ML080930528

2008/03/24-Pilgrim Watch Motion to Permit Late Filled Exhibits

ML080930528
Person / Time
Site:	Pilgrim
Issue date:	03/24/2008
From:	Lampert M Pilgrim Watch
To:	Atomic Safety and Licensing Board Panel
SECY RAS
References
LR-50-293, RAS J-20
Download: ML080930528 (103)

Text

DOCKETED USNRC UNITED STATES OFP AMERICA NUCLEAR REGULATORY COMMISSION March 24, 2008 (4:17pm)BEFORE THE ATOMIC SAFETY AND LICENSING BOARDOFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF In the matter of Docket # 50-293 Entergy Corporation Pilgrim Nuclear Power Station License Renewal Application March 24, 2008 PILGRIM WATCH MOTION TO PERMIT LATE FILLED EXHIBITS Pilgrim Watch hereby submits a motion to permit late filed exhibits.Pursuant to § 2.1207(a)

(1) Process and Schedule for Submissions and Presentations in an Oral Hearing, Pilgrim Watch presented Initial Written Statements of Position and Written Testimony with supporting affidavits on the admitted contention, January 29, 2008. It became apparent to the ASLB that Pilgrim Watch, acting without counsel, was not clear concerning the process.Confusion about the process remains on two issues that underlie the reasons for our request to file late exhibits.First, we had interpreted 2.1207, (b) (2) Oral hearing Procedures, "Written Testimony will be received into evidence in exhibit form" to mean that 'the written testimony and Exhibits would be presented to the board at the Oral Hearing itself as an addition to that presented on January 29, 2008 under 2.1207(a)

(1), described as "Initial Testimony." We interpreted "initial" literally as meaning first or preliminary, not final.Second, we understood, or misunderstood, that any Disclosures produced by Entergy, or any party, during the proceedings would be automatically part of the record and could be used during the hearing and presented as exhibits at the oral hearing scheduled for April 10, 2008.We understand at this late date that our interpretation may be incorrect.

If so, we thank you for your tolerance and request permission to file additional exhibits at this time.TP1 All the Exhibits that we request to file are from Entergy's Disclosures; and being so, there is no prejudice to Entergy since they are their own documents.

Additionally they should not prejudice NRC Staff or any other party because they were provided to the Service List during the course of these proceedings.

We believe that these additional exhibits will assist the board to better understand the issue and are necessary in order to make the best and fairest decision.

A brief summary of the disclosures demonstrates their value. They are attached in Exhibit form.Summary of Disclosures Requested To File 1. Disclosures describing the buried piping under consideration

-description components, corrosion mechanisms, operating experience, aging management.

a) Stand by Gas Treatment System: Exhibit 27, PILLR00000583:

Aging Management Review SGTS 04/19/05 "The internal surface of the buried pipe may be wetted by condensation since the ground temperature may be lower that the dew point of the air. Therefore loss of material from general, pitting, crevice corrosion and MIC is an aging effect requiring management..." Exhibit 28, PILLR00000586:

Aging Management Review SGTS [Draft E 10/07/05]

same comment above, "The internal surface of the buried pipe may be wetted by condensation since the ground temperature may be lower that the dew point of the air. Therefore loss of material from general, pitting, crevice corrosion and MIC is an aging effect requiring management..." Exhibit 29, PILLROO003609:

Email to Ted Ivy from Andrew Taylor 04/18/05"...due to the cooling effect of the soil through which the underground piping passes. Therefore this section of piping would be a "worst case" for loss of material which would not be bounded by the effects detectable by an external system walk-down at other places in the system." 2 Exhibit 30, PILLR000000633, 639, 641, 642, 643,649, 650: Verification of PNPS License Review Project, Aging Management Review of the Standby Gas treatment System.b) Condensate Storage System Piping: Exhibit 31, PILLR00003278:

LRA Technical Information (10/06/05)

Buried Piping Inspection

-hand written note "We will be using new phased UT Technology on the HPCI/RCIC piping from the CST. Alternate inspection method" Exhibit 32, PILLR00003225

& 3228, Pilgrim NPS License Renewal Project Aging Management Review of CSS -describes component (stainless steel), aging effects and management plan.c) Salt Water Service Piping Description Exhibit 33, PILLRO0000939:

'Some carbon steel is ...below ground." Exhibit 34, PILLRO0000940: "Components underground

... and continuously wetted may be protected by a coating. Since the coating does not have a specified life, aging effects are evaluated as if the carbon steel was not coated." [And] "Titanium piping...used in sections of SSW system." Condition Reports: Exhibit 35, PILLR00044657

&44658 Condition Report test pieces west end CIPP liner at"A" SSW discharge line thickness measurements below minimum requirement.

04/28/03 Exhibit 36, PILLR00045284:

SSW patch near MO-3805 spraying water through pinhole leak (02/26/99)

Exhibit 37, PILLR00045281:

SSW Pipe Spool JF29-10-8 (2) area found below min wall of 160" per spec. M591 (2/12/99)Exhibit 38, PILLR00045276-severe OD SSW Pipe Corrosion/Pitting on spools of J-29-7-3, 10-6, 10-7 and 10-9 does not permit 10% UT coverage as required (02-11-99) 3 Exhibit 39, PILLR00044661 Condition Report -corrosion on SSW pipe Spool JF29-15-9(P-208D Discharge pipe spool downstream of 29-HO-3817 valve). Visual inspection performed-corrosion appears to be exterior pipe wall only. No pressure boundary leakage observed with 34 psi (pressure observed at PI-3822).

This indicates to Entergy rubber lining still intact and internals not affected.

Exterior corrosion opined as most likely result excessive salt service water pump packing leakage that had been experienced for a periods of time due to pump shaft coating degradation.

Visual inspection also performed remaining SSW pump discharge pipe spools without finding severe corrosion.

CIPP Lining & Description Piping: Exhibit 40, PILLR0046040:

PNPS Specification for Cured in Place (CIPP) Lining For SSW Discharge Piping [02/17/03]

Provides description discharge piping -[3]piping 22" nominal diameter carbon steel pipe, .375 wall thickness with 3/16' natural rubber lining;flange connections rubber-lined Pressure Class 150 flat-faced slip on flanges. [4] Loop A discharge is approximately 240' (total length) with (3) 45 degree elbows and (1) 90 degree long radius elbow. [5] Loop "B" discharge piping is approximately 225 ft (total length t be lined) with (4) 45 degree elbows and (1) 90-degree long radius elbow.Operating Experience:

Exhibit 41, PILLR00003495 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems -CR-PNP-2004-00391-Issue: Item: Salt service water pipe spool JF29-15-9 (P-208D discharge pipe spool downstream of 29-HO-3817 isolation valve is corroded.

Evaluation:

Loss of material due to corrosion is an aging effect identified in the mechanical tools of carbon steel in raw water. Item: System Engineer Interview SSW. Issue: Salt Service water system has experiences wall thinning due to corrosion of piping, pumps, and the channel assemblies on heat exchangers.

Evaluation:

Loss of material due to corrosion is an aging effect identified in the mechanical tools of carbon steel in raw water.Item: System Engineer Interview SSW. Issue: Three on-line wall leaks occurred due to corrosion following loss of rubber lining inside salt service water system pipe spools 4 sections. (Reference CR-98-9143, 98-9392, 01-9397).

Evaluation:

Loss of material due to corrosion is an aging effect identified in the mechanical tools of carbon steel in raw water.Item: System Engineer Interview SSW. Issue: salt water system has experienced external corrosion due to salt-water environment.

Evaluation:

Loss of material due to corrosion is an aging effect identified in the mechanical tools of carbon steel in raw water.Aging Management:

Exhibit 42, PILLRO0000855:

Verification of PNPS License Renewal Project Report Rev.0, (Draft G) 6/20/05. (3.1) Carbon Steel Components:

SSW system includes carbon steel components (including cast iron), the majority of which are rubber lines. For identifying aging effects the liner is not credited with a protective function, aging effects are identified for carbon steel in contact with salt water. Corrosion effects are discussed herein. Components that are underground and continuously wetted may be protected by coating. "Since the coating does not have a specified life, aging effects are evaluated as if the carbon steel were not coated." Loss of material due to general corrosion, pitting corrosion, crevice corrosion, MIC, and galvanic corrosion is an aging effect requiring management.

Loss of material from selective leaching is an aging effects requiring management for gray cast iron components."(3.2)

Titanium Components: "Titanium is inherently resistant to general corrosion, pitting corrosion, crevice corrosion, and erosion in raw water at temperatures less than 160F. However, in raw water, MIC can result in loss of material from titanium.

Therefore, loss of material due to MIC is an aging effect requiring management for internal surfaces." "Loss of material die to MIC from external buried surfaces is an aging effect requiring management." 4.3 BPTIP and 4.4 Service Water Integrity Program provide brief descriptions Exhibit 43, PILLRO0000658:

AMRM- 11 Aging Management Review of the SSW (Draft 11/12/01)(3.1) "The piping that is underground is protected by a coating, but since the coating does not have a specified life, the aging effects will be evaluated for carbon steel." 5 (4.3) Wall thinning inspection program- Since the SSW is required to be seismically qualified, sample inspections are required to verify that the carbon steel pipe and components are maintained with an adequate wall thickness to remain seismically qualified." 2. Three Disclosures Discuss Limitations BPTIP Methodology.

a) Sampling Exhibit 44, PILLR00003618:

Email from Ted Ivy to David Lach (05/16/05), "On the buried piping question we have committed to do an inspection however the scope is not determined.

It may only be one system if the coating of all the in scope piping is the same. We don't plan on inspecting piping in each system unless forced to do so. This really doesn't tell you anything since the pipe next to where you dug up may be degraded and t you will never know it." (Note that they are referring to fire protection piping however the sampling comments have general application to inspection methodology for pipes that we are considering) b) UT Exhibit 45, PILLRO0000293:

Emails between Alan Cox and Ted Ivy (10/19/05)

Re BPTIP -Ted Ivy: "...this technology tells us that there is thinning but it can't tell us what is causing it. The other question I have is has the technology been proven and can it be used for small bore piping such as fuel oil? No one has done this before and we need to be careful." Alan Cox: "I agree that we need to carefully couch this. However it seems that if we find thinning, we must determine what is causing it. If it is not internal corrosion, then we would have to dig it up anyway to determine the cause. This technology may only help you if it can tell you there is unacceptable thinning.

We may be a little too strong in saying that the technology provides indication of wall thickness without excavation.

I think the technology may do this, but it hasn't been effectively demonstrated (or maybe it just hasn't gained general acceptance yet).6 c) Coatings -life expectancy Exhibit 46, PILLR00000295:

Email Ted Ivy to Potts (10/28/06)

-Region Inspection Item 569- "Unfortunately I do not know of any to approach this question unless we could possibly come up with something that shows the coatings installed on the in scope buried components are good for 40 years" such that there is no reason to inspect prior to 40 years. The piping spec M300 doesn't cover coatings." Exhibit 47, PILLR00045431 (11/19/07)

Request: Inquiry Entergy to Tapecoat Company regarding manufacturer's recommended service life for coating and wrapping that has been applied to buried piping in accordance PNPS Specification M306? Response: "The coating product alone does not establish the expected service life of a protective coating system. Additional factors such as surface cleanliness, surface preparation, and severity of service (soil conditions) also play a large role in expected service life. Since the manufacturer does not control applications he does not predict expected service life." 3. Disclosure reviews substandard/counterfeit parts -specifically flanges in buried components.

Exhibit 48, PILLRO0005493(10/09/1988);

NRC Bulletin 88-05 and Supplements 1&2: Nonconforming materials Supplied by Piping Supplies, Inc at Folsom, NJ and West New Jersey Manufacturing Company at Williamstown, NJ. BECO's response to NRC Bulletin to review records; identify questionable materials supplied by two companies; and test and evaluate materials to determine compliance code. Fifty-two located in the plant- all installed found by BECO to be acceptable, except one. Fifty-five flanges, known to have been ordered and received, need to be located. All installed flanges tested fell into acceptance range -six inaccessible for in situ testing -four 22" flanges in a buried section of SSW piping "B" loop), page 11. Those were determined by BECO to be acceptable, at 12.4. Disclosure Radioactive Contaminants in systems.Exhibit 49, PILLROO004199:

Email from Chan (06/06/06) 7

[1] "Confirm that you test the following systems for radioactivity contamination:

SGTS (Sejkora):

discharges only air (no liquids) to main stack -analyzes only gamma emitters no tritium. SSW (Smalley):

daily grab samples-analyzed only gamma-no tritium.(Loomis):

CST water analyzed monthly for gamma emitters.

Tritium not routinely done..." 5. Ground Water Testing Exhibit 50, PILLR00045349 SAIC Engineering Report (01/05/06) results analysis groundwater sample MW-4 on October 27, 2005 -monitoring well that had been installed to monitor oil leak, now claimed to be the control well in new 4-well NEI monitoring initiative.

Exhibit 51, PILLR00045343 SAIC Engineering Report (07/17/06) results analysis groundwater sample MW-4 on June 13, 2006 -monitoring well that had been installed to monitor oil leak, now claimed to be the control well in new 4-well NEI monitoring initiative.

6. Chemistry Control Condition Reports, Exhibit 52 PILLROOO45108;45112;45116;45432;45431

44867;44883

44897;44981

45043 ;45055;45095;44871;44886;44900;44985;45046;45058;44875;44889;44904;44991;45034;45049; 45063; 44938 The 21 CCR examples are a sample, not exhaustive list. The majority did not require"operability" or "reportability." However they evidence problems with the water chemistry program that Entergy points to as a method to prevent corrosion.

Also included is a PNPS Chemistry Corporate Assessment (01/12/04) highlighting areas of needed improvement and actual and potential consequences problems identified.

Thank you in advance for your tolerance and consideration, Mary lampert Pilgrim Watch, pro se, 148 Washington Street, Duxbury, MA 02332 8 ATTACHMENT EXHIBITS REQUESTED TO LATE FILE EXHIBITS No. 27- 52 C 9 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the matter of Docket # 50-293-LR Entergy Corporation Pilgrim Nuclear Power Station License Renewal Application March 24, 2008 CERTIFICATE OF SERVICE I hereby certify that the following was served March 24, 2008 by electronic mail and by U.S. Mail, First Class to the Service List: Pilgrim Watch Motion to Permit Late Filled Exhibits Administrative Judge Ann Marshall Young, Chair Atomic Safety and Licensing Board Mail Stop -T-3 F23 US NRC Washington, DC 20555-0001 Administrative Judge Paul B. Abramson Atomic Safety and Licensing Board Mail Stop T-3 F23 US NRC Washington, DC 20555-0001 Administrative Judge Richard F. Cole Atomic Safety and Licensing Board Mail Stop -T-3-F23 US NRC Washington, DC 20555-0001 Secretary of the Commission Attn: Rulemakings and Adjudications Staff Mail Stop 0-16 C l United States Nuclear Regulatory Commission

[Two Copies]Office of Commission Appellate Adjudication Mail Stop 0-16 C1 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Atomic Safety and Licensing Board Mail Stop T-3 F23 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Susan L. Uttal, Esq.Kimberly Sexton, Esq.James Adler, Esq.David Roth,Esq.Office of General Counsel Mail Stop -O- 15 D21 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Paul A. Gaukler, Esq.David R. Lewis, Esq.Pillsbury, Winthrop, Shaw, Pittman, LLP 2300 N Street, N.W.Washington, DC 20037-1138 Mr. Mark Sylvia Town Manager, Town of Plymouth 11 Lincoln Street Plymouth MA 02360 Sheila Slocum Hollis, Esq.Town of Plymouth MA Duane Morris, LLP 505 9h Street, N.W. 1000 Washington D.C. 20004-2166 Richard R. MacDonald Town Manager, Town of Duxbury 878 Tremont Street Duxbury, MA 02332 Fire Chief & Director DEMA, Town of Duxbury 688 Tremont Street P.O. Box 2824 Duxbury, MA 02331 Mary Lampert Pilgrim Watch, pro se 148 Washington St.Duxbury, MA 023332 2 X PNPS License Renewal Project AMRM-07 Revision 0 Aging Management Review of the Standby Gas Treatment System Page 9 of 23 3.2 Carbon Steel Components (Exposed to Condensation on Internal Surfaces and Soil or Indoor Air on External Surfaces)The discharges of the SGTS fans combine into a 20-inch carbon steel pipe that passes underground to the stack. The internal surface of the buried pipe may be wetted by condensation since the ground temperature may be lower than the dew point of the air.Therefore, loss of material from general, pitting, crevice corrosion and MIC is an aging effect requiring management for the internal surface of the buried piping. (Ref. 12)Loss of material from MIC and general, pitting, crevice, and galvanic corrosion is an aging effect requiring management for carbon steel external surfaces in contactmwith-soil. e c'2Z PILLROO000583 Y- 04 ý'I 0 E PNPS License Renewal Project AMRM-07" Revision 0 Aging Management Review of the Standby Gas Treatment System Page 9 of 24 3.2 Carbon Steel Comoonents (Exposed to Indoor Air on Internal Surfaces and Soil or Indoor Air on External Surfaces)The discharges of the SGTS fans combine into a 20-inch carbon steel pipe that passes underground to the stack. The internal surface of the buried pipe may be wetted by condensation since the ground temperature may be lower than the dew point of the air.Therefore, loss of material from general, pitting, crevice corrosion and MIC is an aging effect requiring management for the internal surface of the buried piping. (Ref. 12)Loss of material from MIC and general, pitting, crevice, and galvanic corrosion is an aging effect requiring management for carbon steel external surfaces in contact with soil. Loss of material from general corrosion is considered an aging effect requiring management for carbon steel external surfaces in contact with indoor air.A'Q- 8 PILLROO000586

~5x~1 bT From: IVY, TED S Sent: Monday, April 18, 2005 3:13 PM To: TAYLOR, ANDREW C; COX, ALAN B; LOYD, LELAND Cc: BATCH, STAN; GASTON, KERRY

Subject:

RE: info from Monticello LRA for SGTS After more discussion I am agreeable to using one time inspection to manage the buried piping. In order to be consistent with VY Leland is going to look and see if the VY AMRR has a similar situation and make necessary changes to make the two sites consistent.

