ML063610360

Motion for Leave to Add Contentions and Motion to Add Contentions

ML063610360
Person / Time
Site:	Oyster Creek
Issue date:	12/20/2006
From:	Webster R Grandmothers, Mothers & More for Energy Safety, Jersey Shore Nuclear Watch, New Jersey Environmental Federation, New Jersey Public Interest Research Group (NJPIRG), Nuclear Information & Resource Service (NIRS), Rutgers Environmental Law Clinic, Sierra Club, New Jersey Chapter
To:	Abramson P, Anthony Baratta, Hawkens E Atomic Safety and Licensing Board Panel
Byrdsong A T
References
50-219-LR, ASLBP 06-844-01-LR, RAS 12801
Download: ML063610360 (127)

Text

IV In the Matter o AMERGEN E (License Rene Nuclear Gener*

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION OFFICE OF THE SECRETARY ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:

E. Roy Hawkens, Chair Dr. Paul B. Abramson Dr. Anthony J. Baratta DOCKETED USNRC December 20, 2006 (1:35pm)

OFFICE OF SECRETARY RULEMAKINGS AND ADJUDICATIONS STAFF f

NERGY COMPANY, LLC wval for the Oyster Creek ating Station)

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Docket No. 50-0219-LR

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ASLB No. 06-844-01-LR

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December 20, 2006

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MOTION FOR LEAVE TO ADD CONTENTIONS AND MOTION TO ADD CONTENTIONS PRELIMINARY STATEMENT Nuclear Information and Resource Service, Jersey Shore Nuclear Watch, Inc., Grandmothers, Mothers and More for Energy Safety, New Jersey Public Interest Research Group, New Jersey Sierra Club, and New Jersey Environmental Federation (collectively "Citizens") submit this Motion because AmerGen Energy Co. LLC ("AmerGen") has, for the fourth time, amended its proposals for managing the corrosion of the drywell shell, and has, for the first time, proposed to use ultrasonic ("UT") testing to monitor the thickness of the drywell shell in the embedded region. This region is below the sandbed, where the shell is sandwiched between concrete on the inside and the outside. Because many aspects of the proposed UT monitoring for the embedded region are wholly inadequate, Citizens seek leave to add a new contention concerning the proposed UT monitoring in the embedded region.

With regard to the sandbed region, AmerGen reported on December 3, 2006 that significant water has penetrated into the interior floor of the drywell and wet conditions on the inside are the normal operating environment. This means that corrosion at rates similar to those observed in the sandbed could be occurring on the inside of the drywell below the intersection of the interior floor and the steel.

Although AmerGen has just committed to taking UT measurements in the sandbed region from the Pae=5 C 41-0 A

outside, it has failed to include adequate monitoring of this area. Therefore, Citizens seek leave to add a new contention concerning the inadequacy of the proposed UT monitoring in the sandbed region from the outside.

NEW INFORMATION AVAILABLE The enclosure to a letter from Gallagher to NRC, dated December 3, 2006, Ex. ANC I

("Supplemental Information") and other information recently disclosed by AmerGen includes new commitments to carry out UT testing of the embedded region and the lower sandbed region in addition to new information about the current thickness of the drywell shell, routine wet conditions on the inside of the shell, and likely pathways for water to get to the exterior of the shell in the embedded region. This section summarizes this information.

I.

New Thickness Measurements Prior to the outage in October 2006, no thickness measurements had even been carried out in the embedded region. During the October outage AmerGen deepened an existing trench in Bay 5 by six inches to expose a limited area of the embedded region. Supplemental Information at 19. AmerGen then took 42 UT measurements in the newly exposed area. Id. The results showed that the average thickness had decreased from a nominal 1.154 inches to 1.113 inches, a loss of 0.041 inches.

The Supplemental Information is not as specific about the measurements that were taken from the outside of the shell in the sandbed region. It merely states that the thinnest point measured in 2006 was 0.602 inches versus 0.618 inches in 1992. Supplemental Information at 14. More detailed information recently submitted to the Advisory Committee on Reactor Safeguards ("ACRS") shows an apparent thinning of up to 0.039 inches. AmerGen ACRS Information Package, Ex. ANC 2 at 6-12. AmerGen attributes the cause of this thinning primarily to a change in measurement techniques and uncertainty, but acknowledges that corrosion could also be occurring on the inner surface of the drywell. Id. To address this concern, it has committed to repeating these measurements in 2008 and periodically thereafter. Id. at 14-15.

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II.

New Commitments Regarding UT Monitoring On December 3, 2006, AmerGen committed to taking UT measurements in the trench in Bay 5 in 2008 "at the same locations examined in 2006." Supplemental Information at 52-53. As discussed above, these locations included 42 UT measurements in the embedded region. AmerGen further committed to repeating these measurements "at refueling outages during the period of extended operation until the trenches are restored to the original design configuration...." Id. at 53. In addition, AmerGen committed to repeating all the UT measurements taken from the outside of the sandbed in 2008. Id. at 52.

Thereafter, AmerGen proposed to repeat the measurements for two bays per outage starting with Bays 1 and 13 in 2010, unless the examinations yield "unacceptable results," in which case all the bays will be inspected. Id. It is unclear from the commitment what AmerGen means by "unacceptable results."

III.

Wet Conditions on the Inside of the Embedded Shell Previously, AmerGen had considered water on the interior drywell floor a temporary outage condition. Id. at 18. However, when the filler material was removed from the existing trench in Bay 5approximately 5 inches of standing water was discovered in the bottom of the trench. Id. When AmerGen pumped water from the trench, it refilled at a slow rate. Ex. ANC 3. AmerGen thus decided to assume that under normal operating conditions the interior of drywell shell at or below the interior floor level is in contact with water. Supplemental Information at 21.

IV.

Pathways for Water to Reach the Exterior of the Drywell Shell in the Embedded Region AmerGen's latest submission to the ACRS reveals that the bottom of the drywell is below the level of the groundwater table. AmerGen ACRS Information Package, Ex. ANC 2 at 7-4. To respond to the concern that groundwater could contribute to corrosion in the embedded region, AmerGen claims that groundwater could not seep onto the exterior of the shell, but fails to provide any back up information.

Id. For example, although AmerGen argues that leakage from groundwater would also penetrate the Torus room, it fails to provide any figures for the rate at which water is being pumped from sumps in the Torus room. Id. at 7-5. Furthermore, as Dr. Hausler notes, the specifications for construction at Oyster Creek have not always provided a good guide to what was actually constructed. Memorandum of Dr. R.

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H. Hausler, dated December 19, 2006 ("Sixth Hausler Memo"), Ex. ANC 4 at 7. Thus, in the absence of any measurements of whether wet conditions prevail on the exterior of the drywell below the water table, this source of water to the lower portion of the exterior embedded region cannot be eliminated. Id.

Turning to the potential for water to come from above, AmerGen's latest submission to the ACRS acknowledges that in 1992 the concrete floor on the exterior of the drywell was "cratered with some craters adjacent to the shell. A few craters were big, about 12-13 feet long, 12-20 inches deep, and 8-12 inches wide." Ex. ANC 2 at 7-3. The reactor operator repaired the floor with epoxy in 1992, but an AmerGen document entitled "Determine Proper Sealant for DW Sandbed Floor Voids" generated on October 25, 2006 notes that "since 1996 inspections have found indications of the epoxy separating from the concrete." Ex. ANC 5. The document goes on to note that "the separated seams could potentially allow some water to get under the epoxy coating repair." Id. at 2.

Although AmerGen and the previous reactor operator failed to properly monitor for water draining from the sandbed drains, an NRC inspection in March 2006 found that water had been present in the sandbed drains but that AmerGen improperly disposed of the water before it could be sampled. Letter from Conte to Webster, dated November 9, 2006, Ex. ANC 6. Thus, water infiltrated into the exterior sandbed floor at times between 1969 and 1992, and between 1996 and 2006 and may do so again.

ARGUMENT I.

Specific Statement of the Contentions Petitioners must "provide a specific statement of the issue of law or fact to be raised or controverted." 10 C.F.R. § 2.309(f)(1)(i). The first new contention is:

The proposed UT monitoring program for the embedded region of the drywell shell is inadequate to ensure that safety margins will be maintained for any extended licensing period because the spatial scope of the monitoring is too restricted, a reasonable potential corrosion rate has not been developed, the proposed frequency of monitoring is not justified, and the monitoring could cease if AmerGen filled in the trench from which it proposes to do the monitoring.

The second new contention is:

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The proposed UT monitoring program for monitoring the lower portion of the sandbed region from the outside of the shell is inadequate to ensure that safety margins will be maintained for any extended licensing period because it fails to provide systematic monitoring of potential corrosion occurring from the inside of the drywell shell in the sandbed region.

H.

Explanation of Basis A.

Legal Requirements At this preliminary stage, Citizens do not have to submit admissible evidence to support their contention, rather they have to "[p]rovide a brief explanation of the basis for the contention," 10 C.F.R. § 2.309(f)(1)(ii), and "a concise statement of the alleged facts or expert opinions which support the...

petitioner's position." 10 C.F.R. § 2.309(f)(1)(v). This rule ensures that "full adjudicatory hearings are triggered only by those able to proffer... minimal factual and legal foundation in support of their contentions." In the Matter of Duke Energy Corp. (Oconee Nuclear Station, Units 1, 2, and 3), CLI 11, 49 N.R.C. 328, 334 (1999) (emphasis added). Thus, the Commission has indicated that where petitioners make technically meritorious contentions based upon diligent research and supported by valid information and expert opinion, the requirement for an adequate basis is more than satisfied.

B.

Issues Already Addressed by the ASLB As recognized by the ASLB in its decisions admitting the initial contention, Citizens had ample basis for the following points, which are also included in the bases for the new contentions:

i) the drywell shell is a safety structure, LBP-06-07 at 26; ii) water intruded into the sandbed region in the past causing severe corrosion; id. at 33.

iii) water either is intruding, or could intrude in the future, leading to corrosive conditions on the outside of the drywell shell in the sandbed region, id. at 36; and iv)

Citizens have adequately demonstrated representational standing. Id at 3-6.

C.

Deficiencies in the Proposed Embedded Region Monitoring Regime Even though the measured corrosion in the embedded region in Bay 5 was not very severe, it nonetheless affirms Dr. Hausler's previous assessments that such corrosion is possible. g..

Memorandum of Dr. Hausler, dated February 6, 2006, submitted as Ex. C to Motion to Add to Contentions, dated February 7, 2006. It also undercuts previous assertions from AmerGen that corrosion in the embedded region was unlikely. Furthermore, AmerGen established during the recent outage that water is routinely in contact with the inside of the drywell shell. Thus, it is possible that the thinnest areas 5

of the embedded region of the drywell shell have corrosion that is occurring from the inside and the outside. Finally, AmerGen has also recently revealed its assessment that water could have infiltrated into the floor at the bottom of the sandbed region for all but four of the thirty seven years that the reactor has been operating. Thus, as AmerGen has apparently recognized, UT monitoring of the embedded region is necessary.

As outlined in the contention, Citizens have identified many deficiencies in the proposed monitoring regime. Most glaring is that AmerGen did not choose to monitor the embedded region in a bay where the lower sandbed region is highly corroded. In fact, measurements taken in Bay 5 in 1992 show much less corrosion in the lower sandbed than measurements in Bays 1 or 13. Compare Ex. NC 3 at 15-16 with Ex. NC 3 at 10-12, 24-29. AmerGen has failed to even discuss whether the results in Bay 5 represent worst case conditions in the embedded region. As Dr. Hausler notes, "bay 5 was and is the least corroded, and is not the bay where the trench should have been deepened to assess the outside embedded area corrosion." Sixth Hausler Memo, Ex. ANC 4 at 4.

Recent NRC guidance requires applicants for license renewal to develop or establish a corrosion rate from past UT measurements or representative samples and then "demonstrate that the shell will have sufficient wall thickness to perform its function through the period of extended operation." 71 Fed. Reg 67,923 (November 24, 2006). Unfortunately, AmerGen has only one set of measurements of corrosion in the embedded region from the trench in Bay 5. This is insufficient to establish a corrosion rate because there is no way of knowing over which time period the corrosion occurred.

To establish the frequency of monitoring in the embedded region, AmerGen should establish the current smallest margin and apply a worst case corrosion rate and a projection of uncertainty to determine how quickly the region could lose margin. In the Supplemental Information AmerGen applies an acceptance criterion of 0.736 inches. Supplemental Information at 20. However, because neither the worst case current condition nor a worst case corrosion rate has been established, AmerGen is unable to determine what would be an appropriate monitoring frequency.

Finally, it appears from the text of the commitment that if ArnerGen decided to fill in the trench in Bay 5, the embedded region monitoring program would cease. Supplemental Information at 52-53.

This is facially unsatisfactory. AmerGen must commit to undertaking UT testing of the embedded region 6

until it is shown to be unnecessary. Having decided that the monitoring is necessary, AmerGen cannot cease the monitoring simply because it decides to fill in the trench.

D.

Deficiencies in the Proposed UT Monitoring of the Sandbed Region from the Outside of the Shell As discussed above, AmerGen has acknowledged that interior corrosion is possible because of the wet conditions on the inside of the shell below the interior floor. Supplemental Information at 14.

Because the new measurement registered an apparent thinning of the shell and interior corrosion is now a recognized issue, AmerGen has proposed to continue taking measurements from the outside of the shell at the same locations as it did in the October outage. Id. at 14-15. Dr. Hausler wholeheartedly concurs with AmeerGen that interior corrosion needs to be monitored. However, he points out that the points monitored from the outside of the shell in October were originally selected in 1992 on the basis of visual inspection of corrosion on the exterior, not on the basis of where interior corrosion would be most likely.

Sixth Hausler Memo at 4, Ex. NC 3 at 5.

In fact, interior corrosion would more likely occur as a "bathtub ring" below the concrete curb.

Id. Thus, any monitoring effort for interior corrosion should first focus on scanning the shell in the region of the sandbed immediately below the interior floor. Furthermore, the latest NRC guidance states that "when ultrasonic thickness measurements are performed, one foot square grids must be used, unless justified otherwise." 71 Fed. Reg. 67,923 (November 24, 2006). AmerGen should therefore do more than just take single measurements at points that were visually identified as having exterior corrosion.

Instead, it should systematically search areas that are most likely to be corroded from the interior using one foot square grids.

III.

The Scope of License Renewal Includes Corrosion of the Drywell Liner Petitioners are required to demonstrate that the issues raised in their contentions are within the scope of the proceeding, 10 C.F.R. § 2.309(f)(1)(iii). After extensive briefing of this issue, the ASLB concluded that corrosion of the drywell shell is within the scope of license renewal proceedings. In the Matter of AmerGen Energy Company (License Renewal for Oyster Creek Nuclear Generating Station),

LBP-06-07 (slip op. at,39-40) (February, 26, 2006). That finding directly applies to the current contentions, because they also concern corrosion of the drywell shell. Thus, the issue of scope is currently res judicata in this proceeding and is not subject to further dispute.

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IV. The New Contentions Raise Material Disputes The regulations require petitioners to "[d]emonstrate that the issue raised in the contention is material to the findings the N.R.C. must make to support the action that is involved in the proceeding."

10 C.F.R. § 2.309(f)(1)(iv). A showing of materiality is not an onerous requirement, because all that is needed is a "minimal showing that material facts are in dispute, indicating that a further inquiry is appropriate." Georgia Institute of Technology, CLI-95-12, 42 N.R.C. 111, 118 (1995); Final Rule, Rules of Practice for Domestic Licensing Proceedings - Procedural Changes in the Hearing Process, 54 Fed.

Reg. 33,171 (Aug. 11, 1989).

Here, AmerGen boldly concludes that at the end of the period of extended operation a margin of 0.336 inches would remain in the embedded region. Supplemental Information at 20. However, Dr.

Hausler concludes that AmerGen's scant knowledge about corrosion in the embedded region leads to great uncertainty about the integrity of this part of the drywell shell. Sixth Hausler Memo at 6. This dispute is clearly material because it cuts to the heart of relicensing proceedings, which are designed to ensure that applicants demonstrate that their age management regimes can maintain adequate safety margins. Because Citizens' expert disputes AmerGen's conclusion that the monitoring regime for the embedded region will ensure that safety margins are maintained throughout any period of extended operation, the first new contention raises a material dispute.

With regard to the second new contention, AmerGen does not explicitly state that the proposed monitoring regime will ensure that margins will be maintained for any extended period of licensed operation. However, AmerGen has asserted that "there are no additional revisions required to the LRA

[License Renewal Application]." Letter from Gallagher to NRC, dated December 3, 2006. In contrast, Citizens believe that because all parties agree that corrosion from the inside of the drywell shell is a possibility, the spatial scope of the UT monitoring from the outside of the sandbed region must be expanded to fully take account of this newly identified corrosion mechanism. Sixth Hausler Memo at 4.

Thus, the second new contention raises a material dispute.

V.

This Request Is Timely Petitioners may add new contentions after filing their initial petition, so long as they act in accordance with 10 C.F.R. § 2.3 09(f)(2). Entergy Nuclear Vermont Yankee, L.L.C. (Vermont Yankee 8

Nuclear Power Station), LBP-05-32, 62 NRC 813 (2005). The Commission's regulations allow for a "new contention" to be filed upon a showing that:.

(i) The information upon which the amended or new contention is based was not previously available; (ii) The information upon which the amended or new contention is based is materially different than information previously available; and (iii) The amended or new contention has been submitted in a timely fashion based on the availability of the subsequent information.

10 C.F.R. § 2.309(f)(2)(i)-(iii).

Now that AmerGen has committed to monitoring the embedded region during any extended licensing period and has committed to a new monitoring program for the exterior of the sandbed, the decisions of the Atomic Safety and Licensing Board ("ASLB") in this proceeding indicate that this motion in timely. For example, when the ASLB found that AmerGen's new commitment to increase the frequency of monitoring mooted Citizens' initial contention regarding the inadequacy of the proposed UT monitoring for the sandbed, the ASLB allowed Citizens to file a new contention, but required the new contention to be timely in accordance with 10 C.F.R. § 2.309(f). In the Matter of AmerGen Energy Company (License Renewal for Oyster Creek Nuclear Generating Station), LBP-06-16 (slip op. at 8-10),

(June 6, 2006). Subsequently, the ASLB found that Citizens had made a timely new contention that the frequency of the UT monitoring was inadequate, because Citizens based their new contention on the new commitment. In the Matter of AmerGen Energy Company (License Renewal for Oyster Creek Nuclear Generating Station), LBP-06-22 (slip op. at 14-20, 28-30) (October 10, 2006).

Further clarifying the law on timeliness, on a motion for reconsideration regarding the rejection of a previous contention about the spatial scope of the UT measurements in the sandbed, the ASLB commented that "the appropriate time for a challenge by Citizens to the spatial scope of AmerGen's UT measurements was promptly after AmerGen had docketed its December commitment [to take UT measurements from the inside of the drywell in the sandbed region]." In the Matter of AmerGen Energ Company (License Renewal for Oyster Creek Nuclear Generating Station), LBP-06-844 (slip op. at 5-6)

(November 20, 2006).

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Citizens are now moving to add a contention about the inadequacy of the UT monitoring of the embedded region 17 days after AmerGen first committed to perform UT monitoring in the embedded region. In addition, Citizens are seeking to contend that the program of UT monitoring from the outside of the sandbed must cover all areas where potentially significant corrosion could occur 17 days after AmerGen first committed to performing UT measurements from the outside of the sandbed region and revealed that water is routinely in contact with the interior of the drywell shell in the sandbed region.

Thus, like Vermont Yankee and in accordance with its rulings in this proceeding, the ASLB should now find that the new contentions meet the requirements of 10 C.F.R. § 2.3 09(f)(2)(i) and (ii) because they are based upon new commitments and information that were "not previously available," and are "materially different than information previously available."

Finally, the Commission interprets the "timely fashion," requirement of 10 C.F.R. § 2.309(f)(2)(iii) as being anywhere from twenty to thirty days from the availability of the new information upon which the new contention is based. In the Matter of Louisiana Energy Services, L.P., LBP 04-826 (June 30, 2005). Because this motion concerns the adequacy of new commitments made 17 days ago, it meets the 20 to 30 day requirement of 10 C.F.R. § 2.309(f)(2)(iii).

CONCLUSION For the forgoing reasons, the ASLB should grant leave for Citizens to add the proposed new contentions and admit the new contentions into this proceeding.

Respectfully submitted Richard Webster, Esq RUTGERS ENVIRONMENTAL LAW CLINIC Attorneys for Citizens Dated: December 20, 2006 10

UNITED STATES OF AMERICA BEFORE THE NUCLEAR REGULATORY COMMISSION OFFICE OF THE SECRETARY In the Matter of

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AMERGEN ENERGY COMPANY, LLC

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(License Renewal for the Oyster Creek

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Nuclear Generating Station)

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Docket No. 50-0219-LR ASLB No. 06-844-01-LR December 20, 2006 CERTIFICATE OF SERVICE I hereby certify that I caused the foregoing motion for leave to add contentions and motion to add contentions to be sent this 20th day of December, 2006 via email and U.S. Postal Service, as designated below, to each of the following:

Secretary of the Commission (Email and original and 2 copies via U.S Postal Service).

United States Nuclear Regulatory Commission Washington, DC 20555-0001 Attention: Rulemaking and Adjudications Staff Email: HEARINGDOCKET@NRC.GOV Administrative Judge E. Roy Hawkens, Chair (Email and U.S. Postal Service)

Atomic Safety and Licensing Board Panel Mail Stop - T-3 F23 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Email: erh@nrc.gov Administrative Judge Dr. Paul B. Abramson (Email and U.S. Postal Service)

Atomic Safety and Licensing Board Panel Mail Stop - T-3 F23 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Email: pbagnrc.gov I

Administrative Judge Dr. Anthony J. Baratta (Email and U.S. Postal Service)

Atomic Safety and Licensing Board Panel Mail Stop - T-3 F23 United States Nuclear Regulatory Commission Washington, DC 20555-0001 Email: ajb5@lnrc.gov Law Clerk Debra Wolf (Email and U.S. Postal Service)

Atomic Safety & Licensing Board Panel Mail Stop - T-3 F23 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 DAW 1 nrc.gov Office of General Counsel (Email and U.S. Postal Service)

United States Nuclear Regulatory Commission Washington, DC 20555-0001 Email : OGCMAILCENTER@NRC.GOV Mitzi Young (Email and U.S. Postal Service)

U.S. Nuclear Regulatory Commission Office of the General Counsel Mail Stop: 0-15 D21 Washington, DC 20555-0001 E-mail: may@nrc.gov Alex S. Polonsky, Esq. (Email and U.S. Postal Service)

Morgan, Lewis, & Bockius LLP 1111 Pennsylvania Avenue, NW Washington, DC 20004 Email: apolonsky@morganlewis.com Kathryn M. Sutton, Esq. (Email and U.S. Postal Service)

Morgan, Lewis, & Bockius LLP 1111 Pennsylvania Avenue, NW Washington, DC 20004 Email: ksutton@morganlewis.com Donald Silverman, Esq. (Email and U.S. Postal Service)

Morgan, Lewis, & Bockius LLP 1111 Pennsylvania Avenue, NW Washington, DC 20004 Email: dsilverman(iDmorganlewis.com 2

P J. Bradley Fewell (Email and U.S. Postal Service)

Exelon Corporation 200 Exelon Way, Suite 200 Kennett Square, PA 19348 bradley.fewell@exceloncorp.com John Covino, DAG (Email and U.S. Postal Service)

State of New Jersey Department of Law and Public Safety Office of the Attorney General Hughes Justice Complex 25 West Market Street P.O. Box 093 Trenton, NJ 08625 E-mail: john.corvino@dol.lps.state.nj.us Valerie Gray (Email and U.S. Postal Service)

State of New Jersey Department of Law and Public Safety Office of the Attorney General Hughes Justice Complex 25 West Market Street P.O. Box 093 Trenton, NJ 08625 E-mail: valerie.gray@dol.lps.state.nj.us.

Paul Gunter (Email and U.S. Postal Service)

Nuclear Information and Resource Service 1424 16th St. NW Suite 404 Washington, DC 20036 Email: pguntergnirs.org Edith Gbur (Email)

Jersey Shore Nuclear Watch, Inc.

364 Costa Mesa Drive. Toms River, New Jersey 08757 Email: gburl @comcast.net Paula Gotsch (Email)

GRAMMIES 205 6th Avenue Normandy Beach, New Jersey 08723 paulagotsch@verizon.net 3

Crystal Snedden (Email)

New Jersey Sierra Club 139 West Hanover Street Trenton New Jersey 08618 Email: Crystal. Sneddengsierraclub.org Adam Garber (Email)

New Jersey Public Interest Research Group 11 N. Willow St,

.Trenton, NJ 08608.

Email: agarbergnjpirg.org Peggy Sturmfels (Email)

New Jersey Environmental Federation 1002 Ocean Avenue Belmar, New Jersey 07319 Email: psturmfelsgcleanwater.org Michele Donato, Esq. (Email)

PO Box 145 Lavalette, NJ 08735 Email: mdonato@micheledonatoesq.com Signed:

j Richard Webster Dated: December 20, 2006 4

Exhibit ANC I

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AmerGen.

Michael P. Gallaghev, PE Telephone 62o.765.5958 An Exelon Company Vicm President w

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10 CFR 50 License Renewal Projects rnchaelp.gallagher@exloncorp.cor 10 CFR 51 AmrGen 10 CFR 54 200 ExIon Way KSA/2-E Kennett Square,PA 9348 2130-06-20426 December 3, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Oyster Creek Generating Station Facility Operating License No. DPR-16 NRC Docket No. 50-219

Subject:

Information from October 2006 Refueling Outage Supplementing AmerGen Energy Company, LLC (AmerGen) Application fora Renewed Operating License for Oyster Creek Generating Station (TAC No. MC7624)

References:

1. AmerGen's "Application for Renewed Operating License," Oyster Creek Generating Station, Letter 2130-05-20135, dated July 22, 2005

2. AmerGen's "Response to NRC Request for Additional Information, dated March 10, 2006, Related to Oyster Creek Generating Station License Renewal Application (TAC No. MC7624)," Letter 2130-06-20289, dated April 7, 2006

3. AmerGen's "Supplemental Information Related to the Aging Management Program for the Oyster Creek Drywall Shell, Associated with AmerGen's License Renewal Application (TAC No. MC7624)," Letter 2130-06-20353, dated June 20, 2006

4. AmerGen's "Additional Information.Concerning FSAR Supplement Supporting the Oyster Creek Generating Station License Renewal Application (TAC No.

MC7624)," Letter 2130-06-20356, dated July 7, 2006 In References 1 through 4, AmerGen provided detailed Information describing aging management reviews, aging management programs and commitments for future actions associated with the primary containment drywall shell, as part of its license renewal application (LRA) for the Oyster Creek Generating Station (Oyster Creek). In its recently completed Oyster Creek refueling outage, AmerGen performed many of the drywall shell Inspection activities that it had committed to perform prior to the period of extended operation.

Per 10 C.F.R. § 54.21, this submittal serves to update the LRA and the other referenced submittals with the results of the 2006 outage activities. For ease of review, various sections of the original LRA and related responses to NRC requests for additional information (RAts) have been updated to reflect the latest Information. To a great extent, the information learned during this outage confirmed the condition of the drywall as described in previous submittals.

December 3, 2006 Page 2 of 2 However, as a result of performing planned Inspections of the internal surface of the drywell shell In the trenches excavated In the concrete floor In 1986, AmerGen Identified an environmentlmaterlaVaglng effect combination that was not included In the LRA. Aging management reviews of this combination have been performed and, as a result, AmerGen has Identified additional aging management activities that will be Included In aging management programs associated with the drywall.

The Enclosure to this letter more fully describes these reviews and resultant aging management actMties. Updates to the affected portions of the LRA are provided, Including a revision to the License Renewal Commitment List (LRA Appendix A, Section A.5). The Commitment List update clearly Indicates the activities that are being added as part of this submittal.

AmerGen has performed a review to determine whether any additional aspects of the LRA require updating, given the recent.Identification of a new environment requiring evaluation In support of license renewal. Based on its review, AmerGen concludes that there are no additional revisions required to the LRA. This review has been documented in the corrective action program.

In addition, a consolidated summary of key drywall-related Inspections conducted during the outage, with a summary of the results, Is provided In the Enclosure.

If you have any questions, please contact Fred Polaski, Manager Licens6 Renewal, at 610-765-5935.

I declare under penalty of perjury that the foregoing Is true and correct.

Respectfully, Executed on

/.,/,.,

Michael P.Galge Vice President, License Renewal AmerGen Energy Company, LLC

Enclosure:

LRA Supplemental Information, Post-2006 Refueling Outage cc:

Regional Administrator, USNRC Region I, w/ Enclosures USNRC Project Manager, NRA - Ucense Renewal, Safety, w/Enclosures USNRC Project Manager, NRR - Ucense Renewal, Environmental, w/o Enclosures USNRC Project Manager, NRA - Project Manager, OCGS, w/o Enclosures USNRC Senior Resident Inspector, OCGS, w/ Enclosures Bureau of Nuclear Engineering, NJDEP, w/Enclosures File No. 05040

mrnrnmm~~

Enclosure Page 1 of74 Enclosure License Renewal Application Supplemental Information Post-2006 Refueling Outage Oyster Creek Generating Station License Renewal Application (TAC No. MC7624)

Note: Bold font has been used to designate additions made by this submittal to previously submitted documents.

Enclosure Page 2 of 74 Summary of Post-2006 Refuellno Outeae Supplement This submittal Is being made to update the LRA with Information that was Identified during the October/November 2006 (11R21) refueling outage. Included in this update are the results of various Inspections and activities performed which relate to the condition of the drywall shell.

Also, the LRA Is being updated to reflect the Identification of water In contact with the lower portion of the inside surface of the drywall shell.

