detection, locating, and measuring leakage.

LT includes but is not limited to pressure testing, vacuum testing, and tracer gas detection (ASME Section V).

6.0 INTERFACES

[1] Entergy Quality Assurance Program Manual (QAPM)

[2] Engineering Standard PS-S-001 "Localized Pipe Wall Thinning and Crack-Like Flaw Evaluation"

[3] Engineering Standard ENN-CS-S-008 "Piping Wall Thinning Structural Evaluation"

[4] CEP-NDE-0112, "Certification of Visual Examination Personnel"

[5] EN-AD-1 03, "Document Control and Record Management Activities"

[6] EN-DC-1 15, "Engineering Change Development"

[7] EN-DC-141, "Design Inputs"

[8] EN-DC-147, "Engineering Reports"

[9] EN-DC-1 67, "Classification of Systems Structures and Components"

[10] EN-DC-174, "Engineering Program Sections"

[11] EN-TQ-1 04, "Engineering Support Personnel Training"

[12] EN-QV-1 11, "Training and Certification of InspectionNerification and Examination Personnel"

[13] EN-NDE-2.12, "Certification of Visual Testing (VT) Personnel"

[14] EN-WM-101, "On-Line Work Management Process" 7.0 RECORDS

[1] All data generated during the course of buried piping and tanks inspections should be referenced or retained by the Program Owner in the program notebooks. Follow applicable QA retention requirements.

[2] Records and reports generated as a result of the periodic inspections shall be retained and maintained in accordance with EN-AD-1 03 and as directed in the site Program, as applicable.

[3] Changes to the Program based on the periodic review shall be performed in accordance with EN-DC-174, Engineering Program Sections.

8.0 OBLIGATIONS AND COMMITMENTS IMPLEMENTED BY THE PROCEDURE 8.1 OBLIGATIONS AND COMMITMENTS IMPLEMENTED OVERALL Step Document Commitment Number 5.2[2] NUREG-1801, none All NUMARC 93-01 none 5.2[3] NEI 95-10 none 5.2[3] NEI 07-07 none 8.2 SECTION/STEP SPECIFIC OBLIGATIONS AND COMMITMENTS Step Document Document Section/Step I Commitment Number 5.2[21 NUREG-1801 XI.M34 none

eMAMNUCLEAR QUALITY RELATED EN-DC-343 REV. 0

• Enterg MANAGEMENT MANUAL INOMTNAUS INFORMATIONAL USE PAGE 18 OF 34 Buried Piping and Tanks Inspection and Monitoring Program 8.3 SITE SPECIFIC COMMITMENTS Step Site Document I Commitment Number or Reference 9.0 ATTACHMENTS 9.1 XI.M34 Buried Piping and Tanks Inspection 9.2 Roadmap for Buried Piping and Tanks Inspection and Monitoring Program 9.3 List of Affected Buried Piping Systems as per License Renewal Application 9.4 Sample Data Table 9.5 Sample Long Term Inspection Plan 9.6 Corrosion of Materials in Soils 9.7 Buried Piping and Tanks Inspection Program Section Template

ATTACHMENT 9.1 XI.M34 BURIED PIPING AND TANKS INSPECTION Sheet I of 2 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 element/attributes of detection of aging effects (regarding inspection frequency) and operating experience.

Evaluation and Technical Basis

1. 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 polyolifin tape coating, or a fusion bonded epoxy coating to protect the piping from contacting the aggressive soil environment.

3. ParametersMonitored/Inspected: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 X1M-1 11 NUREG-1801. Rev. I

ATTACHMENT 9.1 XI.M34 BURIED PIPING AND TANKS INSPECTION Sheet 2 of 2 The applicant's program is to be evaluated forthe 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. CorrectiveActions: 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.