Ted S. Ivy, P.E.Entergy Services Inc.License Renewal Services N-GSB-45 1448 S.R.333 Russellville, AR 72802 Office: 479-858-5542 Cell: _jRedacted-7'Fax: 479-858-5437

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Original Message -----From: TAYLOR, ANDREW C Sent: Monday, April 18, 2005 1:18 PM To: IVY, TED S; COX, ALAN B Cc: BATCH, STAN; GASTON, KERRY

Subject:

RE: info from Monticello LRA for SGTS Well, the turnover that I got from Stan on this Pilgrim AMRM-07 (SGTS) suggests that the internal environment of the SGTS piping at this location is different from that of the external & internal environments of the piping at other locations, due to the cooling effect of the soil through which the underground piping passes. Therefore, this section of piping would be a "worst case" for loss of material, which would not be bounded by the effects detectable by an external system walkdown at other places in the system.This is all driven by the configuration of the underground piping where it meets the stack.Our VY AMRM-07 for SGTS does not discuss this location at all as a special situation, and of course we cannot determine what was discussed at Monticello merely by reading their LRA.Table 3.2.2-6 of the Brunswick LRA received 10/20/2004 also shows Loss of Material (General Corrosion) managed by One-Time Inspection.

I recommend going along with the Monticello and Brunswick approaches, even if this requires revision to our VY AMRM-07 (SGTS).Andy PILLROO003609

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Original Message -----From: IVY, TED S Sent: Monday, April 18, 2005 12:21 PM To: TAYLOR, ANDREW C; COX, ALAN B

Subject:

RE: info from Monticello LRA for SGTS I would prefer to credit the system walkdown program to manage the internal surface exposed to indoor air and see if the NRC will accept it since the environments are the same and we use the same approach for ductwork.

If they won't then we can commit to performing a one time. This is the way the VY AMRR is written. If we go with one time then we will need to change the VY AMERR to match.Ted S. Ivy, P.E.Entergy Services Inc.License Renewal Services N-GSB-45 1448 S.R.333 Russellville, AR 72802 Office: 479-858-5542 Cell: LI-Re~dacted_.

Fax: 479-858-5437

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Original Message -----From: TAYLOR, ANDREW C Sent: Monday, April 18, 2005 12:10 PM To: COX, ALAN B; IVY, TED S

Subject:

info from Monticello LRA for SGTS Alan / Ted -RE: Pilgrim AMRM-07 (SGTS)In the LRA for Monticello received by NRC on 3/24/2005, the Table 3.2.2-8 "Secondary Containment System (SGTS)" lists carbon steel piping with internal environment of plant indoor air and cites Loss of Material (General Corrosion) managed by One-Time Inspection.

Also the same thing for valve bodies.In Pilgrim AMRM-07 (SGTS), I had listed "This [PM] program will also manage loss of material for the internal surface of the buried pipe on the SGTS discharge to the stack." Alan's comment was "This seems to take PMs beyond the norm." So I recommend retaining this Aging Effect for carbon steel piping & valve bodies within SGTS at Pilgrim, and use One-Time Inspection to manage.PILLR0000361 0

I will proceed bn this basis unless you advise otherwise.

Andy PILLROO003611 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 3 of 21 Table of Contents 1.0 Introduction..............................................................................

4 1. 1 Purpose ...............................................................................

4 1.2 System Description...................................................................

4 1.3 System and Component Intended Functions

........................................

5 2.0 Screening...............................................................................

6 3.0 Aging Effects Requiring Management

...............................................

8 3.1 Carbon Steel Damper and Valve Bodies, Filter Housings, Frames, Piping and Ductwork ....................................................................................

S 3.2 Fire Deluge Piping....................................................................

8 3.3 Expansion Joints.............b.........................................................

9 3.4 Buried Piping .........................................................................

9 3.5 Copper and Stainless Steel Instrument Components

..............................

10 3.6 Bolting ...............................................................................

10 3.7 Operating Experience

.....................................................

10 4.0 Demonstration That Aging Effects Will Be Managed ............................

11 4.1 System Walkdown Program .........................................................

i1 4.2 Periodic Surveillance and Preventive Maintenance Program......................

12 4.3 Buried Pipe Program................................................................

12 4.4 Time Limited Aging Analyses ......................................................

12 5.0 Summary and Conclusions

...........................................................

13 6.0 References

..............................................................................

14 Attachments

...................................................................................

16 Attachment 1 Components Subject to AMRIA .....................................

16 Attachment 2 Aging Management Review Results.....................................

19 PILLROO000633 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 9 of 21 Corrosion is possible on the external surface. Loss of material from general corrosion is conservatively considered an aging effect requiring management for the external surfaces.Minor general corrosion is possible on the internal surface of the fire piping. Loss of material is identified as an aging effect for the internal surfaces of the deluge piping.Intergranular attack and stress corrosion cracking are not applicable for carbon steel.Thermal fatigue is not a concern since the magnitude of system temperature changes is below the threshold for this mechanism.

Wall thinning due to erosion or erosion/corrosion is not significant since the fire piping is not normally in use. Wear is not a concern since there are no sliding surfaces.3.3 Expansion Joints Flexible elastomers expansion joints connect the fan housing to the ductwork.

The aging effects for elastomers are identified from the structural tools. Cracking and change in material properties are the aging effects requiring management for elastomers identified in the structural tools that apply to the internal and external surfaces of the expansion joints. (Ref. 17)3.4 Buried Piping The discharges of the SGTS fans combine into a 20 inch carbon steel pipe that passes underground to the stack. The internal surface of the buried pipe may be wetted by condensation since the ground temperature may be lower than the dew point of the air. Therefore, loss of material from general, pitting, crevice corrosion and MIIC is an aging effect requiring management for the internal surface of the buried piping.Loss of material from general, pitting, crevice corrosion and MIC is an aging effect requiring management for the external surface of the buried pipe.Intergranular attack and stress corrosion cracking are not applicable mechanisms for carbon steel.Cracking from thermal fatigue is not a concern since the magnitude of system temperature changes is below the threshold for this mechanism.

Wall thinning due to erosion or erosion/corrosion is not significant since only air is transported.

Wear is not a concern since there are no sliding surfaces.PILLR00000639 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 11 of 21 4.0 Demonstration That Aging Effects Will Be Managed The components of the SGTS that require aging management review were described in Section 2.0. The aging management review is performed by demonstrating that existing programs, when continued into the period of extended operation, can manage the aging effects identified in Section 3.0. No further action is required for license renewal when the evaluation of an existing program demonstrates that it is adequate to manage the aging effect such that corrective action may be taken prior to loss of the system intended functions.

Alternately, if existing programs cannot be shown to manage the aging effects for the period of extended operation, then action(s)will be proposed to augment existing or create new programs to manage the identified effects of aging.Demonstration for the purposes of this license renewal technical evaluation is accomplished by establishing a clear relationship among: 1) the components under review, 2) the aging effects on these items caused by the material-environment-stress combinations which, if undetected, could result in the loss of the intended function such that the system could not perform its function(s) within the scope of license renewal in the period of extended operation, and 3) the credited aging management programs whose actions serve to preserve the system intended function(s) for the period of extended operation.

Attachment 2 lists each of the component commodity groups and identifies the aging effects requiring management for the material and environment combination.

The System Walkdown Program, Periodic Surveillance and Preventive Maintenance Program, and the Buried Pipe Program will manage the effects of aging precluding the loss of the intended functions of the system. Sections 4.1 through 4.3 provide the clear relationship between the component, the aging effect and the aging management program action(s) which preserve the intended function(s) for the period of extended operation.

Section 4.4 evaluates time limited aging analyses.

For a comprehensive review of the programs credited for the license renewal of Pilgrim Nuclear Power Station and a demonstration of how these programs will manage the aging effects, see PNPS report LRPD-02, "Aging Management Program Evaluation Report".4.1 System Walkdown Program Under the Pilgrim System Walkdown Program, walkdowns are conducted to manage aging effects. For the standby gas treatment system, the System Walkdown Program will manage the effect of loss of material for carbon steel components exposed to ambient air conditions.

The external surface is exposed to the same environment as the internal surfaces, and therefore the monitoring of the external surfaces will also manage the loss of material aging effect on the PILLROO000641 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 12 of 21 internal surfaces.

For additional information on the System Walkdown Program, see the PNPS report LRPD-02, Aging Management Program Evaluation Report.4.2 Periodic Surveillance and Preventive Maintenance Program Under the Periodic Surveillance and Preventive Maintenance Program, inspections are completed of the flexible couplings to detect the aging effects of cracking and change in material properties.

This program will also manage loss of material for the internal surface of the buried pipe on the SGTS discharge to the stack. (OPEN ITEM 4) For additional information on the Periodic Surveillance and Preventive Maintenance Program, see the PNPS report LRPD-02, Aging Management Program Evaluation Report.4.3 Buried Pipe Program The buried pipe program is credited with managing the aging effect of loss of material from the buried pipe on the SGTS discharge to the stack. For additional information on the buried pipe program, see the PNPS report LRPD-02, Aging Management Program Evaluation Report.4.4 Time Limited Aging Analyses There were no TLAAs identified for this system.PILLR00000642 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 13 of 21 5.0 Summary and Conclusions An aging management review of the standby gas treatment system resulted in the following conclusions in support of license renewal. The following aging management programs address the aging effects requiring management for the standby gas treatment system." System Walkdown Program" Periodic Surveillance and Preventive Maintenance Program* Buried Pipe Program For additional review of the programs credited for the license renewal of Pilgrim Nuclear Power Station, see PNPS report LRPD-02, Aging Management Program Evaluation Report.Attachment 2 contains the aging management review results for the standby gas treatment system.In conclusion, the programs described in Section 4.0 will provide reasonable assurance that the effects of aging on the Pilgrim Nuclear Power Station standby gas treatment system will be managed such that the intended functions will be maintained consistent with the current licensing basis throughout the period of extended operation.

PILLROO000643 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 19 of 21 Attachment 2 Aging Management Review Results Aging Effect Component Type Intended Function Material Environment Requiring Aging Management Programs Management Carbon steel Ambient air Loss of material System Walkdown Bolting Pressure boundary Silicone bronze Ambient air None None Stainless steel Ambient air None None Internal Loss of material Periodic surveillance and preventive Buried piping Pressure boundary Carbon steel air/condensation maintenance Soil/groundwater Loss of material Buried pipe Damper (housings)

Pressure boundary Carbon steel Internal air Loss of material System Walkdown Ambient air Loss of material System Walkdown Ductwork Pressure boundary Carbon steel Internal air Loss of material System Walkdown Ambient air Loss of material System Walkdown Cracking Periodic surveillance and preventive Internal air Change in material ropetiesmaintenance Expansion joints Pressure boundary Elastomer prties Cracking Periodic surveillance and preventive Ambient air Change in material maintenance properties FilterPressure boundary Internal air Loss of material System Walkdown (including frames) (incl. Structural Carbon steel support)Ambient air Loss of material System Walkdown PILLR00000649 Pilgrim NPS License Renewal Project AMRM-07 Aging Management Review of the Standby Gas Treatment System Revision 0 Page 20 of 21 Attachment 2 Aging Management Review Results Aging Effect Component Type Intended Function Material Environment Requiring Aging Management Programs Management Orifice Pressure boundary Carbon steel Internal air Loss of material System Walkdown flow control Ambient air Loss of material System Walkdown Piping Pressure boundary Carbon steel Internal air Loss of material System Walkdown Ambient air Loss of material System Walkdown InenlarNone None Thennowell Pressure boundary Stainless steel Internal air Ambient air None None Stainless steel Internal air None None Tubing Pressure boundary Ambient air None None Copper Internal air None None I Ambient air None None PILLR00000650 P~am C)+/-Pilgrim Nuclear Power Station License Renewal Application Technical Information AGING MANAGEMENT PROGRAMS AND ACTIVITIES

\ -v C.i\ \ V B.1.1 BURIED PIPING INSPECTION D\V 2' c~Program Descrliotion The Buried Piping Inspection Program at PNPS is comparable to the program described in Rol," NUREG-1801,Section XI.M34, Buried Piping and Tanks Inspection.

This program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel iv 'components.

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings.

Buried components are inspected when excavated during maintenance. -V o J& /1. Scope of Program This program relies on preventive measures such as coating and wrapping and inspection for loss of material caused by corrosion of the external surface of buried carbon steel components.

Inspections are performed when the components are excavated for maintenance or for any other reason. The PNPS program manages loss of material on buried components subject to aging management review.2. Preventive Actions The preventive actions of the PNPS program will include protective coatings on underground components.

3. Parameters Monitored/inspected PNPS parameters monitored and inspected will be consistent with NUREG-1 801.4. Detection of Aging Effects Buried components will be inspected when excavated during maintenance activities to confirm that coating and wrapping are intact. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems will be evaluated for the need for additional inspection, alternate coating or replacement.

An inspection will be performed within 10 years of entering the period of extended operation, unless an opportunistic inspection occurred within this ten-year period.Appendix B Aging Management Programs and Activities Page B-13 PILLR00003278 Pilgrim NPS License Renewal Project AMRM-27 0 Aging Management Review of the Condensate Storage System PaRe 7 of 16 Stress corrosion cracking/intergranular attack is not of concern for carbon steels.The system temperature remains well below the threshold for cracking due to thermal fatigue.Therefore, thermal fatigue is not an applicable aging mechanism for these components.

3.2 Above Ground Piping/Tubing and Valves The piping and valves listed on Attachment 1 are constructed of stainless steel. This section will review aging effects for the valve bodies and piping that are above ground. (Ref. 1, 8)Stainless steel is inherently immune to general corrosion.

Stainless steel internal surfaces are susceptible to loss of material due to pitting, crevice corrosion or MIC in the presence of high oxygen levels and contaminants.

Erosion is not a concern for stainless steel components.

Therefore, loss of material from the internal wetted surfaces is an aging effect requiring management.

Reduction of fracture toughness due to thermal embrittlement is not an aging effect requiring management for the system components that are included in this review, since the operating temperatures are too low for embrittlement.

Cracking from stress corrosion cracking/intergranular attack is not an aging effect requiring management since the operating temperatures are below the 140°F threshold for this effect.The system temperature remains well below the threshold for cracking due to thermal fatigue during normal plant operation.

Therefore, cracking from thermal fatigue is not an aging effect requiring management for these components.

In an ambient air environment, exterior stainless steel surfaces do not experience aging effects requiring management.

3.3 Underground Piping and Tubing A section of the piping from the CSTs to the HPCI and RCIC systems is underground and the level instrument tubing has a section of piping that is underground. (See drawing LRA-209 for details.)

These are constructed of stainless steel. (Ref. 1, 6, 8)The internal surfaces will have the same aging effects as identified in the previous section.The only change will be the aging effects for the external surfaces since they are exposed to soil and groundwater.

Loss of material from pitting corrosion, crevice corrosion and MIC is an aging effect requiring management for stainless steel piping external surfaces that are underground.