As noted, this submittal provides the results of numerous visual and ultrasonic examinations performed on the drywall shell during the 1 R21 refueling outage. These results serve to confirm the condition of the drywell she!l as discussed In previous LRA correspondence.

During Inspections of the drywell shell that were performed as part of planned license renewal commitment Implementation, water was Identified In contact with the Interior surface of the drywall shell within an Inspection access trench. Moisture was Identified on the shell in a second trench. This was Indicative of water beneath the drywell floor surface, being In contact with both the drywall shell and drywall concrete. Although water Is present at times within the drywell during plant operation, LIRA preparation activities did not Identify this specific condition as a normal operating environment requiring aging management review and ongoing aging management activities because the drywall floor, curb and drainage system were designed to keep water away from the shell.

AmerGen entered this condition Into Its corrective action program. Various Investigations and corrective actions were undertaken during the outage to understand the condition and to minimize water from coming Into contact with the drywall shell and embedded concrete In the future. Corrective actions Implemented during 1 R21 Included repair of the drywall drainage trough and Installation of a moisture barrier between the drywall shell and concrete curb adjacent to the drywall floor. As described further In this Enclosure, AmerGen has also performed analysis concluding that the Impact of water on the Inner surface of the drywall shell and concrete fill slab Is Insignificant. tsaever, AmerGen has decided to treat the entire Internal surface of the lower drywall shell as a wetted component from an aging management perspective. Based upon this approach, additional aging management review activities have been performed and aging management program activities established for the drywall shell and moisture barrier. No additional aging management activities are required for the drywall concrete.

This submittal provides the results of these reviews, Including new aging management program activities and associated aging management commitments, For ease of comparison, the results of the outage Inspections and aging management reviews are presented as updates to previously submitted LRA Information and RAI responses. A consolidated summary of I R21 drywall Inspection activities, correlated to IWE Inspection Program commitments, Is also provided.

A specific listing of the contents of this Enclosure Is provided on the next page.

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. mmnm m--m Enclosure Page 3 of 74 Enclosure Contents LRA Scoping and Screening Results Update (Pages 4 -8) o Revised Section 2.4.1, Primary Containment (Page 4) o Revised Table 2.4.1, Primary Containment - Components Subject to Aging Management Review (Page 7)

LRA Aging Management Review Updates (Pages 9-35)

Revised Section 3.5.2.2, AMR Results Consistent With The GALL Report for Which Further Evaluation Is Recommended (Page 9)

Section 3.5.2.2.1 (Item 4), Loss of Material due to General, Pitting and Crevice Corrosion in Inaccessible Areas of Steel Shell or Liner Plate o

Revised Table 3.5.1 Item Number 3.5.1-13 (Page 30) o Excerpt from Table 3.5.2.1.1; Primary Containment, Summary of Aging Management Evaluation, updated with additional Line Items (Page 31)

LRA Appendix A and Appendix B updates (Pages 36 -64) o Revised Appendix A, Section A.1.27, ASME Section K IWE Program Description (Final Safety Analysis Report Supplement) (Page 36) o Revised Appendix A, Table A.5, License Renewal Commitment List, Item Number 27, ASME Section K Subsection IWE (Page 40) o Revised Appendix B, Section B.1.27, ASME Section K Subsection IWE, Aging Management Program Description (Page 49) o Revised Appendix B, Section B.1.31, Structures Monitoring Program Description (Page 59)

Updates to Other Relevant Correspondence (Pages 65 -69) o Update to Table i from response to RAI 4.7.2-1(d) to reflect 2006 outage measurements (Page 65) o Update to Table 2 from response to RAI 4.7.2-1(d) to reflect 2006 outage measurements (Page 68)

" Consolidated Tabulation of Ky Drywell Inspections Performed During 1R21 (Pages 70 - 74)

Note: Bold font has been used to designate additions made by this submittal to previously submitted documents.

Page 4 of 74 2.4.1 Primary ContaInment System Purpose The Primary Containment Structure Is comprised of the primary containment, containment penetrations, and Internal structures. The structure Is enclosed by the Reactor Building, which provides secondary containment, structural support, shielding, shelter, and protection, to the containment and components housed within, against external design basis events.

The primary containment Is a General Electric Mark I design end consists of a drywell, a pressure suppression chamber, and a vent system connecting the dryal and the suppression chamber. It Is designed, fabriceted, Inspected, and tested In accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section VIII, and Nuclear Code Casesl270N-5, 1271N and 1272N-5. The containment Is safety related, classified Seismic Class 1 structure.

The drywall Is a steel pressure vessel, In the shape of an Inverted light bulb, with a spherical lower section and a cylindrical upper section. The lower spherical section Is embedded externally In the reinforced concrete foundation and covered Internally by a till slab at the bottom of the drywell. The top portion of the drywell vessel consists of a steel head that Is removed during refueling operations. The head Is bolted to the drywall flange and Is sealed with a double seal arrangemenL Access Into the drywall Is through a personnel aldeockequipment hatch, with two mechanicelly Interlocked doors, and other access hatches.

The drywall houses the reactor. pressure vessel, the reactor coolant recirculation system, safety relief valves, electrornatic relief valves (EMRVs), branch connections of the reactor primary system, containment drywell spray header, and Internal structures discussed below. The drywall shell and the enclosing reactor building concrete are separated by an air gap to allow for differential thermal expansion between the shell and the concrete during any mode of plant operation.

The pressure suppression chamber Is a toroldel shaped, steel pressure vessel encircling the base of drywall. The suppression chamber, commonly called the torus, Is partially filled with derninereiized water and Includes Internal steel framing, end access hatches. The suppression chamber Is mounted on support structures that transmit loads to the reactor building foundation. Major components Inside the suppression chamber Include Emergency Core Cooling Systems (ECCS) suction strainera. which are connected to the ECCS suction header located outside the chamber, torus spray header, and Y-Quenchers.

The vent system consists often circular vent lines, which form a connection between the drywell and the pressure suppression chamber. The lines enter the suppression chamber through penetrations provided with expansion bellows end join Into a common header contained within the air space of the suppression chamber. The header discharge Is through 12(0downcomer pipes, which terminate below the water level In the torus. The header end the downoomer pipes are supported from the suppression chamber shell.

The primary containment Is provided with a vacuum breaker system to equalize the pressure between the drywell and the suppression chamber, end between the suppression chamber and the reactor building. The vacuum breaker system assures that the external design pressure limits of the two chambers are not exceeded.

The primary containment Is penetrated at several ioc~tlons by piping, Instrument lines,

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M Endcosure P.g. 5 of 74 ventilation ducts, and electric leads. The penetrations consist of sleeves welded to drywell vessel or suppression chamber end are of two general types. Those required to accommodate thermal movements; and those, which experience relatively little thermal stress. Penetrations required to accommodate thermal movements are provided with expansion bellows.

Internal structures consist of a fill slab, reactor pedestal, biological shield wall and Its lateral support, and structural steel. The fill slab Is reinforced concrete placed in the bottom of the drywall to provide a working base for supporting the reactor pedestal and other structures and components Inside the drywell. A curb Is provided above the fill slab around the drywell perimeter to prevent any water that collects on the floor from being In contact with the drywall shell. The curb Is removed at two locations where 2 trenches were excavated on the floor to allow UT thickness measurements to be taken below the floor. A moisture barrier was added at the junction of the curb and the drywell shell and Inside the trenches, during 2006 refueling outage to prevent water and moisture Intrusion Into the embedded drywell shell.

The reactor pedestal is a reinforced concrete cylinder with an outside diameter of 26 feet. The pedestal provides structural support to the reactor pressure vessel, the biological shield wall, and floor framing. The biological shield wall extends above the reactor pedestal and Is a composite steel, concrete cylinder with an inside diameter of approximately 21 feet. The wall is framed with steel columns covered with steel plate on each face and filled partly with normal density concrete and partly with high-density concrete. The top of the wall Is capped with a steel plate and laterally braced to the drywall vessel.

Structural steel Includes floor framing steel for the platforms Inside the drywall, and a catwalk inside the suppression chamber. It also includes miscellaneous steel Inside the containment such as grating, ladders, connection plates; electrical cable trays, and electrical conduits.

The purpose of the primary containment Is to accommodate, with a minimum of leakage, the pressures and temperatures resulting from the break of any enclosed process pipe; and thereby, to limit the release of radioactive fission products to values, which will insure offsite dose rates well below IOCFR100 guideline limits. it also provides a source of water for ECCS and for pressure suppression in the event of a loss-of-coolant accident. The primary containment and Internal structures also provide structural support to the reactor pressure vessel, the reactor coolant systems, and other safety and nonsafety related systems, structures, and components housed within. The biological shield wall provides the added function of radiation shielding to maintain drywall environment within equipment qualification parameters.

Included in the evaluation boun dary of the Primary Containment are the drywall, drywell head,

'suppression chamber, vent lines. downcomers, drywall and suppression chamber penetrations.

vent line bellows, drywall penetration bellows, personnel air lock/equipment and other hatches, pressure retaining bolting, thermowells, and Internal structures listed above.

Not Included In the evaluation boundary of the Primary Containment are safety relief valves and EMRVa,EMRV discharge lines, Y-Quenchers, drywall and torus spray headers, vacuum breakers, ECCS suction strainers and header, downcomer bracing, suppression chamber (torus) supports, and other component supports. These components are separately evaluated with their respective license renewal systems. That is, safety relief valves, EMRVs, EMRV discharge lines, and Y-Quenchers are evaluated with Main Steam System. Drywall and torus spray headers, and ECCS suction strainers and header are evaluated with the Containment Spray System. Vacuum breakers are evaluated with the Containment Vacuum Breakers Enclosure Pago 6 of 74 System. Downcomer bracing, suppression chamber supports, and other component supports are evaluated with the Component Supports Commodity Group.

For more detailed information, see UFSAR Sections 3.8 and 6.2 Reason for Scone Determination The Primary Containment meets the scoping requirements of 10 CFR 54.4(a)(1) because it Is a safety-related structure which Is relied upon to remain functional during and following design basis events. It meets 10 CFR 54.4(a)(2) because failure of nonsafety related portions of the structure could prevent satisfactory accomplishment of function(s) Identified for 10 CFR 54.4(a)(1). It also meets 10 CFR 54.4(a)(3) because It is relied upon In the safety analyses and plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48), ATWS (10 CFR 50.62), and Environmental Quallfication (10 CFR 50.49). The Primary Containment Is not relied upon In the safety analyses and plant evaluations to perform a function that demonstrates compliance with Station Blackout (10 CFR 50.63).

System Intended Functions

1. Controls the release of fission products to the secondary containment In the event of design basis loss-of-coolant accidents (LOCA) so that off site consequences are within acceptable limits. (10 CFR 54.4(a)(1))

2. Provides sufficient air and water volumes to absorb the energy released to the containment In the event of design basis event so that pressure Is within acceptable limits. (10 CFR 54.4(a)(1))

3. Provides a source of water for core spray, containment spray, and condensate transfer systems. (10 CFR 54.4(a)(1))

4. Provides physical support, shelter, and protection for safety related systems, structures, and components (SSCs). 10 CFR 54.4(a)(1)

5. Provides physical support, shelter, and protection for nonsafety related systems, structures, and components (SSCs) whose failure could prevent satisfactory accomplishment of function(s) Identified for 10 CFR 54.4(a)(1). 10 CFR 54.4(a)(2)

6. Relied upon In safety analyses or plant evaluations to perform a function that demonstrates compliance with the commission's regulations for Anticipated Transients without Scram (10 CFR 50.62). 10 CFR 54.4(a)(3)

7. Relied upon In safety analyses or plant evaluations to perform a function that demonstrates compliance with the commission's regulations for Fire Protection (10 CFR 50.48). 10 CFR 54.4(a)(3)

8. Relied upon In safety analyses or plant evaluations to perform a function that demonstrates compliance with the commission's regulations for Environmental Qudilfication (10 CFR 50.49).

10 CFR 54.4(a)(3)

UFSAR References 3.8 6.2 License Renewal Boundary Drawings LR-JC-19702

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Enclosure Page 7 of 74 Enclosuro Page 0 of 74 Table 2.4.1 Primary Containment Components Subject to Aging Management Review Component Type Intended Functions Access Hatch Covers Pressure Boundary Beam Seats Structural Support Biologlcal Shield Wall - Concrete Shielding Biological Shield Wall - Lateral Support Structural Support Biological Shield Wall - Liner Plate Structural Support Biological Shield Wall - Structural Steel Structural Support Cable Tray Structural Support Class MC Pressure Retaining Boltina Pressure Boundary Concrete embedment Structural Support Conduits Enclosure Protection Structural Sup ort Downcomers Pressure Boundary Drywell Head Pressure Boundary Structural Support Drywell Penetration Bellows Pressure Boundary Drywall Penetration Sleeves Pressure Boundary Structural Support Drywell Shell Pressure Boundary Structural Support Drywall Support Skirt Structural Support Liner (Sump)

Leakage Boundary Locks, Hinges, and Closure Mechanisms Pressure Boundary Structural Support Miscellaneous Steel (catwalks, handralis, Structural Support ladders, platforms, grating, and associated supports)

Moisture Barrier Leakage Boundary Panels and Enclosures Enclosure Protection Structural Support Penetration Closure. Plates and Caps Pressure Boundary (spare penetrations)

Personnel Aildock/Equlpment Hatch Pressure Boundary Reactor Pedestal Structural Support Reinforced Concrete Floor Slab (fill slab)

Enclosure Protection Structural Support Seals, Gaskets, and 0-rings Pressure Boundary Shielding Blocks and Plates Shielding Structural Boling Structural Support Structural Steel (radial beams, posts, Structural Support bracing, plate, connectlons. etc.)

Suppression Chamber Shell Pressure Boundary IStructural Support Suppresslon Chamber Shell Hoop Straps Structural Support Thermowells Pressure Boundary Vent Header Deflector HELB Shielding Vent Jet Deflectors HELB Shielding Vent line bellows Pressure Boundary Vent line, and Vent Header Pressure Boundary The aging management review results for these components are provided In Table 3.5.2.1.1 Primary Containment

-Summary of Aging Management Evaluaton Suppression Chamber Penetrations Pressure Boundary

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M m mm Enclosure Page 9 of 74 3.5.2.2 AMR Results Consistent Nth The GALL Report for Which Further Evaluation Is Recommended NUREG 1801 provides the basis for Identliying those programs that warrant further evaluation by the reviewer In the LRA. For the Containments, Structures, and Component Supports, those programs era addressed In the following subsections, 3.5.2.2.1 PWR and BWR Contelnments

1. Aging of Inaccessible Concrete Areas Cracking, spelling. and Increases In porosity and permeability due to aggressive chemical attack; and cracking, spelling, loss of bond, and loss of material due to corrosion of embedded steel could occur In, Inaccessible areas of PWR concrete and steel containments; BWR Mark II concrete containments; and Mark III concrete end steel containments.

The GALL report recommends further evaluation to manage the aging effects for Inaccessible areas if the environment Is aggressive.

This Is applicable only to PWR and BWR concrete containments. It Is not applicable to the Oyster Creek Mark I steel containment.

2. Cracks end distortion due to Increased stress levels from settlement; Reduction of Foundation Strength due to Erosion of Porous Concrete Subfoundations, If Not Covered by Structures Monitoring Program Cracking, distortion, and Increase In component stress level due to settlement could occur In PWR concrete and steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. Also, reduction of foundation strength due to erosion of porous concrete subfoundations could occur In all types of PWR and BWR containments. Some plants may rely on a de-wateaing system to lower the site ground water level. It the plant's CLB credits a de-waterdng system, the GALL report recommends verification of the continued functionality of the de-waterIng system during the period of extended operation. The GALL report recommends no further evaluation If this activity Is Included In the scope of the applicant's structures monitoring program.

This Is applicable only to PWR and BWR concrete containments. It Is not applicable to the Oyster Creek Mark I steel containment.

3. Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature Reduction of strength and modulus of elasticity due to elevated temperatures could occur In PWR concrete end steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. The GALL report recommends further evaluation if any Enclosure Page 10 of 74 portion of the concrete containment components exceeds specified temperature limits, I.e., general area temperature 66°C (150°F) and local area temperature g3°C (200°F).

The normal operating temperature Inside the Oyster Creek Primary Containment drywall varies from 139'F (at elev. 55') to 2568F (at elev.

95'). The containment structure Is a BWR Mark I steel containment, which Is not affected by general area temperature of 150"F and local area temperature of 200°F. Concrete for the reactor pedestal, and the drywell floor slab (fill slab) are located below elev. 55' and are not exposed to the elevated temperature. The biological shield wall extends from elev. 37'-3' to slev. 82'-2' and Is exposed to a temperature range of 139°F - 184°F.

The wall Is a composite steel-concrete cylinder surrounding the reactor vessel. It Is framed with 27 In. deep wide flange columns covered with steel plate on both sides. The area between the plates Is filled with high density concrete to satisfy the shielding requirements. The steel columns provide the Intended structural support function and the encased high density concrete provides shielding requirements. The encased concrete Is not accessible for Inspection.

The elevated drywell temperature concern was evaluated as a part of the Integrated Plant Assessment Systematic Evaluation Program (SEP Topic 111-7.B). The evaluation concluded that the temperature would not adversely affect the structural and shielding functions of the wall.

The elevated drywell temperature was also Identified as a concern for the reactor building drywall shield wall. Further evaluation for this wall Is discussed In subsection 3.5.2.2.2, item (8).

4. Loss of Material due to General, Pitting, and Crevice Corrosion In Inaccessible Areas of Steel Shell or Liner Plate Loss of material due to general, pitting and crevice corrosion could occur In Inaccessible areas of the steel containment shell or the steel liner plate for all types of PWR and BWR containments. The GALL report recommends further evaluation of plant-specific programs to manage this aging effect for Inaccessible areas if specific criteria defined in the GALL report cannot be satisfied.

At Oyster Creek, the potential for loss of material, due to corrosion, In Inaccessible areas of the containment drywall shell was first recognized In 1980 when water was discovered coming from the sand bed region drains. Corrosion was later confirmed by ultrasonic thickness (UT) measurements taken during the 1986 refueling outage. As a result, several corrective actions were Initiated to determine the extent of corrosion, evaluate the Integrity of the drywell, mitigate accelerated corrosion, and monitor the condition of containment surfaces. The corrective actions Include extensive UT measurements of the drywell shell thickness, removal of the sand In the sand bed region, cleaning and coating exterior surfaces In areas where sand was removed, and an engineering evaluation to confirm the drywall structural Integrity. A corrosion monitoring program was established, In 1987, for the drywell

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Enclosure Page 11 of 74 shell above the sand bed region to ensure that the containment vessel Is capable of performing its Intended functions. Elements of the program have been incorporated Into the ASME Section XI, Subsection IWE (B.1.27) and provide for.

" Periodic UT Inspections of the shell thickness at critical locations,

" Calculations which establish conservative corrosion rates, Projections of the shell thickness based on the conservative corrosion rates, and

" Demonstration that the minimum required shell thickness is In accordance with ASME code.

Additionally, the NRC was notified of this potential generic issue that later became the subject of NRC Information Notice 86-99 and Generic Letter 87-05. A summary of the operating experience, monitoring activities, and corrective actions taken to ensure that the primary containment will perform Its Intended functions Is discussed below.

Drywall Shell In the Sand Bed Region:

The drywall shell Is fabricated from ASTM A-212-61T Gr. B steel plate.

The shell was coated on the Inside surface with an Inorganic zinc (Carbollne carbozinc 11) and on the outside surface with "Red Lead' primer Identified as TT-P-86C Type I. The red lead coating covered the entire exterior of the vessel from elevation 8' 11.25" (Fill slab level) to elevation 94' (below drywall flange).

The sand bed region was filled with dry sand as specified by ASTM 633.

Leakage of water from the sand bed drains was observed during the 1980 and 1983 refueling outages. A series of Investigations were performed to Identify the source of the water and Its leak path. The results concluded that the source of water was from the reactor cavity, which Is flooded during refueling outages.

As a result of the presence of water In the sand bed region, extensive UT thickness measurements (about 1000) of the drywall shell were taken to determine if degradation was occurring. These measurements corresponded to known water leeks and indicated that wall thinning had occurred In this region.

Because of the reduced thickness readings, two trenches were excavated In 1986 Inside the drywell to Inspect the embedded drywall shell below the drywall Interior concrete floor In areas -

corresponding to the exterior sandbed region. The sandbed region was Inaccessible at that time. UT thickness measurements were obtained Inside the two trenches In 1986 and In 1988 to determine the vertical profile of the thinning. One trench was excavated Inside the drywall, In the concrete floor, in the area corresponding to the exterior sandbed region where thinning was most severe (bay #17). A second trench wasexcavated In bay #5 In the area corresponding to the exterior sand bed region where thinning of the drywall shell at the concrete floor level was less severe. UT measurements of the Enclosure Page 12 of 74 drywall shell exposed In the bay #17 trench demonstrated that thinning of the embedded shell In concrete %as no more severe than thinning of the'unembedded shell thatfwds already being monitored.

UT measurements of the drywall shell exposed In the bay #5 trench demonstrated less significant thinning In the embedded shell. Aside from UT thickness measurements performed by plant staff, Independent analysis was performed by the EPRI NDE Center and the GE Ultra Image III "C" scan topographical mapping system. The Independent tests confirmed the UT results. The GE Ultra Image results were used as a baseline profile to track future corrosion.

To validate UT measurements and characterize the form of damage and its cause (i.e., due to the presence of contaminants, microbiological spades, or both) core samples of the drywall shell were obtained at seven locations In 1986, The core samples validated the UT measurements and confirmed that the corrosion of the exterior of the drywall was due to the presence of oxygenated wet sand and exacerbated by the presence of chloride and sulfate In the sand bed region. A contaminate concentrating mechanism due to alternate wetting and drying of the sand may have also contributed to the corrosion phenomenon. It was therefore concluded that the optimum method for mitigating the corrosion was by (1) removal of the sand to break up the galvanic cell, (2) removal of the corrosion product from the shell and (3) application of a protective coating.

Removal of sand was Initiated during 1988 by removing sheet metal from around the vent headers to provide access to the sand bed from the Torus room. During operating cycle 13 some sand was removed and access holes were cut Into the sand bed region through the shield wall.

The work was finished In December 1992. After sand removal, the concrete surface below the sand was found to be unfinished with improper provisions for water drainage. Corrective actions taken In this region during 1992 Included; (1) cleaning of loose rust from the drywall shell, followed by application of epoxy coating and (2) removing the loose debris from the concrete floor followed by rebuilding and reshaping the floor with epoxy to allow drainage of any water that may leak Into the region. UT measurements taken from the outside after cleaning verified the loss of material projections that had been made based on measurements taken from the Inside of the drywall. There were, however, some areas thinner than projected; but In all cases engineering analysis determined that the drywell shell thickness satisfied ASME code requirements. The Protective Costing Monitoring and Maintenance Program was revised to Include monitoring of the coatings of exterior surfaces of the drywall In the sand bed region.

AmerOen had visually Inspected (VT-1) the epoxy coating on the exterior of the drywall shell In the sandbed region In selected bays during refueling outages In 1994,1996,2000, and 2004. During the 2006 refueling outage (1R21), AmerGan conducted VT-1 Inspections of the epoxy coating In ell ten bays In accordance with ASME Section XI, Subsection IWE, and AmerGen's Protective Coating

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Enclosure Page 13 of 74 Monitoring and Maintenance Program. These Inspections would have documented any flaking, blastering, peeling, discoloration, and other signs of degradation of the coating. The VT-i Inspections found the coating to be In good condition with no degradation.

Based on these VT-1 Inspections, AmerGen has confirmed that no further corrosion of the drywall shell Is occurring from the exterior of the epoxy-coated sandbed region. Monitoring of the coating In accordance with the ASME Section XI, Subsection iWE and AmerGen's Protective Costing Monitoring and Maintenance Program will continue to ensure that the drywall shell maintains Its intended function during the period of extended operation.

Also during the 2006 refueling outage (1R21), AmerGen performed UT of the drywall shell In the sandbed region from Inside the drywell, at the same 19 grid locations where UT was performed In 1992,1994, and 1996. Location of the UT grid Is centered at elevation 11'-3" In an area of the drywall shell that corresponds to the aandbed region.

The 2006 UT measurements were made and statistically analyzed In accordance with the enhanced Oyster Creek ASME Section XI, Subsection iWE (51.27) Aging Management Program. The results of the statistical analysis of the 2006 UT data were compared to the 19924 1994 and 1996 data statistical analysis results (see below).

Some of the 1996 data contained anomalies that are not readily Justifiable but the anomalies did not significantly change the results.

The comparison confirmed that corrosion on the exterior surfaces of the drywall shell In the sandbed region has been arrested.

Analysis of the 2006 UT data, at the 10 grid locations, Indicates that the minimum measured 95% confidence level mean thickness In any bay Is 0.807" (bay #19). This Is compared to the 95% confidence level minimum measured mean thickness In bay #19 of 0.806" and 0.800" measured In 1994 and 1992 respeotively. Considering the Instrument accuracy of *0.010" these values are considered equivalent Thus the minimum drywall shell mean thickness at the grid locations remains greater than 0.736" as required to satisfy the worst case buckling analysis, and the minimum available margin of 64 mils for any bay reported prior to taking 2006 UT thickness measurements remains bounded.

In addition to the UT measurements at the 19 grid locations, a total of 294 UT thickness measurements were taken In the bay #5 trench and 290 measurements were taken In the bay #17 trench during the 2005 refueling outage. The computed mean thickness value of the drywall shell taken within the two trenches Is 1.074" for bay #5 and 0.986" for bay #17. These values, when compared to the 1986 mean thickness values of 1.112" for the bay #5 trench and 1.024" for the bay #17 trench, Indicated that wall thinning of approximately 0.038" has taken place In each trench since 1986. Engineering evaluation of the results concluded that considering that the exterior surface of Enclosure Page 14 of 74 bay #5 had experienced a corrosion rate of up to 11.3 milslyr between 1986 and 1992 and the exterior surface of bay #17 had experienced a corrosion rate of up to 21.1 milslyr In the same period, the 0.038" wall thinning measured In 2006 Is due to corrosion on the exterior surface of the drywall between 1986 and 1992.

Additionally the 95% confidence level minimum computed drywell shell mean thickness based on 2006 UT measurements within the two trenches Is greater by a margin of 250 mils than the minimum required thickness of 0.736" for buckling. Also this margin Is significantly greater than the minimum computed margin outside the trenches (64 mil). Individual points within the two trenches met the local thickness acceptance criterion of 0.490"for pressure computed based on ASME Section III, Subsection NE, Class MC Components, Paragraph NE-321312 Gross Structural Discontinuity, NE-32t3.10 Local Primary Membrane Stress, NE 3332.1 Openings not Requiring Reinforcement, NE-3332.2 Required Area of Reinforcement and NE-3335.1 Reinforcement of Multiple Openings.

The Individual points also met a local buckling criterion of 0.536" previously established by engineering analysis.

The above UT thickness measurements were supplemented by additional UT measurements taken at 106 points from outside the drywall In the sandbed region, distributed among the ten bays. The locations of these measurements were established In 1992 as being the thinnest local areas based on visual Inspection of the exterior surface of the drywall shall before It was coated. The thinnest location measured In 2006 Is 0.602" versus 0.616" measured In 1992.

The difference between the two measurements does not necessarily mean a wall thinning of 0.016" has taken place since 1992. This Is because the 2006 UT data could not be compared directly with the 1992 data due to the difference In UT Instruments and measurement technique used In 2006, and the uncertainty associated with precisely Iocating the 1992 UT 'points. A review of the 2006 date for the 106 external locations Indicated that the measured local thickness Is greater than the local acceptance criteria of 0.490" for pressure and 0.536" for local bucking.

As stated above, the 2006 UT data of the locally thinned areas (106 points) could not be correlated directly with the corresponding 1992 UT data. This Is largely due to using a more accurate UT Instrument and the procedure used to tke the measurements, which Involved moving the Instrument within the locally thinned area In order to locate the minimum thickness In that area. In addition the Inner drywall shell surface could be subject to some Insignificant corrosion due to water Intrusion onto the embedded shell (see discussion below). For these reasons the Oyster Creek ASME Section Xl, Subsection IWE Program (B.1.27) will be further enhanced to require UT measurements of the locally thinned areas

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Enclosure Page 15 of 74 In 2008 and periodically during the period of extended operation as explained below.

Drvwell Shell above Sand Bed Region:

The UT Investigation phase (1986 through 1991) also Identified loss of material, due to corrosion, In the Upper regions of the drywall shell.

These regions were handled separately from the sand bed region because of the significant difference In corrosion rate and physical difference In design. Corrective action for these regions involved providing a corrosion allowance by demonstrating, through analysis, that the original drywell design pressure was conservative. Amendment 165 to the Oyster Creek Technical Specifications reduced the drywall design pressure from 62 psig to 44 psIg. The new design pressure coupled with measures to prevent water Intrusion Into the gap between the drywall shell and the concrete will allow the upper portion of the drywell to meet ASME code requirements.

Originally, the knowledge of the extent of corrosion was based on UT measurements going completely around the Inside of the drywell at several elevations. At each elevation, a beat-line sweep was used with readings taken on as little as 11" centers wherever thickness changed between successive nominal 6" centers. Six-by-six gdds that exhibited the worst metal loss around each elevation were established using this approach and included In the Drywall Corrosion Inspection Program.

As experience Increased with each data collection campaign, only grids showing evidence of a change were retained In the Inspection program.

Additional assurance regarding the adequacy of this Inspection plan was obtained by a completely randomized inspection, Involving 49 gdds that showed that all Inspection locations satisfied ASME code requirements.