9. Administrative Controls: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 Ctiferia for Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NUREG-1801, Rev. 2 Xi M-1 12 September 2005

ATTACHMENT 9.2 ROADMAP FOR BURIED PIPING AND TANKS INSPECTION AND MONITORING PROGRAM Sheet 1 of I Program Owner develop site specific response (10 attributes of XI.M34) for all Buried Piping Systems Structure and Components and include in a site Program section per Attachment 9.7 Program Owner develop list of all uried Piping Systems, Structure and Components (SSC)

Program Owner perform Impact Assessment per Table 1 Program Owner prepare Corrosion Risk Assessment and Tabulation per Tables 2 and 3 Program Owner input all data from Tables 1 through 4 into Attachment 9.4 Program Owner prepare and implement a long term inspection plan per Table 4 and Attachment 9.5 Program Owner ensure inspections performed per Table 4 Rank and Re-priodtize for future inspections Program Owner prepare and implement a re-inspection plan per Table 4

ATTACHMENT 9.3 LIST OF AFFECTED BURIED PIPING SYSTEMS AS PER LRA Sheet I of 2 Station teSystem ANO Unit 2 Service Water System Unit 2 Service Water System The plant's Joint Fire Protection Loop Fuel Oil GGNS TBD IPEC City Water Containment Spray Fire Protection - Water System Fuel Oil Plant Drains Safety Injection Security Generator Service Water JAF Condensate Storage Fire Protection - Water System Fuel Oil HPCI RCIC Radwaste and Plant Drains Security Generator Standby Gas Treatment PNPS Condensate Storage Fire Protection - Water System Fuel Oil Salt Service Water Standby Gas Treatment Station Blackout DG-.....

ATTACHMENT 9.3 LIST OF AFFECTED BURIED PIPING SYSTEMS AS PER LRA Sheet 2 of 2 Station PLP/BRP Condensate System Demineralized Water System Diesel Fuel Oil System Feedwater System Fire Protection System Miscellaneous Gas System Service Water System RBS TBD VY Fire Protection - Water System Fuel Oil Service Water

___Standby Gas Treatment W3 TBD

ATTACHMENT 9.4 SAMPLE DATA TABLE Sheet I of I System X Section # X-01 X-02 X-03 Drawing IP2-YY Material CDI O.D. (inches) 10 Schedule 40 Nominal Thickness (inches) 0.365 Cathodic Protection (N, D, S) N Coating Type (N, D, S) N Safety Class (H, M, L) H Public Risk (H, M, L) L Economics (H, M, L) L Overall Impact (H, M, L) H Soil Resisitivity 999 Soil Resisitivity Risk Weight 10 Drainage (P, F, G) P Drainage Risk Weight (4.0, 2.0, 1.0) 4 Drainage Risk Weight 4 Material Carbon and Low Alloy Steel (CS) FALSE Cast and Ductile Iron (CDI) 1.5 Stainless Steel (SS) FALSE Copper Alloy (Cu) FALSE Concrete (CO) FALSE Material Risk Weight 1.5 _

Cathodic Protection/Coating No CP, No Coating (N, N) 2 No CP, Degraded Coating (N, D) FALSE No CP, Sound Coating (N, S) FALSE Degraded CP, No Coating (D, N) FALSE Degraded CP, Degraded Coating (D, D) FALSE Degraded CP, Sound Coating (D, S) FALSE Sound CP, No Coating (S, N) FALSE Sound CP, Degraded Coating (S, D) FALSE Sound CP, Sound Coating (S, S) FALSE rPlrnnfinn RPik W~irihf 9 H = High, M = Medium, L=Low, P=Poor, F=Fair, G=Good, S=Sound, D=Degraded, N=None

ATTACHMENT 9.5 SAMPLE LONG TERM INSPECTION PLAN Sheet 1 of I Long Term Inspection Plan System Section Line Impact Corrosion Inspection Required Actual Required Actual Notes

1. # Risk Priority Initial Initial Re- Re-Inspection Inspection Inspection Inspection Date Date Date Date H H H H M H M H H H L M M M M L H M M L L L M L L L L Put this table in order of impact and corrosion risk and inspection priority as shown above so all the systems with sections rated H-H are first and H-M second etc.

ATTACHMENT 9.6 CORROSION OF MATERIALS IN SOILS Sheet I of 3 Corrosion of Materials in Soils The corrosion of metals in soils can be divided into two broad categories: corrosion in undisturbed soils and corrosion in disturbed soils. Corrosion in undisturbed soils is always low, regardless of soil conditions, and is limited only by the availability of the oxygen necessary for the cathodic reaction.