J Cracking from SCC of the external surface of the buried piping is not an aging effect requiring management since the operating temperatures are below the 140°F threshold for this effect.PILLR00003225 Pilgrim NPS License Renewal Project AMRM-27 Aging Management Review of the Condensate Storage System Revision 0 Page 10 of 16 4.1 Water Chemistry Control Program The water chemistry control program will manage of the aging effect of loss of material for the components that are wetted by the condensate storage tank water as identified on Attachment 2.For additional information on the Water Chemistry Control Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report.4.2 System Walkdown Program Under the Pilgrim System Walkdown Program, walkdowns are conducted to detect and manage aging effects on components.

The System Walkdown Program will manage the effect of loss of material for external surfaces of carbon steel components including bolting as identified on Attachment

2. For additional information on the System Walkdown Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report.4.3 Periodic Surveillance and Preventive Maintenance Program The condensate storage tanks and internal piping are coated to prevent loss of material from the.internal surface. Periodic inspections are performed to ensure the integrity of this coating and manage the aging effect of loss of material from the internal tank surfaces. (Ref. 18) For additional information on the Periodic Surveillance and Preventive Maintenance Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report.4.4 Buried Pipe Inspection Program The Buried Pipe Inspection Program will ensure that loss of material due to external surface corrosion of buried piping is adequately managed. The underground portions of the suction piping to the HIPCI and RCIC systems are within the scope of this inspection.

For additional information on the required Buried Pipe Inspection Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report.4.5 Time Limited Aging Analyses The UFSAR section A.3.1.2 states adequate allowances for corrosion and erosion are made according to individual system requirements for a design life of 40 years. The wall thinning TLAA reviews the corrosion and erosion allowances.

See PNPS Report LRPD-03, TLAA and Exemption Evaluation and LRPD-06, Time-Limited Aging Analyses -Mechanical Fatigue for additional details.PILLROO003228 1 PNPS License Renewal Project Revision 0 Aging Management Review of the Salt Service Water System Page9 of 26 3.0 Aging Effects Requiring Management 35 3.1 Carbon Steel Components Some carbon steel piping is above ground and some is below ground.PILLR00000939 PNPS License Renewal Project Aging Management Review of the Salt Service Water System Components that are underQround (piping exposed to soil and groundwater) or aboveground and continuously wetted maybeprt~

ehay-,Jing.

Since the coating does nothayve a etsare evaluated as if the carbon steel w coated. o'-ý of material due to general corrosion, pitting corrosion, crevice corrosion, MIC, and galvanic corrosion is an aging effect requirinQ manaaement.

3.2 Titanium Components Titanium piping and thermowells are used in sections of the SSW system. The component type "piping" used in this report also includes the insulating flanges on the system. These components are exposed to low temperature raw water on internal surfaces and condensation (that may include salt water) or soil on external surfaces.(Ref. 1, 2, 3)Loss of material due to MIC from external buried titanium surfaces is an aging effect requiring management.

PILLROO000940

/Entergy I CONDITION REPORT J CR-PNP-2003-01706 Originator:

DiGeronimo.Mark E Originator Phone: 8632 Originator Group: QA Insp Staff Operability Required:

N Supervisor Name: KelIy,Gary R Reportability Required:

N Discovered Date: 04/28/2003 21:00 Initiated Date: 04/28/2003 21:23 Condition

==

Description:==

The test pieces obtained from the west end of the CIPP liner at "A" SSW discharge line exhibit thickness measurements averaging

.490 in. including the liner membrane, which is Jheminimum ue minimum thickness specified for the test samples is greater than or equal to .495 in., after deducting the thickness of the liner membrane.

Note: This condition report is being issued concurrently with NCR 03-027.Immediate Action

Description:

Notified Maintenance supervision and Engineering, and initiated NCR 03-027.Suggested Action

Description:

Evaluate the condition for any impact to anticipated performance of the liner.EQUIPMENT:

Tag Name TaE Suffix Name Component Code Process System Code 29 TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=IN CRT=EF PI=10 WP=MAINT PILLR00044657 Entergy ADMIN CR-PNP-2003-01706 Initiated Date: 4/28/2003 21:23 Owner Group :CRG Mgmt Current Contact: Cui-rent Significance:

D -ADMIN CLOSE.Closed by: Buckley.Patricia A 4/29/2003 12:58 Summary

Description:

Remarks

Description:

Closure

Description:

ADM]hN CLOSE.The CRG has determined that the CR identified condition is not a Condition Adverse, to Quality or is an enhancement as defined in LI-1 02. Therefore, further analysis or actions recommended or n eeedessff'o-ndition do not warrant tracking in the CR process, Any further actions should be addressed through the NCR process. This CR will be administratively closed as a CAT "D". NCR 03-027 (4 o r PILLR00044658 Entergy CONDITION REPORT CR-PNT-1999-09053 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 02116/1999 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 02/16/1999 00:00 Condition

==

Description:==

TB TOUR OPERATOR REPORTED SSW PATCH NEAR MO-3805 WAS SPRAYING WATER THROUGH A PLNHOLE LEAK. ---"--Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tag Namie REFERENCE iTEMS: Type Code CONVERTED PR Tag Suffix Name Component Code Process System Code 29 Description PR.99.9053 Ss Lc~7FU k~Q ~I ---PILLR00045284 Entergy I ADMIN CR-PNP-1999-09047 Initiated Date: 2/9/1999 0:00 Owner Group :Regulatory

& Industry Affairs Staff Current Contact: SHATAS, A.Current Significance:

C -CORRECTION Closed by: SHATAS, A. 2/16/1999 0:00 Summary

Description:

TWO AREAS WERE FOUND TO BE BELOW MIN WALL OF 160" PER SPEC M59i.Remarks

Description:

PR=EF M591 SALT SERVICE WATER PIPE SPOOL JF29-10-8 OP99.0007-PIPE-EPIX NOT Closure

Description:

SEE CORRECTIVE ACTION RESPONSE.I.PILLR00045281 Entergy CORRECTIVE ACTION CR-PNP-1999-09047 Ir' A X I u K *1 Group...........

Assigned By: Regulatory

& Industry Affairs Staff Assigned To: Regulatory

& Industry Affairs Staff Name BRENNION, S.EllisDouglas W Subassigned To: Originated By: BRENNION, S. 2/9/1999 00:00:00 Performed By: ELLIS, D. 2/17/1999 00:00:00 Subperformed By: Approved By: Closed By: BRENNION, S. 2/17/1999 00:00:00 Current Due Date: 02/18/1999 Initial Due Date: 02/18/1999 CA Type: GENERAL Plant Constraint:

NONE CA

Description:

CONDUCT A I OCFR50.73 REPORTABILITY REVIEW Response: CONVERTED DATA Subresponse

Closure Comments: MEMO DOCUMENTING RESULTS OF REPORTABILITY REVIEW CLOSURE: A 1I CFR50.73 REPORTABILITY REVIEW WAS PERFORMED FOR CONDITIONS DESCRIBED IN PR99.9097.00 RESULTLNG IN A DETERMINATION OF NOT REPORTABLE UNDER CRITERIA 10CFR50.73(a)(2)(i), (a)(2)(ii), (a)(2)(v) and (a)(2)(vii).

ATTACHED MEMO DOCUtRM TiVULTS OF THIS REVIEW.PILLR00045283 Entergy CONDITION REPORT CR-PNP-1999-00276 Originator:

CONVERTED DATA Originator Group: CONVNERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 02/11/1999 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 02/11/1999 00:00 Condition

==

Description:==

SEVERE OD SSW PIPE CORROSIQ lNGO S S 19-7-3, 10-6, 10-7 AND 10-9 DOES NOT PERMIT 10%UT AS REQUIRE BY SPECIFICATION M59 1, Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tauy Name REFERENCE ITEMS: Type Code CONVERTED PR Tag Suffix Name Component Code Process System Code 29 Description PR.99,0276 TRENDING (For Reference Purposes Only): Trend T Pe KEYWORDS Trend Code MAINT RULE PILLR00045276 Entergy CORRECTIVE ACTION I CR-PNP-1999-00276 CA Number: 1 G rou p Na me Assigned By: Eng DE Mech Civil Struct Staff VALLEE, L.Assigned To: Eng Sys Mech Staff GaedtkeJoseph R Subassigned To: Originated By: VALLEE, L. 2/11/1999 00:00:00 Performed By: GAEDTKE, J. 2/24/1999 00:00:00 Subperformed By: Approved By: Closed By: VALIEE, L. 2/24/1.999 00:00:00 Current Due Date: 04/20/1999 Initial Due Date: 04/20/1999 CA Type: GENERAL Plant Constraint:

NONE CA

Description:

REVIEW THE ISSUES IDENTIFIED IN THIS PROBLEM REPORT REGARDING SSW PIPE SPOOLS.DETERMINE AND IMPLEMENT REQUIRED CORRECTIVE ACTIONS.Response: CONVERTED DATA Subresponse:

Closure Comments: MEMO DETAILING THE RESULTS OF THE REVIEW AND THE CORRECTIVE ACTIONS TAKEN.ATITACHMENT TO PR99.0276.00 Discussion:

While attempting to performing Ultrasonic Examination of SSW pipe spools 3F29-10-7-3, 10-6 & 10-9 per BECo Specification M591, severe surface corrosion has prevented Q.C inspectors from obtaining at least 10% UT examination of each spool per PNPS Spec. M59 1.Due to the severely corroded surfaces of these spools, three areas of spool JF29-10 -6 were ground smooth to allow UT examinations to be performed.

The UT results were well above the minimum wall thickness of this pipe and were found to be at nominal wall thickness for this spool. Due to the surface conditions preventing at least 10% examination of these spools without grinding at least t0% of the surfaces smooth, and the fact that theses spool still have their original rubber lining, NESG is recommending replacing these spool in-kind during RFO#12. NESG has submitted.

Task Identification

& Change Forms to Outage Management to included replacing these spool in-kind during RFO#12. TIC#RI 2-340 & TIC#R12-341 have been approved by Outage management to replace SSW Spools JF29-7-3, JF29-10-6, JF29-10-7 and MF29-10-9.

Mrs.19800596

& 19803033 has been revised to include fabricating and installing these spools during RFO#12. Nucleis has been updated.ct kc, -ý LcrcQ10g/I PILLR00045279 Entergy I CONDITION REPORT CR-PNP-2004-00391 Originator:

Gaedtke,Joseph R Originator Group: Eng Sys Mech Staff Supervisor Name: Fox.Thomas Discovered Date: 02/05/2004 19:52 Originator Phone: 8359 Operability Required:

Y Reportability Required:

Y Initiated Date:02/05/2004 21:03 (I1-6 TT 3 9 Condition

==

Description:==

During reassembly of P-208D, the Maintenance Department identified a concern of corrosion on Salt Service Water Pipe Spool J_ (-9-- (P:208D.Qjschargepipe spool downstream of 29-HO-3817 isolation valve). A visual mspecduii performed by Systems Engineering and Maint-e-nan-ce Vi-i -ip-Sitsuthf-the corrosion is on the exterior of the pipe wall only. There was n.-pr¢sure beundrbserved with 34 psi. (pressure observed at PI-3822).

This indicates that rubber lining is still intact and the internals of the pipe spool has not been affected.The -exterior corrosion is most likely the result of excessive Salt Service Water Pump Packing leakage that has been experienced for a period of time due to pump shaft coating degradation.

Reference CR-PNP-2002-12941 and CR-PNP-2003-042.

A visual inspection was also performed on the remaining SSW Pump discharge pipe spools without findings of severe corrosion.

Immediate Action

Description:

Generate this CR, Notify the Control Room and generate a WRT#091697 Suggested Action

Description:

Perform a Ultrasonic examination of SSW Plpe Spool JF29-15-9 to determine wall thickness.

EQUIPMENT:

Tas, Name Tag Suffix Name Component Code Process System Code 29 TRENDING (For Reference Purposes Only): Trend Type Trend Code CRT=EF P1=SI WP=MAINT PILLR00044661 Entergy I ADMIN TCR-PNP-2004-00391 Initiated Date: 2/5/2004 21:03 Owner Group :Eng Sys Mgmt Current Contact: Current Significance:

C -CORRECTION Closed by: Buckley,Patricia A 5/8/2005 13:32 Summary

Description:

During reassembly of P-208D, the Maintenance Department identified a concern of corrosion on Salt Service Water Pipe Spool JF29-15-9 (P-208D Discharge pipe spool downstream of 29-HO-3817 isolation valve). A visual inspection was performed by Systems Engineering and Maintenance Supervision.

It appears that the corrosion is on the exterior of the pipe wall only. There was no pressure boundary, leakage observed with 34 psi. (pressure observed at PI-3822).

This indicates that rubber lining is still intact and the internals of the pipe spool has not been affected.The exterior corrosion is most likely the result of excessive Salt Service Water Pump Packing leakage that has been experienced for a period of time due to pump shaft coating degradation.

Reference CR-PNP-2002-12941 and CR-PNP-2003-042.

A visual inspection was also performed on the remaining SSW Pump discharge pipe spools without findings of severe corrosion.

Remarks

Description:

Closure

Description:

oe closed in control room6/7/04 All CA's associated with this CR were reviewed by the responsible manager. Upon the manager's recommendation, this CR is being closed.Per EN-LI-102, Para. 5.9[2](c):

Independent reviews are not required for non-significant condition reports. The documented closeout verification performed by the Responsible Management is adequate authorization for closure of the CR.I PILLR00044662 1ýý>c-2-f Cý)[] Safety-Related

[S Non-Safety-Related f] "Q".LI9 t Item [] Non-"Q` RTYPE 85.21 PILGRIM NUCLEAR POWER STATION SPECIFICATION FOR CURED-IN-PLACE-PIPE (CIPP) LINING FOR SSW DISCHARGE PIPING SPECIFICATION NUMBER -M-624[ BID Addendum No,_ Z PURCHASE DATE, 12-MAR-2003 tN.Ln ASME B&PV CODE CERTIFIOATION:

[ REQ'D [ NOT REQ'D 0 C', EO PD, Harizl 04/02101 SP, Woods D4/02/01 04102/07 ace 41/02/01 PREPARED VERIFIED SoM APPROVED REV BY DATE BY DATE REVIEW DATE _ BY DATE ENTERGY NUCLEAR GENERATING COMPANY PILGRIM NUCLEAR POWER STATION 600 ROCKY HILL ROAD PLYMOUTH, MA 02360 Specifioation M-624 Page 1 of 12 NE3.08 Rev. 18 Attachment 1 PILLROO46040 1.0 SCOPE (1] This spealfioatlon provides Iha requirements for the deslgn, materials, Installation, Inspections, end testing of a Ouredln.Plaoe-Pipe (CIPP) lining for the Salt Serce Water (SSW) disoharge piping at PlIgrim Nuclear Power Slalion (PNPS). The purpose of the CIPP Is to provide a new protective lining for the existing steel pipe that mainlains the structural Integrity of the discharge pipe for soil, overburden, seismic, and live foade, (2) The SSW piping to receive the 1FFP Is the discharge piping for Loop "A" and Loop "1" from the last flange oonnection in the Auxiliary Building piping vault to the and of the discharge pipe at the Seal Well opening.[3) The SSW discharge pIping Is 22" nominal diameter standard weight carbon steel pipe (0,375' walJ thickness) wIth a 3/16" natural rubber lining thickness.