Evaluation of UT measurements taken through 2000 concluded that corrosion Is no longer occurring at two (2) elevations (51'10" and 60'10"), the 3" elevation (50'2") Is undergoing a corrosion rate of 0.6 mins/year, while the 4e elevation (87'5") is subject to 1.2 mils/year. The UT measurements taken In 2004 confirmed thatthe corrosion rate continued to decline, The two elevations that previously exhibited no Increase In corrosion continued to show no additional corrosion. The rate of corrosion for the 3'd elevation decreased from 0.6 mlislyear to 0.4 milstyear. The rate of corrosion for the 4' elevation decreased from 1.2 mils/year to 0.75 mils/year. After each UT examination campaign, an engineering analysis was performed to ensure the required minimum thickness Is provided through the period of extended operation. Thus corrosion of the drywell shell Is considered a TLAA further described In Section 4.7.2.

During the 2006 refueling outage (1R21i, UT thickness measurements were taken at the 4 elevations discussed above In accordance with the Oyster Creek ASME Section XI, Subsection IWE aging management program. The results of the UT thickness measurements Indlcated that no observable corrosion Is occurring Enclosure Page 16 of 74 at elevations 51' 10" and 60' 10". A single location (Bay 15 -23L) of the 3V* elevation (50 '2") continues to experience minor corrosion at a rate of 0.66 milslyr. The corrosion rate for the 4e elevation (87' 5")

Is now statistically Insignificant and this elevation can be considered as no longer undergoing observable corrosion.

In addition UT measurements were taken on 2 locations (bay #15 and bay #17) at elevation 23' 6" where the circumferential weld joins the bottom spherical plates and the middle spherical plates. This weld joins plates that are 1.154" thick to the plates that are 0.770" thick. These two bays were selected because they are among those that have historically experienced the most corrosion In the sandbed region. At each location 49 UTs were taken above the weld on the 0.770" thick plate and 49 UT. were taken below the weld on the 1.154" thick plate. The minimum average thickness measured on the 0.770" thick plate Is 0.766" and 1.160" on the 1.154" thick plate. The loss of material of 0.004" (0.770" - 0.766") In the 0.7TO" thick plate Is Insignificant and Is bounded by corrosion experienced In other areas of the drywell above the sandbed region.

The thicker plate (1.154") appears not to have experienced observable corrosion.

The minimum measured local thickness on the 0.770" thick plate Is 0.628" and on the 1.154" thick plate Is 0.867". The minimum required general thickness to satisfy ASME Code stress requirements Is 0.541" for the 0.770" thick plate and 0.736" for the 1.154" thick plate. Thus, the minimum margin at these locations Is 225 mils (0.766 -0.541).

The minimum required local thickness to satisfy ASME Code stress requirements Is 0.490" for 1.154" thick plate and 0.360" for the 0.770" thick plate. The minimum local thickness margin Is 268 mils (0.628-0.360).

UT measurements were also taken on 2 locations (bay #15 and bay

1. 19) at elevation 71' 6" where the circumferential weld Joins the transition plates (referred to as the knuckle plates) between the cylinder and the sphere. This weld joins the knuckle plates, which are 2.625" thick to the cylinder plates, which are 0.640" thick. These two bays were selected because they also have historically experienced the most corrosion In the sandbed region. At each location 49 UTW were taken above the weld on the 0.640" thick plate and 49 UTs were taken below the weld on the 2.625" thick plate. The minimum measured average thickness on the 0.640" thick plate Is 0.624". and 2.630" on the 2.625" thick plate. The loss of material of 0.016" (0.640" - 0.624") In the 0.640" thick plate Is Insignificant end Is bounded by corrosion experienced In other areas of the drywall above the sandbed region. The minimum measured average thickness of 0.624" meats the minimum thickness of 0.452" required to satisfy ASME stress requirements with a margin of 172 mile. The minimum measured local thickness on the 0.640" thick plate of 0.449" meets the minimum thickness of 0.300" required to satisfy ASME local stress requirements with a margin of 149 mils.

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m Enclosure Page 17 of 74 For the 2.625" plate, the minimum measured average thickness of 2.530" meets the minimum thickness of 2.260" required to satisfy ASME stress requirements with a margin of 270 mils. The loss of material of 0.095" (2.625-2.530) appears to be greater then other periodically monitored locations In the upper regions of the drywell.

However the loss of material could be a result of other factors such as a variation in the original nominal plate thickness, and removal of the materiel during Joint preparation for welding and not entirely due to corrosion. Even If the loss of material Is attributed entirely to corrosion, the available thickness margin of 270 mile Is adequate to ensure that the intended function of the drywell Is not Impacted before the next Inspection planned for 2010 as discussed below. The minimum measured local thickness Is 2.428", which Is also greater than the minimum required general thickness of 2.260".

Since the 2006 readings are the first UT thickness measurements taken at plate transition at elevation 23'0" and 71'1", a corrosion rate specific to these areas is not established. AmerGen has committed to take UT measurements In 2010 in these areas to confirm that corrosion Is bounded by areas of the upper drywall that are monitored periodically. If corrosion In these locations is greater than areas monitored In the upper drywall, UT Inspections of the areas will be performed on a frequency of every other refueling outage (Commitment 27.10, 27.11 In AmerGen Letter No. 2130 20358 dated July 7, 2006).

inner Drywall Shell In the Embedded Reglon In 1986, as part of an ongoing effort at the Oyster Creek Generating Station to Investigate the Impact of water on the outer drywall shell, concrete was excavated at two locations inside the drywell (referred to as trenches) to expose the drywall shell below the Elevation 10'-

3" concrete floor level to allow ultrasonic (UT) measurements to be taken to characterize the vertical profile of corrosion in the sand bed region outside the shell. The trenches (approximately 18" wide) were located In Bays 5 and 17 with the bottom of the trenches at approximate elevations 8'-9" and 9'-3" respectively (The elevation of the sand bed region floor outside the drywall Is approximately 8'-

11").

Following UT examinations In 1986 and 1988, the exposed shell In the trenches was prepped and coated and the trenches were filled with Dow Coming 3-6548 silicone RTV foam covered with a protective layer of Promatic low density silicone elastomer to the height of the concrete floor (Elevation 10'-3"). The assumption was that these materials would prevent water that might be present on the concrete floor from entering the trenches. Before the 2006 outage these materials had not been removed from the trenches since 1988.

Enclosure Page 18 of 74 During the preparation of a response to NRC question AMR-164 In April 2006 during the Aging Management Review Audit, an Internal memo was Identified that Indicated the Intermittent presence of water In the two trenches Inside the drywell. This was not an expected condition. That memo, dated January 3, 1995 was referenced In a 1996 Structural Monitoring Walkdown Report but was not entered into the Corrective Action Process such that It could be considered as Operating Experience Input to the Aging Management Program reviews.

Based on activities performed under the Structures Monitoring Program and IWE Inspection program, and the reviews performed In support of the Ucense Renewal Application, the water on the drywell floor and potentially Inside the trenches was previously considered a temporary outage condition and not an operating environment for the embedded shell. However, In Its response to NRC Aging Management Review Audit question AMR-164, AmerGen committed to Inspect the condition of the drywell Interior shell In the trench areas end to evaluate any Identified degradation prior to entering the period of extended operation (Commitment 27.5 In AmerGen Letter No. 2130-06-20358 dated July 7,2006). The results of these Inspections and associated corrective actions are described below.

During the October 2006 refueling outage, the filler material from the two trenches was removed to allow Inspection of the shell In accordance with commitment #27.5. Upon removal of the filler material, approximately 5" of standing water was discovered In the trench located in bay #5. The trench area In bay #17 was damp; but no standing water was observed. Investigations concluded that the likely source of water was a deteriorated drainpipe connection end a void In the bottom of the Sub-Pile Room drainage trough, or condensation within the drywell that either fell to the floor or washed down the Inside of the drywall shell to the concrete floor. Water samples taken from the trench In bay #5 were tested and determined to be non-aggressive with pH (8.40 - 10.21), chlorides (13.6 - 14.6 ppm), and sulfates (228 -230 ppm). The joint between the concrete floor and the drywell shell had not been sealed to prevent water from coming In contact with the Inner drywell shell. The degraded trough drainage system and the unsealed gap between the concrete slablcurb and the Interior surface of the drywall shell was first discovered during this October 2006 refueling outage. This condition was entered Into the Corrective Action Process (IR 546049). The following corrective actions were taken during the October 2006 refueling outage.

Walkdowns, drawing reviews, tracer testing and chemistry samples were performed to Identify the potential sources of water In the trenches.

e Standing water was removed from trench In bay #5 to allow visual Inspection and UT examination of the drywall shell.

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" An engineering evaluation was performed by a structural engineer, reviewed by an Industry corrosion expert, and an Independent third-party expert to determine the Impact of the as-found water on the continued Integrity of the drywell.

" Field repairsl/modificatlons were Implemented to mitigateaminimize future water Intrusion Into the area between the shell and the concrete floor. These repairsl/modifications consisted of:

o Repair of the trough concrete In the area under the reactor vessel to prevent water from potentially migrating through the concrete and reaching the drywall shell rather than reaching the drywell sump, o Caulking the Interface between the drywall shell and the drywell concrete flooricurb to prevent water from reaching the embedded shell and o

Groutinglcaulklng the concrete/drywell shell Interfaces In the trench areas.

" The trench In bay #5 was excavated to uncover an additional 6" of the Internal drywall shell surface for Inspection and allow UT thickness measurements to be taken In an area of the shell that was embedded by concrete.

" Visual Inspection of the drywell shell within the trenches was performed.

" A total of 584 UT thickness measurements were taken using a 6"x6" template (49 points) within the two trenches. Forty-two (42) additional UT measurements were taken In the newly exposed area In bay #5.

Visual examination of the drywall shell within the two trenches Initially Identified minor surface rust; with water In bay #5 and moisture In bay #17. After the surfaces were cleaned with a flapper wheel (lightly to avoid removing the metal) a visual examination of the shell was conducted In accordance with ASME Section Xl, Subsection IWE. The visual examination Identified no recordable (significant) corrosion on the Inner surface of shell.

As discussed previously, a total of 294 UT thickness measurements were taken In the bay #5 trench and 290 measurements were taken In the bay #17 trench during 2006 refueling outage. The results of the measurements Indicated that the drywall shell In the trench areas experienced a reduction In the average thickness of 0.038"since 1986. AmerGen's evaluation concluded that the wall thinning was a result of corrosion on the exterior surface of the drywell shell In the sandbed region between 1986 and 1992 when the sand was still In place and corrosion was known to exist.

An engineering evaluation of the Oyster Creak Inner drywall shell condition was prepared by a structural engineer and reviewed by an Industry corrosion expert end Independent third-party expert to determine the Impact of the as-found water on the continued Enclosure Page 20 of 74 Integrity of the drywall shell. The evaluation utilized water chemical analysis, visual Inspections and UT examinations. It concluded that the measured water chemistry values and the lack of any Indications of rebar degradation or concrete surface spalling suggest that the protective passive film established during concrete Installation at the embedded steel/concrete Interface Is still Intact and significant corrosion of the drywall shell would not be expected as long as this benign environment Is maintained. Therefore, since the concrete environment complies with the EPRI concrete structure guidelines, corrosion would not be considered significant within the Oyster Creek drywall end the water could remain In contact with the Interior drywell shell Indefinitely without having long term adverse effects.

More specifically, the results of this engineering evaluation Indicate that no significant corrosion of the Inner surface of the embedded drywell shell would be anticipated for the following reasons:

" The existing water In contact with the drywall shell has been In contact with the adjacent concrete. The concrete Is alkaline which Increases the pH of the water and, In turn, Inhibits corrosion. This high pH water contains levels of Impurities that are significantly below the EPRI embedded steel guidelines action level recommendations.

" Any new water (such as reactor coolant) entering the concrete-to-shell Interface (now minimized by repalralmodifications Implemented during this outage) will

• also Increase In pH due to Its migration through and contact with the concrete creating a non-aggressive, alkaline environment.

" Minimal corrosion of the wetted Inner drywell steel surface In contact with the concrete Is only expected to occur during outages since the drywall Is Inarted with nitrogen during operations. Even during outages, shell corrosion losses are expected to be Insignificant since the exposure time to oxygen Is very limited and the water pH Is expected to be relatively high. Also, repalrelmodificatlons Implemented during the 2006 outage will further minimize exposure of the drywell shell to oxygen.

Based on the UT measurements taken during the 2006 outage of the newly exposed shell area In Bay 5 that has not been examined since It was encased In concrete during Initial construction (pre-1969),.It was determined that the total metal lost based on a current average thickness measurement of 1.113" versus a nominal plate thickness of 1.154" Is only 0.041" (total wall loss for both Inside and outside of the drywall shell).

Although no continuing corrosion Is expected, but conservatively assuming that a similar wall loss could occur between now and the end of the period of extended operation, a margin of 336 mile to the 0.736" required wall thickness would exist.

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--l Enclosure Page 21 of 74 As for the 0.676" thick embedded plate, conservatively assuming the plate has undergone corrosion of 0.041" to date, and will undergo similar wall lass between now and the end of the period of extended operation a margin of 115 mils against the required minimum general thickness of 0.479" required for pressure Is provided.

The engineering evaluations summarized above confirmed that the condition Identified during the 2006 outage would not Impact safe operation during the next operating cycle. Also, a conservative projection (noted above) of wal loss for the 1.154" and 0.876" thick embedded shell sections Indicates that significant margin Is provided In both sections through the period of extended operation.

Although a basis Is established that ongoing corrosion of the shell embedded In concrete should not be expected and repalrelmodiflcatlons have been performed to limit or prevent water from reaching the Internal surface of the drywall shell, AmerGen has now established that the existence of water In contact with the Internal surface of the drywall shell and,oncrete at and below the floor elevation will be assumed to be a normal operating environment: AmerGen will further enhance the Oyster Creek ASME Section XI, Subsection IWE aging management program to require periodic Inspection of the drywall shell subject to concrete (with water) environment In the Internal embedded shell area and water environment within the trench area. Specific enhancements are:

UT thickness measurements will be taken from outside the drywall In the ssndbed region during the 2008 refueling outage on the locally thinned areas examined during the October 2006 refueling outage.

The locally thinned areas are distributed both vertically and around the perimeter of the drywall In all ten bays such that potential corrosion of the drywall shell would be detected.

" Starting In 2010, drywell shell UT thickness measurements will be taken from outside the drywell In the sandbed region in two bays per outage, such that Inspections will be performed In all 10 bays within a 10.year period. The two bays with the most locally thinned areas (bay 01 and bay #13) will be inspected In 2010. if the UT examinations yield unacceptable results, then the locally thinned areas In all 10 bays will be Inspected In the refueling outage that the unacceptable results are Identified.

Perform visual inspection of the drywall shell inside the trench In bay 95 and bay #17 and take UT measurements Inside these trenches In 2008 at the same locations examined In 2006. Repeat (both the UT and visual) Inspections at refueling outages during the period of extended operation until the trenches are restored to the original design configuration using concrete or other suitable material to prevent moisture collection In these areas.

Perform visual Inspection of the moisture barrier between the drywall shell end the concrete floorlcurb, Installed Inside the drywall during the October 2006 refueling outage, In accordance with ASME Section Xl, Subsection IWE during the period of extended operation.

Enclosure Page 22 of 74 After each Inspection. UT thickness measurements results will be evaluated and compared with previous UT thickness measurements. If unsatisfactory results are Identified, then additional corrective actions will be Initiated, as necessary, to ensure the drywall shell Integrity Is maintained throughout the period of extended operation.

The corrective actions taken as discussed above and the continued monitoring of the drywall for loss of material through the enhanced ASME Section Xi, Subsection IWE program, the Protective Coating Monitoring and Maintenance Program, and 10 CFR Part 50, Appendix J provide reasonable assurance that loss of material In Inaccessible areas of the drywell will be detected prior to the loss of en intended function. Observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process. The ASME Section XI, Subsection IWE program, the Protective Coating Monitoring and Maintenance, and 10 CFR Part 50 Appendix J programs are descdbed'in Appendix B.

5. Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature Loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for PWR prestressed concrete containments and BWR Mark II prestressed concrete containments Is a TLAA as defined In 10 CFR 54.3. TLAAs are required to be evaluated In accordance with 10 CFR 54.21(c). The evaluation of this TLAA Is addressed separately In Section 4.5 of this standard review plan.

This Is applicable only to PWR and BWR prestressed concrete containments. It Is not applicable to the Oyster Creek Mark I steel containment.

6. Cumulative Fatigue Damage If Included In the current licensing basis, fatigue analyses of containment steel liner plates and steel containment shells (including welded Joints) and penetrations (including penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of PWR and BWR containments and BWR vent header and downcomers are TLAAs as defined In 10 CFR 54.3. TLAAS are required to be evaluated In accordance with 10 CFR 54.21(c). The evaluation of this TLAA Is addressed separately in Section 4.6 of the standard review plan.

At Oyster Creek, cumulative fatigue damage of the primary containment penetration sleeves, penetration bellows, suppression chamber (torus),

vent header, downcomers, vent line bellows, main steam expansion Joints Inside the drywell, and containment vacuum breakers system piping, piping components, and expansion joints Is a TLAA as defined In 10 CFR 54.3. The TLAA Is evaluated In accordance with 10 CFR 54.21 (c).

Evaluation of this TLAA Is discussed In Section 4.6

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7. Cracking due to Cyclic Loading and Stress Corrosion Cracking Cracking of containment penetrations (including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading or SCC could occur In all types of PWR end BWR containments. Cracking could also occur In vent line bellows, vent headers end downcomers due to SCC for BWR containments. A visual VT-3 examination would not detect such cracks. Moreover, stress corrosion cracking is e concern for dissimilar metal welds. The GALL report recommends further evaluation of the inspection methods implemented to detect these aging effects.

At Oyster Creek, cracking of containment penetrations (including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic loading is considered metal fatigue and Is addressed as a TLAA In Section 4.6.

Stress corrosion cracking (SCC) Is an aging mechanism that requires the simultaneous action of a corrosive environment, sustained tensile stress, and a susceptible material. Elimination of any one of these elements will eliminate susceptibility to SCC. Stainless steel elements of primarq containment and the containment vacuum breakera system, Including dissimilar welds, are susceptible to SCC. However these elements are located Inside the containment drywell or outside the drywell, In the reactor building, and are not subject to corrosive environment as discussed below.

The drywell is made inert with nitrogen to render the primary containment atmosphere non-flammable by maintaining the oxygen content below 4%

by volume during normal operation. The normal operating average temperature Inside the drywell Is less than 1399F:and the relative humidity range is 20-40%. The reactor building normal operating temperature range is 65°F - 921F; except In the trunlon room where the temperature can reach 1401F. The relative humidity is 100% maximum. Both the containment atmosphere and indoor air environments are non-corrosive (chlorides <150 ppb, sulfates <100 ppb, and fluorides < 150 ppb).

Thus SCC Is not expected to occur In the containment penetratson bellows, penetration sleeves, and containment vacuum breakers expansion joints; piping and piping components, and dissimilar metal welds. A review of plant operating experience did not identify cracking of the components and primary containment leakage has not been identified as a concern. Therefore the existing 10 CFR Part 50 Appendix J leak testing and ASME Section XI, Subsection IWE, are adequate to detect cracking. Observed conditions that have the potential for Impacting an intended function are evaluated or corrected In accordance with the corrective action process. The ASME Section XI, Subsection IWE and 10 CFR Part 50 Appendix J programs are described In Appendix B.

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8. Scaling, Cracking. and Spelling due to Freeze-Thaw; and Expansion and Cracking due to Reaction with Aggregate Scaling, cracking, and spelling due to freeze-thaw could occur In PWR and BWR concrete containments; and expansion end cracking due to reaction with aggregate could occur In concrete elements of PWR and BWR concrete and steel containments. Further evaluation Is not necessary if stated conditions are satisfied for inaccessible areas This is applicable only to PWR and BWR concrete containments. it Is not applicable to the Oyster Creek Mark I steel containment.

3.5.2.2.2 Class I Structures

1. Aging of Structures Not Covered by Structures Monitoring Program The GALL report recommends further evaluation of certain structurelaging effect combinations if they are not covered by the structures monitoring program. This includes (1) scaling, cracking, and spalling due to repeated freeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spelling and Increase in porosity and permeability due to leaching of calcium hydroxide and aggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion end cracking due to reaction with aggregates for Groups 1-5. 7-9 structures; (4) cracking, spaeling, loss of bond, and loss of material due to general, pitting and crevice corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks and distortion due to Increase In component stress level from settlement for Groups 1-3, 5, 7-9 structures; (6) reduction of foundation strength due to erosion of porous concrete subfoundatlon for Groups 1-3, 5-9 structures; (7) loss of material due to general, pititng and crevice corrosion of structural steel components for Groups 1-5, 7-8 structures; (8) loss of strength and modulus of concrete structures due to elevated temperatures for Groups 1-5; and (9) cracking due to SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8 structures. Further evaluation Is necessary only for structure/agIng effect combinations not covered by the structures monitoring program.

Technical details of the agingrmanagement Issue are presented in Subsection 3.6.2.2.1.2 for Items (5) and (6) and Subsection 3.5.2.2.1.3 for Item (8).

Loss of material (spelling, scaling) and cracking due to freeze-thaw could occur in below-grade Inaccessible concrete areas for Groups 1-3, 5, 7-9 structures; and expansion and cracking due to reaction with aggregates could occur In below-grade Inaccessible concrete areas for Groups 1-5, 7-9 structures. The GALL report recommends further evaluation of plant-specific programs to manage the aging effects for Inaccessible areas If specific criteria defined in the GALL report cannot be satisfied.

At Oyster Creek, the Structures Monitoring Program (B.1.31) Is used to manage aging affects applicable to Groups 2,3, 4, and 8-9 structures as

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Enclosure Page 25 of 74 discussed below. The GALL structures Group I and Group 7 do not exist for Oyster Creek. Group 5, 'Fuel Storage Faclilty, Is Included with Group 2 structures.

(1) Loss of material and cracking due to repeated freeze-thaw for Groups 2,3A and 8-9 structures are managed through the Structures Monitoring Program and thus a further evaluation Is not necessary.

(2) Scaling, cracking, spelling end Increase In porosity and permeability due to leaching of calcium hydroxide and aggressive chemical attack for Groups 2, 4, and 8-9 structures are not applicable. The structures are not exposed to aggressive environment or water - flowing environment. Group 3 structures are also not exposed to aggressive, or water - flowing environments except for the Fire Water Pumphouses (fresh water pumphouse only), and the service water seal wall (Included With Miscellaneous Yard structures). The structures are within the scope of Structures Monitoring Program and Inspected as described In Appendix B.

(3) Cracking due to reaction with aggregates for Groups 2-4, and 8-9 structures Is monitored through Structures Monitoring Program, and thus a further evaluation Is not necessary.

(4) Loss of material, cracking, and change In material properties due to corrosion of embedded steel for Groups 2.4, and 8-9 structures are monitored through the Structures Moniltoring Program and thus a further evaluation Is not required.

(5) The Structures Monitoring Program will be used to manage Cracks and distortion due to Increase In component stress level from settlement for Groups 2-4. and 8-9 structures. However this aging mechanism Is Insignificant for Oyster Creek structures because the structures are founded on highly dense soil. Evaluation of soil explorations, during the original construction, predicted no more than 1" settlement for Class I structures. Observed settlement of the reactor building has ranged from 0.33" - 0.75" and was essentially complete soon after construction. Thus a settlement monitoring program is not required; nor Is a da-watering system reaied upon In the CLB to control settlement (8) Reduction of foundation strength due to erosion of porous concrete sub foundation for Groups 2-4, and 8-9 structures. This aging effect and mechanism Is not applicable to Oyster Creek. The Oyster Creek design does not Include porous concrete Into the sub foundation of Groups 2-4 and 8-9 structures.

(7) Loss of material due to general, pitting and crevice corrosion of structural steel components for Groups 2-4, and 9 structures Is monitored through the Structures Monitoring Program, and thus a further evaluation Is not required.

Enclosure Page 26 of 74 (8) For loss of strength and modulus of concrete structures due to elevated temperatures for Groups 2-5, GALL recommends a Plant Specific AMP and further evaluation if the general temperature Is greater than 1500 F or If the local temperature Is greeter than 200'F.

For Oyster Creek, the Structures Monitoring Program Is used to manage cracking of concrete structures exposed to elevated temperatures.

Concrete temperature limits specified In the GALL report are exceeded only In a section of the reactor building (Group 2) drywall shield wall that encloses the containment drywall head.

Thermocouples mounted on the head, In the general area of the shield wall, Indicated a maximum temperature of 285°F. Engineering analysis predicted that the average temperature through the 5' thick concrete wall could be In the range of 18 0 F-215*F: considering a worst case thermal environment inside the containment of 3400F. As a result, an Investigation was Initiated to evaluate the Impact of the elevated temperature on the structural Integrity of the shield wall. The Initial Inspection of the shield wall Identified concrete cracking In the area that Is subject to high temperature. A map of the cracked area that Includes crack length and width was developed for future monitoring.

Subsequently, an engineering evaluation was conducted to assess the Impact of the elevated temperature on the drywall shield wall. For this purpose, a finite element model was created considering geometry of the shield wall and structural elements connected to It.

The analysis was based on a temperature of 285°F and a reduced concrete compressive strength that accounts for temperature-induced reduction. The results concluded that concrete and rebar stress limits are In accordance with ACI 349 criteria with an adequate safety margin. NRC staff review found the analysis acceptable end concluded that the wall is capable of performing Its Intended function.

The Staff also recommended condition monitoring of the drywall shield wall to ensure Its continued function. The wall has been Included In the scope of the Structures Monitoring Program and Inspected periodically to ensure its continued function. Observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process. The Structures Monitoring Program Is described In Appendix B.

(9) Cracking due to SCC and loss of material due to crevice corrosion of stainless steel liner are not In the scope of Structures Monitoring Program. Instead, the aging effects are managed through the Water Chemistry Program (B.1.2) and monitoring of spent fuel pool water level, consistent with the GALL AMP., Therefore a further evaluation Is not necessary.

At Oyster Creek, the Structures Monitoring Program (B.1.31) Is used to manage concrete aging effects due to various aging mechanisms.

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n-- mm Enclosure Page 27 of 74 The program requires periodic inspection of accessible areas and Inspection of Inaccessible areas when theybecome accessible. The below-grade concrete structures are Inspected, when excavated for any reason. In addition, the criteria defined In the GALL report Is satisfied as discussed below.

Oyster Creek is located In a moderate to severe weathering conditions. As a result loss of material (spelling, scaling) and cracking due to free-thaw Is applicable to Groups 2-3' and 8-9 structures.

However these concrete structures are designed and constructed In accordance with AC1 318 and provide for low permeability and adequate air entraInment (4% -6%) such that the concrete Is not susceptible to freeze-thaw aging effects. Inspections of accessible areas have Identified cracks on the exterior wells of the reactor building. The cracks have been attributed to a combination of early concrete shrinkage, expansion, and contraction due to temperature variation. Spelling and scaling of any significance have not been observed.

At Oyster Creek, expansion and cracking due to reaction with aggregates could occur In below-grade Inaccessible concrete areas for Groups 2-4, and 8-9 structures.

At Oyster Creek, concrete specifications require Type 11; low alkali cement shall be used. Alkali content Is limited to 0.6 per cent total alkali unless tests performed In accordance with ASTM C295 end C227 demonstrate no potential for alkali reactivity for the aggregate.

Inspection activities In accordance with the Structures Monitoring Program described above, In conjunction with concrete quality that meets ACI 318, ASTM 295, and ASTM C227 standards, provide reasonable assurance that the below-grade concrete will perform Its Intended function. Observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process. The Structures Monitoring Program Is described In Appendix B.

2. Aging Management of Inaccessible Areas Cracking, spelling, and Increases In porosity and permeability due to aggressive chemical attack; and cracking, spelling, loss of bond, end loss of material due to corrosion of embedded steel could occur In below-grade Inaccessible concrete areas. The GALL report recommends further evaluation to manage these aging effects In Inaccessible areas of Groups 1-3, 5, 7-9 structures.

Recent Oyster Creek groundwater analysis results (pH: 5.6 - 6.4, chlorides: 3 -138 ppm, and sulfates: 7-73 ppm) have shown that the groundwater at Oyster Creek Is not aggressive for Groups 2-3, 8-9 structures. Therefore further evaluation of below-grade Inaccessible Enclosure Page 28 of 74 concrete areas for Groups 2z and 8-9 structures Is not required. Similariy inaccessible areas of Group 3 structures are not exposed to aggressive environment except for Fire Water Pumphouses (fresh water pumphouse only). Further evaluation of group 3 structures, other than fresh water pumphouse Is not required.

The fresh water pumphouse reinforced concrete Is subject to slightly aggressive water from the Fire Pond Dam (pH: 4.8, chlorides = 12 ppm, and sulfates = 6 ppm). Inaccessible areas will be Inspected If excavated for any reason, or if observed conditions In accessible areas, which are exposed to the Same environment, show that significant concrete degradation Is occurring.

The Structures Monitoring Program will be enhanced to Include periodic groundwater monitoring In order to demonstrate that the below grade environment remains non-aggressive. Observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process. The Structures Monitoring Program Is described In Appendix B.

3.5.2.2.3 Component Supports

1. Aging of Supports Not Covered by Structures Monitoring Program The GALL report recommends further evaluation of certain component support/aging effect combinations If they are not covered by the structures monitoring program. This Includes (1) reduction In concrete anchor capacity due to degradation of the surrounding concrete, for Groups B1-B6 supports; (2) loss of material due to environmental corrosion, for Groups 82-B5 supports; and (3) reduction/loss of Isolation function due to degradation of vibration Isolation elements, for Group B4 supports. Further evaluation Is necessary only for structure/aging effect combinations not covered by the structures monitoring program.