Corrosion of metals in disturbed soils is strongly affected by soil conditions, electrical resistivity, mineral composition, dissolved salts, moisture content, total acidity or alkalinity (pH), redox potentials, microbiological activity, and concentration of oxygen. Any metal buried by backfilling is in a disturbed soil and is subject to corrosion attack, depending on the characteristics of the soil, Reference 12, page 497.

The supply of oxygen is comparatively large above the groundwater table but is considerably less below it and is influenced by the type of soil. It is high in sand but low in clay. The different aeration characteristics may lead to significant corrosion problems due to the creation of oxygen concentration cells, Reference 13, page 8.

Cast and Ductile Irons Neither metal-matrix nor graphite morphology has an important influence on the corrosion of cast irons in soil. Corrosion of cast irons in soils is a function of soil porosity, drainage and dissolved constituents in the soil. Irregular soil contact can cause pitting, and poor drainage increases corrosion rates substantially above the rates in well-drained soils, Reference 13, page 48.

Carbon and Low-Alloy Steels The corrosion rate of carbon and low alloy steels in soil depends primarily on the nature of the soil and certain other environmental factors, such as the availability of moisture and oxygen. The water content, together with the oxygen and carbon dioxide contents are major corrosion-determining factors. The redox potential in the soil becomes nobler with the increase of oxygen concentration in the soil.

In the pH range of 5 to 8, factors other than pH have greater influence on the corrosion of steel. The risk of localized corrosion (pitting) is high if the soil resistivity is lower than 1000 ohm-cm.

Sulfate-reducing bacteria, which occur under anaerobic conditions such as in deep soil layers, form iron sulfide as a corrosion product. Anaerobic bacterial corrosion is more serious

NUCLEAR QUALITY RELATED EN-DC-343 REV. 0 Enter*y MANAGEMENT.

MANUAL INFORMATIONAL USE PAGE *27 OF 34 Buried Piping and Tanks Inspection and Monitoring Progiam ATTACHMENT 9.6 CORROSION OF MATERIALS IN SOILS Sheet 2 of 3 when it is combined with a differential aeration cell, in which the anaerobic cell works as a local anode.

Steel buried in the ground provides a better electrical conductor than the soil for stray return currents from electrical systems such as electrical grounding equipment and cathodic protection systems on nearby buried metal. Accelerating corrosion occurs at the point where the current leaves the steel to the earth, Reference 13, pages 8-9.

Stainless Steels Generally, buried stainless steels suffer from soil corrosion because of one or more of the following conditions: high moisture content, pH less than 4.5, resistivity less than 1000 ohm-cm, presence of chlorides (> 500ppm), sulfides and bacteria and the presence of stray currents.

Oxygen takes part in the cathodic reaction and a supply of oxygen is therefore, in most circumstances, a prerequisite for corrosion in soil. The supply of oxygen changes with the type of soil and the different oxygen levels may lead to corrosion problems due to the creation of oxygen concentration cells. The oxygen concentration of the soil moisture generally will determine its redox potential. The higher the oxygen content Ithe higher the redox potential. However, low redox values may provide an indication that conditions are conducive to anaerobic microbiological activity.

Another of the most important conditions for corrosion to occur is the chloride ion (CI-)

concentration in the soil and the moisture, which can contain different dissolved species such as sulfate ions (S042) and some others e.g.: H', HC0 3 , etc., Reference 14.

Copper Alloys Copper exhibits high resistance to corrosion by most soils. National Bureau of Standards (NBS) study results indicate that tough pitch coppers, deoxidized coppers, silicon bronzes and low-zinc brasses behave essentially alike. The corrosion rate of copper in quiescent groundwater tends to decrease with time due to the formation of a protective film in which the underlying layer consists of species from the groundwater as well as copper.

For copper and copper alloys, corrosion rate depends strongly on the amount of dissolved oxygen present; deoxygenation results in ground water tests show at least an order of magnitude decrease in the short-term corrosion rate. In aerated solutions,, the addition of nickel (90 Cu-10 Ni) decreases the uniform corrosion rate of copper by the formation of a more highly protective surface film.