Flange connections are rubber-Ilned Pressure Class 160 flat-faded slip-on flanges, Existing rubber Ilning and coatings that are Inltat will remain In piece for the CIPP Installation,[4) The Loop 'A' discharge piping Is approximately 240 ft (total length to be lined) with three(3) 45-degree elbows and one(l) g0-degree long radius elbow,*, [6) The Loop 11B" discharge piping Is approximately 225 ft (total length to be lined) with four(4) 45-degree elbows and one(i) g0.degree long radius elbow, (6) As a result of pipe spool replacements performed In 1999, there Is a 40'-0" spool In Loop'A" and a 40 spool in Loop "'V that are 22" nominal diameter standard weight carbon steel pipe (0,376" wall thickness) coated with Duromar EAC-FE epoxy with a minimum 1/32" (0.031") thickness, and Include "WEKO" elastomerlo expansion seals on both end flange joilts of the replacement spool, which are to be removed before the CIPP M Installation, (71 This speolflcatlon provides the requirements (or the CIPP design, materials, Installation, C\, Inspections, testing, and Supplier documentation,[8) The SSW discharge piping is part of a 'Q", Safety-Related, PNPS Class I system, The CIPP design, materials, Installatlon, inspections, testing, and documentation are to be performed and/or acoepted under the PNPS Nuclear Quality Assurance program In accordance with Appendix B to Part 60 of Title 10 of the Code of Federal Regulations (1i oFR6 Appendix B), Specification M-624 Rev, El Page 2 of 12 PILLROO46041 CALCULATION SHEMT CALC. 0 M-1031 REV. 1 DATE 14-MAY-2003 SHEET j OF A. Statement of Problem This calculation provides the design for a CuredIn-Place-Pipe (CIPP) lining for the Salt Service Water (SSW) buried discharge piping at Pilgrim Nuclear Power Station (PNPS).The purpose of the CIPP is to provide a new internal lining for the existing steel pipe that can withstand the imposed hydraulic and mechanical loads while maintaining the structural integrity of the discharge pipe for soil, overburden, seismic, and live loads (Re(, 1].The SSW piping to receive the CIPP is the discharge piping for Loop "A" and Loop "B" from the last fange connection in the Auxiliary Building piping vault to the end of the discharge pipe at the Seal Well opening.The Loop "A" discharge piping is approximately 240 ft total (length to be lined) with three(3) 45-degree elbows and one(i) 90-degree long radius elbow (Ref. 2).The Loop "B" discharge piping is approximately 225 ft total (length to be lined) with four(4) 45-degree elbows and one(l) 90-degree long radius elbow [Ref. 31.This calculation also includes the as-built CIPP material test results from lining the Loop "B" discharge in RFO-13 and the Loop "A" discharge in RFO- 14.C)CD PILLROO46104

~-~XJTh) L~d7 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation CR-PNP- RBCCW "A" loop suction header valve 30- Loss of material due to corrosion is an 2002-11632 HO-2 and RBCCW "B" loop suction header aging effect identified in the mechanical valve 30-HO-6 have corroded carbon steel tools for carbon steel external surfaces bolting. exposed to condensation.

CR-PNP- RCIC turbine trip throttle valve pipe plug Loss of material due to corrosion is an 2003-00286 has a steam leak attributable to corrosion.

aging effect identified in the mechanical tools for carbon steel in steam.CR-PNP- Fire water piping on both sides of valve 12- Loss of material due to corrosion is an 2003-01143 PW-103 is corroded.

aging effect identified in the mechanical tools for carbon steel in treated water.CR-PNP- RBCCW heat exchanger (E-209A) inlet Loss of material due to erosion is an 2003-01507 channel head has minor erosion of the aging effect identified in the mechanical copper-nickel partition plates. tools for copper alloy in high velocity raw water.CR-PNP- Clean radwaste equipment drain pipe is Loss of material due to corrosion is an 2003-01722 leaking due to corrosion.

aging effect identified in the mechanical tools for carbon steel in raw water.CR-PNP- HPCI turbine gland seal cases have light Loss of material due to general and pitting 2003-01726 corrosion and pitting. corrosion is an aging effect identified in the mechanical tools for carbon steel in steam or treated water.CR-PNP- HPCI steam line drain valve, 2301-203, Loss of material due to corrosion is an 2003-02983, has leakage attributable to corrosion.

aging effect identified in the mechanical MR tools for carbon steel in treated water or 03 .steam.CR-PNP- Salt service water drain line to the auxiliary Loss of material due to corrosion is an 2003-04416 bay sump has a through-wall leak aging effect identified in the mechanical attributable to corrosion.

tools for carbon steel in raw water.CR-PNP- Salt service water pipe spool JF29-15-9 Loss of material due to corrosion is an 2004-00391 (P-208D discharge pipe spool downstream aging effect identified in the mechanical of 29-HO-3817 isolation valve) is corroded.

tools for carbon steel in raw water.CR-PNP- The access door and frame to the outside Loss of material due to corrosion is an 2004-03373 air supply plenum to fan room 1 on the roof aging effect identified in the mechanical of the auxiliary building is corroded open. tools for carbon steel in outside air.CR-PNP- Control room ventilation damper housing Loss of material due to corrosion is an 2004-03981 (AO-X6) is corroded.

aging effect identified in the mechanical tools for carbon steel in indoor air.System System walkdowns have identified Loss of material due to corrosion is an Engineer condensation on piping surfaces.

External aging effect identified in the mechanical Interview portion of carbon steel piping can tools for carbon steel exposed to RBCCW experience corrosion due to wetting of the condensation.

insulation.

System Heat exchangers (E-209s) have Loss of material due to erosion is an Engineer experienced wall thinning in the transition aging effect identified in the mechanical Interview area between the heat exchanger sleeves tools for copper alloy tube surfaces RBCCW and the heat exchanger tubes. Loss of exposed to high velocity raw water.material is an aging effect requiring management.

PILLR00003495 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation System Salt service water system has experienced Loss of material due to corrosion is an Engineer wall thinning due to corrosion of piping, aging effect identified in the mechanical Interview pumps, and the channel assemblies on tools for carbon steel components SSW heat exchangers.

exposed to raw water.System Three on-line through-wall leaks occurred Loss of material due to corrosion is an Engineer due to corrosion following loss of rubber aging effect identified in the mechanical Interview lining inside of salt service water system tools for carbon steel in raw water.SSW pipe spool sections. (Reference CR-98-9143, 98-9392, 01-9397).System Salt service water system has experienced Loss of material due to corrosion is an Engineer external corrosion due to salt-water aging effect identified in the mechanical Interview.

environment, tools for carbon steel exposed to salt SSW (Reference CR-99-276) water spray or immersed in salt water./i PILLR00003497 Table 3.1.1 Operating Experience Applicable to Non-Class 1 Mechanical Systems Item Issue Evaluation System Carbon steel station blackout diesel intake The aging management review of the Engineer air piping is exposed to rain and station blackout diesel generator system Interview condensation.

considers indoor air as the internal and SBO external environment for the carbon steel intake air piping. Since indoor air is assumed to have entrained moisture, the aging effects for carbon steel exposed to indoor air encompass the aging effects for carbon steel periodically exposed to rain and condensation. (Ref. Error! Reference source not found.)System Rust has been observed on the inlet pipe Loss of material is an aging effect Engineer from the roof to the station blackout (SBO) identified in the mechanical tools for Interview diesel turbocharger.

carbon steel in outdoor air or exhaust gas.SBO System Salt service water system has experienced Loss of material due to corrosion and Engineer wall thinning due to corrosion of piping, erosion is an aging effect identified in the Interview pumps, and the channel assemblies on mechanical tools for carbon steel SSW heat exchangers.

components exposed to raw water.System Three on-line through-wall leaks occurred Loss of material due to corrosion is an Engineer due to corrosion following loss of rubber aging effect identified in the mechanical Interview lining inside of salt service water -system tools for carbon steel in raw water.SSW pipe spool sections. (Reference CR-98-9143, 98-9392, 01-9397).

_________________

System Salt service water system has experienced Loss of material due to corrosion is an Engineer external corrosion due to salt-water aging effect identified in the mechanical Interview environment, tools for carbon steel exposed to salt SSW (Reference CR-99-276) water spray or immersed in salt water.V PILLRO0003487 DRAFT Pilgrim Nuclear Power Station License Renewal Application Technical Information Environment Standby liquid control system components are exposed to the following environments." air -indoor* sodium pentaborate

• concrete Aging Effects Requiring Management The following aging effects associated with the standby liquid control system require management.

• loss of material Aging Management Programs The following aging management programs manage the aging effects for the standby liquid control system components." system walkdown* water chemistry control -BWR" periodic surveillance and preventive maintenance 3.3.2.1.2 Salt Service Water System Materials Salt service water system components are constructed of the following materials.

• carbon steel" copper alloy (aluminum bronze)" copper alloy < 15% zinc" copper alloy > 15% zinc" nickel alloy* stainless steel" titanium Environment Salt service water systems components are exposed to the following environments.

• condensation

• soil 3.0 Aging Management Review Results Page 3.3-6 PILLR00003250 VERIFICATION OF PNPS LICENSE RENEWAL PROJECT REPORT RTYPE A6.10 Title of Report: Report Number: Revision: Aging Management Review of the Salt Service Water System AMRM-1 1 0, (Draft G) 6/20105 This report documents evaluations related to the PNPS License Renewal Project.Signatures certify that the above report was prepared, checked and reviewed by the license renewal project team in accordance with the PNPS license renewal project guidelines and that it was reviewed and approved by the ENI License Renewal Project Manager and PNPS project management in accordance with PNPS procedures.

License renewal project team signatures also certify that a review for determining potential impact to other license renewal documents, based on previous revisions, was conducted for this revision.fLýI Other document(s) impacted by this revision: No__ Yes, See Attachment X License Renewal Project Team Prepared by: Date: Stan Batch Reviewed by: Date: Jack Orlicek Approved by: Date: David J. Lach, ENI LR Project Manager I PNPS Approvals PNPS License Re Inewal Project AMRM-11 Aging Management Review of the Salt Service Water System Revision 0 Page 9 of 26 3.0 Aging Effects Requiring Management EPRI reports 1003056 and 1002950 are used in this section to identify and evaluate aging effects requiring management.

Aging effects that may result in loss of intended functions for non-Class 1 components are cracking (i.e., crack initiation, crack growth, and through-wall cracking), change in material properties, fouling and loss of material.For additional information on aging effects, refer to the EPRI reports. (Ref. 4, 19)Attachment 1 is a list of SSW system components that form the system pressure boundary.

These components require aging management review in this AMVRR and are highlighted on the associated LRA drawings.The SSW system is normally in operation.

During normal plant operation, the temperatures for components in this AMVRR remain within the range of ocean temperature plus the temperature rise across the system such that at the outlets of the heat exchangers, temperatures will not normally exceed 80 0 F for the RBCCW and 95'F for the TBCCW. (Ref. 3)The following sections document the determination of aging effects requiring management for specific component materials and environments.

3.1 Carbon Steel Components The SSW system includes carbon steel components (including cast iron), the majority of which are rubber lined. Since for the purposes of identifying aging effects the liner is not credited with a protective function, aging effects are identified for carbon steel in contact with salt water. Some carbon steel piping is above ground and some is below ground. See Attachment 1 for a list of carbon steel components.

The component type"'piping" used in this report also includes the insulating flanges on the system. (Ref. 1, 6, 17)The generic component type "valve body" is used for the intake structure sluice gates to describe the pressure boundary even though it does not have a separate "body" for the pressure boundary.

These components are identified as exposed to low temperature raw water on internal surfaces (even though they do not actually have an "internal surface")

and condensation that may include some salt water on external surfaces to match the standard terminology and identify bounding aging effects for these components.

Loss of material due to general corrosion, pitting corrosion, crevice corrosion, MIC, erosion, selective leaching (for gray cast iron), and galvanic corrosion (where different materials are in contact with carbon steel) is an aging effect requiring management for internal surfaces of carbon steel components exposed to raw water.Condensation (including salt water) may occur on un-insulated surfaces when the surface temperature is less than or equal to the dew point of the surrounding air. Loss of material due to general, pitting, crevice, and galvanic corrosion is an aging effect requiring management for external carbon steel surfaces exposed to condensation.

PILLROO000855 PNPS License Renewal Project AMRM-1 1 Aging Management Review of the Salt Service Water System Revision 0 Page 10 of 26 Components that are underground (piping exposed to soii and groundwater) or aboveground and continuously wetted may be protected by a coating. Since the coating does not have a specified life, aging effects are evaluated as if the carbon steel was not coated. Loss of material due to general corrosion, pitting corrosion, crevice corrosion, MIC, and galvanic corrosion is an aging effect requiring management.

Loss of material from selective leaching is an aging effect requiring management for gray cast iron components.

Cracking due to thermal fatigue is not an aging effect requiring management since system temperature remains below the 220OF threshold for carbon steel thermal fatigue.3.2 Titanium Components Titanium piping and thermowells are used in sections of the SSW system. The component type "piping" used in this report also includes the insulating flanges on the system. These components are exposed to low temperature raw water on internal surfaces and condensation (that may include salt water) or soil on external surfaces.(Ref. 1, 2, 3)Titanium is inherently resistant to general corrosion, pitting corrosion, crevice corrosion, and erosion in raw water at temperatures less than 160 0 F. However, in raw water, MIC can result in loss of material from titanium.

Therefore, loss of material due to MIC is an aging effect requiring management for internal surfaces.Cracking from stress corrosion and intergranular attack is not an aging effect requiring management for titanium due to the inherent resistance of titanium to these mechanisms.

Cracking due to thermal fatigue is not an aging effect requiring management since the system operates at low temperatures.

Titanium exposed intermittently to condensation does not experience aging effects as MIC requires a continuously wetted surface. Loss of material due to MIC from external buried titanium surfaces is an aging effect requiring management.

3.3 Copg~er Alloy Components The SSW system pump casings, some system valves, and tubing are constructed of copper alloy'. The tubing and valves are conservatively assumed to contain >15% zinc when identifying aging effects. These components are exposed to low temperature raw water on internal surfaces and condensation (that may include salt water) or low temperature raw water (for submerged components such as the pump casings) on external surfaces. (Ref. 3, 17)1The pumps are aluminum bronze per page 79 of reference

3. This is a copper alloy.PILLROO000856 PNPS License Renewal Project AMRM-1 1 Aging Management Review of the Salt Service Water System Revision 0 Page 15 of 26 4.1 Water Chemistry Control -Closed Cooling Water Program The Water Chemistry Control -Closed Cooling Water Program manages loss of material for the TBCCW heat exchanger components that are wetted by treated water by minimizing levels of contaminants in the water. The Water Chemistry Control -One-Time Inspection Program utilizes inspections or non-destructive evaluations of representative samples to verify that the Water Chemistry Control -Closed Cooling Water Program has been effective at managing loss of material for the TBCCW heat exchangers.

This program applies to component types indicated on Attachment

2. For additional information on this program and the Water Chemistry Control -One-Time Inspection Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report.(Ref. 18)4.2 System Walkdown Program Under the System Walkdown Program, visual inspections are conducted to manage aging effects on components.

For the SSW system, the System Walkdown Program manages loss of material for external carbon steel, stainless steel, and copper alloy components by visual inspection of external surfaces.This program applies to component types indicated on Attachment

2. For additional information on this program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report. (Ref. 18)4.3 Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program manages loss of material from external surfaces of buried carbon steel and titanium components by visual inspection.

This program applies to component types indicated on Attachment

2. For additional information on the Buried Piping and Tanks Inspection Program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report. (Ref. 18)4.4 Service Water Integrity Pro-gram The Service Water Integrity Program includes condition and performance monitoring activities to inspect components for erosion and corrosion.

Chemical treatment using biocides and chlorine and periodic cleaning and flushing of redundant or infrequently used loops are additional methods used under this program to manage loss of material in SSW carbon steel, stainless steel, titanium and copper alloy components.

This program applies to component types indicated on Attachment

2. For additional information on this program, see PNPS Report LRPD-02, Aging Management Program Evaluation Report. (Ref. 18)PILLROO000861 RTYPE A6.10 IWA udmT F@qj MIE~~ ~~ 13po AMRM- 11 Aging Management Review of the Salt Service Water System Revision Draft 11/12/01 j PILLR00000658 Pilgrim License Renewal Project RTYPE A6.10 Aging Management Review of the Salt Service Water System AMRM-1 1 Revision 0 The following sections review the specific component materials and the potential aging effects for the environments.

3.1 Carbon Steel Piping and Valves The majority of the carbon steel piping is class JF. The pipe class JF is rubber lined carbon steel pipe and some of the valves are carbon steel including cast iron. When the liner is intact, the salt service water does not come in contact with the carbon steel piping. Since the liner does not have a specified qualified life and leakage of the liner have occurred at Pilgrim, the aging effects will be identified for carbon steel in contact with the salt water.There is a small portion of the piping to the RHR system that is class GB (carbon steel-unlined) but this portion of the line is maintained isolated from the salt water with the drains open. (See M212 Sh. 1) This portion of the system will also be bounded by a review aging effects of carbon steel in salt water.General corrosion of the internal carbon steel surfaces is an aging effect that requires aging management.

Loss of material due to pitting, crevice corrosion and MIC is coniered anaging effect that requires management.

Sorqe localized galvanic c-rrosion is applicable at the interface of the carbon steel piping with the system components that are const ed of materials ther than carbon steel (heat exchangers, pump casings, titanium piping, brass valves, etc) if not protected by an insulating flange. (Insulating flanges are used extensively in this system to prevent galvanic corrosion-see the P&ID M212 SH. 1 for specific locations.)

Erosion is a concern, especially at localized high velocity areas. Selective leaching is possible for any gray cast iron components.

Loss of material is an aging effect that requires management for the internal surfaces of the carbon steel components.