At Oyster Creek, (1) reduction In concrete anchor capacity due to degradation of the surrounding concrete, for Groups B1-B5 supports, (2) loss of material for Groups B2-B5 supports; end (3) reduction/toss of Isolation function due to degradation of vibration Isolation elements for Group B4 supports are covered under the Structures Monitoring Program.

The Structures Monitoring Program will be used to manage loss of material on exterior surfaces of piping, piping components, HVAC components end ductwork, tanks, and other mechanical components located In outdoor air environment. The program will also be used to manage loss of material and change In materiel properties of exterior surfaces of mechanical system components In Indoor air environment as described In Appendix (B.1.31) and as evaluated In sections 3.1, 3.2, 3.3, and 3.4 of this application.

Observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the Corrective

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-M-Enclosure Page 29 of 74 Action Process. The Structures Monitoring Program Is described in Appendix B.

2. Cumulative Fatigue Damage Due To Cyclic Loading Fatigue of support members, anchor bolts, and welds for Groups B1.1, 61.2, and B1.3 component supports Is a TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. TLAAs are required to be evaluated In accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed separately In Section 4.3 of the standard review plan.

At Oyster Creek, there are no fatigue analyses applicable to Groups B1.1, and 61.2 component supports in the CLB. Therefore, cumulative fatigue damage for Groups B1.1 and 61.2 component supports is not a TLAA as defined In 10 CFR 54.3.

The Oyster Creek CLB Includes fatigue analysts for certain Group 61.3, ASME Class MC component supports. For these supports (Torus support columns and sway braces), cumulative fatigue damage is a TLAA evaluated In accordance with 10 CFR 54.21(c) in Section 4.6.1.

3.5.2.3 Time-Limited AoIna Analysis The time-limilted aging analyses identified below are associated with the Primary Containment, Structures, and Component Supports components:

Section 4.6, Primary Containment, Attached Piping and Components Section 4.7.1, Reactor Building Crane, Turbine Building Crane, Heater Bay Crane Load Cycles Section 4.7.2, Drywall Corrosion Section 4.7.3, Equipment Pool and Reactor Cavity Walls Rebar Corrosion 3.

5.3 CONCLUSION

The Primary Containment, Structures, Component Supports, and Piping and Component Insulation components that are subject to aging management review have been Identified in accordance with the requirements of 10 CFR 54.4. The aging management programs selected to manage aging effects for the Primary Containment* Structures, Component Supports, and Piping and Component Insulation components are identified In the summaries In Section 3.5.2.1 above.

A description of these aging management programs Is provided In Appendix B, along with the demonstration that the Identified aging effects will be managed for the period of extended operation.

Therefore, based on the conclusions provided in Appendix B, the effects of aging associated with the Primary Containment Structures, and Component Supports components will be adequately managed so that there is reasonable assurance that the Intended function(s) will be maintained consistent with the current licensing basis during the period of extended operation.

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Enclosure Page 31 of 74 Table 3.5Z1.1 Primary Containment Summary of Aging Management Evaluation Table 3.5.2-1.1 Primary Containment Component Intended Material Environment Aging Effect Aging Managernent NUREG-110i Table 1 item Notes Type Function Requiring Programs VoL 2 Item Management DOrell Shal Preseree Boundary CUarbo and low Concree (Interral Lose of Material 10 CFR Part 50.

11.11.1-2 (C-19) 3.5.1-13 A. 10 aloy stee l aiter)

Appenrdi J (B.129)

ASME Sedioi )0.

i.B1.1-2 (C-19) 3.5.1-13

a. 10 Subsection IWE (B.1.27)

TLAAe vmtajted in IL1..1-2 (C-19) 3.5-1-13 E.4 oda Inc.

lh 10 CFR 54.12(G)

Water (Internal)

Loss of Material 10 CFR Part 50, 11.81.1-2(C-19) 3.5.1-13 A 10 Appendix J (0.1.29)

ASME Section X).

ILB1.1-2 (C-19) 3.5.1-13 0,10 Subseoion IWE (0.1.27)

TIAA, evabuated in (1.01.1-2 (0-19) 3.5-1-13 E. 4 aemonre wlth 10 CFR 54.12(c)

Strutural Support Carbon and low Concte (Internre Loss of Material 10 CFR Part 50, iI.1.1-2 (C-19) 3.5.1-13 A. 10 alloy steel whwater)

Appendix J (B.1.29)

ASME Soctio XM IB1..1-2 (C-19) 3.5.1-13 0,10 Subsection IW5 (B.1.27)

Enrlosure Page 32 of T4 Table 3.5.-1.1 Prlma Containment

ontlnued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table I Item Notes Type Function Requiring Programs VbL 2 Item Management DryweU Shea Strucural Support Carbon end low Cerncete (Internal LOSe of Material TLAA.

evraluated In 11.01.1-2 (C-19) 3.5-1-13 E, 4 aetoy steel w*rater) accordance %it 10 CFR 54.12(c)

Water(Inteeral)

LossofMaterial 10CFRParSt0, I.11.1-2(C-19) 3.5.1-13 A.10 Appendlexi (B.1.29)

ASME Section XL.11-131.1-2 (C-19) 3.5.1-13 B. 10 Subsection WE (B.1-27)

TLAA, evetoated in IIJ1.1-2 (C-19) 3.5-1-13 E. 4 acmdanm with 10 CPR 54.12(c)

Moisture Barrier Lealkge Boundary Eelstorner Contairrnent Change In Material ASME Seotlon X!,

11.B4-7(C-18) 3.5.1-8 B, 11.12 Arrpe Properties Sub*ecieon WE (B.1.27)

Treated Water Change in Material ASME Bedt X(,

G. 11.12 Properties Sueecdton WE (8.127)

Reinfreond leoure Proeteion C*oreet Treated Water Change In Material Structure Moneng G,013 Concrete Floer (Submerged)

Propertes Program (0.1.31)

Slab (IS siab)

Ciaddng Structures Metorng (3,13 Program (B.I.31)

Lose of Material Sb-time Montoring G. 13 Program (0.1.31)

Stsrduret Support Coset Treated Wale Change hr Material Streueme Monltersrg G, 13 (Submerged)

Proprtio Progream (0.1.31)

Endotaun Pase 33 of 74 Table 3.52.1.1 Prim

, Containment

_ontlnued)

Component Intended Material Environment Aging Effect Aging Management NUREG-1801 Table 1 Item Notes Type Function Requiring Programs Vol. 2 Item Management Reirdorcd Structural S pport Concete Treated Water C.,dfte Suctures M.n"d nrg G, 13 Concret Floor (sutbmtled)

Pn~m (B.I.3i)

Slab (Fl slab)

Lcu of Materia Structuas Monttrdaig

r. 13 P_ _ _m_ (B.1.31)

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End-osur fag. 34 af 74 Notes Definition of Note A

Consistent with NUREG-1801 item for component, material, environment, and aging effect AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component Is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment and aging effect. AMP takes some exceptions to NUREC-1 801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited.

F Material not in NUREG-1801 for this component.

G Environment not In NUREG-1801 for this component and material.

H Aging effect'not In NUREG-1 801 for this component, material end environment combination.

I Aging affect in NUREG-1801 for this component, material and environment combination is not applicable.

J Neither the component nor the material and environment combination is evaluated in NUREG-1801.

Plant Specific Notes:

1. The biological shield wall high density concrete is unreinforced, encased in steel plates (biological shield wall liner plate) and is inaccessible.

2. ASME Section Xi, Subsection IWE and 10 CFR Part 50, Appendix J are the applicable aging management programs for Class MCpressure retaining bolting.

3. The Aging effects and Aging Management Program identified for this material/environment combination am consistent with industry guidance.

4. Loss of material due to corrosion is a TLAA for the dryweit shell in Oyster Creek CLB

5. Protective coatings applied to the external surfaces of the drywell where the sand is removed (sand pocket region) has been credited for mitigating loss of material due to corrosion In CLB.

6. Concrete In contact with the embedded containment shell meets the requirements of ACI 318 and the guidance of 201.R.

7. Reduction of strength and modulus due to elevated temperature is not an aging effect requiring management. See further evaluation in Section 3.5.2.2.1.3

8. Structures Monitoring Program is the applicable aging management program for this component

9. Primary containment leakage Is controlled in accordance with Oyster Creek Technical Specifications.

10. Water environment for the drywell shell and the reinforced concrete slab (fill slab) was Identified during 21186 In two trenches Inside the drywell concrete floor. The source of water Is most likely from leakage of treated water from plant equipment Inside the dryweil. Chemical tests of water

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Enclosure Page 36 of 74 A.1.27 ASME SECTION XI; SUBSECTION IWE The ASME Section XI, Subsection WE aging management program is an existing program based on ASME Code and complies with the provisions of 10 CFR 60.55a. The program consists of periodic inspection of primary containment surfaces and components, including integral attachments, and containment vacuum breakers system piping and components for loss of material, loss of sealing, and loss of preload.

Examination methods Include visual end volumetrc testing as required by the Code. Observed conditions that have the potential for Impacting an intended function are evaluated for acceptability In accordance with ASME requirements or corrected In accordance with corrective action process. Procurement controls and Installation practices, defined in plant procedures, ensure that only approved lubricants and tension or torque are applied to bolting.

In accordance with commitments made during the Oyster Creek license renewal application review process, the program will be enhanced to Include:

1. Ultrasonic Testing (UT) thickness measurements of the drywall shell In the sand bed region will be performed on a frequency of every 10 years, except that the Initial Inspection will occur prior to the period of extended operation and the subsequent Inspection will occur two refueling outages after the Initial Inspection to provide early confirmation that corrosion has been arrested.

Subsequent Inspection frequency will be established as appropriate, not to exceed 10-year intervals. The UT measurements will be taken from the inside of the drywell at the same locations where UT measurements were performed In 1996.

The inspection results will be compared to previous results. Statistically significant deviations from the 1992, 1994, and 1996 UT results will result in corrective actions that Include the following:

Perform additional UT measurements to confirm the readings.

Notify NRC within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of confirmation of the Identified condition.

Conduct visual Inspection of the external surface In the sand bed region In areas where any unexpected corrosion may be detected.

Perform engineering evaluation to assess the extent of condition and to determine If additional Inspections are required to assure drywall Integrity.

Perform operability determination and Justification for operation until next inspection.

These actions will be completed prior to restart from the associated outage.

2. A strilpeble coating will be applied to the reactor cavity liner to prevent water intrusion Into the gap between the drywall shield wall and the drywell shell during periods when the reactor cavity is flooded.

3. The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored for leakage during refueling outages and during the plant operating cycle:

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Enclosure Page 37 of 74

" The sand bed region drains will be monitored daily during refueling outages. If leakage Is detected, procedures will be In place to determine the source of leakage and Investigate and address the Impact of leakage on the drywell shell, Including verification of the condition of the drywell shell coating and moisture barrier (seal) In the sand bed region and performance of UT examinations of the shell In the upper regions. UTs will also be performed on any areas In the sand bed region where visual Inspection Indicates the coating Is damaged and corrosion has occurred.

UT results will be evaluated per the existing program. Any degraded coating or moisture barrier will be repaired. These actions will be completed prior to exiling the associated outage.

" The sand bed region drains will be monitored quarterly during the plant operating cycle. If leakage Is Identified, the source of water will be investigated, corrective actions taken or planned as appropriate. In addition, If leakage Is detected, the following items will be performed during the next refueling outage:

• Inspection of the drywell shell coating and moisture barrier (seal) In the affected bays In the sand bed region

• UTs of the upper drywell region consistent with the existing program UTs will be performed on any areas In the sand bed region where visual Inspection Indicates the coating Is damaged and corrosion has occurred UT results will be evaluated per the existing program Any degraded coating or moisture barrier will be repaired

4. Prior to the period of extended operation, AmerGen will perform additional visual Inspections of the epoxy coating that was applied to the exterior surface of the Drywall shell in the sand bed region, such that the coated surfaces in all 10 Drywall bays will have been Inspected at least once. In addition, the Inservice Inspection (IS) Program will be enhanced to require Inspection of 100% of the epoxy coating every 10 years during the period of extended operation. These Inspections will be performed In accordance with ASME Section XI, Subsection IWE. Performance of the Inspections will be staggered such that at least three bays will be examined every other refueling outage.

5. A visual examination of the drywall shell In the drywall floor Inspection access trenches will be performed to assure that the drywell shell remains Intact. If degradation Is identified, the drywall shell condition will be evaluated and corrective actions taken as necessary. In addition, one-time ultrasonic testing (UT) measurements will be taken to confirm the adequacy of the shell thickness In these areas. Beyond these examinations, these surfaces will either be Inspected as part of the scope of the ASME Section XI, Subsection IWE Inspection program or they will be restored to the original design configuration using 'concrete or other suitable material to prevent moisture collection In these areas.

6. The coating Inside the torus will be visually Inspected In accordance with ASME Section XI, Subsection IWE, per the Protective Coatings Program. The scope of each of these Inspections will Include the wetted area of all 20 torus Enclosure Page 38 of 74 bays. Should the current torus coating system be replaced, the Inspection frequency and scope will, as a minimum, meet the requirements of ASME Section XI, Subsection IWE.

7. AmerGen will conduct UT thickness measurements In the upper regions of the drywall shell every other refueling outage at the same locations as are currently measured.

8. The IWE Program will be credited for managing corrosion In the Torus Vent Line and Vent Header exposed to an Indoor Air (Extemal) environment.

8. During the next UT Inspections to be performed on the drywall sand bed region (reference AmerGen 414106 letter to NRC), an attempt will be made to locate and evaluate some of the locally thinned areas identified In the 1992 Inspection from the exterior of the drywall. This testing will be performed using the latest UT methodology with existing shell paint In place. The UT thickness measurements for these locally thinned areas may be taken from either Inside the drywall or outside the drywall (sand bed region) to limit radiation dose to as low as reasonably achievable (ALARA).

10. AmerGen will conduct UT thickness measurements on the 0.70 Inch thick plate at the junction between the 0.770 Inch thick and 1.154 Inch thick plates In the lower portion of the spherical region of the drywall shell. These measurements will be taken at one location using the 6"x6 grid. These measurements will be performed prior to the period of extended operation and repeated at the second refueling outage after the Initial Inspection, at the same location. If corrosion In this transition area Is greater than areas monitored In the upper drywall, UT Inspections In the transition area will be performed on the same frequency as those In the upper drywell (every other refueling outage).

11. AmerGen will conduct UT thickness measurements In the drywall shell

'knuckle' area, on the 0.640 Inch thick plate above the weld to the 2.625 Inch thick plate. These measurements will be taken at one location using the 6"x6 grid. These measurements will be performed prior to the period of extended operation and repeated at the second refueling outage after the Initial Inspection, at the same location. If corrosion In this transition area Is greater than areas monitored In the upper drywell, UT inspections In the transition area will be performed on the same frequency as those In the upper drywell (every other refueling outage).

12. When the sand bed region drywell shell coating Inspection Is performed, the seal at the Junction between the sand bed region concrete and the embedded drywall shell will be Inspected.

13. The reactor cavity seal leakage concrete trough drain will be verified to be clear from blockage once per refueling cycle.

14. UT thickness measurements will be taken from outside the drywall In the sandbed region during the 2008 refueling outage on the locally thinned areas examined during the October 2006 refueling outage. The m

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Enclosure Page 39 of 74 locally thinned areas are distributed both vertically and around the W

perimeter of the drywall In all ten bays such that potential corrosion of E

16 the drywall shell would be detected.

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15. Starting In 2010, drywell shell UT thickness measurements will be taken 1

from outside the drywell In the sandbed region In two bays per outage, o

such that Inspections will be performed In all 10 bays within a 10-year period. The two bays with the most locally thinned areas (bay #1 and V

V-a 4 bay #13) will be inspected In 2010. If the UT examinations yield

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16. Perform visual Inspections of the drywell shell Inside the trenches In

'- RI bay #5 and bay #17 and take UT measurements Inside these trenches In 1

2008 at the some locations examined In 2006. Repeat (both the UT and 2z visual) Inspections at refueling outages during the period of extended 0 ;

operation until the trenches are restored to the original design configuration using concrete or other suitable material to prevent 0

co9g4 moisture collection In these areas.

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17. Perform visual Inspection of the moisture barrier between the drywall o-a shell and the concrete floorlcurb, Installed Inside the drywell during the "Z

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$A October 2006 refueling outage, In accordance with ASME Section XI,

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1 Subsection IWE during the period of extended operation.

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Enclosure Page 41 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE Perform addional UT measurements to confirm the readings.

Notify NRC within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of confirmation of the identified condition.

Conduct visual inspection of the external surface In the sand bed region In areas where any unexpected corrosion may be detected.

Perform engineering evaluation to assess the extent of condition and to determine if additional inspections are required to assure drywell integrity.

P Perform operability determination and justification for operation until next inspection.

These actions will be completed prior to restart from the associated outage.

2. A shippable coating will be applied to the Refueling outages reactor cavity liner to prevent water intrusion prior to and during Into the gap between the drywell shield wall and the period of the drywall shell during periods when the extendedoperation reactor cavity is flooded.

3. The reactor cavity seal leakage trough drains Periodically and the drywall sand bed region drains will be monitored for leakage.

The sand bed region drains will be Daily during monitored daily during refueling I

refueling outages I

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Enclosure Page 42 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE outages.

if leakage is detected, procedures will be In place to determine the source of leakage and investigate and address the Impact of leakage on the drywell shell, Including verification of the condition of the drywell shell coaling and moisture barrier (seal) In the sand bed region and performance of UT examinations of the shell In the upper regions. UTs will also be performed on any areas In the sand bed region where visual Inspection Indicates the coating is damaged and corrosion has occurred.

UT results will be evaluated per the, existing program. Any degraded coating or moisture barrier will be repaired.

These actions will be completed prior to exiting the associated outage.

The sand bed region drains will be Quarterly during monitored quarterly during the plant non-outage periods operating cycle. If leakage Is identified, the source of water will be investigated, corrective actions taken or planned as appropriate. In addition, if leakage is detected, the following Items will be performed during the next refueling outage:

Inspection of the drywall shell coating and moisture barrier (seal) in I

Enclosure Page 43 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE the affected bays in the sand bed region

" UTs of the upper drywell region consistent with the existing program

" UTs will be performed on any areas in the sand bed region where visual inspection Indicates the coating is damaged and corrosion has occurred

" UT results will be evaluated per the existing program Any degraded coating or moisture barrier will be repaired.

4. Prior to the period of extended operation, Peor to the period of AnmerGen wilt perform additional visual extended operation Inspections of the epoxy coating that was and every ten years applied to the exterior surface of the Drywell during the period of shell In the sand bed region, such that the extended operation coated surfaces in all 10 Drywall bays will have been Inspected at least once. In addition, the Inservice Inspection (ISI) Program will be enhanced to require Inspection of 100% of the epoxy coating every 10 years during the period of extended operation. These inspections will be performed In accordance with ASME Section XI, Subsection IWE. Performance of the Inspections will be staggered such that at least three bays will be examined every other refueling outage.

Enclosure Page 44 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE

5. A visual examination of the drywell shell in the Prior to the period of drywall floor inspection access trenches will be extended operation performed to assure that the drywell shell remains intact if degradation is identified, the drywell shell condition will be evaluated and corrective actions taken as necessary. In addition, one-time ultasonic testing (UT) measurements will be taken to confirm the adequacy of the shell thickness in these areas.

Beyond these examinations, these surfaces will either be inspected as part of the scope of the ASME Section XI, Subsection iWE inspection program or they will be restored to the original design configuration using concrete or other suitable material to prevent moisture collection in these areas.

6. The coating Inside the torus will be visually Every other refueling inspected in accordance with ASME Section Xl, outage prior to and Subsection WE, per the Protective Coatings during the period of Program. The scope of each of these extended operation inspections will include the wetted area of all 20 torus bays. Should the current torus coating system be replaced, the inspection frequency and scope will, as a minimum, meet the requirements of ASME Section XA, Subsection PWE.

7. AmerGen will conduct UT thickness Every other refueling measurements in the upper regions of the outage prior to and hdrywll shell every other refueling outage at the 1 1 during the period of 1

Enclosure Page 45 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE same locations as awe currently measured, extended operation

8. The IWE Program will be credited for managing corrosion In the Torus Vent Line and Vent Header exposed to an Indoor Air (Extemal) environment

9. Diatng the next UT inspections to be performed Prior to the period of on the drywall sand bed region (reference extended operation AmerGen 414/06 letter to NRC). an attempt will be made to locate and evaluate some of the locally thinned areas Identified In the 1992 Inspection from the exterior of the drywall. This testing wil be performed using the latest UT methodology with exisling shell paint in place.

The UT thickness measurements for these locally thinned areas may be taken from either inside the drywall or outside the drywall (sand bed region) to bIut radiation dose to as tow as reasonably achievable (ALARA).

10. AmearGen will conduct UT thickness Priorto the period of measurements on the 0.770 Inch thick plate at extended operation the junction between the 0.770 Inch thick and and two refueling 1.154 Inch thick plates, In the lower portlon of outages later the spherical region of the drywall shalt. These measurements will be taken at one location using the Wx6 grid. These measurements will be performed prior to the period of extended operation and repeated at the second refueling outage after the Initial Inspection, at the same location. If corrosion In this transition area is I

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Enclosure Page 46 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE greater toan areas monitored in the upper drywall, UT inspections In the transition area will be performed on the same frequency as those In the upper drywell (every otherrefuetlng outage).

11. AmerGen will conduct UT thickness Prior to the period of measurements In the drywall shell 'knuclde" extended operation area, on the 0.640 Inch thick plate above the and two refueling weld to the 2.625 Inch thick plate. These outages later measurements will be taken at one location using the 6"6 grid. These measurements will be performed prior to the period of extended operation and repeated at the second reffeling outag efiýr the iti inspectio* at the same location. If corrosion In this transtion area Is greater than areas monitored In the upper drywall, UT inspections In the transition area will be performed on the same frequency as those In the upper drywall (every other refueling outage).

12. When the sand bed region drywall shell coating Coincident with the Inspection is performed (commitment 27, item sand bed region 4), the seal at the junction between the sand dryw0l shell coating bed region concrete and the embedded drywell inspection shell will be inspected per the Protective Coatings Program.

Endcosure Page 47 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE

13. The reactor cavity concrete bough drain will be Once per refueling verified to be dear from blockage once per cycle refueling cycle. Any identified issues will be addressed via the corrective action process.

14. UT thickness measurements will be taken During the 2008 fron outside the drywell In the sandbed refueling outage region during the 2008 refueling outage on the locally thinned areas examined during the October 2006 refueling outage. The locally thinned areas are distributed both vertically and around the perimeter of the drywell In all ten bays such that potential corrosion of the drywall shell would be detected.

15. Starting In 2010, drywell shell UT thickness Starting In 2010, measurements will be taken from outside two bays wil be the drywell In the sandbed region In two Inspected per bays per outage, such that Inspections will outage, such that be performed In all 10 bays within a 10-year the shell will be perlod. The two bays with the most locally inspected from all thinned areas (bay #1 and bay #13) will be 10 sandbed bays Inspected In 20`0. If the UT examinations within a 1B-year yield unacceptable results, then the locally period. See thinned areas in all 10 bays will be Inspected commitment for In the refueling outage that the unacceptable scope expansion results are identified, criteria.

Enclosure Page 48 of 74 UFSAR ITEM NUMBER COMMITMENT SUPPLEMENT ENHANCEMENT SOURCE LOCATION OR (LRA APP. A)

IMPLEMENTATION SCHEDULE

16. Perform visual Inspection of the drywell During the 2008 shell Inside the trenches In bay #5 and bay refueling outage

1. 17 and take UT measurements Inside these and subsequent trenches In 200B at the same locations outages until examined In 2006. Repeat (both the UT and trenches am visual) Inspections at refueling outages restored to original during the period of extended operation configuration until the trenches are restored to the original design configuration using concrete or other suitable material to prevent moisture collection In these areas.

17. Perform visual Inspection of the moisture In accordance with barrier between the drywall shell and the ASME Section X),

concrete floodcurb, Installed Inside the Subsection IWE drywell during the October 2006 refueling outage, In accordance with ASME Section X(, Subsection IWE during the period of extended operation.

Enclosure Page 49 of 74 B.1.27 ASME SECTION XI, SUBSECTION IWE Program Description The ASME Section XI, Subsection IWE aging management program provides for Inspection of primary containment components and the containment vacuum breakers system piping and components. It Is Implemented through station plans and procedures and covers steel containment shells and their Integral attachments; contalnrnient hatches and aldocks, seals and gaskets, containment vacuum breakers system piping and components, and pressure retaining bolting.

The program Includes visual examination and limited surface or volumetric examination, when augmented examination Is required, to detect loss of material.

The program also provides for managing loss of sealing for seals and gaskets, and toes of preload for pressure retaining bolting. Procurement controls and Installation practices, defined In plant procedures, ensure that only approved lubricants and tension or torque are applied. The Oyster Creek program compiles with Subsection IWE for steel containments (Class MC) of ASME Section XI, 1992 Edition Including 1992 Addenda In accordance with the provisions of 10 CFR 50.55a. Enhancements to the program, which are negotiated with NRC, to provide reasonable assurance that drywall corrosion Is adequately managed during the period of extended operation are described below.

NUREG-1801 Consistency The ASME Section XI, Subsection IWE aging management program Is consistent with the ten elements of aging management program XI.S1, 'ASME Section XI, Subsection WE,' specified in NUREG-1801 with the following exception:

Exceptions to NUREG-1801 NUREG-1801 evaluation Is based on ASME Section XI, 2001 Edftlon Including 2002 and 2003 Addenda. The current Oyster Creek ASME Section XI.

Subsection IWE program plan for the First Ten-Year inspection Interval effective from September 9, 1998 through September 9, 2008, approved per 10CFR50.55a, Is based on ASME Section XI, 1992 Edition Including 1992 addenda. The next 120-month inspection Interval for Oyster Creek will Incorporate the requirements specified In the version of the ASME Code Incorporated Into 10 CFR 50.55a 12 months before the start of the Inspection Interval.

Enhancements

1. Ultrasonic Testing (UT) thickness measurements of the drywall shell in the send bed region will be performed on a frequency of every 10 years, except that the initial Inspection will occur prior to the period of extended operation and the subsequent inspection will occur two refueling outages after the Initial Inspection to provide early confirmation that corrosion has been arrested.

Subsequent Inspection frequency will be established as appropriate, not to exceed 10-year lntervals. The UT measurements will be taken from the Enclosure Page 60 of 74 Inside of the drywall at the same locations where UT measurements were performed In 1996. 'The inspection results will be compared to previous results. Statistically significant deviations from the 1992. 1994, and 1996 UT results will result In corrective actions that Include the following:

" Perform additional UT measurements to confirm the readings.

" Notify NRC within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of confirmation of the Identified condition.

" Conduct visual Inspection of the external surface In the send bed region In areas where any unexpected corrosion may be detected.

" Perform engineering evaluation to assess the extent of condition end to determine If additional Inspections are required to assure drywall Integrity.

" Perform operability determination and Justification for operation until next inspection.

These actions will be completed prior to restart from the associated outage.

2. A stdppable coating will be applied to the reactor cavity liner to prevent water Intruslon Into the gap between the drywall shield wall and the drywall shell during periods when the reactor cavity Is flooded.

3. The reactor cavityseal leakage trough drains and the drywall sand bed region drains will be monitored for leakage during refueling outages and during the plant operating cycle:

" The send bed region drains will be monitored daily during refueling outages. If leakage Is detected, procedures will be In place to determine the source of leakage and Investigate and address the Impact of leakage on the drywall shell, Including verification of the condition of the drywell shell coating and moisture barrier (seal) In the send bed region and performance of UT examinations of the shell In the upper regions. UTs will also be performed on any areas in the sand bed region where visual Inspection Indicates the coating Is damaged and corrosion has occurred.

UT results will be evaluated per the existing program. Any degraded coating or moisture barrier will be repaired. These actions will be completed prior to exiting the associated outage.

" The sand bed region drains will be monitored quarterly during the plant operating cycle. If leakage Is Identified, the source of water will be investigated, corrective actions taken or planned as appropriate. In addition, If leakage Is detected, the following items miil be performed during the next refueling outage:

Inspection of the drywell shell coating and moisture barrier (seal) In the affected bays In the sand bed region UTs of the upper drywell region consistent with the existing program UTs will be performed on any areas In the sand bed region where visual Inspection Indicates the coating Is damaged end corrosion has occurred M

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4. Prior to the period of extended operation, AmerGen will perform addltional visual Inspections of the epoxy coating that was applied to the exterior surfa6e of the Drywall shell In the sand bed region, such that the coated surfaces In all 10 Drywall bays will have been Inspected at least once. In addition, the InservIce Inspection (ISI) Program will be enhanced to require Inspection of 100% of the epoxy coating every 10 years during the period of extended operation. These Inspections will be performed In accordance with ASME Section XI, Subsection IWE. Performance of the Inspections will be staggered such that at least three bays will be examined every other refueling outage, Inspection of the coating Is accomplished through the Protective Coating Monitoring and Maintenance Program (B.1.33)

5. A visual examination of the drywell shell In the drywell floor Inspection access trenches will be performed to assure that the drywall shell remains IntacL If degradation Is Identified, the drywall shell condition will be evaluated and corrective actions taken as necessary. In addition, one-time ultrasonic testing (UT) measurements will be taken to confirm the adequacy of the shell thickness In these areas. Beyond these examinations, these surfaces will either be Inspected as part of the scope of the ASME Section XI, Subsection IWE Inspection program or they will be restored to the original design configuration using concrete or other suitable material to prevent moisture collection In these areas.

6. The coating Inside the torus will be visually Inspected In accordance with ASME Section XI, Subsection IWE, per the Protective Coatings Monitoring and Maintenance Program (B.1.33). The scope of each of these Inspections will Include the wetted area of all 20 torus bays. Should the current torus coating system be replaced, the Inspection frequency and scope will, as a minimum, meet the requirements of ASME Section XI, Subsection IWE.