ATTACHMENT 9.6 CORROSION OF MATERIALS INSOILS Sheet 3 of 3 Soils containing high concentrations of sulfides, chlorides, of hydrogen ions (H+) corrode these materials. Where local soil conditions are unusually corrosive, it may be necessary to use some means of protection, such as cathodic protection, neutralizing backfill (limestone, for example), protective coating or wrapping, Reference 13, pages 132 to 138.

Titanium Alloys There are no indications in the literature that titanium alloys are susceptible to corrosion in soils; however, some reference to the corrosion resistance of titanium alloys in waters that would be present in soils is beneficial to this understanding.

"Titanium and its alloys are fully resistant to water, all natural waters, and steam to temperatures in excess of 600 0 F. Titanium alloys exhibit negligible corrosion rates in seawater to temperatures as high as 500°F' Pitting and crevice corrosion will not occur in ambient seawater, even if marine deposits form and biofouling occurs." (Reference 13, page 260).

"Crevice attack of titanium alloys will generally not occur below a temperature of 160°F regardless of solution pH or chloride concentration or when solution pH exceeds 10 regardless of temperature." (Reference 13, page 268).

ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet I of 6 PROGRAM SECTION for Buried Piping and Tanks Inspection and Monitoring ENTERGY NUCLEAR ENGINEERING PROGRAMS APPLICABLE SITES All Sites: [

Specific Sites: ANO F1 BRP [1 GGNS E IPEC [I JAF PLP E PNPS ] RBS E VYEl W3 [E Safety Related: El Yes Z No APPLICABLE SITES for Dry Fuel Storage (72.48 Review)

All Sites: El Specific Sites: ANO E] GGNS M IPEC E] JAF [] PNPS [] RBS E] VY E] W3 E]

Continuous Use 0 Reference Use E] Informational Use 0

ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet 2 of 6 REVIEW AND CONCURRENCE SHEET Program Section No.:

Revision No.:

Program Section

Title:

Prepared By: Date:

Checked By: Date:

ANII Date:

Reviewed By (or N/A)

Concurred: Date:

Responsible Supervisor

ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet 3 of 6 REVISION STATUS SHEET Program Section No.:

Page No.:

Revision No.:

PROGRAM SECTION REVISION

SUMMARY

REVISION DESCRIPTION OF CHANGES

ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet 4 of 6 TABLE OF CONTENTS Section Title Paqe 1.0 PURPOSE ....................................................................................... 5

2.0 REFERENCES

................................................................................ 5 3.0 DEFINITIONS ................................................................................... 5 4.0 RESPONSIBILITIES ........................................................................ 5 5.0 DETAILS ....................................................................................... 5 6.0 INTERFACES ................................................................................... 6 7.0 RECORDS ........................................................................................ 6 8.0 OBLIGATIONS AND COMMITMENTS ............................................ 6 9.0 ATTACHMENTS ................................................................................ 6

ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet 5 of 6 1.0 PURPOSE

[1] This Program section (referred to as the Program) provides the scope for the site specific Buried Piping and Tank Inspection and Monitoring Program. The Program contains all the evaluations used to develop the scope, impact evaluation, corrosion risk and the long term inspection plan per EN-DC-343.

2.0 REFERENCES

[1] Don't need to repeat all the references in EN-DC-343 except for the ones applicable to the specific site or site commitments and others such as procedures, reports, etc.

that are not already in EN-DC-343 3.0 DEFINITIONS

[1] Only add definitions that specifically apply for this Program. If using any definitions from EN-DC-343 they shall be verbatim from the procedure.

4.0 RESPONSIBILITIES

[1] Program Owner is responsible for preparation and maintenance of the site Program.

[2] Program Owner is responsible for obtaining outside inspection services as needed for the inspection activities.

[3] Maintenance is responsible for excavating as needed to support inspection activities.

5.0 DETAILS 5.1 Precautions and Limitations Insert any specific precautions and limitations necessary at the site for this Program, can draw upon those already in EN-DC-343 5.2 Scope of Program The buried piping and tank program developed shall include, as a minimum, piping and tanks described in sections 5.2. [1] through 5.2. [3] of EN-DC-343.