Reduction of fracture toughness due to thermal embrittlement is not an aging effect that requires management for the SSW system components in this AM1RR, since the operating temperatures are too low for embrittlement and carbon steel is not susceptible to thermal aging.Creep generally occurs at greater than 40% of the alloy melting temperature and is, therefore, not a significant aging mechanism at the temperatures for the components in this AMRR.Neutron irradiation embrittlement is not significant since the valves and piping are located in regions of low neutron fluence.Wear is not a significant aging mechanism since there are no sliding surfaces and fretting will not occur for the rigid components in this aging management review.Stress corrosion cracking/intergranular attack are not of concern for carbon steels.PILLROO000664 Pilgrim License Renewal Project RTYPE A6.10 S.Aging Management Review of the Salt Service Water System AMRM-11 Revision 0 The system temperature remains low; therefore, thermal fatigue is not an applicable aging mechanism for the SSW system components.

The exterior surfaces of the above ground carbon steel SSW piping and valves in the plant are indoors and protected by paint. Since the ocean water is cool, condensation can occur on the uninsulated surfaces when the dew point temperature is at or below the ocean temperature.

Loss of material is identified as an aging effect that requires management for the external surfaces.The piping that is underground is protected by a coating, but since the coating does not have a specifiedife, aing effects will be evaluated for carbon steel. Loss of material trom general, pitting, crevice, and MIC is an aging effect that requires management for the underground carbon steel pipe external surfaces.3.2 Titanium Piping Pipe class JF is titanium piping which has been used to replace sections of the piing that was originally rubber lined carbonsteel. (Ref. 1, 2, 3)Titanium' is inherently immune to general corrosion, pitting or crevice corrosion.

However, in raw water, MIC canresult in a o m ~teril rrnmJtianium.

Erosion is not a concern for titanium components.

Therefore, loss of material from the internal wetted titanium surfaces will be identified as an aging effect that requires management.

Reduction of fracture toughness due to thermal embrittlement is not an aging effect that requires management for the SSW system components that are included in this review, since the operating temperatures are too low for embrittlement.

Creep generally occurs at greater than 40% of the alloy melting temperature and is, therefore, not a significant aging mechanism at the temperatures in the SSW system.Neutron irradiation embrittlement is not significant since the valves and piping are located in regions of low neutron fluence.Wear is not a significant aging mechanism since there are no sliding surfaces and fretting will not occur for the rigid components in this aging management review.Stress corrosion cracking/intergranular attack are not applicable to titanium.The aging effects in this section required the review of the heat exchanger section of the mechanical tools for the raw water/titanium material/environment evaluation since this combination was not included in the raw water tool.PILLROO000665 Pilgrim License Renewal Project RTYPE A6.10 Aging Management Review of the Salt Service Water System AMRM-1 1 Revision 0 4.1 Water Chemistry Control Program The S SW system normally draws a suction from the intake structure.

The intake is treated to help to minimize the corrosion, but this program is not credited with total elimination of the effect of loss of material for carbon steel. The Water Chemistry Control Program in combination with the W-all Thinning Inspection Program are credited with managing the aging effects of loss of material from the internal carbon steel surfaces.

Due to inherent corrosion resistance, the only aging effect fcu5-mý , jiping internal su f IiTited loss of materiaif MIC is )reent. The hypochlorite added by the SW chemistry program is credited with the prevention of significant loss of materi~1 from MIG on the titanium piping. For additional information on the Water Chemistry Control Program, see LRPD-02, "Evaluation of Aging Management Programs".

4.2 Maintenance Rule Under the Pilgrim Maintenance Rule Program, system and structural walkdowns are conducted to detect and manage aging effects on structures and components.

For the Salt Service Water system, credit is taken for the Maintenance Rule Program to manage the effect of loss of material for external carbon steel components exposed to ambient conditions.

For additional information on the Maintenance Rule Program, see LRPD-02,"Evaluation of Aging Management Programs".

4.3 Wall Thinning Inspection Program Since the SSW system is reuired to b smicall qualified, sample inspections are required to verify that the carbon steel pipe and components are maintained with an adequate wall thicikness to remain seismically qualified.

Testing or inspections need to be performed to bound all carbon steel components with sample locations and frequency defined as required to provide a reasonable assurance that piping and components are maintained above the minimum thickness for seismic qualification.

The copper instrument tubing could also experience a loss of material, albeit lower than for carbon steel due to the inherent corrosion resistance of copper. The wall thinning of the copper tubing is to be managed by the wall thinning inspection program.For additional information on the required Wall Thinning Inspection Program, see LRPD-02, "Evaluation of Aging Management Programs".

4.4 Buried Pipe Inspection Program The buried pipe inspection program is credited with managing the aging effect of loss of material from the external surfaces of the buried carbon steel and titanium piping. For additional information on the required Buried Pipe Inspection Program, see LRPD-02,"Evaluation of Aging Management Programs".

PILLROO000671 From: IVY, TED S Sent: Thursday, June 16, 2005 12:12 PM To: Lach, David J Cc: FRONABARGER, DON

Subject:

RE: AMRM-17, AMRM-18 Fire Protection comments from System Engineering Importance:

High I On the buried piping question we have committed to do an inspection however the scope is not determined.

It may only be one system if the coating of all the in scope piping is coated the same. We don't plan on inspecting piping in each system unless forced to do so. This really doesn't tell you anything since the Nipe next to where you dug up may be degraded and you will never know it.On your chemistry sampling response we have credited operation of the engine to detect aging effects on the diesel fire pump and it was accepted for ANO-2 and Cook without crediting the water chemistry program. We don't want to change this since this is not what we did on VY and we have precedence for using this program without water chemistry.

It may be the NRC doesn't realize exactly what the fire protection program does for the fire diesel, but I would like to keep this information in our hip pocket if during the review the NRC raises the question.

We don't want to change our previous stance on using only the fire protection program.Ted S. Ivy, P.E.Entergy Services Inc.License Renewal Services N-GSB-45 1448 S.R.333 Russellville, AR 72802 Office- 479-858-5542 Cell i:; .-Fax: 479-858-5437

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Original Message -----From: Lach, David J Sent: Thursday, June 16, 2005 10:53 AM To: Mogolesko, Fred Cc: Trask, Timothy; Burke, Stephen; Almeida, Edward; Landry, Mathieu; IVY, TED S; FRONABARGER, DON;Chan, Laris; Brochu, Jill; ROLFSON, GREGORY A

Subject:

RE: AMRM-17, AMRM-18 Fire Protection comments from System Engineering Fred, My thanks to Mathieu for his review and comments on the Halon and H20 fire protection systems. lam providing responses to Mathieu's comments and note them below. I am at extension 8521 if Mathieu (or anyone else) would like to discuss these further.Mathieu's comment on sampling the engine coolant of the diesel fire pump is very good!. I am expecting comments from Laris on the AMRR on, or about 6/20. Therefore, we will incorporate Mathieu's comment as part of the comment resolution cycle to incorporate Laris' comments when we get them. That way we re-issue the AMRR back to you one time.If this is not OK, please let me know.PILLR00003618 From: COX, ALAN B Sent: Wednesday, October 19, 2005 6:31 PM To: IVY, TED S; POTTS, LORI; 'jrlingenfelter@earthlink.net' Cc: NICHOLS, WILLIAM L

Subject:

RE: RE: PNPS Buried Piping and Tanks Inspection Program I agree that we need to carefully couch this. However. it seems that if we find thinningi, we must determine what is causing it. If it is not internal corrosion, then we would have to dig it up anyway to determine the cause. ThMis technology will only help you if it can tell ou there is no unacceptable thinning.

We may be a little too strongq in yin te nology provides indication of wall thickness without excavation.

I think the technology may do this, but it hasn't been effectively demonstrated (or maybe it just hasn't gained general acceptance yet). I think we just want to give ourselves the option to use alternative methods if proven effective, so we don't have to change the commitment to do so.Alan Cox License Renewal Services 479.858.3173

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Original Message -----From: IVY, TED S Sent: Wednesday, October 19, 2005 4:42 PM To: POTTS, LORI; 'jrlingenfelter@earthlink.net' Cc: COX, ALAN B; NICHOLS, WILLIAM L

Subject:

RE: PNPS Buried Piping and Tanks Inspection Program The only problem I see with this is that this technology tell us that there is thinning but it cant tell us what is causing it. The other ques~tjiioha h nn ee-ven and can it be used for small bore piping such as fuel oil? No one has done this before and we need to be very careful.----- Original Message -----From: POTTS, LORI Sent: October 19, 2005 3:53:14 PM CDT To: 'jrlingenfelter@earthlink.net' Cc: COX, ALAN B;IVY, TED S;NICHOLS, WILLIAM L

Subject:

PNPS Buried Piping and Tanks Inspection Program Jacque, Due to a comment from the site, the subject program now has an exception to GALL (see below). Sorry, but notes will need to be changed.Attributes Affected Exception 4. Detection of Aging Effects Inspections via methods that allow assessment of pipe condition without excavation may be substituted for opportunistic inspections of excavated piping. (Note 1)Exception Notes PILLROO000293

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 coatings or wrappings.

Thanks,£ofii.)nn Potts Entergy License Renewal Services 1448 SR 333 Russellville , AR 72802 ANO-GSB-45 phone: 479-858-3529 email: Ipott90@entergy.com PILLROO000294 From: IVY, TED S Sent: Thursday, September 28, 2006 12:48 PM To: POTTS, LORI; COX, ALAN B

Subject:

RE: Region Inspection Item 569 -buried piping I've reviewed the attached document.

Minor editorial change that can be accepted or rejected.Unfortunately I don't know of any other way to approach this question unless we could possibly come up with something that shows the coatings installed on the in scope buried components are good for 40 years such that there is no reason to inspect prior to 40 years. The piping sec M300 doesn't cover coai.gs. O'Hara asked this question on the qualified life but I didn't have a good response at the time.I don't know if the site would have time to check into this.PILLR00000295

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Ite~m Recsuest Resoonse Lead Suoport Cateaorv Item Re uest ResDonse A --584 What is the manufacturer's recommended service life for coating and wrapping that has been applied to buried piping in accordance with PNPS Specification M306?For Field Coating, Tapecoat Co. "TC Cold Prime" and -CT Tape Coat" were applied.The Tapecoat Company was contacted."Conversations with Katie Simon (847-866-8500) yielded the following:

TC Cold Prime" was discontinued quite a while ago. In general, the Tapecoat products used are not expected to become degraded over time when properly applied.From Tapecoat Company Information:

Tapecoat CT -Cold Applied Tape Coating ]TAPECOAT CT -a 35 mil cold-applied tape coating with a 7 mil polyethylene film backing and 28 mils of adhesive, for ambient temperature below grade application.

Appropriate for coating small to moderate size pipe with a single layer; a 50% overlap may be preferred when coating larger diameter pipe.Buried Pipe Coating Warranties The coating product alone does not establish the expected service life of a protective coating system. Additional factors such as surface cleanliness, surface preparation, and severity of service (soil conditions) also play a large roll in expected service life. Since the manufacturer does not control applications he does not predict expected service life.Bechen, Gerry Mogolesko.

Fred-------------Open -NRC Reviewi///I//N N/",\.Redacted/ .C I//-0 I-I-0 0 0 Monday, November 19, 2007 Page 31 of 39 Pilgrim Nuclear Power Station Rocky Hill Road Plymouth, Massachusetts 02360 Ralph G. Bird Senior Vice President

-Nuclear September 9, 1988 BECo 88-133 U. S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555 License DPR-35 Docket 50-293 NRC BULLETIN 88-05, AND SUPPLEMENTS I and 2: NONCONFORMING MATERIALS SUPPLIED BY PIPING SUPPLIES, INC. AT FOLSOM, NEW JERSEY AND WEST JERSEY MANUFACTURING COMPANY AT WILLIAMSTOWN, NEW JERSEY

Dear Sir:

This letter provides Boston Edison Company's 120 Day response as requested by NRC Bulletin 88-05. The Bulletin 88-05 and Supplements 1 and 2 requested licensees to take actions to ensure that materials supplied by Piping Supplies, Inc. and West Jersey Manufacturing Company comply with ASME Code and design specification requirements and to ensure that these materials are suitable for their intended service or replace such materials.

In addition, licensees were requested to submit information regarding materials supplied by the two companies.

Upon receipt of NRC Bulletin 88-05, we initiated a review of records to identif qestionable,.materials supplied by WJM and PSI companies.

The testing and evaluation of identified questionable materials to determine the PILLR00005493 BOSTON EDISON COMPANY Nuclear Regulatory Comnmission Page Two o .I extent of conformance with ASME Code and design requirements, was suspended on Ayzta..-.U8J.8, as direrted b theNC in Supplement

2. A status report describing our records rev~ew--, s and analysis performed as of the date of Supplement 2 is attached to complete the 120 day reporting requirement specified in paragraph 1 of Bulletin 88-05.1.G -i rd Attachment NGL/amm/2421 Commonwealth of Massachusetts)

County of Plymouth Then personally appeared before me, Ralph G. Bird, who being duly sworn, did state that he is Senior Vice President

-Nuclear of Boston Edison Company and that he is duly authorized to execute and file the submittal contained herein In the name and on behalf of Boston Edison Company and that the statements in said submittal are true to the best of his nowledge and belief.My commission expires: DATE NOTARY PUBLIC L E cc: Mr. D. McDonald, Project Manager Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Station P1-137,,-Y

.Washington D. C. 20555 U. S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406 Senior NRC Resident Inspector Pilgrim Nuclear Power Station PILLR00005494 a BOSTON EDISON COMPANY Response to NRC Bulletin 88-05 and Supplements 1 & 2, Nonconforming Materials September 1988 PILLR00005495 Response to NRC Bulletin 88-05 1.0 Summary In response to the NRC Bulletin 88-05, the Boston Edison Company (BECo)implemented a comprehensive and multi-discipline effort at Pilgrim Nuclear Power Station (PNPS) to identify, locate and test material purchased from Piping Supplies, Inc. (PSI) and West Jersey Manufacturing (WJM) Company. This effort was divided into the following five tasks: a Review purchasing records to identify WJM and PSI supplied flanges and fittings.a Locate suspect material (i.e., installed in safety related/non-safety related plant systems or stored in the warehouse).

• Test suspect flanges and fittings.* Analyze test results.* Maintain a database of suspect flanges and fittings.In accordance with Supplement 2, issued August 3, 1988, BECo suspended field measurements, testing, records review and preparation of justifications for continued operation (JCOs). When these activities were suspended, BECo's review of purchase orders and material receipt inspection reports included approximately 15,000 items. The record search resulted in the identification of 212 flanges and three caps supplied by NJM and PSI. Fifty-two flanges were Io-f a 170 tanaes and two caps were locatedin -BECo's warehouse and the balance (l.e, 55 flanges and one cap) had nQLyet been lofc-aeT"-when Supplement 2 was issued. Table 1 presents a summary of installed OUi-warehouse flanges and fittings (i.e., system, size, pressure rating, etc.).Seventeen flanges were tested in situ prior to the issuance of Supplement 2.BECo personnel trained in the use of the Equotip Hardness method conducted the in situ tests. A1linstalledfJ]anges tested were found to be acceptable except one. The flange in question had a Brinnel HardnessN umber HN) of 112_-Tightly less than the acceptable BHN range (i.e., 137 to 187 BHN for ASTM A105). A subse ten.Lginr-xigevaluation concluded that this flange was acceptable for its intended application and, therefore, does not require replacement.

Thirty flanges from the warehouse were sent to a certified material test laboratory for destructive chemical and mechanical analysis.

The chemical analysis included the following elements:

carbon, manganese, phosphorous, sulfur and silicon. The mechanical properties included tensile strength (i.e., yield and ultimate), Brinell Hardness, elongation and reduction in area. The lab test results indicated that all flanges were acceptable and exceeded ASTM/ASME code requirements except for three. The tensile strength for those three flanges was slightly less than the allowable of 70,000 psi (i.e., 68,000, 69,500 and 68,000 psi) and one of the three flanges had a yield strength slightly less than the allowable of 36,000 psi (i.e., 35,500 psi, 1.4% below the allowable).

In addition, one warehouse flange was tested using the Equotip Hardness method and found acceptable.

Thus, a total of 31 warehouse flanges were tested.Page 1 PILLR00005498 A subsequent engineering evaluation indicated that these deviations were not significant and the flanges were, therefore, for the intended application.

All flanges and fittings supplied by WJM and PSI that were found in BECo's onsite wareh]jjusejbave been rem -ve.dadaxe~-steired in a BECo warehouse offsite. Currently, this material is segregated from other warehouse material and is marked "NRC Bulletin 88-05 Nonconforming Material -Do Not Use." BECo conducted a review of available industry data and determined that for identified installed flanges and fittings not yet tested at PNPS (as of the issuance of Supplement 2), none are fro eat-aumba iled hardness testing at other nuclear Dower stations.Page 2 PILLROO005499

)2.3 Supplement 2 Supplement 2, issued on Auqut 3 tempo.iy, the field measurements, testing, recoris rev ew, and he preparation of JCOs that were requested by Bulleti:n 88-05 and Supplement 1 until further notice. However, licensees were requested to analyze the test results performed to date. In addition to WJM and PSI, the NRC also identifie an fil eompGhews-Landing Metal Manufacturers, Inc., (CLM) which also appeared to have falsified CMTRs.Page 4 PILLROO005501 At the suspension of records search activities, an estimated 90% of the search had been completed.