7. AmerGen will conduct UT thickness measurements In the upper regions of the drywell shell every other refueling outage at the same locations as are currently measured.

8. The IWE Program will be credited for managing corrosion In the Torus Vent Line and Vent Header exposed to an Indoor Air (External) environment

9. During the next UT Inspections to be performed on the drywall sand bed region (reference AmerGen 4/4106 letter to NRC), an attempt will be made to locate and evaluate some of the locally thinned areas Identified In the 1992 Inspection from the exterior of the drywall. This testing will be performed using the latest UT methodology with existing shell paint In place. The UT thickness measurements for these locally thinned areas may be taken from either Inside the drywall or outside the drywell (send bed region) to limit radiation dose to as low as reasonably achievable (ALARA).

10. AmerGen will conduct UT th!ckness measurements on the 0.770 inch thick plate at the Junction between the 0.770 Inch thick and 1.154 Inch thick plates in the lower portion of the spherical region of the drywall shell. These Enclosure Page 52 of 74 measurements will be taken at one location using the 6"x6* grid. These measurements will be performed prior to the period of extended operation and repeated at the second refueling outage after the Initial Inspection, at the same location. If corrosion In this transition area Is greater then areas monitored In the upper drywell, UT Inspections In the transition area will be performed on the same frequency as those In the upper drywell (every other refueling outage).

11. AmerGen will conduct UT thickness measurements In the drywell shell

'knuckle* area, on the 0.640 Inch thick plate above the weld to the 2.625 Inch thick plate. These measurements will be taken at one location using the 6'x6' grid. These measurements will be performed prior to the period of extended operation and repeated at the second refueling outage after the initial Inspection, at the same location. If corrosion In this transition area Is greater than areas monitored In the upper drywall, UT Inspections In the transition area will be performed on the same frequency as those In the upper drywell (every other refueling outage).

12. When the sand bed region drywall shell coating Inspection Is performed, the seal at the Junction between the sand bed region concrete and the embedded drywall shell will be Inspected

13. The reactor cavity seal leakage concrete trough drain will be verified to be clear from blockage once per refueling cycle.

During the 2006 drywell license renewal Inspections, standing water was Identified In contact with the drywall shell Inside the trench In bay #5 as described below. Inspection and evaluation of the drywell shell concluded that because the water environment Is alkaline and oxygen Is limited during plant operation, the expected corrosion Is Insignificant. However, AmerOen will further enhance this aging management program to ensure potential drywell corrosion Is detected and corrective actions ere taken before a loss of the drywall Intended function. Specific enhancements are:

14. UT thickness measurements will be taken from outside the drywell In the sandbed region during the 2008 refueling outage on the locally thinned areas examined-during the October 2006 refueling outage. The locally thinned areas are distributed both vertically and around the perimeter of the drywell In all ten bays such that potential corrosion of the drywell shell Would be detected.

15. Starting In 2010, drywell shell UT thickness measurements will be taken from outside the drywall In the ssndbed region In two bays per outage, such that Inspections will be performed In all 10 bays within a 10-year period. The two bays with the most locally thinned areas (bay #1 and bay #13) will be Inspected In 2010. If the UT examinations yield unacceptable results, then the locally thinned areas In all 10 bays will be Inspected In the refueling outage that the unacceptable results are Identified.

16. Perform visual Inspection of the drywall shell Inside the trench In bay #5 and bay #17 and take UT measurements Inside these trenches In 2008 at

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Inspections at refueling outages during the period of extended operation until the trenches are restored to the original design configuration using concrete or other suitable material to prevent moisture collection In these areas.

17. Perform visual Inspection of the moisture barrier between the drywall shell and the concrete floorlcurb, Installed Inside the drywall during the October 2006 refueling outage, In accordance with ASME Section X),

Subsection IWE during the period of extended operation.

After each Inspection, UT thickness measurements results will be evaluated and compared with previous UT thickness measurements. If unsatisfactory results are Identified, then additional corrective actions will be InItiated, as necessary, to ensure the dryweli shell Integrity Is maintained throughout the period of extended operation.

Operating Experience ASME Section XI, Subsection IWE as described In Oyster Creek Firet-10 Year Containment (IWE) Inservice Inspection Program Plan and Basis Is effective September 9, 1998 to September 9, 2008. Base line inspection of containment surfaces was completed In 2000 and a second Inspection was completed In 2004. The 2004 Inspection Identified (2) recordable conditions, a loose locknut was Identified on a spare drywall penetration and a weld rod was found stuck to the underside of the drywall head. Engineering evaluation concluded the stuck weld rod has no adverse Impact on drywell head structural integrity and the loose locknut did not affect the seal of the containment penetration.

The upper region of drywall shell has experienced loss of material, due to corrosion, as result of water leakage Into the gap between the containment and the reactor building In the 1980's. As a result the area Is subject to augmented examinations as required by ASME Section XI, Subsection IWE. The examination Is by ultrasonic (UT) thickness measurements. UT measurements taken In 2004 showed that the drywell shell thickness meets ASME criteria and that the rate of corrosion Is In a declining trend. Engineering evaluation of the UT results also concluded that the containment drywall, considering the current corrosion rate, Is capable of performing its Intended function through the period of extended operation. Further discussion Is provided In Section 4.7.2, "Drywall Corrosion' TLAA evaluation.

Similarly the sand bed region also experienced loss of material due to corrosion.

Corrosion was attributed to the presence of oxygenated wet sand and exacerbated by the presence of chloride and sulfate In the sand bed region. As a corrective measure, the sand was removed and a protective coating was applied to the shell to mitigate further corrosion. Subsequent Inspections confirmed that corrosion of the shell has been arrested. The coating is monitored periodically under the Protective Coating Monitoring and,Maintenance Program, B.1.33.

Refer to program B.1.33 for additional details.

The suppression chamber (Torus) and vent system were originally coated with Carboltn Carbo-Zinc 11 paint. The coating Is inspected every outage and Enclosure Page 54 of 74 repaired, as required, to protect the torus shell and the vent system from corrosion. Refer to program B.1.33 for additional details.

Operating experience review concluded that ASME Section XI, Subsection IWE Is effective for managing aging effects of primary containment surfaces.

During the October 2006 refueling outage UT thickness measurements in the sandbed region were made Inside the drywall at the same locations examined In 1996. The results of the statistical analysis of the 2006 UT date were compared to the 1992, 1994 and 1996 data statistical analysis results. Some of the 1996 data contained anomalies that are not readily justifiable but the anomalies did not significantly change the results. The comparison confirmed that corrosion on the exterior surfaces of the drywell shell In the sandbed region has been arrested.

in addition 106 UT thickness measurements were made In locally thinned areas, Identified In 1992, from outside the drywall In the sandbed region.

The 2006 UT thickness readings In the locally thinned areas are lower when compared to 1992 readings. This Is largely due to using a more accurate UT Instrument and the procedure used to take the measurements, which involved moving the instrument within the locally thinned area In order to locate the minimum thickness In that area. In addition the Inner drywall shell surface could be subject to some Insignificant corrosion due to water Intrusion onto the embedded shell (see discussion below). Additional measurements of the locally thinned areas will be taken In 2008 using the same type of UT Instrument to better correlate the measurements and confirm significant corrosion Is not ongoing In the Inner drywall shell surface.

During the 2006 refueling outage (1R21), UT thickness measurements were taken at the 4 elevations discussed above In accordance with the Oyster Creek ASME Section Xl, Subsection IWE aging management program. The results of the UT thickness measurements Indicated that no observable corrosion Is occurring at elevations 51' 10" and 60' 10". A single location (Bay 15 -23L) of the 3'V elevation (50 '2") continues to experience minor corrosion at a rate of 0.66 milslyr. The corrosion rate for the 40 elevation (87' 5") Is now statistically Insignificant and this elevation can be considered as no longer undergoing observable corrosion.

In addition UT measurements were taken on 2 locations (bay #15 and bay

1. 17) at elevation 23' 6" wher" the circumferential weld joins the bottom spherical plates and the middle spherical plates. This weld joins plates that are 1.154" thick to the plates that are 0.770" thick. These two bays were selected because they are among those that have historically experienced the most corrosion In the sandbed region. At each location 49 UTs were taken above the weld on the 0.770" thick plate and 49 UTs were taken below the weld on the 1154" thick plate. The minimum average thickness measured on the 0.770" thick plate Is 0.766" and 1.160" on the 1.154" thick plate.. The minimum measured local thickness on the 0.770" thick plate Is 0.628" and on the 1.154" thick plate Is 0.867". The minimum measured

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UT measurements were also taken on 2 locations (bay #15 and bay #19) at elevation 71' 6" where the circumferential weld joins the trensltion plates (referred to as the knuckle plates) between the cylinder and the sphere.

This weld Joins the knuckle plates, which are 2.625" thick to the cylinder plates, which are 0.640" thick. These two bays were selected because they also have historically experienced the most corrosion In the ssndbed region. At each location 49 UTs were taken above the weld on the 0.640" thick plate and 49 UTs were taken below the weld on the 2.625" thick plate.

The minimum measured average thickness on the 0.640" thick plate Is 0.624" and 2.530" on the 2.625" thick plate. The minimum measured local thickness on the 0.640" thick plate Is 0.449" and 2.428" on the 2.625" thick plate. The minimum measured general and local thickness on each plate meets the minimum thickness required to satisfy ASME stress requirements with an adequate margin.

Inner Drywall Shell In the Embedded ReAlon In 1986, as part of an ongoing effort at the Oyster Creek Generating Station to Investigate the Impact of water on the outer drywall shell, concrete was excavated at two locations Inside the drywall (referred to as trenches) to expose the drywall shell below the Elevation 10'-3" concrete floor level to allow ultrasonic (UT) measurements to be taken to characterize the vertical profile of corrosion In the sand bed region outside the shell. The trenches (approximately 18" wide) were located In bays #5 and #17 with the bottom of the trenches at approximate elevations 8'-9" and 9'-3" respectively (The elevation of the sand bed region floor outside the drywall Is approximately 8'-11").

Following UT examinations In 1956 and 1988, the exposed shell In the trenches was prepped and coated and the trenches were filled with Dow Coming 3.6548 silicone RTV foam covered with a protective layer of Promatic low density silicone elastomar to the height of the concrete floor (Elevation 10'-3"). The assumption was that these materia!s would prevent water that might be present on the concrete floor from entering the trenches. Before the 2006 outage these materials had not been removed from the trenches since 1988.

During the October 2006 refueling outage, the filler material from the two trenches was removed to allow Inspection of the shell In accordance with commitment #27.5. Upon removal of the filler material, approximately 6" of standing water was discovered In the trench located In bay #5. The trench area In bay #17 was damp; but no standing water was observed.

Investigations concluded that the likely source of waterwas a deteriorated drainpipe connection and a void In the bottom of the Sub-Pile Room drainage trough, or condensation within the drywall that either fell to the floor or washed down the Inside of the drywall shell to the concrete floor.

Water samples taken from the trench In bay #5 were tested and determined to be non-aggressive with pH (5.40 - 10.21), chlorides (13.6 - 14.6 ppm),

Enclosure Page 56 of 74 and sulfates (228 - 230 ppm). The joint between the concrete floor and the drywell shell had not been sealed to prevent water from coming In contact with the Inner drywall shell. The degraded trough drainage system and the unsealed gap between the concrete slab/curb and the Interior surface of the drywall shell was first discovered during this October 2006 refueling outage. This condition was entered Into the Corrective Action Process (IR 546049). The following corrective actions were taken during the October 2006 refueling outage.

" Walkdowns, drawing reviews, tracer testing and chemistry samples were performed to Identify the potential sources of water In the trenches.

Standing water was removed from trench In bay #5 to allow visual Inspection and UT examination of the drywell shell.

An engineering evaluation was performed by a structural engineer, reviewed by an Industry corrosion expert, and an Independent third-party expert to determine the Impact of the as-found water on the continued integrity of the drywell.

Field repairetmodiflcations were Implemented to mitigate/minImIze future water Intrusion Into the area between the shell and the concrete floor. These repaire/modIfications consisted of:

o Repair of the trough concrete In the area under the reactor vessel to prevent water from potentially migrating through the concrete and reaching the drywall shell rather than reaching the drywall sump, o

Cauilking the Interface between the drywall shell and the drywall concrete floor/curb to prevent water from reaching the embedded shell and o

Groutlng/caulklng the concrete/lrywell shell Interfaces In the trench areas.

" The trench In bay #5 was excavated to uncover an additional 6" of the Internal drywall shell surface for Inspection and allow UT thickness measurements to be taken In an area of the shell that was embedded by concrete.

• Visual Inspection of the drywell shell within the trenches was performed.

" A total of 584 UT thickness measurements were taken using a 6"x6" template (49 points) within the two trenches. Forty-two (42) additional UT measurements were taken In the newly exposed area In bay #5.

Visual examination of the drywall shell within the two trenches Initially Identified minor surface rust; with water In bay #5 and moisture In bay #17.

After the surfaces were cleaned with a flapper wheel (lightly to avoid removing the metal) a visual examination of the shell was conducted In accordance with ASME Section XI, Subsection IWE. The visual examination Identifiedno recordable (significant) corrosion on the Inner surface of shell.

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m Enclosure Page 57 of 74 A total of 294 UT thickness measurements were taken In the bay #5 trench and 290 measurements were taken In the bay #17 trench during 2006 refueling outage. The results of the measurements Indicated that the drywell shell In the trench areas experienced a reduction In the average thickness of 0.038"aInce 1986. AmerGen's evaluation concluded that the wall thinning was a result of corrosion on the exterior surface of the drywall shall in the sandbed region between 1986 and 1992 when the sand was still In place and corrosion was known to exist.

An engineering evaluation of the Oyster Creek Inner drywall shall condition was prepared by a structural engineer and reviewed by an Industry corrosion expert and Independent thlrd-party expert to determine the Impact of the as-found water on the continued Integrity of the drywall shell.

The evaluation utilized water chemical analysis, visual Inspections and UT examinations. It concluded that the measured water chemistry values and the lack of any Indications of rebar degradation or concrete surface epalling suggest that the protective passive film established during concrete Installation at the embedded steealconcrete Interface Is still Intact and significant corrosion of the drywall shell would not be expected as long as this benign environment Is maintained. Therefore, since the concrete environment complies with the EPRI concrete structure guidelines, corrosion would not be considered significant within the Oyster Creek drywall and the water could remain In contact with the Interior drywell shell Indefinitely without havinglong term adverse effects.

More specifically, the results of this engineering evaluation Indicate that no significant corrosion of the Inner surface of the embedded drywell shell would be anticipated for the following masons:

The existing water In contact with the drywell shell has been In contact with the adjacent concrete. The concrete Is alkaline which Increases the pH of the water and, In turn, Inhibits corrosion. This high pH water contains levels of Impurities that are significantly below the EPRI embedded steel guidelines action level recommendations.

Anynow water (such as reactor coolant) entering the concrete-to-shell Interface (now minimized by repairs/modifications implemented during this outage) will also Increase In pH due to Its migration through and contact with the concrete creating a non-aggressive, alkaline environment.

Minimal corrosion of the wetted Inner drywall steel surface In contact with the concrete Is only expected to occur during outages since the drywall Is Inerted with nitrogen during operations. Even during outages, shell corrosion losses are expected to be Insignificant ince the exposure time to oxygen Is very limited and the water pH Is expected to be relatively high. Also, repalrslmodifications Implemented during the 2006 outage will further minimize exposure of the drywall shell to oxygen.

Based on the UT measurements taken during the 2006 outage of the newly exposed shell area In Bay 5 that has not been examined since It was encased In concrete during Initial construction (pre-1969), it was Enclosure Page 58 of 74 determined that the total metal lost based on a current average thickness measurement of 1.113" versus a nominal plata thickness of 1.154" Is only 0.041" (total wall loss for both Inside and outside of the dryweU shell).

Although no continuing corrosion Is expected, but conservatively assuming that a similar wall loss could occur between now and the end of the period of extended operation, a margin of 336 mils to the 0.736" required wall thickness would exist.

As for the 0.676" thIck embedded plate, conservatively assuming the plata has undergone corrosion of 0.041" to data, and will undergo similar wall loss between now and the end of the period of extended operation a margin of 115 mile against the required minimum general thickness of 0.479" required for pressure Is provided.

The engineering evaluations summarized above confirmed that the condition Identified during the 2006 outage would not Impact safe operation during the next operating cycle. Also, a conservative projection (noted above) of wall loss for the 1.154" and 0.676" thick embedded shell sections Indicates that significant margin Is provided In both sections through the period of extended operation.

Although a basis Is established that ongoing corrosion of the shell embedded In concrete should not be expected and repaerslmodifications have been performed to limit or prevent water from reaching the Internal surface of the drywell shell, AmerGen has now established that the existence of water In contact with the Intemal surface of the drywell shell and concrete at and below the floor elevation will be assumed to be a normal operating environment. AmerGen will further enhance the Oyster Creek ASME Section Xl, Subsection IWE aging management program to require periodic Inspection of the drywall shell subject to concrete (with water) environment In the Internal embedded shell area and water environment within the trench area.

Conclusion The enhanced ASME Section XI, Subsection [WE aging management program ensures, that loss of material, loss of sealing, and loss of preload of primary containment components and the contaenment vacuum breakers system piping and components are adequately managed so that there is a reasonable assurance their intended function will be maintained consistent with the current licensing, basis during the period of extended operation.

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Enclosure Page 59 of 74 B.1.31 STRUCTURES MONITORING PROGRAM Program Description The Structures Monitoring Program provides for aging management of structures and structural components, Including structural bolting, within the scope of license renewal. The program was developed based on guidance In Regulatory Guide 1.160 Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and NUMARC 93-01 Revision 2, 'Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," to satisfy the requirement of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

The scope of the program also Includes condition monitoring of masonry walls and water-control structures as described In the Masonry Wall Program and In the RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants aging management program. As a result, the program elements Incorporate the requirements of NRC IEB 80-11, "Masonry Wall Design*, the guidance In NRC IN 87-67, "Lessons eained from Regional Inspections of Licensee Actions In Response to IE Bulletin 80-11", and the requirements of NRC Regulatory Guide 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power Plants."

The program relies on periodic visual Inspections by qualified personnel to monitor structures and components for applicable aging effects. Specifically, concrete structures are Inspected for loss of material, cracking, and a change In material properties. Steel components are inspected for loss of material due to corrosion. Masonry walls are Inspected for cracking, end elastomera will be monitored for a change In material properties. Earthen structures associated with water-control structures and the Fire Pond Dam will be inspected for loss of material and loss of form. Component supports will be Inspected for loss of material, reduction or loss of isolation function, and reduction In anchor capacity due to local concrete degradation. Exposed surfaces of bolting are monitored for loss of material, due to corrosion, loose nuts, missing bolts, or other Indications of loss of preload. The program relies on procurement controls and Installation practices, defined in plant procedures, to ensure that only approved lubricants and proper torque are applied consistent with the NUREG-1801 bolting Integrity program.

The scope of the program will be enhanced to Include structures that are not monitored under the current term but require monitoring during the period of extended operation. Details of the enhancements are discussed below.

Inspection frequency Is every four (4) years; except for submerged portions of water-control structures, which will be Inspected when the structures are dewatered, or on a frequency not to exceed 10 years. The program contains provisions for more frequent Inspections to ensure that observed condltons that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process Enclosure Page 60 of 74 NUREG-1801 Consistency The Structures Monitoring Program Is consistent with the tan elements of aging

-management program Xi.S6,"Structures Monitoring Program," specified In NUREG-1801.

Exceptions to NUREG-1801 None.

Enhancements The scope of the program will be Increased to add buildings, structural components and commodities that are not In scope of maintenance rule but have been determined to be In the scope of license renewal. These Include misceilaneous platforms, flood and secondary containment doors, penetration seals, liner for sumps, structural seals, and anchors and embedment.

The scope of the program will be enhanced to Include Station Blackout System Structures, structural components, and phase bus enclosure assemblies.,

Inspection frequency, Inspection methods, and acceptance criteria will be the same as those specified for other structures in scope of the program.

The scope of the program will be Increased to Include component supports, other than those In scope of ASME XI, Subsection IWF.

The scope of the program will be enhanced to Include Inspection of external surfaces of Oyster Creek and Forked River Combustion Turbine mechanical components that are not covered by other programs, Including exterior surfaces of HVAC duct, damper housings, and HVAC closure bolting. Inspection and acceptance criteria of the exterior surfaces will be the same as those specified for structural steel components and structural bolting.

The program will be enhanced to require removal of piping and component Insulation to permit visual Inspection of Insulated surfaces. Removal of Insulation will be on a sampling basis that bounds Insulation materiel type, susceptibility of Insulated piping or component material to potential degradations that could result from being In contact with Insulation, and system operating temperature.

The program will provide for Inspections of; electrical panels and racks, Junction boxes, Instrument racks and panels, cable trays, offsite power structural components and their foundations, end anchorage.

The program will provide for periodic sampling and testing of ground water and review its chemistry data to confirm that the environment remains non-aggressive for buried reinforced concrete.

The program will provide for periodic Inspection of components submerged In salt water (intake Structure and Canal, Dilution structure) and in the water of the fire pond dam, Including trash racks at the Intake Structure and Canal.

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M Enclosure Page 61 of 74 The program willrequire Inspection of penetration seals, structural seals, and other elastomers for change In matedal properties by Inspecting the elastomers for cracking and hardening.

The program will require Inspection of vibration Isolators, associated with component supports other than those covered by ASME XI, Subsection IWF, for reduction or loss of Isolation function by Inspecting the Isolators for cracking and hardening.

The current Inspection criteria will be enhanced to add loss of material, due to corrosion for steel components, and change In matarial properties, due to leaching of calcium hydroxide and aggressive chemical attack for reinforced concrete. Accessible wooden piles and sheeting will be Inspected for loss of material and a change In material properties. Concrete foundations for Station Blackout System structures will be Inspected for cracking and distortion due to Increased stress level from settlement that may result from degradation of the Inaccessible wooden piles.

The program will be enhanced to include periodic Inspection of the Fire Pond Dam for loss of material and loss of form.

The program will be enhanced to Include Inspection of Meteorological Tower Structures. Inspection and acceptance criteria will be the same as those specified for other structures In the scope of the program.

The program will be enhanced to Include Inspection of exterior surfaces of piping components associated with the Radio Communications system, located at the mateorological tower site, for loss of material due to corrosion. Inspection and acceptance criteria will be the same as those structures. Enhancements will be Implemented prior to the period of extended operation.

Operating Experience The review of program documentation, and other plant operating experience before the program was Implemented, Identified cracking of reinforced of exterior walls of the reactor building, drywall shield wall above elevation 95', and the spent fuel pool support beam. Cracking of the reactor building exterior walls was generally minor and attributed to early shrinkage of concrete and temperature changes. Engineering evaluation concluded that the structural Integrity of the walls Is unaffected by the cracks. Repairs to areas of concern were made to prevent water Intrusion and corrosion of concrete rebar. The cracks and repaired areas are monitored under the program to detect any changes that would require further evaluation and corrective action.

Enclosure Page 62 of 74 Cracking of the drywell shield wall was attributed to high temperature In the upper elevation of the containment drywall. Engineering analysis concluded that stresses are well below allowable limits taking Into consideration the existing cracked condition. The shield wall cracking was addressed In NRC SEP review of the plant under Topic 111-7B. The cracks have been mapped and Inspected periodically under the program. Recent Inspections Identified no significant change In the cracked area.

Cracking of the spent fuel storage pool concrete support beams was Identified in mid-I 980. Subsequently crack monitors were installed to monitor crack growth and an engineering evaluation was performed. Based on the evaluation results and additional non-destructive testing to determine the depth of the cracks, it was concluded that the beams would perform their intended function, and that continued monitoring with crack monitors is not required. The cracks are examined periodically under the program and have shown little change.

Inspection of the Intake canal, performed in 2001, Identified cracks and fissures, voids, holes, and localized washout of coatings that protect embankment slopes from erosion. The degradations were evaluated and determined not to Impact the Intended function of the Intake canal (UHS). However the Inspector recommended repair of the degradations to prevent further deterioralion. A project to repair the canal banks has been Initiated.

Inspections conducted In 2002, concluded that degradations discussed above have not become Worse and remains essentially the same as Identified In previous Inspections. In addition minor cracking, rust stains, water stains, localized exposed rebars and rebar corrosion, and damage to siding were observed. The degradations were evaluated and determined not to have an Impact on the structural Integrity of affected structures. Operating experience review concluded that the program Is effective for managing aging effects of structures, structural components, and water-control structures.

In 1986, as part of an ongoing effort at the Oyster Creek Generating Station to Investigate the Impact of water on the outer drywall shell, concrete was excavated at two locations Inside the drywall (referred to as trenches) to expose the drywell shell below the Elevation 10'-3" concrete floor slab level to allow ultrasonic (UT) measurements to be taken to characterize the vertical profile of corrosion In the sand bed region outside the shell. The trenches (approximately 18" wide) were located In Bays 5 and 17 with the bottom of the trenches at approximate elevations 8'.B" and 9'-3" respectively (The elevation of the sand bed region floor outside the drywell Is approximately 8'-11").

Following UTexamInations In 1986 and 1988, the exposed shell In the trenches was prepped and coated and the trenches were filled with Dow Coming 3-6548 silicone RTV foam covered with a protective layer of PromatIc lowdensity silicone etastomer to the height of the concrete floor slab (elevation 10'-3"). At that time It was expected that these materials would prevent water that might be present on the concrete floor slab from entering the trenches. Before the 2006 outage these materials had not been removed from the trenches since 1988.

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Enclosure Page 63 of 74 During the October 2006 refueling outage, the filler material from the two trenches was removed to allow Inspection of the shell In accordance with license renewal commitment #27.5 (AmerGen Letteir No. 2130-06-20358 dated July 7, 2006). Upon removal of the filler material, approximately 5" of the standing water was discovered In the trench located In bay #5. The trench area In bay #17 was damp, but no standing water was observed.

Water samples taken from the bay #5 trench were tested and determined to be non-aggressive with pH (8.40 - 10.21), chlorides (13.6 - 14.6 ppm), and sulfates (228 - 230 ppm). The high pH In water Is typical of the concrete alkaline environment. This condition was entered Into the Corrective Action Process (IR 546049).

As a result of Identifying standing water Inside the bay #5 trench and dampness In the bay #17 trench, Investigations were conducted to Identify the entry point of water Into the concrete below the floor slab level. The Investigations concluded that the likely entry point for the water was a deteriorated connection In the Sub-Pile Room (room within the reactor pedestal, below the CRD housings) drainage trough drainpipes, at a void In the bottom of Sub-Pile Room drainage trough, and at the unsealed gap at the elevation 101-3" concrete slab curb and the Interior surface of the drywall shell. Field repairelmodifications were Implemented to mitigatelminimize future water Intrusion Into the area between the shell and the concrete floor slab. Engineering evaluations were conducted to assess the Impact of the water environment on the structural Integrity of the drywall shell and reinforced concrete. Evaluation of the drywall shell Is discussed In detail In LRA Section 3.5.2.2.1.4 and In Appendix B.1.27.

Evaluation of the reinforced concrete fill slab Is discussed below.

Visual Inspection of the reinforced concrete slab was conducted In accordance with this program (Structures Monitoring Program, 8.1.31) during the October 2006 refueling outage. The structural engineer who conducted the inspection noted that the concrete floor slab outside the reactor pedestal is In good condition with no visible evidence of rebar corrosion (cracking, spelling), or other structural defects. The edge of the concrete curb where It meets the drywell shell was uneven. Some concrete had chipped off due to sharp edges. The loss of.material It not a structural concernbut the gap where chipped concrete was observed could be a possible path for water Intrusion (this area was later sealed). Inspection of the'reactor pedest-t wall and the floor slab of the Sub-Pile Room were observed to be In good condition.

In summary, engineering evaluation of the Inspection results concluded that water Intrusion Into the concrete has no Impact on the structural Integrity of the slab. The observed condition of the concrete Is typical of concrete In other areas of the plant. There Is no evidence of rebar

• corrosion, significant cracking, or other concrete degradations. Such degradations would not be expected due to the high pH, end the low

• chlorides and sulfates content of the concretetwater environment.

Enclosure Page 64 of 74 Conclusion The Structures Monitoring Program was developed to Implement the requirements of 10 CFR 50.65, 'Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.' The program relies on periodic visual Inspections to moniltor the condition of structures and structural components.

Inspection frequency is every four (4) yeara (except for water-control structures) with provisions for more frequent Inspections to ensure that observed conditions that have the potential for Impacting an Intended function are evaluated or corrected In accordance with the corrective action process. Submerged portions of waler-control structures will be Inspected when dewatered or on a frequency not to exceed ten (10) years.

The scope of the program will be enhanced to Include all structures, and component supports not covered by other programs, the Fire Pond Dam, and exterior surfaces of mechanical components In the scope of license renewal that are not covered by other programs. Inspection criteria will also be enhanced to provide reasonable assurance that the aging effects are adequately managed so that the intended functions of structures and components within the scope of license renewal are maintained consistent with the current licensing basis during the period of extended operation.

Enclosme Page 65 of74 Table -L UT Thidwdes mesuremen for the Upper Region of the Drywelt Shell Avnge Measured Thidcmeim

, inches Moentored Loalion Mllmm oI Pm)ected Ele*.fieo Required

] Thiwckm In

Thiclio, 1987 In11 19m I91 199 199 193 199 1996 I"

2m1) 2m) 206 22 Elevabo 0342" 50" 2" Bays-0.743 0.742 0.747 No Obsenoble D1.2 0.74S 0745 90-747 0.741 0.748 0.741 0.743 L.747 ogong 0.746 0.748 Coonsie Bay 5;- H 9.761 0.755 0.759 No Ob,.rroble 0.761 0.759 0.759 0.754 0.757 0.734 0.756 0.760 Omsog.