SNUCLEAR QUALITY RELATED EN-DC-343 REV. 0

-*Enterrgyv MANAGEMENT MANUAL INFORMATIONAL USE PAGE 34 OF 34 Buried Piping and Tanks Inspection and Monitoring Program ATTACHMENT 9.7 BURIED PIPING AND TANKS INSPECTION PROGRAM SECTION TEMPLATE Sheet 6 of 6 5.3 Program Summary The design information, impact evaluation and corrosion risk from Tables 1-4 and long term inspection plan in EN-DC-343 shall be input into Attachments 9.4 and 9.5 of EN-DC-343 and included in section 9.0 "Attachments" of the Program section.

6.0 INTERFACES

[1] EN-DC-147, "Engineering Reports" 7.0 RECORDS Design records consist of Attachments 9.4 and 9.5 in EN-DC-343 and inspection records shall be documented in accordance with EN-AD-1 03 "Document Control and Records Management Activities".

8.0 OBLIGATIONS AND COMMITMENTS Insert site specific Program section Obligations and Commitments as applicable 9.0 ATTACHMENTS Attach tables from Attachment 9.4 and 9.5 from EN-DC-343 as information is completed.

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION Before the Atomic Safety and Licensing Board In the Matter of )

)

Entergy Nuclear Generation Company and ) Docket No. 50-293-LR Entergy Nuclear Operations, Inc. ) ASLBP No. 06-848-02-LR

)

(Pilgrim Nuclear Power Station) )

CERTIFICATE OF SERVICE I hereby certify that copies of "Testimony of Alan Cox, Brian Sullivan, Steve Woods, and William Spataro 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," Declarations of Steven P. Woods, Alan B. Cox1 , Brian R. Sullivan and William H. Spataro In Support Of Entergy's Pre-Filed Testimony On Pilgrim Watch Contention 1," Entergy Exhibits to Testimony of Alan Cox, Brian Sullivan, Steve Woods and William Spataro 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,"

and Entergy's Initial Statement of Position on Pilgrim Watch Contention 1," were served on the persons listed below by deposit in the U.S. Mail, first class, postage prepaid, and where indicated by an asterisk by electronic mail, this 8 th day of January, 2008.

Alan Cox was unable to execute his declaration because he was on travel. An executed copy of his declaration will be provided later.

400698281vl

• Administrative Judge *Administrative Judge Ann Marshall Young, Esq., Chair Dr. Richard F. Cole Atomic Safety and Licensing Board Atomic Safety and Licensing Board Mail Stop T-3 F23 Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, D.C. 20555-0001 amy@nrc.gov rfc 1@nrc.gov

• Administrative Judge *Secretary Paul B. Abramson Att'n: Rulemakings and Adjudications Staff Atomic Safety and Licensing Board Mail Stop 0-16 C I Mail Stop T-3 F23 U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, D.C. 20555-0001 secy(ý,nrc.gov; hearingdocket(anrc.gov pba(anrc.gov Office of Commission Appellate Atomic Safety and Licensing Board Adjudication Mail Stop T-3 F23 Mail Stop 0-16 C I U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Washington, D.C. 20555-0001

• Susan L. Uttal, Esq. *Mr. Mark D. Sylvia

• Kimberly A. Sexton, Esq. Town Manager

• James E. Adler, Esq. Town of Plymouth Office of the General Counsel 11 Lincoln St.

Mail Stop 0- 15 D21 Plymouth MA, 02360 U.S. Nuclear Regulatory Commission msvlvia(*townhall.nlvmouth.ma.us Washington, D.C. 20555-0001 slu@nrc.gov; KAS2@nrc.gov:

JEA 1@nrc. gov

• Ms. Mary Lampert *Chief Kevin M. Nord 148 Washington Street Fire Chief and Director, Duxbury Emergency Duxbury, MA 02332 Management Agency mary.lampert@comcast.net 688 Tremont Street P.O. Box 2824 Duxbury, MA 02331 nord@town.duxbury.ma.us 400698281vl

• Sheila Slocum Hollis, Esq. *Richard R. MacDonald Duane Morris LLP Town Manager 1667 K Street, N.W. 878 Tremont Street Suite 700 Duxbury, MA 02332 Washington, D.C. 20006 macdonald@town.duxbury.ma.us sshollis(aduanemorris.com Paul A. Gaukler 400698281vi