No flanges or fittings from heat number 7218 were identified at PNPS.Once a flange or fitting was identified via the records search, the next task was to locate it within the plant or in the warehouses by a variety of methods.The BECo and Bechtel warehouses were physically walked down to locate and segregate flanges and fittings stamped with WJM or PSI identification stampings.

Each flange and fitting was documented as it was located on Nonconformance Reports (NCRs) and QC hold tags were issued.To locate flanges and fittings installed in the plant, relevant Plant Design Change (PDC) packages associated with the MRR or MRIR were researched.

Construction records for the PDCs were reviewed to determine the location of the flanges and fittings in the plant. When readily accessible, the actual stamping on the flange and fitting was verified by physical walkdown.

When not readily accessible due to ALARA considerations, installed insulation, staging requirements, etc., stampings were verified when the fitting or flange was tested. Each flange or fitting located in the plant was documented on a NCR and QC hold tags were issued.Supplement 2 was issued, 105 flanges and two caps had been located in warehouses and 52 flanges have been located in the plant. Of the flanges and fittings identified to date, 55 flanges and one cap remain to be located Table 1 indicates the quantities, sizes and ratings of the flanges and caps and the plant systems in which they are located or for which they were purchased.

Attachment I presents the data collected for each of the 215 flanges and fittings supplied by WJHM and PSI (e.g., intended application, material specification, type of the component, size, pressure rating, chain of purchase, etc).3.2 Bulletin and Supplement 1 Action Request 2 Bulletin Action Request 2 2. For ASME Code and ASTM materials furnished by PSI or WJM that are either not yet installed in safety-related systems at your facility or are installed in safety-related systems of plants under construction, the following actions are requested: (perform action a and either action b or c).a. provide a list of WJM- and PSI-supplied materials that are found not to be in conformance with the applicable code requirements or procurement specifications and identify the applications in which these materials are used or will be used. Include the material specification, the nature of the component (e.g., pipe flange), size and pressure rating; also indicate the chain of purchase, and either Page 8 PILLROO005505

b. Take actions that provide assurance that all received materials comply with ASME Code Section III, ASTM, and applicable procurement specification requirements, or that demonstrate that such materials are suitable for the intended service. For example, this program should include specific verification that austenitic stainless steels have been received in a non-sensitized condition, or, c. Replace all questionable fittings and flanges with materials that have been manufactured in full compliance with ASME Code Section III, ASTM, and the applicable procurement specification requirements.

Supplement I Action Request 2 2. The scope of paragraph 2 of Bulletin 88-05 is reduced from ASME and ASTM "materials" to ASME and ASTM "flanges and fittings." All other provisions of paragraph 2 of Bulletin 88-05 remain in effect.BECo Response In response to Action Request 2a, BECo conducted chemical and mechanical tests to determine if any flanges and fittings found in the warehouse were nonconforming.

As a result of these tests, three flanges (i.e., components 7.01, 7.02 and 7.03) were identified which did not meet the code requirements.

Table 4 presents the information requested in Action Request 2a.Lab test results for components 7.01, 7.02 and 7.03 indicated that component 7.01 was slightly less than the yield strength allowable of 36,000 psi (i.e., 35,500 psi, 1.4% below the allowable) and that the tensile strength for components 7.01, 7.02 and 7.03 was slightly less than the allowable of 70,000 psi (i.e., 68,000, 69,500 and 68,000 psi, respectively).

Note that these three flanges were from the same heat number (i.e., CKS).A subsequent engineering evaluation indicated that these deviations were 4pL signi-fl*&f~t and the flanges would, therefore, be acceptable for the intended In response to Action Request 2b, at the time Supplement 2 was issued, BECo had sent 30 of the 107 flanges and fittings located in the warehouse to a testing laboratory for detailed chemical and mechanical analysis.

The chemical analysis included the following elements:

carbon, manganese, sulfur, phosphorous and silicon. The mechanical properties included tensile strength (i.e., yield and ultimate), Brinnel Hardness, elongation and reduction in area. The testing lab used ASTM E30 for the chemical analysis and ASTM A370 for the mechanical testing. In addition, one warehouse flange was tested using the Equotip Hardness method and found acceptable.

Thus, a total of 31 warehouse flanges were tested.Table 5 presents a comparison between the CMTR values and those obtained in the lab test. These tests were used to provide assurance that all received materials comply with ASME Code Section III, ASTM and applicable procurement) specification requirements.

For detailed information, refer to the appropriate component number in Attachment 1.Page 9 PILLR00005506

)b. If any inaccessible flanges or fittings are identified, an analysis must be performed justifying continued operation.

c. All other provisions of paragraph 3 of Bulletin 88-05 remain in effect.BECo Response In response to Bulletin Action Request 3a and 3b, BECo conducted in situ testing to determine which installed flanges and fittings were nonconforming.

As a result of these tests, one flange (i.e. component 13.09) was identified which did not meet the code requirements based on the Equotip Hardness method. Component 13.09 represents a two inch ASTM A105 flange in the salt service water (SSW) pump cross-connect header. Table 6 presents the information requested in Bulletin Action Request 3a.Component 13.09 tested at 126 Brinell Hardness Number (BHN) based on the Equotip Hardness method. This was outside the 137 -187 BHN acceptance range.The heat number recorded on the CMTR and stamped on the flange was COX.A subsequent engineering evaluation determined that this deviation was not significant and that the flange was acceptable for this application.

The NRC Operations Center was notified on August 3, 1988, in accordance with the Bulletin.In response to Supplement 1 Action Request 3a, 17 of the 52 installed flanges and fittings had been tested using the Equotip Hardness method. Testing was subsequently suspended per Supplement 2.Temporary Procedure (TP)88-39 (see Attachment

2) was issued to control the testing of installed flanges and fittings.

This procedure included a table for converting the Equotip Hardness values to Brinell Hardness Numbers. Prior to in situ testing, BECo personnel were trained in the use of the Equotip Hardness method. Training consisted of a minimum of one half hour verbal instruction using Temporary Procedure (TP)88-39 and testing flanges which had been previously tested at the laboratory.'

Table 7 compares the results of the Equotip qualifying tests and the lab results.The results of the in situ testing are presented in Table B. Aled flanges tested fell (i.e., 137 to 187 BHN) ex .llt for discussed previous y.In response to Supplement 1 Action R est 3b, total of six flanneswe re inacc sible for in situ tttu. 22" ASTMFAT05TD 0# flanges in a-sec'ton of the). Two 2" 900# flanges, one on each scram dis arge vo ume s andpipe were located in a high radiation area.Page 11 PILLROO005508 The i~l"ur SSW flan are heat number 9321, supplied by PSI. Destructive testunused flanges in the warehouse from the same purchase order and heat number were used to assess mechanical and chemical properties of heat number 9321. The average yield strength for these 13 lab tests was 45,231 psi and ultimate strength was 75,692 psi (refer to Table 5, heat number 9321 for detailed.

results).

Furthermore, an in sitfuLr one accessSible ge omthe same4t. A-rine11Hardness of 185 was found(see Attachment 1, component 1.04).The two scram discharge flanges from heat number 37862, supplied by tJM, are considered inaccessible due to ALARA considerations.

In situ testing was performed on the four exposed scram discharge volume flanges installed from the same lot. Brfnell Hardness readings of 148r 144, 141 and 153 were found using the Equotip Hardness method (see Attachment 1, component numbers 9.01, 9.02, 9.04 and 9.05). These results are well within the acceptable range (i.e., 137 to 187 BHN). There were no flanges located in the warehouse with similar heat numbers for destructive testing.Subsequent n e n el s. a S W flrf-cheý fwo inaccessible scram d issharge olug japes e-r Y aacord3cewisth th eoulletrin, the NRC was notified on July 28, 1988, concerning all six flanges.In response to Bulletin Action Request 3c, the basis for continued plant operation is presented in the disposition of Nonconformance Reports (NCRs)88-54, 88-60 and 88-62. All documentation associated with this Bulletin is available for NRC inspection.

3.4 Bulletin Action Request 4 4. For any PSI or WJM supplied materials having suspect CMTRs and used in systems that are not safety-related, take actions commensurate with the function to be performed.

BECo Response Emphasis was placed on safety related components in an effort to locate these materials as quickly as possible.

However, during our search for "Q" flanges and fittings, some "non-Q" material was identified.

At the time Supplement 2 was issued, 21 non-Q flanges were located in the warehouse.

These flanges have been removed from PNPS, and stored in a BECo warehouse offsite. This material is segregated from other warehouse material and is marked "NRC Bulletin 88-05 Nonconforming Material --Do Not Use." Also, six flanges were purchased "Q" but were installed in the "non-Q" Augmented Offgas System.Page 12 PILLROO005509 TIt 112I4517W31/188 TABLE I#IR FU.LETIN gyS UM REPORT SYSTEM DESCRIPTION-No3 SfSTE ASSIBED ND) SYflM ASSIGNE ND SYSTM ASS! E NO3 SYSTM ASSIGNED ND3 S"SE ASSIGNED NO SYSTEM ASSISNED NO3 SYSTEM ASS1SE8 NO3 SYSM ASSIGNED VAIN STEAK PAIN STERN HAIN SEM CONROL 0 DRIV & HYDA RLIC SYSTEM 0BENTED OFF-BAS kMfTE OFF-US PRIMAf ATP1GEI COTROL PRIMtRY CONTAItffi ATNOSPHE CONRL RSWIDAL HEAT WK SYSTEM RESIUL HEAT MM SYTM RESIDIA HEAT EMU SYSTER RESIDUAL HEAT MVAL AT W SYTE RESIDUAL HEAT OM ST IRACTOR WE ISOLATION COOI.INB SYSTE"iTaR COR ISOLATION COOLIN" SYSTEM mum ME ISOLATION COOLIN8 SYSTEM HIGH PRSSM CO.Al INJUECTION SYSTEM HIGH PREE COOLANT INJECTION SYSEm HIGH PREESI COOLANT INJETION SYSTEM SAT SERVCE

-~SALT SRICEWATER SYSEM SIZE (IN.) PRESSU TYPE I 12 FL 1 38 FL I 600FL 2 15M FL6 2 151 FU 4 38 FLO 12 610FLO 6 13 FL6#H SI-TOTM #H 2 988 F.6 w* SiITUTAL w*8 12 FLO ffU -TOTA.6 1N FLO*H SLI-TflTPI.

• 0'3 13 Fi.a 4 8 Cw 4 15 FLO 4 301 FL6 o 151 FLB S-TOT L***36FLS m m m TOTAL vTY. 19TY.413 4 4 2 12 31 22 2 1 715 6 12 661i46 2 1 2 4, 1 4 2122 616 6 13 i-1-13 1 13 1 4 6 13 19 1 6 2131 213 4135 2131 2 13-1-413 NsWmi AMIBE. TESmTE 3 1 8 a 4 4 2 2 22 1 i3 3 2 9 46 16 2 a 4 3 6 8 3 3 3 3 3 3 3 3 3 3 3 3 2 3 3 3 4 3 3 3 6 31 3 31 3 31 3 II 1 31t 3 3-. INSTN.LED IN PLRm -NOT YET I QTY. AESSILE INACESSIBLE TESTED FOU I a I 1 2 13 3 1 4 15 3 3 3 9 1 6 4 22 I i 1 B 4 2 4 13 3 3 1 29 I I 1 36 6 31 1 13 3 a II 4 83 3 1 6 16 4 2 41 9 26 4 2 1 i 16 6 3 31 3 I1 6 3 1 6 2B 2 8 131 1 4 4 1 1 6 2 2 a 2I a 3 3 3 31 2 2 2 3 2 3 4 4 3 41 9.2 2 3 31 3.2 2 3 DI S 4 4 a I a 2 2 3 11 3 2 2 3 31 3 4 4 3 11 3 8 3 3 31 2 13 681 FLO 23 15FLO 2 13 FLO 3 151FLG m m (I) 'NO BYGM A6tGED- indicates that either the fittings have not baool phyically Located in the pisnt or tile ftttings "e in the warehluse Page 16 PILLR00005513 TOLE 11:45:17 DAUE: 3188/1l TAK.E I (CONT.)K S LLETIN

• gym EMIRIPTIOINI 1 SAL OSEE WATER SYSEN SALT M WATER Slma SALT SER VIECE WTER M SALT SERVICE WATER MYS'M CONTAIWIN AN REM SYSTM COMTAIWN N W OR MEN Six 6 Is FLS 12 1i FLB 22 12 FLO UTOT L *0 Is M3FLO 2a I FLS* 9WMUTIL I*Tmk I 1WO --1)TCS IN MU-1 MDT YET 41 33 3 11 5 5 i 5 3 1t 13 13 13 1 5 1 4 11 3 67 14 49 14 112 8 4 9 1 7 34 U III U 31 23.411 1 1 13 3 ! I I *24 1 1 1 215 113 117I I I I 3 3 1 17 I a9 56 31 11 46 6-I (1) 'N BY8W ASSINED indicates that either the fittings have not been physically located in the plant or the fittings are in the warehosle Page 17 PILLR0005514

~7J>~k4~\

L4 6 f From: Sejkora, Kenneth Sent: Wednesday, November 01,2006 9:40 AM To: Brochu, Jill

Subject:

FW: NRC questions on underground component leakage for license renewal Potentially Related To Discovery From: Chan, Laris Sent: Tuesday, June 06, 2006 11:02 AM To: Sejkora, Kenneth Cc: Mogolesko, Fred

Subject:

RE: NRC questions on underground component leakage for license renewal Ken: Thanks for your help Laris From: Seikora, Kenneth Sent: Tuesday, June 06, 2006 10:45 AM To: Chan, Laris; Burke, Stephen; Gaedtke, Joseph; Collis, Thomas; O'Meara, Michael; Mulcahy, Francis; Loomis, Larry; Smalley, Paul Cc: Mogolesko, Fred; Trask, Timothy; McElhinney, Thomas

Subject:

RE: NRC questions on underground component leakage for license renewal See answers below in blue -Ken Sejkora From: Chan, Laris Sent: Tuesday, June 06, 2006 9:33 AM To: Chan, Laris; Burke, Stephen; Gaedtke, Joseph; Collis, Thomas; O'Meara, Michael; Mulcahy, Francis; Loomis, Larry; Sejkora, Kenneth; Smalley, Paul Cc: Mogolesko, Fred; Trask, Timothy; McElhinney, Thomas

Subject:

RE: NRC questions on underground component leakage for license renewal Ken/Paul/Larry:

I asked the system engineers to help me respond to NRC's question on underground system leakage and may be these questions are better answer by you folks.Please answer the following questions:

[11] Confirm that you test the following systems fo radioactivity contaminants; o Standby gas treatment (Ken Sejkora) We do not monitor SBGT directly for radioactivity.

SBGT discharges only air (no liquids) to main stack, which is continuously monitored for radioactivity (noble gas, particulates, iodines; no tritium on continuous).

Gaseous release from Main Stack is sampled for tritium via monthly grab sample.o Salt service water (Paul Smalley) Daily grab sample, analyzed only for gamma emitters -no tritium analyses.o SBO diesel generator (Paul Smalley) We do not analyze anything (fuel orjacket water) from SBO for radioactivity.

No radioactive interfaces.

PILLROO004199 o Fuel oil (Paul Smalley) We do not analyze fuel oil for radioactivity.

No radioactive interfaces.

o Fire protection water (Paul Smalley) Fire water is sampled by monthly grab sample, and analyzed for gamma emitters only; no tritium analyses." Condensate storage (Larry Loomis) CST is considered a contaminated system, and CST water is analyzed monthly for gamma emitters.

Tritium analysis is not routinely performed, but based on past samples, tritium in CST is at equilibrium with tritium in reactor water.Reactor water tritium is analyzed monthly.[2] What trace element are you looking for, is tritium included?

It depends on system; tritium analyses are performed on some systems, but not others. See answers above.[3] Why is the system being tested? Is it because of suspected system underground leakage? None of the listed systems are tested to look for underground leakage, but some systems are monitored to detect potential cross-contamination..