Caw.760 Corrosion Bay S-- SL 0.706 0.703 0.703 No Obou-vbik 0.703 0.705 a.702 0.7 0.705 0.706 0.701 0.705 Ongoig 10.706 (7) cfun Boy 13-0.762 0.760 0.765 No Oboerwbl 31H 0.779 0.750 a-763 0.759 0.766 0.762 0.750 99762 Ongoing 0.765 Conolion Boy 13-0.697 0.689 0.685 No Obur-b 31L 0.654 0.670 0.600 0.683 0.690 0.692 0.693 0.67D Oogoiog 0.619 Conosim Boy 15-09759 0.762 0.767 23H 0.764 0.762 0.763 0.758 0.760 0.750 0.757 0.765 IL749 I.L720 Boy 15-0.726 0.726 0.726 23L 0.720 0.729 0.724 0.720 0.714 0.729 0.727 10.725 I

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Enclosume Page 66 of 74 Table -L UT Thickmess measurements for the Upper Region of the Drywell Sbell

Enclosure Page 67 of 74 Table -1. UT Thickness mneasurements for the Upper Region of the Drywell Shell Nottes:

1. The average thiti.mess is based on 49 Utrasonic Teeting (UT) mesu-rents peeformed ad each location 2 Multiple insoess eme pefmed in the years 198

,1990 1991, and 1992.

3. The 1993 elevation 60' 10rBay 5-22 inspectonw ns perfonoed aos Janary 6.,1993. All other locationso nse inspected in December 1992.

4. Accureay ofUthasonic Testing Equlpment is plus or minus 0.010 inches.

5. Rke s SE-00243-02.

6. Mlnaiam required thilckess for elevation 51' 1o" was Inadvertenlty listed a 0.541" in the orilgnal RAI respoese. The eorrect watve Is 0.1". There is no Impact on the analysis, as this m a transcription erro between the calculation and Table 1.

7. This 1I92 salne for losatlsn Dlay 5-1 was Iasdvertently reported as 0.707" (Instead of I.702") In the original RAI respoase There is lna mpact as the anaaysis, as tIis was a transeelption error be6teem the ealculatlon msd Table 1.

6. The 2004 adue for Loeatioa Bay 1-5*-22 was Itadeesteatly listed a.689 In the original RAI response. This was the result of an e-ror Identified In the old ealculations that has bees asbmequently eorrected and factored Into the latest analysis.

Condcuson:a Summary of oCrosm Rates of UTmeasremets taken thlrough year 206

" Themeisnoebservmbleongoingoonusieonsthree eltaetons(51' 10". 60' 10. and 97'5")

" Eased on tatistical analysis, one locatien al eeation 50' 2" is sndagoing anoinor oessin at of tl66 ms pe ayear.

Enclosure Page 60 of 74 Table -2 UT Thickness measurements for the Sand Bed Region of the Drywell Shell Locatilon Sub Dec Feb Ap r-MayI Aug S ap Ju l Oct J

un Sep Feb Apr Mar May No

,, May S p Sep r p

¢'

say Loca fl*on 1986 19 ST 1987 19 97!

t9 97 1987 198 B 1988 1989 1989 1990 1990 1991 t9 1 4 9 19 92 199 2

i 1994 1996 2006 10 1.115 1.101 1.151 1.122 1D 1.17 0

1.184.175(41 1.180 5D 1 174 1.168 1.173 1.185 I0

.1 3 5 1.1 3 6 1.1 3 8 1.1 23 9A 1.155 1,157 1.155 1.154 D

0.0 1W 1.054 1.020 1.02t 1.022 0.5M7 tOtO 0.07 1tOJt UMi 0a r

.t m.01 0.55 1_A 0.004 0.90 22 0.905 L0913.04, 0.358 0.81O 001

5.

01 3

0.003 0.000 0.042 0.J50 0.1 O30 8OM 11C D

0.170 0.954 0.910 0.906 0.7 0.20 0.845 0.50 0.05 0.085% 0DAM 0.04 0.458 0.A040 0.85 0.037 0.55

_ op 11.0461 1.109 10.07 1 0.047 1.01,09

,01. 0.04 0.I31 2.920 0.082 0.0.94 1.010 0.070 0.0254) 1.042

.0 13A 0.0 9 O9 5

0,883 D M8 0 O M I. 5 0-8 55 0.853 i 0.849 0.88.5 0.85 a08 3 (4) l.8 58 (4 1 a m&4 13D (1)

Elft 0.962 (1)

O-sn (1) 0.*0 0.901 0.9o O.=3 0.W0e 0z 0.533 0.904 To p

1.0 7 2 1 X0 4 9 1.0 4 B 1.0 8 8 1.0 5 5 1.03 7 1 1 45 9 t 1. 4 7 13C(l) t.14a(l 1.14o(lI).154(1j 1.142 15A 1.120 1.114 1.127 1.121 1SD 1.011 IA 1

.06 e0 1.061 1.059 1.057 1.980 1450 1.042 1.065 1.058 1,053 1.0s tI553I 17A amont I. mm 0.067 0-965 I0.955 0.94 0251 0OMS 0.S42 0433 0"94 0.941 0.934 0.597 0.23S Tap 10-%

1.133 1.13DI t.131 1.120 1.129 1.131 1.129 1.123 1.125 1.125 1.129 7.144 1.122 17D) 0.5=

0,8'S 0.e91 0ý895 0.878 0.50 0,857 0.847 0"4 0J52 02 8.2

.22 DAM2 0.017 0.A1 LM4 K< 0218 17/19 rop 0J Mt 1.019 1.131 0.990 0386 0.5 0.6 055 0 972 0,*7*

0 GAST 0.987 0.

S Btob=

1*04

.59N Ga5ss 1.010 1JO 0.9m s

0,9_71 0.990 0.989 0.957 0.99!_ 0.a" 1 9A T AW8O4 0.80" 0.8 5 90. 5 0.8 4 9 0.8 3 7 0, 82 9

O. 8 2 0.1.

1 2 (2 )

o i5 s a 0s 1 0.8 0 3 0 *

. 0

. 0

. 1

. 0 IgB I

aJ* ~~0.892 0.868 0.964 i

.o-ro7 0

.8W 5 3.4

• OS3/,

08 3

.4 r86 08 0.840 O -sod 0.5 s a.84 1 9 :j0 9 1

. 8 n

• 0 8 3 : 0 8 6

4

. 4 0.0 81 0

• 5 0. 4

. 2 0

. =2 0.8 W 1 0.8 1 9 0

., 2 D,45 4

K4 0.8 2 4

E*ca*surs'Page 69 of 74 Table -2 UT Thickness measur.ments for the Sand Bed Region of the Drywefl Shell Table 2 Notes:

1. The Location Bay idoilfcatlsas far 13C and 13D were Inadvertently reversed In the olginal RAI resonse, and erreneeos low values were entered for Loeartoa Bay 13C.

There Is o Impact a. the analysl, as this was a transcrptlon error betwera the csleslation and Table 2.

2. The Pebrueary 1990 valust for Lado Bays 19A and 1PB w de Iasdverentey reversed Inthe origiaal RAI respene. Tharhsno impact an the a.

sl " this was a transcription error between the calculation and Table 2.

3. The May1991 aMse for Lacation Bay 1IC Top vas lnadvetently reported as L.O1i (verars 1.0018" which rounds to l.00M) il the original RAI mpom There Is no Impact oa the aaalya, as this wstasrlptia errartIwess the calcslatiaosn ad Table 2.

4. The remainlng changes are minor errors identfied in the old cslaluations that hawe bees sibsestenaey corrected and factored lat the latest analysis.

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I Consolidated Summay of Drywell lispct ions Performed During 2006 Outage Enclosure Page 70 of 74 IWE Program Inspections/Actions Performed During 2006 Refueling Outage "WE Program. Comm[tmants (Numbers consistent with LRA A-5 table.

2006 (1R21) Outage Results Commitment # 27)

1. Ultrasonic Testing (UT) thickness measurements of the drywell

1. Ultrasonic Inspections of the drywell shea at shell In the sand bed region will be performed on a frequency of every locations previously measured, as outlined In the 10 years, except that the Initial inspection wIll occur prior to the period previous column, were performed. Review of the of extended operation and the subsequent inspection will occur two 1992. 1994, 1996 and 2006 data for all grids show that refueling outages after the initial Inspection, to provide early these monitored locations have not experienced any confirmation that corrosion has been arrested. The UT measurements observable corrosion. This conclusion Is based on a will be taken from the Inside of the drywell at the same locations where statistical comparison with the mean thicknesses UT measurements were performed in 1996. The Inspection results measured in 1992 1994, 1996 and 2006 at each will be compared to previous results. Statistically significant deviations location.

from the 1992. 1994, and 1996 UT results will result in corrective actions that Include the following:

a. Perform additional UT measurements to confirm the readings.

Notify NRC within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of conftmation of the Identified condition.

Conduct visual Inspection of the extemat surface in the sand bed region In areas where any unexpected corrosion may be detected.

Perform engineering evaluation to assess the extent of condition and to determine if additional inspections are required to assure drywell integrity.

a Perform operability determination and Justification for operation until next inspection.

These actions will be completed prior to restart from the associated outage.

Consolidated Summary of Drywell Eipect ions Performed During 2006 Outage Enclosure Page 71 of 74 IWE Program Commitments (Numbers consistent with LRA A.5 table, 2006 (1R21) Outage Results Commimnent # 27)

2. A strippable coating will be applied to the reactor cavity liner to

2. Strippable coating was applied to the reactor cavity prevent water inisusion into the gap between the drywell shield wall liner prior to flooding the cavity with water for refueling and the drywell shell during periods when the reactor cavity is flooded.

activities.

3. The reactor cavity seal leakage trough drains and the drywell sand

3. The reactor cavity seal leakage brough drain was bed region drains will be monitored for leakage, monitored for leakage daily after the reactor cavity was The sand bed region drains will be monitored daily during flooded up for refueling. There was a small stream of refueling outages. If leakage Is detected, procedures will be in water (approximately one gallon per minute) observed place to determine the source of leakage and investigate and to be coming from the reactor trough.drain line. This address the impact of leakage on the drywell shell, including rate was observed to be consistent throughout the verification of the condition of the drywell shell coating and period that the cavity was filled with water.

moisture barrier (seal) in the sand bed region and performance of UT examinations of the shell In the upper regions. UTs will Also, the sandbed region drain lines were monitored also be performed on any areas In the sand bed region where daily during the outage, after the cavity was flooded.

visual inspection Indicates the coating Is damaged and No leakage was observed from any of the drain lines, corrosion has occurred. UT results will be evaluated per the in the sand bed area itself, nor was any collected In the existing program. Any degraded coating or moisture barrier will associated poly collection bottles. Note that the sand be repaired. These actions will be completed prior to exiting bed drains ware checked to ensure that they were the associated outage, clear. Some debris was found and cleared from two of the five drain lines.

Any degraded coating or moisture barrier will be repaired.

Consolidated Summary ofDrywell fispect ions Performed During 2006 Outage Enclosure Page 72 of 74 IWE Program Commitments (Numbers consistent with LIRA A.5 table, 2006 (1R21) Outage Results Commitment # 27)

4. Pror to the period of extended operation, AmerGen will perform

4. 100% of the epoxy coating applied to the external additional visual Inspections of the epoxy coating that was applied to surface of the drywell shell In the sandbed region In the exterior surface of the Drywell shell in the sand bed region, such 1992 was Inspected in accordance with the inspection that the coated surfaces in all 10 Drywell bays will have been specification and the condition of the coating was inspected at least once. In addition, the Inservice Inspection (ISI) determined to be satisfactory (i.e.j no evidence of Program will be enhanced to require inspection of 100% of the epoxy flaking, blistering, peeling, discoloration or other signs coating every 10 years during the period of extended operation. These of coating distress).

Inspections will be performed In accordance with ASME Section X1, Subsection IWE. Performance of the inspections will be staggered such that at least three bays will be examined every other refueling outage.

5. Avisual examination of the drywell shell in the drywell floor

5. Visual and ultrasonic examinations of the drywall inspecltion access trenches will be performed to assure that the drywell shell were performed from the Inspection access shell remains intact. If degradation is Identified, the drywell shell trenches. Visual inspection of the trenches Identified condition will be evaluated and corrective actions taken as necessary.

approximately 5" of standing water in the trench in Bay In addition, one-time ultrasonic testing (UT) measurements will be 5, and moisture in the trench in Bay 17, and minor taken to confirm the adequacy of the shell thickness in these areas.

surface oxidation on the exposed shell areas. The Beyond these examinations, these surfaces will either be inspected as ultrasonic test measurements determined that the part of the scope of the ASME Section X), Subsection IWE Inspecion drywell shell retains significant thickness margin in program or they will be restored to the original design configuration these areas.

using concrete or other suitable material to prevent moisture collection in these areas.

Also, additional concrete was excavated during 1R21 to expose approximately six more inches of previously embedded drywell shell surface at the bottom of the trench in bay 5 for Inspection. UT results Indicate that the average thickness in this area of the shell is approximately 0.041 inches (41 mils) below the nominal thickness of 1.154 inches, signifying that

Consolidated Summary of Drywell I'spect ions Performed During 2006 Outage Enclosure Page 73 of 74 IWE Program Commitments (Numbers consistent with IRA A.5 table, 2006 (1R21) Outage Results Commitment # 27) substantial margin exists In this previously embedded plate material.

7. AmerGen will conduct UT thickness measurements in the upper

7. UT thickness measurements in the upper drywall regions of the drywell shell every other refueling outage at the same were taken. Statistical evaluation of the mean data locations as are currently measured.

Indicates that the upper dryweti shell is not undergoing observable corrosion, with the exception of one grid location. Analysts of the data at that grid location indicates a corrosion rate of 0.66 mils per year.

9. During the next UT inspections to be performed on the drywell sand

9. 106 areas that had been Identified in 1992 as bed region (reference AmerGen 414/08 letter to NRC), an attempt will locally thinned were ultrasonically examined. These be made to locate and evaluate some of the locally thinned areas areas are geometrically distn'buted throughout the identified in the 1992 inspection frot the exterior of the drywell. This periphery of the drywNl shell, at various elevations testing wil be performed using the latest UT methodology with existing within the sand bed region. The results Indicate that shell paint in place. The UT thickness measurements for these locally all the measured local thicknesses meet the thinned areas may be taken from either inside the drywall or outside established design basts criteria.

the drywell (sand bed region) to limit radiation dose to as low as reasonably achievable (ALARA).

10. AmerGen will conduct UT thlckness measurements on the 0.770

10. Two sets of UT thickness measurements were inch thick plate at the junction between the 0.770 inch thick and 1.154 taken at the junction between the 0.770 Inch thick and inch thick plates, in the lower portion of the spherical region of the 1.154 Inch thick plates, In the lower portion of the drywall shall. These measurements will be taken at four locations spherical region of the drywall shell, using a 6xW grid.

using the 6x6 grid. The specific locations to be selected will consider Evaluation of these first-time readings shows that the previous operational experience (Le. will be biased toward areas that mean and Individual thicknesses currently meet have experienced corrosion or have been exposed to water leakage).

acceptance criteria, with adequate margin. Note that, These measurements will be performed prior to the period of extended per the commitment, an additional two sets of operation and repeated at the second refueling outage after the initial measurements wll be taken at different azimuths at I

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I Consolidated Summary of Drywcll ispect ions Performed Drinng 2006 Outage Enclosure Page 74 of 74 IWE Program Commitments (Numbers consistent with LRA A.5 table, 2006 (1R21) Outage Results Commitment #27)

Inspection, at the same location. If corrosion in this transition area is this elevation prior to the period of extended operation.

greater than areas monitored in the upper drywell, UT inspections In the transition area wil be performed on the same frequency as those In the upper drywell (every other refueling outage).

11. AmerGen will conduct UT thickness measurements in the drywell

11. Two sets of UT thickness measurements were shell knuclde' area, on the 0.640 inch thick plate Wbave the weld to taken in the drywell shell knuckle area at the junction the 2.625 inch thick plate. These measurements will be taken at four between the 0.640 inch thick and 2.625 inch thick locations using the 6Wr6 grid. The specific locations to be selected will plates, using a 6x6 grid. Evaluation of these first-consider, previous operational experience (.e., will be biased toward time readings shows that the mean and Individual areas that have experienced corrosion or have been exposed to water thicknesses currently meet acceptance criteria, with leakage). These measurements will be performed prior to the period adequate margin. Note that per the commitment, an of extended operation and repeated at the second refueling outage additional two sets of measurements will be taken at after the initial Inspection, at the same location. If corrosion In this different azimuths at this elevation prior to the period of transition area Is greater than areas monitored In the upper drywell. UT extended operation.

inspections In the transition area wil be performed on the same frequency as those In the upper drywell (every other refueling outage).

12. When the sand bed region drywall shell coating inspection is

12. A visual Inspection of the seal at the junction performed (commitment 27, item 4), the seal at the junction between between the sand bed region concrete and drywell the sand bed region concrete and the embedded drywell shell will be shell was performed in all 10 bays. The Inspection inspected per the Protective Coatings Program.

revealed the seal at this junction to be In acceptable condition with no repairs required.

13. The reactor cavity concrete trough drain will be verified to be clear

13. The reactor cavity trough drain was Inspected with from blockage once per refueling cycle. Any Identified Issues will be a boroscope and verified to be clear.

addressed via the corrective action process.

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Exhibit ANC 2

m m-m m

mm Section 1 Introduction to the Information Package Page 1-1 Enclosure - Table of Contents Section 1 - Introduction to the Information Package (2 pages)

Section 2 - Oyster Creek Drywell Corrosion Timeline (2 pages)

Section 3 - Oyster Creek Drywell General Description (9 pages)

Section 4 - Water Leakage onto the Exterior Surface of the Drywell Shell (7 pages)

Section 5 - The Upper Regions of the Drywell (21 pages)

Section 6 - Corrosion of the Outer Drywell Shell in the Sandbed Region (48 pages)

Section 7 - Embedded External Drywell Shell (7 pages)

Section 8 - Interior Embedded Drywell Shell (4 pages)

Section 9 - Reference Index (3 pages)

References This package of historical information and 2006 outage Information Is being provided to the ACRS Subcommittee reviewing the License Renewal Application for Oyster Creek. The purpose of the information is to respond to questions that were raised at the ACRS Subcommittee meeting on October 3, 2006 concerning the corrosion of the drywell shell and to update the Subcommittee on the results of recent inspection activities. This package is meant to help the ACRS members understand the information that the NRC staff has already reviewed over the course of weeks of audits and inspections. As such, the information set forth In this package consists of documents and responses to questions that were available to the NRC staff during the NRR AMR and AMP audits In January and February 2006, during the NRC Region 1 inspection in March 2006, In response to NRC RAts during the review of the Oyster Creek License Renewal Application, in docketed correspondence between GPUN or AmerGen and the NRC, and in documents reviewed by NRC Region 1 during the 2006 refueling outage. The information provided also Includes some historical information that serves as the basis or support for documents that were reviewed by the NRC.

Although the information included in this package has been available to the NRC, AmerGen has in many cases formatted the information differently in order to address some of the questions asked by ACRS members.

For example, the NRC staff may have reviewed numerical data on drywall shell corrosion provided in a table. In this document, however, AmerGen prepared a graphical representation of the data to show how the drywell shell corrosion rate has changed with time up to and including data obtained during the 2006 refueling outage and including the margin that is available.

The information being provided by AmerGen Is organized into the following five primary areas of interest dealing with the corrosion on the surfaces of the Oyster Creek drywell shell:

Leakage of water onto the drywell shell external surface during refueling outages.

(Section 4)

Includes a summary of significant events related to water leakage, information on the historic identification and evaluation of reactor cavity liner defects, historic troubleshooting and repairs to the reactor cavity trough area, and actions in place to minimize, detect and assess the impact of any leakage going forward.

The Upper Regions of the drywall. (Section 5)

Includes Information on periodic UT measurements taken from the inside of the drywall, the process to determine the locations monitored, and the random sampling confirmation of the monitored locations.

The Sandbed Region. (Section 6)

This Includes information on historical and recent UT thickness readings, the early 19gOs General Electric buckling analysis, and early 1990s preparing and coating of the external surface of the drywall shell.

Section 1 Introduction to the Information Package Page 1-2 Section 2 Oyster Creek Drywell Corrosion TImeline Page 2-1 The embedded part of the drywell shell exterior. (Section 7)

Includes Information on environmental conditions for the embedded part of the shell located below the sandbed region.

The embedded part of the drywell shell interior. (Section 8)

Includes Information on construction, required shell thicknesses and environmental conditions for the embedded part of the shell that Is inside the drywall Information In each topic area Is presented somewhat differently. Topics 1, 4 and 5 are generally narrative in nature presenting historical and technical information, with references to supporting documents. Topics 2 and 3 provide both a narrative presentation of the topic, and include UT measurement data that support AmerGen's understanding of and position on corrosion of the outer surface of the drywell shell.

The information on each of the five topics references many source documents, all of which are included in this package. Some of the references Include the detailed inspection results.

in addition to these 5 topics, the package also Includes a timealne that shows the sequence of relevant events, starting with the first discovery of water in the sand bed drains In 1980 up to and Including the Inspections performed during the refueling outage in October 2006. Also, the package includes a section on the general description of the Oyster Creek drywall, with associated drawings and figures.

1969 Begin Oyster Creek plant operation.

1980 Water Identified coming from sand bed drains.

1980, 83. 86, Investigation into source of water leaking from sandbed drains, and the and 89 leakage path.

1986 2 trenches excavated In the floor Inside the containment to gain access to the Inside of the drywall shell at an elevation corresponding to a lower portion of the sandbed region (Bays 5 & 17).

1986 to 89 Corrosion monitoring of the drywell shell from the inside to establish and characterize the extent of corrosion.

19 grid locations Inside the drywell at Elev. 11' 3" established for monitoring corrosion In the sandbed region with UT measurements.

Approximately 1,000 UT points taken circumferentlally around the Inside of the drywall shell.

12 representative grid. locations selected from the 1.000 points for continued monitoring of the upper drywall area.

Core samples taken at 9 locations of the drywall shell.

1988 Cathodic protection system installed on drywell shell.

Sand removal from the sandbed region started.

Repairs made to reactor cavity concrete trough to improve drainage.

Visual and UT Inspections In trenches.

1990 UT thickness measurements of the drywell shell taken at 57 randomly selected locations to confirm the 12 grid locations Identified previously for monitoring were representative of the leading corrosion locations.

One additional location added to the original 12.

1992 Cathodic protection system removed because it was not effective in preventing corrosion.

Sand removal from the sandbed regions completed.

External surface of the drywall shell In the sand bed region cleaned.

125 UT readings taken to confirm minimum thickness locations from the external surface.

Epoxy coating applied to the external surface of the drywell shell in the sandbed region.

Surface of the concrete floor In the sandbed regions finished with epoxy and sealed against the drywall shell.

UT of the sandbed region from Inside the drywall at 19 grid locations at Elevation 11V-3".

UT readings from the Inside of the drywell shell at the 13 grid locations In the upper elevations.

1994 UT of the sand bed region from inside the drywell at 19 grid locations at Elevation 11'-3"..

Visual Inspection of epoxy coating on outside of drywell In the sand bed region (Bays 3 & 11).

UT readings from the Inside of the drywall shell at the 13 grid locations In the upper elevations.

1996 UT of the sand bed region from inside the drywall at 19 grid locations at Elevation 11V-3", but some data appeared anomalous.

Visual inspection of epoxy coating on outside of drywell In the sand bed region (Bays 11 & 17).

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-m-m-Section 2 Oyster Creek Drywell Corrosion Timeline Page 2-2 Section 3 Oyster Creek Drywell General Description Page 3-1 UT readings from the inside of the drywell shell at the 13 grid locations in the uoDer elevations.

2000 Visual inspection of epoxy coating on outside of drywell in the sand bed region (Bays 1 & 13).

LUT readings from the inside of the drywell shell at the 13 grid locations in the upper elevations.

2004 Visual inspection of epoxy coating on outside of drywell in the sand bed region (Bays 1 & 13).

AUT readings from the inside of the drywell shell at the 13 grid locations in the upper elevations.

2005 Oyster Creek License Renewal Application submitted to the NRC on July 22, 2005.

2006 Visual inspection of epoxy coating on outside of drywell in the sand bed region in all 10 bays.

Visual inspection of the caulk seal at the junction between the sand bed region floor and the drywell shell in all 10 bays.

L UT readings at 19 grid locations in the sand bed region from inside the drywell at Elevation 11V-3".

L UT readings at 106 locally thinned areas (previously inspected in 1992) from outside the drywell in the sand bed region.

Visual inspections and UT readings of the drywell shell in the two trenches inside the drywell including additional excavation in the Bay 5 trench.

L UT readings at two grid locations each at two transition plate locations from inside the drywell (Elevations 23'-6" and 71'-6").

L UT readings from the inside of the drywell shell at the 13 grid locations in the upper elevations to confirm low corrosion rates or no observable corrosion.

Boroscopic examination of reactor cavity trough drain line and all 5 sand bed drain lines.

Monitored the Sandbed Regions drains for leakage.

Monitored the Reactor cavity trough drain for leakage.

Repaired/modified areas internal to the drywell to minimize the potential for water intrusion into the area between the embedded.

drywell shell and the drywell concrete floor.

The Oyster Creek primary containment is a General Electric Mark I design, with a drywell, suppression chamber, and a vent system connecting the drywell and the suppression chamber. It is designed, fabricated, inspected, and tested in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section VIII, and Nuclear Code Cases 1270N-5, 1271N, and 1272N-5.

The drywell is a steel pressure vessel, in the shape of an inverted light bulb, with a spherical section and a cylindrical section (See Figures 1 thru 4) located inside the Reactor. Building. The Reactor Building Foundation floor is a 10 ft thick reinforced concrete mat. The bottom elevation of the mat is minus 29' 6" and its top elevation is minus 19' 6" (See Figure 4). There is a waterproof membrane at the bottom of the mat that extends up the outside of the exterior walls to an Elevation of 5' 0". The concrete pedestal that supports the drywell is located at the center of the mat. The Torus Room completely surrounds this concrete pedestal with a floor elevation of minus 19' 6" (top of mat). The drywell shell has a bottom elevation of 2' 3".

The spherical section of the drywell was supported on a 39-foot diameter continuous steel skirt during construction (See Figures 4 & 7). The area within the skirt was filled with concrete and the floor inside the bottom of the sphere (drywell floor) was poured up to elevation 10' 3". The reactor support structure (pedestal) sits on top of the drywell floor (See Figure 5). The area within the reactor pedestal provides access for Control Rod Drive exchanges and is typically referred to as the Sub-Pile Room. The room also contains the drywell sump and a drainage trough that collects any leakage within the drywell. The Sub-Pile Room floor is raised at the center and slopes toward the drainage trough. Leakage outside the Sub-Pile Room, in the drywell, is directed to the drainage trough through 4 holes in the reactor pedestal equally spaced around the circumference. A concrete curb is installed around the perimeter of the drywell floor (See Figure 4 & 5) to prevent any water that collects on the floor from coming in contact with the drywell shell. The curb is removed in two locations where two trenches (Figure

3) were excavated in the floor in 1986 to allow UT thickness measurements to be taken below the floor. A moisture barrier was added at the junction of the curb and the drywell shell and inside the trenches during the 2006 refueling outage to prevent water and moisture intrusion into the embedded drywell shell.

Outside the drywell support skirt and the spherical section, concrete was poured in contact with the sphere up to elevation 6' 11". At this point, the concrete was stepped back 15" radially up to elevation 12' 3" and later filled with sand (sandbed region), refer to Figures 5 & 7 for details. The purpose of the sandbed was to provide a cushion to smooth the transition of the shell plate from a condition of fully embedded between two concrete masses to a free standing condition. The sandbed region was provided with five drains designed to allow drainage of any water that may enter the region.

Above the sandbed region, the drywell shell is closer to the reactor building concrete shield wall. The outer surface of the drywell shell and the shield wall are separated by a gap filled with compressible material. After construction completion, this material was

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At the top of the Reactor Building concrete shield wall, a concrete trough is located below the reactor cavity seal to collect any water that might leak from the reactor cavity during refueling outages. This trough is equipped with a drain line designed to direct any leakage to the Reactor Building equipment drain tank and prevent it from entering the gap between the drywell shell and the Reactor Building concrete shield wall (See Figure 6).

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Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-1 The following discussion addresses water leakage onto the exterior surface of the Oyster Creek drywelt shell. Part I, below, provides a historic overview of information about water leakage prior to the October 2006 outage. The discussion in Part If summarizes prior commitments made by AmerGen aimed at preventing leakage onto the shell, monitoring for such leakage and performing corrective actions If leakage occurs. Part III sets forth information discovered and analyzed as a result of the October 2006 outage. Overall conclusions about the drywell, AmerGen's performance of associated commitments, and continued drywell operability during the proposed twenty-year renewal term are summarized in Part NV.

I.

Historical Background Water leakage onto the exterior of the Oyster Creek drywell shell over a period of years, in combination with an historically degraded sand bed region drainage system, created a condition that was conducive to corrosion of the exterior surface of the drywell shell.

The previous owner/operator of Oyster Creek conducted extensive troubleshooting and repairs to determine and address the leakage and the corrosive effects of that leakage onto the drywell shell. As part of its license renewal activities, AmerGen has reviewed previous actions and instituted new measures (see Section II below) to ensure that leakage will be minimized and monitored, and that corrective actions will be implemented to ensure the drywell continues to perform its intended functions throughout the proposed twenty-year period of extended plant operation.

In addition, drywell commitments for license renewal are embedded in a formal AmerGen tracking system that includes specific work tasks, thereby ensuring timely implementation of the commitments and effective management oversight. Therefore, AmerGen is confident that the measures put into place to prevent and monitor leakage, in conjunction with the implementation of drywell shell visual and ultrasonic testing aging management program activities. will protect the shell such that it continues to perform its intended functions throughout the proposed period of extended operation.

A.

Chronology of Significant Events (Also see Timeline, Section 2) 1980 - Water was observed coming from the sand bed drains. As part of the original design, these drains had been filled with sand during plant construction. The sand was restrained at the outlet with a 100-mesh stainless steel screen (0.006 inch opening). The intent was to prevent loss of sand from the sand bed region through the drain lines, yet allow drainage of water.

1980, 1983 and 1986 refueling outages - Extensive investigations were performed to identify the source of water and the leakage path. Results of the investigations indicated that:

Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-2

" Leakage was not attributed to the reactor cavity metal trough drain line gasket or the refueling bellows seal (See Figure 6 of Section 3 of this Enclosure).

The reactor cavity metal trough drain line gasket leak was ruled out as the primary source of water observed in the sand bed drains because there was no clear leakage path to the gap between the drywell shell and reactor building concrete shield wall (i.e., drywell expansion gap).

Any gasket leakage would be minor and would be collected in the concrete trough below the gasket. Also, inspections concluded that the refueling bellows (seals) were not the source of water leakage.

The bellows were repeatedly tested using helium (external) and air (internal) without any indication of leakage. Furthermore, any minor leakage from the refueling bellows would be collected in the same concrete trough as would collect water from the gasket. The concrete trough is equipped with a drain line that would direct any leakage to the reactor building equipment drain tank and prevent it from entering the drywell expansion gap (Ref [13), Attachment I1l).

" Leakage was attributed to through-wall cracks in the reactor cavity liner attributed to mechanicaldamage and to fatigue (Ref [13],

Attachment Ill); and The leakage path was from the reactor cavity, to the concrete trough (later found to have been degraded - see Section C below) and through the drywell expansion gap down to the sandbed region within the reactor building (See Figure 6 of Section 3 of this Enclosure).

Between 1988 and 1993, multiple mitigating actions were taken to address the corrosion problem. These actions included (Ref [32], page 9):

Cleared the former sand bed region drains of sand and corrosion products to improve drainage.

Replaced reactor cavity metal trough drain gasket, which was found to be leaking (See Figure 6 of Section 3 of this Enclosure).

Removed water from the sand bed region.

Installed a cathodic protection system in bays with greatest wall thinning. Subsequent UT thickness measurements in these bays showed that the system was not effective in reducing the rate of corrosion and the system was removed from service in 1992.

Removed sand from the sand bed region to break up the galvanic cell (Ref [46]).

Removed corrosion products from the external side of the drywell shell in the sand bed region.

Leakage was observed (from the sand bed drains) during refueling outages;

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Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-3 Upon sand removal, the sand bed concrete floor was found to be cratered and unfinished. The concrete floor was repaired, finished and coated to permit proper drainage of the sand bed region (Refer to Section 7 of this Enclosure for details).

Applied an epoxy caulk seat at the junction of the drywell shell and the sand bed concrete floor to prevent intrusion of moisture into the drywell shell embedded in concrete (Refer to Section 6 of this Enclosure for details).

Applied a multi-layered epoxy protective coating.to the exterior surfaces of the drywell shell in the sand bed region (i.e., one pre-primer coat, and two top coats). (Refer to Section 6 of this Enclosure for details).

Applied stainless steel type tape and strippable coating to the reactor cavity during refueling outages to seal cracks in the stainless steel liner, in order to limit leakage from the reactor cavity. (Note that the steel tape was applied to larger cavity liner cracks and then the.

strippable coating was applied over the entire liner surface that would be (otherwise) wetted.)

Confirmed that the reactor cavity concrete trough drain line was not clogged (See Figure 6 of Section 3 of this Enclosure)

B.

Discovery and Evaluation of Cavity Liner Defects In 1987, defects in the reactor cavity liner were documented and evaluated in material nonconformance report MNCR 87-240 (Ref [49]). These defects consisted of through-wall and surface indications detected by non-destructive examination of the liner near weld joints. The purpose of the cavity liner is to facilitate filling the reactor cavity with water for refueling activities.

The defects do not pose problems except when the reactor cavity is filled with water during refueling outages. If no preventive action is taken, the defects allow water to leak behind the liner and run down into the reactor cavity concrete trough. If the flow rate exceeds the capacity of the two-inch trough drain, then water would back up into the drywell expansion gap and drain onto the outside of the drywell shell.

Safety Evaluation 328257-002 was generated in 1988 with the purpose of addressing the adequacy of the design and the safety impact of installation of a temporary barrier on the OC Reactor Cavity Pool to prevent leakage of water during refueling operation (Ref 6, pages 7 - 13). In it, two major options were considered - weld repair of the liner and a temporary barrier over the entire cavity liner. The weld repair option had the following drawbacks: (a) there were too many defects in the liner, (b) weld repair of these defects would produce large residual stresses and warping of the liner, and (c) if weld repairs were implemented, the repair areas would eventually fail due to the same mechanism, in the future. Therefore, the temporary barrier option of metal tape and strippable coating was chosen for the repair (Ref [6), page 6).

Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-4 C.

Reactor Cavity Concrete Trough Area Testing and Repairs As a result of observations of water leaking from concrete biological shield penetrations and sand bed drain lines during refueling outages in the early 1980s, numerous troubleshooting and repair activities were implemented over several years. These included:

Air and helium leak testing of the bellows seal in the bottom of the reactor cavity (no leakage detected) and cavity drain line (no significant leakage found),

Leak testing and some minor repairs to reactor cavity liner welds, Further pressure testing of the bellows (no leakage detected) at a later

outage, Liquid penetrant testing of the cavity "steps" upon which the cavity shield plugs are placed (no Indications detected), and Air purge testing of the drain line that channels refueling cavity leakage away from the gap between the drywell shell and concrete drywell shield wall (drain line did not appear to be restricted).

During the 1986 refueling outage, the drain line from the refueling cavity metal trough was inspected and the drain line gasket was found to have leaks, and was replaced. Additional teak tests were performed on the bellows during the 1986 outage and no leaks were detected (Ref [1], Attachment 2, pages 2-1 and 2-2).

During the 1986 refueling outage, camera inspections identified that the lip of the reactor cavity concrete trough was not sufficient to assure that water would not enter the area between the concrete shield wall and drywell shell. (Ref [5], page 3). Prior to reactor cavity flooding for the 1988 refueling outage, repairs were made to the concrete trough to rectify the condition. These repairs were determined to be effective based on visual inspections for leakage during the 1988 outage.

As noted previously, the mitigating features described above were implemented between 1988 and 1993. For the strippable coating, a latex coating was used at first. This latex coating had (a) stringent surface preparation requirements; (b) long curing time; and (c) lack of strength to absorb mechanical abuse during refueling. Accordingly, it was not applied during the 1994 and 1996 refueling outages. Discontinuation was also prompted by the fact that sand had been removed from the sand bed region and drainage in the area was improved during the 1994 outage. However, the observed water leakage during the 1996 outage prompted investigation and use of a more durable barrier. InstaCote ML-2 coating barrier was effectively used on the reactor cavity during the 1998 outage.

(Ref [28], page 6). Strippable coating has also been applied to the reactor cavity in all refueling outages since 1998.

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-m Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-5 It.

Summary of IWE Program Elements Related to Water Leakage The following is a summary of Oyster Creek's commitments related to preventing and monitoring for water leakage onto the exterior surface of the drywell shell.

These are captured within the ASME Section XI, Subsection IWE Aging Management Program. These committed actions were performed during the 2006 refueling outage and will be performed during refueling outages In the future, including during the period of extended operation. For further details on these commitments, see Ref [39], Enclosure 2.

Strippable coating, as discussed above in Section C, is applied to the reactor cavity liner surface prior to filling the reactor cavity with water for refueling activities.

Periodic verification (once per refueling cycle) that the reactor cavity trough drain is functional (clear).

Periodic monitoring (when reactor cavity is flooded) of reactor cavity trough drain for leakage.

Daily visual monitoring of drywell sand bed drains for leakage during refueling outages when the reactor cavity is flooded.

If leakage is detected. AmerGen will determine the source of leakage and investigate and address the impact of leakage on the drywell shell, including verification of the condition of the drywell shell coating and moisture barrier (seal) in the sand bed region and performance of UT examinations of the shell in the upper regions. UTs will also be performed on any areas in the sand bed region where visual inspection indicates the coating is damaged and corrosion has occurred. UT results will be evaluated per the existing program. Any degraded coating or moisture barrier will be repaired. These actions will be completed prior to exiting the associated outage.

Quarterly visual monitoring of the sand bed drains for leakage during plant power operation. If leakage is identified, then the source of water will be investigated, corrective actions taken or planned as appropriate. In addition, if leakage is detected, the following Items will be performed during the next refueling outage:

Inspection of the drywell shell coating and moisture barrier (seal) in the affected bays in the sand bed region UTs of the upper drywell region consistent with the existing pfrogram UTs will be performed on any areas in the sand bed region where visual inspection indicates the coating is damaged and corrosion has occurred UT results will be evaluated per the existing program Section 4 Water Leakage onto the Exterior Surface of the Drywall Shell Page 4-6 Any degraded coating or moisture barrier will be repaired.

Mhen the sand bed region drywell shell coating inspection is performed, the seal at the junction between the sand bed region concrete and the embedded drywell shell will be Inspected per the Protective Coatings Program.

Through these commitments, AmerGen will minimize any water leakage through the reactor cavity liner that may occur during refueling outages, and prevent or minimize water from reaching the external surface of the drywell shell. These commitments were made with the expectation that corrosion of the external surface of the drywell shell will be minimized, thus maximizing the margin remaining above the design-required thicknesses of the drywell shell.

1[].

Findings and Analysis from the 2006 Outage During the 1 R21 (October 2006) refueling outage, AmerGen implemented its commitments related to preventing water from reaching the outer surface of the drywell shell and monitoring for evidence of water leakage. The results of these activities were successful. Based on daily observations of sandbed drain water collection bottles and upon numerous visual reports from the sand bed region, no water leakage onto the exterior surface of the drywell shell during 1 R21 was evident and no corrective actions related to water leakage onto the shell were required (Ref [47]).

The reactor cavity was coated with a strippable coating prior to flooding the cavity for refueling activities. A small amount of leakage (approximately 1 gallon per minute (GPM)) was observed coming from the cavity trough drain line during the time period when the refueling cavity was flooded. Daily observations of the cavity trough drainage confirmed a steady stream of approximately 1 GPM during this period. Because this small amount of leakage did not exceed the drainage capacity of the trough, no water would have leaked onto the exterior surface of the drywell shell. The minor leakage was discharged to the plant's radwaste system as designed.

Specifically, AmerGen performed the following actions during the October 2006 refueling outage to prevent or minimize water leakage onto the exterior of the drywell shell. These activities are consistent with commitments made in AmerGen Letter 2130-06-20358 (Ref

[39)).

Applied a strippable coating to the reactor cavity liner prior to flooding the cavity for refueling activities.

Verified that the reactor cavity trough drain was clear prior to flooding the reactor cavity for refueling activities.

Monitored the trough drain for leakage daily while the cavity was flooded with water. Documented results identified only a steady "pencil stream" of water coming from the trough drain, indicating, as expected, that the leakage was being handled by the cavity trough drain system, keeping water away from the drywell shell.

~

~ -

m rn Section 4 Water Leakage onto the Exterior Surface of the Drywell Shell Page 4-7 Inspected the five sand bed drain lines to verify they were clear; removed some debris from two of the drain lines.

inspected the five poly collection bottles associated with the sand bed drains on a daily basis. Documented results identified no leakage observed coming from the sand bed drains.

Verified no water on the concrete floor in any of the ten bays of the sand bed region through visual inspection.

Inspected the seal at the junction between the sand bed region floor and drywell shell in all 10 bays. The inspection revealed the seal at this junction to be in good condition with no repairs required.

IV.

Conclusion Oyster Creek historically experienced water.leakage onto the external surface of the drywell shell as described in Section I above, Various investigative and corrective activities have been performed to understand the issue and prevent water from continuing to drain onto the shell during refueling activities.

As part of the License Renewal process, AmerGen has established specific commitments within the formal Exelon Passport commitment tracking system to ensure license renewal commitments, including those addressing water leakage onto the drywell shell external surface (described in Section II above), are implemented. In addition, the recurring tasks, preventive maintenance activities, and surveillance procedures that are used to implement these commitments are annotated such that it is clear from looking at them that the subject actions are associated with commitments made to the NRC. In this way, there are formal controls to ensure awareness and oversight of the activities and to ensure that commitments are implemented.

The inspections performed during the 2006 refueling outage (IR21) confirm that the license renewal-related committed actions for leakage prevention and monitoring prevented water from reaching the external surface of the drywall shell. AmerGen has committed to perform these preventive/monitoring actions in future refueling outages, with the objective of preventing water leakage onto the drywell shell exterior. In addition, commitments are in place to investigate and address any leakage onto the shell exterior, should it occur.

This set of actions, aimed at preventing water from reaching the external surface of the drywell shell, serve as an additional level of assurance beyond that provided by performing and trending drywell shell thickness measurements and conducting visual inspections of the epoxy coating in the sand bed region (also part of the [WE Aging Management Program), that corrosion is not impacting the ability of the drywell to perform its design functions.

Section 5 The Upper Regions of the Drywell Page 5-1 The following discussion addresses upper drywell corrosion at the Oyster Creek Generating Station. Part I, below, provides an overview of information pre-dating the October 2006 outage. The discussion in Part It sets forth information discovered and analyzed as a result of the October 2006 outage. Overall conclusions about the upper drywell, and its continued operation during the proposed twenty-year renewal term, are summarized in Part Ill.

t.

Historic Summary and Past Findings Outer drywell shell corrosion was first identified at Oyster Creek in the late 1980's. As explained in the Section 4 of this Enclosure, water intrusion into the gap between the drywell shell and the drywall shield wall was determined to be the source of the water, which created the corrosive environment. Corrective actions have been taken to mitigate corrosion in the upper region of the outer drywell shell. These actions have effectively reduced the rate of corrosion to a negligible amount in the upper region as demonstrated by UT thickness measurements (Ref [32], Table 1). In 1991, Oyster Creek and its consultants performed stress and buckling analyses considering all design basis loads and load combinations (Ref [15], Ref [16]). The results of these analyses indicate that the minimum measured drywell shell thickness satisfies ASME Section III Requirements.

A.

Original Inspection Plan (1986 - 1992)

Inspections using UT thickness measurements were conducted during refueling outages and outages of opportunity between 1986 and 1989 to establish and characterize the extent of corrosion of the outer drywall shell. The initial UT measurements were not based on a sampling process. Instead the measurements were taken in areas that correspond to locations where water leakage was observed from the sand bed region drains. The UT measurements were then expanded around the drywell perimeter and vertically into the upper drywell to establish locations affected by corrosion. Approximately 1000 ultrasonic (UT) thickness measurements were taken at various elevations.to access extent/scope of corrosion around the drywell perimeter and vertically to establish locations affected by corrosion and to identify the thinnest areas (Ref [4b], Ref [4c], Ref [4d]). Based on the results of the above-mentioned 1000 UT measurements, Oyster Creek continued to monitor 12 grid locations at elevations 50' 2",.and 87' 5", that would be representative of the upper drywell shell condition. In addition, core samples of the drywell shell were taken at upper drywell region locations, believed to be representative of general corrosion, to confirm UT results (Ref [7]).

In addition to the above mentioned core samples of the drywell shell, the impact of Firebar-D on the drywell shell corrosion was discussed in a General Electric report (Ref [3]). Section 2.1.3.2 of the GE report discusses the material and Section 6.2.1 discusses the impact. The report concluded that the lack of y*Fe2O3 in the oxide on the core plug surface/crust, the relative low amount of Mg in the sand samples and the absence of corrosion at the 51' elevation level suggest that the role of Firebar-D in the degradation of the OC drywall corrosion phenomena is not significant.

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Section 5 The Upper Regions of the Drywell Page 5-2 Section 5 The Upper Regions of the Drywell Page 5-3 In 1990, a third elevation, 51' 10", was added to the scope of inspection after it was determined that the supplied plate thickness is slightly less than the adjacent 50' 2" plate. For each of the three elevations, sets of 49 UT measurements, spaced approximately V apart within a 6"x6" area, were taken from inside the drywell around the entire perimeter of each elevation. The 6"x6" area with one Inch spacing results in a 7x7 grid of points located on one inch centers. These are identified as 49 point UT grid locations.

Engineering evaluation of the UT results concluded that monitoring of 12 upper drywell grid locations within these three elevations would represent the outer drywell shell condition and provide reasonable assurance that significant corrosion would be detected prior to a loss of an intended function. This is because the 12 grid locations were selected considering the degree of drywell shell thinning and the minimum required thickness to satisfy ASME stress requirements. Seven of the locations are at elevation 50' 2", three locations are at elevation 87' 5", and two locations are at elevation 51' 10" (Ref [31]). These locations are inspected from the inside of the drywell shell on a frequency of every other refueling outage.

B.

Sampling Plan Justification and Confirmation - Augmented Inspection Plan (1990 - 1995)

In response to an NRC Staff concern regarding whether the inspected locations represent the condition of the entire drywell, in 1990 a new random UT inspection plan (also know as the augmented inspection) was prepared (Ref [11]). The plan was based on a non-parametric statistical approach using attribute sampling that assumes no prior knowledge of the distribution of corrosion above the sand bed region (Ref [121). The plan consisted of random UT testing of 60 drywell shell plates. 57 plates were included in the inspection plan because three plates were inaccessible for inspection. On each plate, 49 point UT measurements were made on one 6"x6" area. Acceptance criteria were that the mean and local thickness of the shell equal or exceed the required minimum thickness plus a corrosion allowance necessary in order to reach the next inspection.

Inspection results using the new random inspection plan confirmed that previously monitored locations bound the condition of the drywell above the sand bed region; except one location at elevation 60' 10". This elevation was added to elevations 50' 2", 51' 10", and 87' 5" and all four elevations have been monitored on the frequency of every other refueling outage since 1992 (Ref [31], Ref [32]).

The augmented inspection plan, the original inspection plan, and justification for sampling techniques and statistical methodology were submitted to the NRC on November 26, 1990 (Ref [14]). In its Safety Evaluation dated November 1, 1995, the Staff noted that the licensee provided a table of UT measurement results from the Fall 1994, 1 5 h refueling outage Inspection. This table shows the locations of the measurements, the nominal as-constructed thickness, the minimum as-measured thickness, the ASME Code required thickness and the corrosion margin available at the time. The Staff found the current program based on the submitted information acceptable.

The current ongoing inspection plan is described in Oyster Creek specification IS-328227-004 (Ref [41]). The current inspection results are provided in Tables 1 and 2.

11.

Confirmatory Actions During the Octolber 2006 Outage During the 2006 refueling outage (1 R21), UT thickness measurements were taken at the 4 elevations (50' 2", 51' 10". 60" 10", and 87'5") discussed above in accordance with the Oyster Creek ASME Section XI, Subsection IWE aging management program. The results of the UT thickness measurements indicated that no statistically observable corrosion is occurring at elevations 51' 10", 60' 10" and 87' 5". A single grid location (Bay 15 -23) of the elevation 50 '2" continues to experience minor corrosion at a rate of 0.66 mils/yr. The corrosion rate for the elevation 87' 5" is now statistically Insignificant and this elevation can be considered as no longer undergoing statistically observable corrosion (Ref [47]), however it will continue to be monitored.

In addition, UT measurements were taken on 2 locations (bay #15 and bay #17) at elevation 23' 6" where the circumferential weld joins the bottom spherical plates and the middle spherical plates. This weld joins plates that are 1.154" thick to the plates that are 0.770" thick. These two bays were selected because they are among those that have historically experienced the most corrosion in the sandbed region. At each location, 49 UTs over a 6"x6" area grid were taken above the weld on the 0.770" thick plate and 49 UTs over a 6"x6" area grid were taken below the weld on the 1.154" thick plate. The minimum average thickness measured on the 0.770" thick plate is 0.766" and 1.160" on the 1.154" thick plate. The minimum measured local thickness on the 0.770" thick plate is 0.628" and on the 1.154" thick plate is 0.867".

The minimum measured general and local thickness on each plate meets the minimum thickness required to satisfy ASME stress requirements with an adequate margin (Ref [47]).

UT measurements were also taken on 2 locations (bay #15 and bay #19) at elevation 71' 6" where the circumferential weld joins the transition plates (referred to as the knuckle plates) between the cylinder and the sphere. This weld joins the knuckle plates (2.625" thick) to the cylinder plates (0.640" thick). These two bays were selected because they also have historically experienced the most corrosion in the sandbed region. At each location 49 UTs over a 6"x6" area grid were taken above the weld on the 0.640" thick plate and 49 UTs over a 6"x6" area grid were taken below the weld on the 2.625" thick plate. The minimum measured average thickness on the 0.640" thick plate is 0,624" and 2.530" on the 2.625" thick plate. The minimum measured local thickness on the 0.640" thick plate is 0.449" and 2.428" on the 2.625" thick plate. The minimum measured general and local thickness on each plate meets the minimum thickness required to satisfy ASME stress requirements with an adequate margin (Ref [47]).

The above information identified dudng the recent outage has confirmed the condition of the upper drywell as described in previous submittals. AmerGen thus concluded that outer drywell shell corrosion at Oyster Creek is being effectively managed both during the current and proposed renewed terms of plant operation. The monitored locations under the current term were subject to extensive UT measurements conducted over several years. NRC Staff found the sampling methodology to identify these locations, and the results of inspections, acceptable for the current term.

mm m+m m

-U m m_-I+l N

,N Section 5 The Upper Regions of the Dryweal Page 5-4 Section 5 The Upper Regions of the Drywell Page 5-5 l1t.

Conclusion In conclusion, Oyster Creek has conducted extensive examinations of the OCNGS upper drywell to identify the cause of drywell corrosion, employed a sampling process, quantified the extent of outer drywall shell thinning due to corrosion, and assessed its impact on the drywell structural integrity. Inspection results for the upper region are provided in Table 2. A summary of the upper region outer drywell shell corrosion rates and margins and the associated reference source documents are provided on Table 1. A summary of corrosion rates of UT measurements taken in the upper drywell every 4 years through year 2006 is provided below:

" There is no statistically observable ongoing general corrosion at three elevations (51' 10", 60' 10", and 87' 5")

" Based on statistical analysis, one location at elevation 50' 2" is undergoing a minor general corrosion rate of 0.66 mils per year

" The drywell corrosion inspection program will ensure sufficient margin will be maintained through 2029 Therefore, AmerGen has concluded that upper drywell corrosion at Oyster Creek is effectively managed, both during the current and proposed renewed term of plant operation. The upper drywell region is not experiencing statistically observable corrosion, except a single location that continues to experience minor corrosion at a rate of 0.66 mils/yr. When this monitored corrosion rate is projected through the year 2029, sufficient margin exists to acceptance criteria.

Table 1 Drywell Shell Thickness and Minimum Available Thickness Margins are provided below:

Minimum Nominal Measured Minimum Required Drywell Region Design Thickness, mils Thickness, mils Minimum Available (Elevation Thickness, mils Acceptance Criteria Thickness margin, monitored)

(Ref (21], Ref [25],

mils (Ref 140])

Ref [31], Ref [47])

(Ref [43], Ref [15])

Cylindrical 640 604 452 152 (87' 5")

Upper Sphere 722 676 518 158 651' 10", 60' 10" Middle Sphere 770 678 641 137 (50' 2"1

==

Conclusions:==

Summary of Corrosion Rates of UT measurements taken every 4 years through year 2006 (Ref [47])

There is no statistically observable ongoing general corrosion at three elevation (51' 10", 60' 10", and 87' 5")

Based on statistical analysis, one location at elevation 50' 2" is undergoing a minor general corrosion rate of 0.66 mils per year The drywell corrosion inspection program will ensure sufficient margin will be maintained through 2029 For illustrations of the margins of monitored locations in upper drywell see attached Key Plan and Graphs 1-13.

Section 5 The Upper Regions of the Drywell Page 5-6 Table 2 Average Measured Thickness -', Inches Monitored Location Minimum Projected Elevation Required Thickness in nob.s 1197 198B 198g 1990 1991 1922 1993 1994 11 5 1i 2009 1 20D4 2006 2029 Elevabon 50' 0.W41" 2

B 5-0.743 0.742 0.747 No Obseroable D12 0.745 0.745 0.747 0.741 0.748 0.741 0.743 0.747 Ongoing 0.746 0.748 Corrosion Bay 5-5H 0.761 0.755 0.759 No Observable 0.761 0.750 0.759 0.754 0.757 0.754 0.756 0.760 Ongoing 0.760 Corrosion Bay 5-5L 0.706 0.703 0.703 No Observable 0.703 0.700 0.702 0.702 0.705 0.706 0.701 0.705 Ongoing 0.706 Corrosion Bay 13-0.762 0.760 0.765 No Observable 31H 0.779 0.758 0.763 0.759 0.766 0.762 0.758 0.762 Ongoing 0.765 Corrosion Bay 13-0.067 0.689 0.685 No Observable 31L 8.654 0.070 0.688 0.683 0.690 0.682 0.693 0.678 Ongoing 0.688 Corrosion Bay 15-0.758 0.762 0.767 23H 0.764 0.762 0.763 0.758 0.760 0.758 0.757 0:765 0.749 0.720 Bay 15-0.726 0.726 0.726 23L 0.728 0.729 0.724 0.720 0.724 0.729 0.727 0.725 I

I I

I I

i Section 5 The Upper Regions of the Drywell Page 5-7 Average Measured Thickness "", inches Monitored Location Minimuem I

projected Elevation Required Thickness in Thi knees, Thckes7I

hicne, 107 1988 1989 1990 1991 1992 11903 1994 10996 2000 20054 2006 2029 Elevation 51' 0.518" (6) 1(0 Bay 13-0.716 0.715 0717 No Obsernable 32GJ 5

I0.71 7 0.7177t4 0.715 0.715 0.713 0.715 Ongoing 10.720 1

0

[

Corrosion Bay 13-0.686 0.683 0603 No Observable 32L 0.683 0676 0.680 0.694 0.679 0.667 0.685 Ongoing 0.602 Corrosion Elevation 60' 0.518" fit.

91 No Observable 22 I

I

[

1 0.653 0.711 0.693 0.689 0.693 0.691 Ongoing Elevation 87' 0.452" Bay 9

- 20 0.619 0.622 0.619 0.620 0.614 0.629 No Observable 0.620 0.612 0.614 0.613 D.613 0.60.4 0.612 0.617 Ongoing Corrosion Bay 13-28 0.643 0.641 0.645 0.643 0.635 0.641 No ObserVable 0.642 0.629 0.637 0.640 0.636 0.635 0.640 0,642 Ongoing Corroion Bay 15-31 0.638 0.636 0.638 0.642 0.628 0.631 No Observable 0.636 0,627 0.630 0,633 0,632 0.628 0.630 0.633 Ongoing Corrosion Notes:

1. The average thickness Is based on 49 Ultrasonic Testing (UT) measurements performed at each location

2. Multiple inspections

-ern performed in the years 1988. 19950, 1991, and 1992.

3. The 1903 elevation 60' 10" Bay 5-22 inspection -as performed on January 6. 1993. All other locations were inspected in December 1992.

4. Accaracy of Ultrasonic Testing Equiprnent is plus or minus 0.010 inches.

5. Reference SE-G00243-002 (Ref [26D.

I I

I I

i I

I

-~

mm,-m

-m

• m

=

m m

m

-m Ongoing Upper Drywell Thickness Monitoring UT Measurement Locations S

C 5-0ý 0.

1.0 Q.0

-55i 0>

0u V-:

(0 C)

C:

0 'M (CL Si) 900Z

+1o Ef 270

~000 Z 8661 966-t,66 I0, N7 0661 8961 L T~

>N 5V _

Co 0

0 C) a C

C 0

C o>

0 a

a a

(D C

CD 00 r-(.0 U)

IJ-Cý)

('1 SIMl' - SSewpIqjO IIGmAka Numbers in parentheses refer to the attached Graeh identification numbers.

2. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 5 - 5H 770 Mil Nominal Shell

/ Plate Thickness 800 -

700 -

600

== 500 400 I-

= 300 200 0

100 0

Measured Mean Shell Thickness Margin = 213 MilsI

• I.