SBGT is not "tested", but the air discharged from SBGT is monitored via the main stack. Salt service water and fire water are "tested" to monitor for cross-contamination in accordance with IE Bulletin 80-10. SBO and diesel fuel are not "tested", as there are no radioactive interfaces for these systems. CST is considered a radioactive system, and is sampled for routine monitoring/trending of radioactivity.

Please respond with your answer by end of day 6/6/06. Your assistance is greatly appreciated.

Laris From: Chan, Laris Sent: Tuesday, June 06, 2006 8:56 AM To: Burke, Stephen; Gaedtke, Joseph; Collis, Thomas; O'Meara, Michael; Mulcahy, Francis Cc: Mogolesko, Fred; Trask, Timothy

Subject:

NRC questions on underground component leakage for license renewal Gentlemen:

NRC has asked for responses for the following questions in preparation of the public hearings for license renewal. Please provide answers for these questions for your system;" Confirm no radioactively contaminated water in the systems that are covered by the Buried Piping and Tanks Inspection Program.o Standby gas treatment (Frank Mulcahy)o Salt service water (Joe Gaedtke)o SBO diesel generator (Tom Collis)o Fuel oil (Tom Collis)o Fire protection water (Steve Burke)o Condensate storage (Mike O'Meara)" Provide information on history of leakage from these systems for systems listed above (to be answer by system engineer who owns the system)PILLRO0004200

-9,ro7sma tcoa osaitions W January 5. 2006 Entergy Nuclear Operations, Inc.Pilgrim Nuclear Power Station 600 Rocky Hill Road Pl.mouth, MA 02360 Attention:

Mr. Jay Scheffer

Reference:

Results of Analysis of Groundwater Sample NRC License Renewal Pilgrim Station, Plymouth, Massachusetts

Dear Mr. Scheffer:

As discussed, Science Applications International Corporation Engineering (SAIC) provided assistance to Entergy Nuclear Operations, Inc. (Entergy) with the collection and analysis of a groundwater sample at the Entergy Nuclear Power facility located at the Pilgrim Station in Plymouth, MA. This letter confirms the completion of the groundwater sampling at MW-4 and presents the results of the laboratory analysis.

In addition., this letter provides a description of the level of effort conducted by SAIC in order to complete the sampling of the monitoring well. Documentation of this work is included in the attached Field Inspection Daily Reports.SAMPLE COLLECTION SAIC collected a groundwater sample from an existing monitoring well (MW-4) on October 27, 2005 at the Pilgrim Station. The depth to water and depth to the bottom of the well were measured using an electric coaxial water sounder, The depth to water was about 16.3 feet and the bottom of the well was approximately 25 feet below ground surface (BGS). Prior to collecting the water sample, SAIC purged approximately three well casing volumes of groundwater from the well using a new, clean, disposable plastic bailer. The disposable bailer was used to collect the sample for analysis.Purge water was collected in a five gallon bucket and discharged back into the well after sample collection was complete.

Approximately 2 gallons of water was purged from the well prior to sampling.The groundwater sample was field screened using a Horiba U-10 meter for pH, turbidity, dissolved oxygen, salinity, and temperature and submitted for additional analysis to the contract laboratory, Rhode Island Analytical, Warwick, RI. The sample was analyzed for chloridcs, phosphorous, sulfates, and pH. All sample containers were labeled and placed on ice in the field in preparation for delivery (via a laboratory courier) to the contract laboratory.

The sample was to be transported under chain-of custody. A copy of the analytical results and chain-of-custody form are attached.5.4 1 C (' neering, Inc., 10 Alain S'treet, lA 02X-47 Phon: ,5(;') 923-5100 -*x: (5.) 923.5110!PILLR00045349 January 5, 2006 Mr. Jay Scheffer Page 2 of 3 ANALYTICAL RESULTS A summary of the field measurements is provided below: Pa ".i:i;. .8ramaeter....:

U.:=::.nits

___ ___ __.___ ___ .i i .: -." ... !- ., Conductivity mS/cm 1.14 1.16 1.17 1.17 Dissolved Oxygen mg/L 3.83 3.50 3.20 3.30 pH 1-14 SU 4.76 .477 4.77 4.77 Salinity 0-4% 0.05 0.05 0.05 0.05 Temperature Degrees 17.3 17.4 17.3 17.2 Celsius Turbidity NTU 498 1 506 503 515 Per your request, the groundwater sample was tested for chlorides, phosphorous, sulfates, and pH. The results of the October 27., 2005 sampling are summarized below. The laboratory report for the October 2005 sampling is attached, P*r... eter j Vnits "Result 10/27105 chlorides, mg/L 420 Total Phosphate mg/t 0.26 (phosphorous) sulfate mg/L 16 pH 1-14 SU 6.2 The results of the analysis were faxed to your attention on November 11, 2005.SCOPE OF WORK On October 12, 2005 Stacic Ragusa met with Mr. Jay Scheffer and Mr. David Leach of Entergy. They escorted Mrs. Ragusa to the protected area of the site to collect a groundwater sample from MW-4. Mr. Scheffer and Mr.Leach remained onsite during the work activity.Prior to this site visit, Entery provided SAIC with an as-built drawing of the monitoring well. The drawing identified the diameter of the steel well riser pipe as approximately 1.75-inch diameter; however, the actual diameter of the steel well riser pipe was measured in the field to be approximately 1.0-inch diameter.

The well was proposed to be sampled using a 1.5-inch diameter plastic bailer, which was too large to lower down into the opening of the well riser pipe. Mrs. Ragusa was not able to collect a groundwater sample during the first site visit.Mrs, Ragusa also attempted to measure the depth to water and depth to the bottom of the well using an electric co-axial sounder; however, an obstruction in the well casing prevented Mrs. Ragusa from lowering the meter cable down into the well. The obstruction appeared to be plastic tubing located approximately 4-inches below the!0e , Lr.& U3 ,5tkeet v L ei,.?,.ii.e.

1A0, 02347 fIho ,re: (5 923- -.' 5 ,a.: ! 500; 923-5 01 PILLR00045350 July 17, 2006 Entergy Nuclear Operations, Inc.Pilgrim Nuclear Power Station 600 Rocky Hill Road Plymouth, MA 02360 Attention:

Mr. Jay Scheffer

Reference:

Results of Analysis of Groundwater Sample Monitoring Well 4 Pilgrim Station, Plymouth, Massachusetts

Dear Mr. Scheffer:

As discussed, Science Applications International Corporation Engineering (SAIC) provided assistance to Entergy Nuclear Operations, Inc. (Entergy) with the collection and analysis of a groundwater sample at the Entergy Nuclear Power facility located at the Pilgrim Station in Plymouth, MA. This letter confirms the completion of the groundwater sampling at MW-4 and presents the results of the field screening laboratory analyses.SAMPLE COLLECTION SAIC collected a groundwater sample from an existing monitoring well (MW-4) on June 13, 2006 at the Pilgrim Station (Work Order No. 0607-12526).

The depth to groundwater (i.e., static water level) and depth of the well measurements were measured using an electric coaxial water sounder. The depth to groundwater was about 17.36 feet and the bottom of the well was approximately 24.97 feet below ground surface (BGS). The reference point for the measurements was from the top of the riser pipe inside the well protective casing. The well measurements were made prior to purging for sample collection.

SAIC purged approximately three well casing volumes of groundwater from the well using new, clean, dedicated plastic tubing and a peristaltic pump prior to collecting the water sample. The new plastic tubing and pump were used to collect the sample for analyses.Purge water was collected in a five gallon bucket and discharged back into the well after sample collection was complete.

Approximately 5 gallons of water was purged from the well prior to sampling.The groundwater sample was field screened using a Horiba U- 10 meter for pH, conductivity, temperature, turbidity, and dissolved oxygen, and submitted for additional analyses to the contract laboratory, Rhode Island Analytical, Warwick, RI. The sample was analyzed for chlorides, phosphorous, sulfates, and pH. All sample containers were labeled and placed on ice in the field in preparation for delivery (via a laboratory courier) to the contract laboratory.

The sample was to be transported under chain-of custody. A copy of the analytical results and chain-of-custody form are attached.SAIC Engineering, Inc., a subsidiary of Science Applications International Corporation 10 Main Street / Lakeville, MA 02347 / tel: 508.923.5100

/ fax: 508.923.5101

/ www.saic.com PILLR00045343 July 17, 2006 Mr. Jay Scheffer Page 2 of 3 ANALYTICAL RESULTS Field Screening Results The field screening results are summarized in Table 1.TABLE 1 -Field Screening at MW-4 June 13, 2006 pH 1-14 SU 6.82 6.77 6.74 6.72 Conductivity pS/cm 633 641 654 670 Temperature Degrees 20.03 19.98 19.90 19.89 Temperature

__ Celsius Turbidity NTU 658 644 591 566 Dissolved Oxygen mg/L 2.30 2.51 2.76 2.77 Laboratory Results Per your request, the groundwater sample was tested for chlorides, phosphorous, sulfates, and pH. The inorganic analyses results are shown in Table 2.TABLE 2 -Laboratory Results for MW-4 June 13, 2006..ra e .. ... -10/27/05

...chlorides, mg/L 210 Total Phosphate mg/L 0.20 (phosphorous) sulfate mg/L <5.0 pH t-14 SU 6.3 A copy of the laboratory analytical results and chain-of-custody form are attached.Science Applications International Corporation PILLR00045344

---

tergy DATE: January 12, 2004 TO; Paul McNulty FROM: Gus Mavrikis

SUBJECT:

Pilgrim Nuclear Power Station Chemistry Corporate Assessment Pilgrim Nuclear Power Station Chemistry Program Corporate Assessment November 17-21, 2003 tXECUTIVE

SUMMARY

The team's evaluation of each performance objective and focus area is documented within the Strengths, Areas for Improvement (AFIs), and Noteworthy Observations contained in the body of this report. The team documented one Strength, six AFIs, and one Noteworthy Observation.

Overall the team found the PNPS Chemistry Program effective.

While effective, toe team did identify six Areas for Improvements (AFIs).The team found the Pilgrim staff to be hospitable, candid and supportive.

The Chemistry team was determined to be professional and customer service oriented.The Strength is summarized as follows: The routine and sustainable practice of performing electronic reviews of chemistry trends every other month and including technicians in these reviews allows a comprehensive view of plant chemistry performance that allows checks and adjustments to improve station chemistry performance.(CY-3.J)The Areas for Improvement are summarized as follows: " The availability and reliability of Hydrogen Water Chemistry Injection system does not meet industry or site standards reducing the effectiveness of the system to mitigate IGSCC (Intergranular Stress Corrosion Cracking) of reactor vessel internals and piping. (CY-1.E.4, CR-PNP-2003-04346)" The lack of post-UV anion diagnostic analysis as recommended by EPRI increases PNPS' potential for sulfate or chloride contamination of the CST, condensate, or reactor water system (CY-3.B, CR-PNPS-2003-3514)" The Chemistry organization has not been fully effective in the implementation of some Quality Control Measures to ensure reliable Bench Top Instrument availability and accuracy as required by ENN-CY-102. (CY-4 E, CR-PNP-2003-04281)

Page 2 PILLROO045108 Pilgrim Nuclear Power Station Chemistry Program Corporate Assessment November 17-21, 2003 CONCLUSIONS AND RECOMMENDATIONS Area for Improvement CY-1.E.4 The availability and reliability of Hydrogen Water Chemistry Injection system does not meet industry or site standards reducing the effectiveness of this system to mitigate IGSCC (intergranular stress corrosion cracking) of reactor vessel internals and piping.Examples;1. The hydrogen water chemistry injection system (Extended Test System)has tripped or cycled 15 times since May 2003. The system tripped or cycled 55 times during cycle 14.2. During the assessment the A train of the system was in service. The B train was not available and has not been since March 2003.3. Hydrogen injection occasionally trips due to a low oxygen signal from panel C-610 when condensation gets in the lines.4. Hydrogen Water Chemistry Availability currently is 83%. It will be very difficult to achieve the site goal of 95% by the end of the cycle.Actual or Potential Consequences Hydrogen addition is needed to protect the reactor internals from IGSCC.Temporary cycles of this system cause changes to the oxidation potential inside the reactor vessel and could cause increases in growth of existing cracks. There is also a potential for increased drywell dose rates.Failure to achieve availability rate of hydrogen injections will results in increased vessel inspections during outages. This will result in increase personnel dose and outage scope.Emergent work effects manpower and schedule efficiency.

Causes and Contributors There is a tendency to fix the immediate symptoms and get the system back in service and not take the time to assess the causes to prevent reoccurrence.

The station hasn't taken an integrated, multi-department approach to resolve the system problems.Page 6 PILLROO045112 Pilgrim Nuclear Power Station Chemistry Program Corporate Assessment November 17-21, 2003 CONCLUSIONS AND RECOMMENDATIONS

5. Trends are displayed on a large screen and are easily viewed to allow technicians see the results of their daily, weekly and monthly efforts. The station uses WinCDMS to trend data that is input by Technicians to support this program 6. Schedule adherence is trended to determine effectiveness of shift schedule.Area for Improvement CY-3.B The lack of post-UV anion diagnostic analysis as recommended by EPRI increases PNPS' potential for sulfate or chloride contamination of the CST, condensate and reactor water systems.Examples 1. Post-UV anion analysis is not done on plant waters that enter the reactor.This includes Waste Sample Tanks, Demineralized Water Storage Tanks, and Condensate Storage Tanks.2. Chemistry management indicated that post-UV analysis is not being considered for inclusion to the chemistry sampling program.3. Appendix B of the EPRI Guidelines recommends that a technical evaluation be performed if a recommended analysis or action is not performed.

There is no technical evaluation available stating why it is acceptable not to perform this analysis on plant water systems. It also recommends having the ability to perform this analysis for assessment of reactor water chemistry transients..

4. Results from a recent questionnaire sent to BWR Chemists indicate that 90%of BWRs perform this analysis.

PNPS was the only domestic BWR in the survey that is not performing the analysis.Actual or Potential Consequences Intrusion from undetected organochlorides and organosulfates can contaminate the condensate storage tanks resulting in increased chlorides or sulfates in the condensate system and reactor. Industry operating experience (OE) has shown that performing post-UV analysis during plant startup and operation can prevent sulfate excursions.

Current conductivity, sulfate analysis and TOC methods done at PNPS will not provide the information needed to prevent this.Page 10 PILLROO045116

.. .. ............

.V.y Item Request Response Lead Support Category j 584 What is the manufacturer's recommended service life for coating and wrapping that has been applied to buried piping in accordance with PNPS Specification M306?For Field Coating, Tapecoat Co. "'T Cold Prime" and "CT Tape Coat" were applied.The Tapecoat Company was contacted."Conversations with Katie Simon (847-866-8500) yielded the following:

TC Cold Prime" was discontinued quite a while ago. In general, the Tapecoat products used are not expected to become degraded over time when properly applied.From Tapecoat Company Information:

Tapecoat CT -Cold Applied Tape Coating iTAPECOAT CT -a 35 mU cold-applied tape coating with a 7 mil polyethylene film backing and 28 mils of adhesive, for ambient temperature below grade application.

Appropriate for coating small to moderate size pipe with a single layer; a 50% overlap may be preferred when coating larger diameter pipe.Buried Pipe Coating Warranties The coating product alone does not establish the expected service life of a protective coating system. Additional factors such as surface cleanliness, surface preparation, and severity of service (soil conditions) also play a large roll in expected service life. Since the manufacturer does not control applications he does not predict expected service life.Bechen, Gerry Mogolesko, Fred Open -NRC Reviewi/ I// I/ I// I/ I N / I/ / I N // I N I Redaoted/N N/N I N/N/"///.....N N-u I--i--0o 0 0 (3 Monday, November 19, 2007 Page 31 of 39..............-.

~-~~~-,'w--

--

Entergy CONDITION REPORT TCR-PNP-2000-01680 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 0710712000 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 07/0712000 00:00~12~ ci(ZI&V~A~LS~rzL' C Qr-J Ic) (~-~6 &cATh f~t3~ -(ZE: Qc~it7S~4Zd vL~2 ~L) S Condition

==

Description:==

WEEKLY SAMPLE OF THE CST SHOWS AN INCREASING TREND IN TOC LEVELS Immediate Action

Description:

Suggested Action

Description:

? V~ A-A~Z7~~v~f v~CJ L~-~+/----~cd~Is~I EQUIPMENT:

Tag Name REFERENCE ITEMS: Type Code CONVERTED PR Tag Suffix Name Comonent Code Process System Code 26 Description PR.00.1680 TRENDING (For Reference Purposes Only): Trend Type KEYWORDS Trend Code MAINT RULE I PILLR00044867 Entergy CONDITION REPORT ICR-PNP-2001-00435 I Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 01/25/2001 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 01/25/2001 00:00 Condition

==

Description:==

DOWNWARD TREND IN RX ECP Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tag Name Tag Suffix Name Component Code Process System Code 62 REFERENCE ITEMS: Type Code CONVERTED PR Description PR.01.0435 TRENDING (For Reference Purposes Only): Trend Type KEYWORDS Trend Code MAINT RULE I PILLR00044883 S Entetg I CONDITION REPORT JCR-PNP-2001-01643 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 04/13/2001 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:-N Initiated Date: 04/13/2001 00:00 Condition

==

Description:==

REACTOR WATER SULFATES TRENDING UPWARD SINCE JANUARY 2001. SULFATES HAVE INCREASED FROM APPROXIMATELY 1 PPB TO 2.3 PPB Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Taa Name Tae Suffix Name Component Code Process System Code 04 20A REFERENCE ITEMS: Tvye Code CONVERTED PR Description PR.01. ] 643 TRENDING (For Reference Purposes Only): Trend Type KEYWORDS Trend Code MAINT RULE PILLR00044897 I

Entergy CONDITION REPORT [CR-PNP-2004-00080 Originator:

McNulty,Paul J Originator Group: Tech Chemistry Mgmt Supervisor Name: Dietrich,Peter T Discovered Date: 01/1.212004 07:22 Originator Phone: 8096 Operability Required:

N Reportability Required:

N Initiated Date: 01/12/2004 07:31 Condition

==

Description:==

Increasing trend in 7-day integrated feedwater iron values over last 4 weeks, Average of L. I ppb from 12/15/03 now 1.8 ppb.Immediate Action

Description:

Document trend in problem report.Suggested Action

Description:

Continue to monitor. Trend attributed to two cond demins reaching 90 day cleaning criteria, drop in condensate temperatures and age of two resin beds scheduled for replacement in early 2004.TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=AN PI-=S WP=CE I PILLR00044981 I Entergy I CONDITION REPORT ICR-PNP-2003-02102 I Originator:

McNultyPaul J Originator Group: Tech Chemistry Mgmt Supervisor Name: Dietrich,Peter T Discovered Date: 05/14/2003 10:03 Originator Phone: 8096 Operability Required:

N Reportability Required:

N Initiated Date: 05/14/2003 10:19 Condition

==

Description:==

Reactor Water Chemistry Out of Specification from procedure 7.8.1 limits during power ascension:

Rx Sulfates 3.5 ppb, achievable limit 1.8 ppb Rx Chlorides 1.5 ppb, achievable limit 0.5 ppb Rx Conductivity

0. 19 uS/cm, achievable limit 0.1 uS/cm Rx Zinc 15 ppb. achievable limit 10 ppb Rx Water oxygen 250 ppb, achievable limit <2.0 ppb Recirc ECP, >-230 mV, achievable limit -450 mV Immediate Action

Description:

None Suggested Action

Description:

Evaluate and capture impact to reactor vessel and internals.

TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=EV PI=SI WP=CE Etergy I CONDITION REPORT [CR-PNP-2004-02,426 Originator:

DettermanDavid E Originator Group: Tech Chemistry Mgmt Supervisor Name: McNulty,Paul I Discovered Date: 08116/2004 14:37 Originator Phone: 8273 Operability Required:

N Reportability Required:

N Initiated Date: 08/16/2004 14:38 Condition

==

Description:==

Rx ECP value >achievable value due to loss of H2 injection Immediate Action

Description:

Notified CR Suggested Action

Description:

Trend EQUIPMENT:

Ta2 Name Tap Suffix Name Component Code Process System Code 68 TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=SM PI=SI WP=CE PILLR00045043 Entergy I CONDITION REPORT CR-PNP-2004-03691 Originator:

GarrellKenneth W Originator Group: Tech Chemistry Staff Supervisor Name: Detterman,David E Discovered Date: 11/22/2004 23:46 Originator Phone: 8137 Operability Required:

N Reportability Required:

N Initiated Date: I 1/2212004 23:50 Condition

==

Description:==

Reactor coolant conductivity exceeds achievable limit of 0.1 us (0.101 us)Immediate Action

Description:

none required, will trend conductivity Suggested Action

Description:

EQUIPMENT:

Tae Name Ta2 Suffix Name Component Code Process System Code 04 TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=AN PI=SI WP=CE I PILLR00045055 Entergy CONDITION REPORT FCR-PNP-2002-12237 Originator:

Loomis,LUrry Originator Group: Tech Services Staff Supervisor Name: McNulty,Paul J Discovered Date: 10/28/2002 17:23 Originator Phone: 8968 Operability Required:

N Reportability Required:

N Initiated Date: 10128/2002 17:33 Condition

==

Description:==

At -1610 on 10/28/02 I-PFW and CDE dissolved oxygen levels spiked to -500 and 400 ppb respectively.

Action level one for HPFW 02 is 200 ppb, By -1615 02 concentrationsreturned to normal. The cause is unknown but this occurred just prior to placing the V condensate polisher in recycle following URC.Immediate Action

Description:

Notified the CRS.Suggested Action

Description:

Systems should evaluate the cause, Oxygen excursions could cause a crud release. May also indicate leaking valves.EQUIPMENT:

Tag Name Ta2 Suffix Name Component Code Process System Code 06 I PILLR00045095 Entergy CONDITION REPORT CR-PNP-2000-02469 Originator:.

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 09/27/2000 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 09/27/20(X) 00:00 Condition

==

Description:==

AVG REACTOR WATER SILICA HAS INCREASED FROM 70 PPB TO 130 PPB SINCE FEBRUARY 2000. THIS HAS NO IMMEDIATE IMPACT ON REACTOR VESSEL AND PIPING CRACKING OR PERFORMANCE Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Ta2 Name Tag Suffix Name Component Code Process System Code 04 12 18 REFERENCE ITEMS: Type Code CONVERTED PR Description PR.00.2469 TRENDING (For Reference Purposes Only): Trend Type KEYWORDS Trend Code MAINT RULE I PILLR00044871 Entergy CONDITION REPORT -CR-PNP-2001-00510 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 01/29/2001 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 01/29/2001 00:00 Condition

==

Description:==

INCREASING TREND FOR 'A' RWCU EFFLUENT CONDUCTIVITY.

Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tag Name REFERENCE ITEMS: Type Code CONVERTED PR Tag Suffix Name Component Code Process System Code 12 Description PRo01.0510 TRENDING (For Reference Purposes Only): Trend Tyve KEYWORDS Trend Code MAINT RULE I-PILLR00044886

~5kk~fy ýTr S- ce I Entergy I CONDITION REPORT I CR-PNP-2001-04354 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 10/09/2001 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 10/09/2001 00:00 Condition

==

Description:==

INCREASING ADVERSE TREND WITH FEEDWATER IRON DURING PERIOD FROM 9/21 TO 10/3. VALUES TRENDING TOWARDS AND ABOVE 2.0 PPB WITH LATEST RESULT AT 2.8 PPB ABOVE THE GOAL OF 2.0 PPB Immediate Action

Description:

Suggested Action

Description:

EQUIPPMENT:

Ta2 Name Tag Suffix Name Component Code Process System Code 18 06 REFERENCE ITEMS: Type Code CONVERTED PR Description PRP- 1.4354 I PILLR00044900 I I E tergy CONDITION REPORT I CR-PNP-2004-00235 I I Originator:

McNultyPaul J Originator Group: Tech Chemistry Mgmt Supervisor Name: Dietrich,Peter T Discovered Date: 01/26/2004 10:41.Originator Phone: 8096 Operability Required:

N Reportability Required-N Initiated Date: 01/26/2004 10:44 Condition

==

Description:==

November/December chemistry trend meeting noted several reactor water samples detecting chloride levels above the limit of instrument detection.

Immediate Action

Description:

Performed trend on blank sample runs and found similar trend with ultra-pure water. This is a leading indicator that problem is with the instrument pertbrmance.

Suggested Action

Description:

Suspect trend is due to instrument.

Investigate further, document results and resolve to correct trend.EQUIPMENT:

Tag Name Tau Suffix Name Component Code Process System Code 64 TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=ER CRT=EF P1=S!WP=CE PILLR00044985 Entergy I CONDITION REPORT CR-PNP-2004-02430 Originator:

Detterman,David E Originator Group: Tech Chemistry Mgmt Supervisor Name: McNultyPa ut I Discovered Date: 08/16/2004 17:06 Originator Phone: 8273 Operability Required:

N Reportability Required:

N Initiated Date: 08116/2004 17:08 Condition

==

Description:==

Reactor water sulfates >achievable levels Immediate Action

Description:

Init CR Suggested Action

Description:

Trend and monitor more frequently during RWCU outage EQUIPMENT:

Tag Name TRENDING (For Reference Purposes Only): Trend Type rag Suffix Name Component Code Process System Code 04 Trend Code, KA=SM PI=SI WP-CE PILLR00045046 Entergy CONDITION REPORT ICR-PNP-2004-04003 Originator:

Nogas,Anthony A Originator Group: Tech Chemistry Staff Supervisor Name: Detterman.David E Discovered Date: 12/17/2004 21:45 Originator Phone: 8137 Operability Required:

Y Reportability Required:

Y Initiated Date: 12/19/2004 21:52 Condition

==

Description:==

Feedwater Iron above achievable level. This was a probable result of the loss of feedwater hydrogen injection on 12-16-2004.

Immediate Action

Description:

Notified Chemistry Supervision Suggested Action

Description:

Monitor feedwater iron TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=AN PI=SI WP=-CE PILLROO045058 Entergy CONDITION REPORT I CR-PNP-2000-02546 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 10/03/2000 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 10/03/2000 00:00 Condition

==

Description:==

REACTOR WATER CHLORIDES AND SULFATES INCREASED TO 11.2 AND 7.8 PPB RESPECTIVELY.

Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tag Name Tla Suffix Name Component Code Process System Code 04 18 06 REFERENCE ITEMS: Type Code CONVERTED PR Descrintion PR.00.2546 TRENDING (For Reference Purposes Only): Trend Type KEYWORDS Trend Code MAINT RULE I PILLR00044875 Entergy CONDITION REPORT CR-PNP-2001-00686 Originator:

CONVERTED DATA Originator Group: CONVERTED DATA Supervisor Name: CONVERTED DATA Discovered Date: 02/0512001 00:00 Originator Phone: 0 Operability Required:

N Reportability Required:

N Initiated Date: 02/05/2(0)1 00:00 Condition

==

Description:==

NOTED UPWARD TREND IN RX H20 CONDUCTIVITY Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Tag Name Taa Suffix Name Component Code Process System Code 02 04 06 REFERENCE ITEMS: Tvpe Code Description CONVERTED PR PR.01.0686 TRENDING (For Reference Purposes Only): Trend Type Trend Code KEYWORDS MAINT RULE PILLR00044889 S Entcrgy" CONDITION REPORT CR-PNP-2002-12563 i Originator:

LoomisLarry Originator Group: Tech Services Staff Supervisor Name: McNultyPaul J Discovered Date: 11/18/2002 08:58 Originator Phone: 8968 Operability Required:

Y Reportability Required:

N Initiated Date: 11/18/2002 09:14 Condition

==

Description:==

Recirc Electrochemical Corrosion Potential (ECP) is at -347 mVSHE and moving in the positive direction.

ECP is increasing with increasing core flow even with the hydrogen injection rate at 32 scfm. At the current rate of increase it is projected that ECP will go out of protection at >-230 mnVSHE in about a week, Immediate Action

Description:

Notified chemistry management, Operations and Alara.Suggested Action

Description:

t) Raise H- injection with the B' ETS train to an indicated 45 scfm which is actually 39 scfm. A temporary alternative would be to lower core flow.2) Alara should evaluate dose impact to station.3) Need to return either the 'A' or 'B' ETS train to full injection capabilities. (May need to inject hydrogen above 39 scfm before the end of the cycle.)EQUIPMENT:

Tae Name Tag Suffix Name Component Code Process System Code 73 REFERENCE ITEMS: Tvye Code ODMI RPR Description I, PILLR00044904 I Entergy CONDITION REPORT I CR-PNP-2004-02468 Originator:

Loomis,Larry Originator Group: Tech Services Staff Supervisor Name: McNulty, Paul J Discovered Date: 0811.8/2004 16:00 Originator Phone: 8968 Operability Required:

N Reportability Required:

N Initiated Date: 08/19/2004 16:33 Condition

==

Description:==

Reactor water chemistry analysis during RWCU outage indicated a small increase in sodium concentration.

This is likely due to a small seawater leak. Rough calculations estimate the leak at -0.14 GPD (530 mis/min).Immediate Action

Description:

Chemistry Superintendent notified.Suggested Action

Description:

Consider plan during RFO15 to check for condenser leaks including verifying condenser tube plug fittings are tight.EQUIPMENT:

Tae Name Tag Suffix Name Component Code Process System Code 12 REFERENCE ITEMS: Type Code ODMI Description TRENDING (For Reference Purposes Only): Trend Tyne Trend Code PI=SI WP--CE I PILLR00044991 Entergy [ CONDITION REPORT f CR-PNP-2004-01496 Originator:

Griffin, J Originator Group: Tech Chemistry Staff Supervisor Name: ReillyRobert M Discovered Date: 05/17/2004 14:10 Originator Phone: 8137 Operability Required:

N Reportability Required:

N Initiated Date: 05/17/2004 14:12 Condition

==

Description:==

Rx cond >0. I us Immediate Action

Description:

Suggested Action

Description:

EQUIPMENT:

Ta2 Name Tao Suffix Name Component Code Process System Code 04 TRENDING (For Reference Purposes Only): Trend Type Trend Code KA=SM PI=S1 WP=CE PILLR00045034 Entery CONDITION REPORT CR-PNP-2004-02556 Originator:

Aunaral,Mark R Originator Group: Tech Chemistry Staff Supervisor Name: ReillyRobert M Discovered Date: 08/30/2004 16:06 Originator Phone: 8137 Operability Required:

N Reportability Required:

N Initiated Date: 08/30/2004 16:08 Condition

==

Description:==

Reactor water oxygen and ECP greater than Achievable due to ETS trip.Immediate Action

Description:

Notified Chem Supervision and wrote CR.Suggested Action

Description:

EQUIPMENT:

Tag Name Tap-Suffix Name Comp4Code Process System Code TRENDING (For Reference Purposes Only): ,Trend Type 04 Trend Code WP=CE PI=Sl PILLROO045049 Entergy I CONDITION REPORT I CR-PNP-2004-04089 Originator:

Garrell,Kenneth W Originator Group: Tech Chemistry Staff Supervisor Name: Detterman,David E Discovered Date: 12/29/2004 18:29 Originator Phone: 8137 Operability Required:

N Reportability Required:

N Initiated Date: 12/29/2004 18:35 Condition

==

Description:==

feedwater ITon (Fe) greater than achievable value.Value 2.12 ppb.achievable limit 2.0 ppb.Immediate Action

Description:

continue sampling Suggested Action

Description:

TRENDING (For Reference Purposes Only): Trend Type Trend Code PI=sI WP--CE I PILLR00045063 Entergy CONDITION REPORT CR-PNP-2003-02536 Originator:

McNultyPaul J Originator Group: Tech Chemistry Mgmt Supervisor Name: DietrichPeter T Discovered Date: 06/25/2003 16:25 Originator Phone: 8096 Operability Required:

Y Reportability Required:

Y Initiated Date: 06/2512003 16:41 Condition

==

Description:==

Chemistry reactor water samples have not been representative for grab samples and in-line instrument readings when sampling from Rx Water Clean-up (RWCU) Inlet. RWCU samples appear to be a factor of 10 lower than actual as compared to 'B' Recirc samples.Immediate Action

Description:

1) Verified 'B' recirc is representative by closing the AO-220-45 and observing no change in conductivity (this allowed reverse flow sampling from RWCU before heat exchangers).

2) Notified control room.Suggested Action

Description:

1) Chemistry to take all future samples from 'B recirc until problem corrected.

2) Evaluated assurance that Tech Spec Surveillance limits of 4.6.B met (chloride, conductivity and iodines)3) Determine if compliance with Technical Specification Surveillances 3.6.B on reactor coolant chemistry samples were met.3) Evaluate wether in-line conductivity meter in control room is 'operable'.

4) Evaluate lining up flow from 'B' recirc to control room conduct.ivity meter.5) Determine reason for dilution of RWCU inlet via troubleshooting (MR 03112056).

Suggest bypass valve isolation or possible regenative heat exchanger leak.EQUIPMENT:

Tag Name Tag Suffix Name Comnonent Code Process System Code 04 REFERENCE ITEMS: Type Code ODMI Description TRENDING (For Reference Purposes Only): Trend Tyve Trend Code KA=SM WP--CE PI=SI PILLR00044938