541 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 BW 15 BW 17 TB"e11 0c0w BW7 BW,5 KW, Iý I I 0I I

I I

I I

I I-I I

I I

II 0

)0

( N (D

• (

(0 N

c It (D

CO

0)

0)

0)

M

0)

C0)

O C

O

0)

0)

0)

)

0)

0) 0D O

0 C

Source: Averaged Data -AmerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data - AmnerGen calculation C-1302-187-E310-037, Rev 2 Instrument Uncertainty +/- 10 Mils Raw Data - AmerGen Calculation C-1302-167-E210-037, Rev 2 Instrument Uncertainty +/- 10 Mils I

I I

I I

I I

I I

i I

i I

I I

i I

I I

3. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 5 - 5L 770 Mil Nominal Shell

/

Plate Thickness 800 700 600 500 400

= 300 200 -

100 -

0~

Measured Mean Marginhie160 MilsI Shell Thickness M ri 6

is 541 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 Bayl3 aSia Bay7 Bay 5 Key Pfan I I CO C0 CF) o (3

0) 0)

(C 0(

a, 0

(N O

D

0) 0M 0M O

3 0

C

0) 0

0) 0 0

0C 04 December 3, 2006 7, Rev 2 Instrument Uncertainty +/- 10 Mils Source: Averaged Data - AmerGen Letter 2130-06-20426 dated Raw Data - AmerGen Calculation C-1302-187-2310-037

800 -

700 -

600 -

500 -

400 -

I-

= 300 -

Q'200 100

4. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 13 - 31H 770 Mi Nominal Shell Plate Thickness Measured Mean' Shell Thickness Margin = 217 Mils

/

541 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 f

BayIs BW17 1e1 9-W 10,v "BaS I I 0

1 i

I I

I 0o 0

C14

'IT (0

00 CF)

0) 03 0)

0)

0)

0)

0) 0)

Source: Averaged Data -AmerGen Letter 213"-6-20426 dated December 3, 2006 Raw Data -AmerGen Calculation C-1302-187-E310-037, Rev 2 co 3) 0)

Co 0NJ

'~t (D

Co)

C:)

0:"

0:O C:)

C)

C:)

C:

04 (N

(14 C14 Instrument Uncertainty +/- 10 Mils

5. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 13 - 31L 770 Mu Nominal Shell 800 Plate Thickness 700-70 Measured Mean/

1 Margin 137 Mils 600 Shell Thickness U~u 500-4

/

541 Mil Minimum Required

= 400 Shell Thickness Strippable

.2 Coating Not WVl seWy7 Used in 1994 B 13*

,*B 19 300 and 1996 200

-3'

1004, 0

I I

IT I

I CO

0) 04 4"

(0 Do 03 C4 It C.0 0C

0)

0)

0)

0)

0) 0 0

0 O

0)

0)

0)

0) 00

0) 0 0

0 0

04 C4 0"4 Source: Averaged Data - AmerGen Letter 2130-06-20426 dated December 3. 2006 Raw Data -AmerGen Calculation C-1302-187-E31M-037, Rev 2 Instrument Uncertainty +/- 10 MIls

6. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 15 - 23H 770 Mil Nominal Shell 0Plate Thickness 800 I

700 Measured Mean t

Shell Thickness Margin = 216 Mils 600

) 500

/

W 541 Mil Minimum Required Strippable 400 Shell Thickness Coating Not 1w,.

.sW,7 Used in 1994 BW We9 300 and 1996 S2001 I

B?

awO 100 1,,

a a

y 0II I

I I

I 00 0

CIS 114 (0

0 0

N:

I (0)

O

0)

0)

0)

0)

0)

O OD 0

0)

0)

0) 0M

0)

0) 0 0

0 0

04 C,4 N

C14 Source: Averaged Data -AmerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data -AmerGen Calculation C-1302-167-E310-037, Rev 2 Instrument Uncertainty + 10 Mils I

I i

I I

I I

I I

I U

I I

I I

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7. Upper Drywell Corrosion Trend and Margin Elevation 50' 2" Bay 15 - 23L 770 Mil Nominal Shell

/

Plate Thickness 800 700 A 600 E

u) 500

-* 400-I-= 300 E-200 100 Measured Mean Shell Thickness, e

l 0

I Margin 183 MilsI

/7 541 Mil Minimum Required Shell Thickness I I Strippable Coating Not Used in 1994 and 1996 a"l BseWl1 tawe B i "W I B

ays OW e WW I I n - A I

I I

i I I i I

I I

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I i I

CO a

N

't (C

CO C0 0

ND O

OD M

M

0)

CF)

0) 0D 0

0 0

0)

F)

0) 0M

0)

M

0) 0 0

C O Source: Averaged Data -ArerGen Letter 2130-D6-20426 dated December 3. 2006 Raw Data - AmerGen Calculation C-1302.t87-E31M037, Rev 2 Instrument Uncertainty +/- 10 Mils

8. Upper Drywell Corrosion Trend and Margin Elevation 51' 10" Bay 13 - 32H 800 I 700 600 u) 500 400-I--

= 300 -

o 200 100 7,2 Mli lNomlnal Snell Plate Thickness Measured Mean M rn 1

Shell Thickness Margin 195 Mils

/

518 Ml Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 I I Dw7s

&W1 0

I I 0

III 1 I

o N

(0 03 0

M 0)

T-T-

03 0) i I

I I

Co 03 03 03 0

J N

00 N,

N O

ND Source: Averaged Data-AmerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data - AmerGen Calculation C-1302-187-E310-037, Rev 2 Instrument Uncertainty +/- 10 Mils

9. Upper Drywell Corrosion Trend and Margin Elevation 51' 10" Bay 13 - 32L 722 Mu Nominal Shell

/

Plate Thickness 800 700 600 0U 500 (D

400-

,.-=

= 300 -

Q 200 -

100-0 Measured Mean M

Shell Thickness Margin 158 Mist 518 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 I I e'

is0Y1 One?

OW (0

03 03 03 03 03 03 03 03 03 DO C0 N

(0 M3 C) 0 0

0 G-C) 0 0

04 Instrument Uncertainty +/- 10 Mils Source: Averaged Data - ArnerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data - ArmerGen Calculation C-1302-187-E310-037, Rev 2

10. Upper Drywell Corrosion Trend and Margin Elevation 60' 10" Bay 1 22 722 Mil Nominal Shell

/

Plate Thickness 800 700 600 -

== 500 -

"* 400 -

I--

= 300 -

a'200 -

10 Measured Mean Shell Thickness Margin = 171 Mils 518 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 I

I II OD 0

N IT (0

00 0

N

't (0

C0) 0

0)

0)

M)

0) 0 0

0 0

0 M

0)

0)

0)

0) 0 0

0 0

N N

Nq N

Source: Averaged Data - AmerGen Letter 2130-D6-20426 dated December 3. 2006 Raw Data - AmerGen Calculation C-1302-187-E310-037, Rev 2 Instrument Uncertainty + 10 Mils I

I i

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I I

I I

I I

I I

I i

I

11. Upper Drywell Corrosion Trend and Margin Elevation 87' 5" Bay 9 - 20 800 640 Mil Nominal Shell 700 Plate Thickness Measured Mean 500 Shell Thickness Margin =152 Mils 400

/

452 Mil Minimum Required Strppabge Coating Not OW's OW 7

300 Shell Thickness i,,

• 7 a)

Used in 1994 2and 1996 100 1-I M

IO I

I I

I I

O0 O0

0)

M)

0)

C)

0) 0 0

0 0

0 0*)o 00')

0 0

0 Source: Averaged Data-AmerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data -AmerGen Calculation C-1302-187-E310M37, Rev 2 Instrument Uncertainty _ 10 Mils

800 700 600

= 500 400 I-300 1 200 100 0

12. Upper Drywell Corrosion Trend and Margin Elevation 87-5" Bay 13 -28 640 Mil Nominal Shell Plate Thickness measured meane Shell Thickness /jMargin

=177 Mils

/

452 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996

~,,

~

ewe I

a.,

ruee~

I i

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ýý I-G) 0)

00 0) 0D LO 0) 0)

r-03 0) 0)

0) o)

C,4 01 C')

0 0

04 LO 04 Source: Averaged Data - AmerGen Letter 2130-06-20426 dated December 3, 2006 Raw Data - AmerGen Calculation C-1302-187-E310-037, Rev 2 Instrument Uncertainty +/- 1 a Mils

13. Upper Drywell Corrosion Trend and Margin Elevation 87'5" Bay 15 - 31 800 -

700 U) 600 500 400 I-

" 300

• 200 100 0

640 Mil Nominal Shell Plate Thickness Measured Mean Shell Thickness Margin = 175 Mils Mils

/

452 Mil Minimum Required Shell Thickness Strippable Coating Not Used in 1994 and 1996 SWIS S.,,

'a.

rure.

I r-O 0)

0) r-CO)

CID 0')

C)

G) 0l) 0')

to 0) 0)

0) 0)

0)

S0) 0)

C4 Ct4 o

U 0

o 0

0 Instrument Uncertainty + 10 Mils Source: Averaged Data -AmerGen Letter 2130-06ý20426 dated December 3, 2006 Raw Data -ArnerGen Calculation C-1302-187-E310-037, Rev 2

Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-1 Section 6 Corrosion of Containment Outer Drywell Shell In the Sandbed Region Page 6-2 Table-i. Minimum Available Thickness Margin The following discussion addresses corrosion of the Oyster Creek outer drywell shell in the sanded region. Part I, below, provides an overview of historic information pre-dating the October 2006 outage. The discussion In Part II sets forth information discovered and analyzed as a result of the October 2006 outage. Overall conclusions about the drywell, and its continued operation during the proposed twenty-year renewal term, are summarized in Part Ill.

I.

Historical Summary and Past Findings In the 1980's, the Oyster Creek containment drywell experienced wall thinning in the sandbed region caused by water In contact with the outer drywell shell. Beginning in 1986, corrective actions were implemented to monitor, mitigate or reduce the rate of corrosion, which was Initially estimated to vary from negligible in certain bays to 39 mlls/year at the thinnest location in bay 13 (Ref 110]). The corrective actions were effective in reducing accelerated corrosion as evidenced by the decline in the rate of corrosion starting in 1990 (see Attachment 1).

Beginning In 1986, UT thickness measurements were taken at elevation 11'3" from the interior of the drywell shell In each bay using a 6"x6" template every refueling outage and outage of opportunity. The template is centered on points determined by UT thickness measurements taken between 1983 and 1986 to be thinnest location In each bay. The points were marked on the shell to ensure that the same location is examined each time (See Attachment 2).

Analysis and trending of UT thickness data collected between 1986 and 1992 showed that thinning of the shell was not uniform and varied within a bay and from one bay to another. The measured average thickness in some bays (1,3,5,7,15) is nearly equal to the plate original nominal thickness of 1154 mils. In other bays, the nominal thickness is reduced significantly, with bay 19 having the thinnest area of 800 mils, In all cases, the average thickness Is greater than 736 mils, which Is required to satisfy ASME Code buckling stress requirements.

As shown In Table-1 below, the thinnest average measured area in each bay has adequate thickness margin In addition to the ASME Code safety factor of 2 for refueling load combination and 1.67 for post accident load combination (Ref [32]). As explained in Part II, below, AmerGen took UT thickness measurements during the October 2006 refueling outage to confirm the margin remains within the calculated uncertainty listed In Table-6.

Bay No.

1 3

5 17 9

11 13 15 17 19 Minimum Available 365 439 432 397 256 84 101 306 74 64 Margin, mils Corrosion mitigating actions in the send bed region were completed In 1992, when the sand was completely removed from the region, followed by removal of corrosion products, and preparation of the shell surface for the epoxy coating. Prior to applying the coating, the entire surface of the sandbed area was visually inspected to validate UT thickness measurements, previously made from Inside the drywell, and to identify local areas thinner than the minimum required average general thickness of 736 mils. 125 local areas were Identified by visual Inspection as areas that could be potentially thinner than 736 mils (See Table-2). UT thickness measurements of the 125 locations Identified 20 locally thinned areas less than the minimum required general thickness of 736 mils, but greater than analyzed local criteria of 536 mils (the minimum required to withstand buckling), and 490 mils local criteria developed in accordance with ASME Code requirements (the minimum required to withstand design pressure).

Following the UT inspections discussed above, the outer drywell shell surface in the sandbed region was coated with a multi-layered epoxy coating system designed for moisture environment. The sandbed region floor also was repaired to improve drainage of the region and the junction of the embedded outer drywell shell with the sandbed region concrete floor was sealed to prevent moisture Intrusion into the embedded outer drywell shell.

Analysis of UT thickness measurements conducted In 1992 and 1994 showed that corrosion of the outer drywell shell in the sandbed region had been arrested. LUT thickness measurements taken In 1996 also indicated that corrosion in the outer drywell shell had been arrested. Some of the1996 data contained anomalies that are not readily Justifiable but the anomalies did not significantly change the results (Ref [371). Between 1996 and the October 2006 outage, UT thickness measurements had not been taken; Instead the epoxy coating In selected bays was inspected every other refueling outage.

Coating Inspections conducted in 1994 (Bays 11,3), 1996 (Bays 11, 17), 2000 (Bays 1, 13), and 2004 (Bays 1113) showed that the coating was in good condition and there were no indications that the outer drywell shell was undergoing further corrosion (Ref (341).

Furthermore, the periodic UT thickness measurements of the shell In the upper regions of the drywell that are not coated with epoxy can be used conservatively as an indicator of the condition of the outer drywell shell in the sandbed region. The 2004 and 2006 upper region UT results showed that the highest general corrosion rate Is less than 1 mil/year.

moo=

m

-O

-m m

Mm m -m

m m

m m

Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-3 Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-4 A detailed discussion of the various historic activities follows:

A.

Initial Corrective Actions Upon discovery of water in the sandbed region in 1980, corrective actions were initiated to a) determine the source of water leakage, b) establish if corrosion is occurring by taking UT thickness measurements, and c) assess the impact of corrosion on the drywell structural integrity.

1.

Source of Water Leakage into the Sand Bed Region Extensive examination and testing of potential water sources concluded that water found in the sandbed region was from the refueling cavity during refueling outages. Cracks were identified in the reactor cavity stainless steel liner that permitted water to leak from the cavity, collect in an improperly functioning concrete trough below the cavity seals, and enter the gap between the outer drywell shell and the reactor building concrete. Once water entered the gap, it flowed down to the sandbed region. The water collected and was retained in the sandbed region in part as a result of unfinished concrete floor in some bays and clogged sandbed drains. Refer to the section 4 of this Enclosure for additional details.

2.

Initial Ultrasonic Testing (UT) Thickness Measurements Initial UT thickness measurements were made in 1983 from inside the drywell, through paint, above the concrete floor level (elev. 10' 3") in the bays that corresponded to where water was observed coming from sandbed drains. The measurements indicated that the drywell shell was thinner than expected. The accuracy of these measurements was questioned because the readings were taken through paint. As a result, calibration tests were conducted to evaluate the impact of the paint on the UTs. The test results indicated that UT measurements through paint overestimated the actual thickness by 0.3% for a 5-mil coating and 1.

5%

for a 1 0-mil coating. For this reason, the paint was removed at the inspection locations and a new set of UT measurements was taken from inside the drywell in 1986. The new UT readings continued to indicate that the drywell shell was thinner in those sand bed bays. (Ref [7])

The scope of the UTs was expanded to include several areas near the drywell floor adjacent to the sandbed region (elevation 11' 3"). The nevi readings also indicated that the drywell shell was thinner than expected.

(Ref [7])

As a result of the 1986 UT readings, a program was initiated to obtain detailed measurements in order to determine the extent and characterization of the thinning. Where thinning was detected, additional measurements were made in a cross pattern to determine the extent of the thinning. After the cross pattern was completed, the lowest reading at each location was used to expand the UT readings to a 6"x6" grid on 1" center with the lowest reading at the center of the grid. Approximately 560 total UT measurements were made in the ten bays at locations shown in drawing 3E-SK-S-85 (Ref [4a]). In 1986, as part of an ongoing effort at the Oyster Creek Generating Station to investigate the impact of water on the outer drywell shell, concrete was excavated at two locations inside the drywell (referred to as trenches) to expose the drywell shell below the Elevation 10' 3" concrete floor level to allow ultrasonic (UT) measurements to be taken to characterize the vertical profile of corrosion in the sand bed region outside the shell. The trenches (approximately 18" wide) were located in Bays 5 and 17 with the bottom of the trenches at approximate elevations 8' 9" and 9' 3" respectively (The elevation of the sand bed region floor outside the drywell is approximately 8' 11"). A total of 579 UT thickness measurements were taken inside the 2 trenches.

The measurements inside the 2 trenches showed that the reduction in shell thickness below the drywell concrete floor level (Elev. 10' 3") is no greater than indicated above the floor level (Ref [7], Ref [4a], Ref [1], Ref

[47])

Additional UT thickness measurements were taken at the plate-to-plate welds under the vent lines and the vent opening reinforcement plates.

These areas were given extra consideration on the basis that material sensitized by welding may have been attacked by a corrosion mechanism with greater potential for damage or cracking. The readings did not detect wall thinning or cracks at these locations (Ref [7]),

3.

UT Thickness Data Statistical Analysis Prior to 2006 The following steps have been performed to test and analyze the UT measurement data for those locations where 6"x6" grid data has been taken at least three times. The results of the analysis yield the measured average general thickness (+/- standard error), F-Ratio, which was used to determine if corrosion was occurring, and the upper 95% confidence interval was used after corrosion was identified. See Table-5, Table-6, and Attachment 1 for the results of the analysis. The steps are:

Edit each 49-point data set by setting all invalid points to "missing".

Invalid points are those that are declared invalid by the UT operator or are at a plug (i.e., core sample) location.

Perform a Univariate Analysis of each 49 point data set to ensure that the data is normally distributed.

Calculate the mean thickness and variance of each 49-point data set.

Perform an Analysis of Variance F-test to determine if there is a significant difference between the means of the data sets.

Using the mean thickness values for each 6"x6" grid, perform linear regression analysis over time at each location

M M m m

m

=

m

- M

=

=

m M

m

=

M Section 6.

Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-5 Section 6 Corrosion of Containment Outer Drywall Shell in the Sandbed Region Page 6-6 o

Perform F-test for significance of regression at the 5% level of significance.

Calculate the ratio of the observed F value to the critical F value at 5% level of significance. The result of this test indicates whether or not the regression model is more appropriate than the mean level.

Calculate the coefficient of determination (R

2) to assess how well the regression model explains the percentage of total error and thus how useful the regression line will be as a predictor Determine if the residual values for the regression equations are normally distributed.

Calculate the y-intercept, the slope and their respective standard errors. The y-intercept represents the fitted mean thickness at time zero, the slope represents the corrosion rate, and the standard errors represent the uncertainty or.random error of the two parameters. Calculate the upper 95% one-sided confidence interval about the computed slope to provide an estimate of the maximum probable corrosion rate at 95% confidence after corrosion was identified.

When the corrosion rate is not statistically significant compared to random variations in the mean thickness, the slope and confidence interval slope computed in the regression analysis still provides an estimate of the corrosion rate, which could be masked by the random variations.

Use the chi-square goodness-of-fit test results to determine if low thickness measurements are significant pits. If the measurement deviates from the mean thickness by three standard deviations, it is to be considered a pit. (Ref [27])

4.

Verification of UT Thickness Measurements The UT thickness measurements described above were verified in 1986 by removing seven 2-inch diameter core samples from the sandbed region shell. Core sample locations shown in Table-3 below (bays 11, 15, 17, &19) were selected to represent areas where UT measurements showed the most significant wall thinning, as well as areas where UT measurements indicated little or no wall thinning. Thicknesses obtained by physical measurement of the core samples were consistent with the UT readings, and in general were greater by about 2% (Ref [7)).

Table 3 - Core Sample Thickness Evaluation Post-removal Pre-removal UT Measured Sample Location Average Average No.

(Bay No.)

thickness, mils Thickness, mils 1

19C 815 825 2

15A 1170 1170 3

17D 840 860 4

19A 830 847 5

11A 860 885 6

11A 1170 1190 7

19A 1140 1181 Source: Ref [1]

In summary, extensive UT readings of drywell shell thickness were taken inside the drywell to establish areas of largest wall thinning between 1986 and 1992. UT measurements were also taken in 2 trenches excavated in the drywell concrete floor to establish the vertical profile of corrosion in the sandbed region in 1986 and in 1988. The measurements showed that corrosion in the sandbed region below the drywell floor level, elevation 10' 3", was no greater than the corrosion measured at the floor level. UT measurements taken from outside the drywell after removing the sand in 1992 (discussed in section C.1 below) confirmed this observation. Thus locations selected inside the drywell for repetitive UT measurements represented the condition of the entire sandbed region.

5.

Initial Analysis to Assess Impact of Corrosion on the Drywall Structural Integrity and Operability.

A detailed engineering analysis was conducted in 1987, assuming a corroded thickness of 700 mils. The analysis concluded that, with sand in place and conservatively assuming the thickness was reduced to 700 mils, the drywell was capable of performing its intended function and that the containment is operable (Ref [2])

B.

Other Corrective Actions Taken in Response to UT Measurements As a result of significant walt thinning and accelerated rate of corrosion in the sandbed region (bays 11, 13, 17, and 19), Oyster Creek Initiated additional corrective actions in 1987 to assess the impact on corrosion on the dryweli intended function, and minimize the rate of corrosion. These included but were not limited to: a) an initial analysis to determine if the containment was operable, b) actions to minimize the potential for water intrusion into the affected area, c) actions to effect removal of any water that might intrude into the affected area, d) installation of a cathodic protection system in 2 bays, a) taking UT measurements every refueling outage and outage of opportunity, and f).trending the UT results.

Refer to (Ref [32]) for additional details.

m a

a a

a a*_

a a

a a

a" a

a a

a Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-7 Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-8

t.

Corrective Actions to Minimize the Rate of Corrosion Beginning in 1988, the strippable coating was applied to reactor cavity walls to minimize water leakage during the refueling outages. Leakage monitoring, implemented later, confirmed that this coating is effective in minimizing the water intrusion into the sandbed region. See section 4 of this Enclosure for additional details.

UT thickness measurements taken through 1988 showed that the corrosion rate of the outer drywell shell in the sandbed region continued to increase (see Attachment 1). Also the rate of corrosion in the bays where the cathodic protection system was installed showed no improvement. It was then concluded that the most effective way to mitigate corrosion was to remove the sand and corrosion products, and apply a protective coating to the outer drywell surface in sandbed region.

Refer to section C.1 below for details of the coating. (Ref [9], Ref [32]).

2.

Engineering Analysis Performed to Establish the Minimum Required Thickness With Sand Removed An engineering analysis, based on ASME Code requirements, was conducted in the early 1990's to establish the minimum required general thickness without sand for both pressure and buckling stress (Ref [15],

Ref [16], Ref [32]). The analysis was based on a partial finite element model (36-degree slice - Fig. 1) of the dryweln. Loads and load combinations were in accordance with the original design basis requirements as follow: (Ref [16])

CASE I - INITIAL TEST CONDITION Deadweight + Design Pressure (62 psi) + Seismic (2 x DBE)

CASE II - FINAL TEST CONDITION Deadweight + Design Pressure (35 psi)+ Seismic (2 x DBE)

CASE III - NORMAL OPERATING CONDITION Deadweight + Pressure (2 psi external) + Seismic (2 x DBE)

CASE IV - REFUELING CONDITION Deadweight + Pressure (2 psi external) + Water Load +

Seismic (2 x DBE)

CASE V - ACCIDENT CONDITION Deadweight + Pressure (62 psi @ 175'F or 35 psi @ 281F) +

Seismic (2 x DBE)

CASE VI - POST ACCIDENT CONDITION Deadweight + Water Load @ 74'6" + Seismic (2 x DBE)

Note: Subsequent to this analysis GE developed Oyster Creek plant specific accident pressure, approved In accordance with Technical Specification Amendment 165 (Ref [46])

The results of the analysis showed that the minimum required thickness was controlled by buckling and that a oenerat thickness of 736 mils will satisfy ASME Code requirements with a safety factor of 2 against buckling for the controlling operating load combination (Case IV -

refueling condition), and 1.67 safety factor for accident flooding load combination (Case V - Accident condition). See Table 4 below for additional details). (Ref [32]).

Local areas where the thickness was less than the general 736 mils were evaluated based on 490 mils local acceptance criteria (Ref [42]). The local acceptance criteria of 490 mils was confined to an area less than 2%"' in diameter experiencing primary membrane + bending stresses based on ASME B&PV Code, Section lIt, Subsection NE, Class MC Components, Paragraphs NE-3213.2 Gross Structural Disconfinuity, NE-3213.10 Local Primary Membrane Stress, NE-3332.1 Openings not Requiring Reinforcement, NE-3332.2 Required Area of Reinforcement and NE-3335.1 Reinforcement of Multiple Openings. The use of Paragraph NE-3332.1 is limited by the requirements of Paragraphs NE-3213.2 and NE-3213.10. In particular, NE-3213.10 limits the meridional distance between openings without reinforcement to 2.5 x (square root of Rt). Also Paragraph NE-3335.1 only applies to openings in shells that are closer than two times their average diameter.

A review of all the 1992 UT data presented in Appendix D of calculation C-1302-187-6320-024 (Ref [42]) indicated that all thicknesses in the drywell sand bed region exceeded the required pressure thickness by a substantial margin. Therefore, the requirements for pressure reinforcement specified in the previous paragraph were not required for the very local wall thickness evaluation presented in Calculation C-1 302-187-5320-024 (Ref [42]).

Reviewing the stability analyses provided in both the GE Report 9-4 (Ref

[16]) and the GE Letter Report Sand Bed Local Thinning and Raising the Fixity Height Analysis (Ref [22]) and recognizing that the plate elements in the sand bed region of the model are 3" x 3" it was clear that the circumferential buckling lobes for the drywell were substantially larger than the 2 'A"' diameter for very local wall areas. This, combined with the local reinforcement surrounding these local areas, indicated that these areas would have no impact on the buckling margins in the shell. It was also clear from the GE Letter Report (Ref [22]) that a uniform reduction in thickness of 27% to 0.536" over a one square foot area would only create a 9.5% reduction in the load factor and theoretical buckling stress for the whole drywell resulting in the largest reduction possible. In addition, to the reported result for the 27% reduction in wall thickness, a second buckling analysis was performed for a wall thickness reduction of 13.5% over a

'In some evaluations 2" diameter is conservatively used to define very local arms instead of 2 I'/'

m

-MAI-MM

-M M

-M Section 6 Corrosion of Containment Outer Drywell Page 6-9 Shell in the Sandbed Region one square foot area which only reduced the load factor and theoretical buckling stress by 3.5% for the whole drywall resulting in the largest reduction possible. To bring these results into perspective, a review of the NDE reports indicated there were 20 UT measured areas in the whole sand bed region that had thicknesses less than the 0.736 inch thickness used in GE Report 9-4 (ref [16]) which cover a conservative total area of 0.68 square feet of the drywell surface with an average thickness of 0.703" or a 4.5% reduction in wall thickness. Therefore, to effectively change the buckling margins on the drywell shell in the sand bed region, a reduced thickness would have to cover approximately one square foot of shell area at a location in the shell that is most susceptible to buckling with a reduction in thickness greater than 25%. GE analysis concluded that the buckling of the shell was unaffected by the distance between the very local wall thicknesses; in fact, these local areas could be contiguous provided their total area did not exceed one square foot and their average thickness was greater than the thickness analyzed in the GE Letter Report (Ref (22]) and provided the methodology of Code Case N284 was employed to determine the allowable buckling load for the drywell.

Furthermore, all of these very local wall areas were centered about the vents, which significantly stiffen the shell. This stiffening effect limits the shell buckling to a point in the sand bed region, which is located at the midpoint between two vents. (Ref [35), [32], [161)

Table 4-Buckling Analysis Sum mary Load Combination CASE IV - REFUELING CASE V - ACCIDENT CONDITION CONDITION Service Condition Design Level C Thickness used in Analysis, mils 736 736 Factor of Safety Applied 2.00 1.67 Applied Compressive Meridional 7.59 12.0 Stress (ks!)

Allowable Compressive Meridional 7.59 12.93 Stress (ksi)

Actual Buckling Safety Factor' 2.00 1.80 Source: Ref [16]

The actual buckling safety factor is greater than 2.00 and 1.80 since the minimum measured general thickness is greater than 0.736 inches.

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Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-It Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-12 C.

Final Corrective Actions (early 1990's)

The corrective actions, implemented in early 1993, included removal of sand from the sandbed region, performance of additional UT inspections on the outside of the drywell shell to confirm the results of measurements previously taken from the inside, and application of epoxy coating to the exterior surface of the drywell to protect it from further corrosion.

I Removal of the sand was initiated in 1988 and completed in 1992.

The surface of the outer drywell shell was cleaned in preparation for coating (Ref [19]). Before the coating was applied, inspection of the outer drywell shell in all 10 sandbed bays was conducted.

125 UT measurements were taken in local areas suspected by visual inspection to be less than the minimum required general thickness of 736 mils. Of the 125 UT thickness measurements, 20 were determined to be less than 736 mils, but greater than the analyzed local thickness of 536 mils. The locally thinned areas were evaluated using criteria provided in ASME Section I11, Subsection NE3213.10 and found acceptable (Ref [32], [35]). See Table 2.

Table 2 - UT Thickness Measurement of Locally Thinned Areas Taken from Outside The Drywall In the Sandbed Region.

1992 UT Measurements 2006 UT Measurements Location Number Thickness in No. of Number Thickness in No.of UT of UT<

of UT<

736 mils mite UT 736 mils mils 700,710, 710,690, 705,700.

665,680,731, Bay 1 23 9

680,690, 23 10 669,711,722.

714,724,726 719,712 Bay 3 8

0 8

0 Bay 5 8

0 7

0 Bay 7 7

0 5

0 Bay 9 10 0

10 0

Bay 11 8

1 705 8

1 700 672,722, 708,658, Bay3 29 9

1655, 15 6

602,704.

618, 718.

728, 685,683 669,666 Bay 15 11 1

722 11 0

Bay 17 11 1

720 10 1

681 Bay 19 10 0

9 0

Total 125 21 1 0 6 '

18 Source: Ref [42], Ref [47]

1 The tocally thinned areas prepared for UT measurements in 1992 were measured in 2006. However the inspection team was able to locate only 106 points instead of 125.

2.

Coating of the Outer Drywell Shell in the Sandbed Region:

In 1992 the outer drywell shell was coated with a DEVOE Epoxy system, comprised of one coat of DEVOE 167 Rust Penetrating Sealer followed by two coats of Devran 184 epoxy coating (see attachment 3, Ref [19])

The DEVOE coating system was selected based on anticipation of less than ideal surface preparation of the outer drywell shell due to the confined space of the sandbed region. It was designed for application on surfaces prepared by hand cleaning tools to remove loose rust, mill scale, and other detrimental foreign matter in accordance with Steel Structures

M

-M m M M

M M

M m

M M

M M

Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-13 Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-14 Paint Council surface Preparation Specification No. 2.(SSPC-SP2). (Ref

[17])

The Pre-Prime DEVOE 167 Sealer penetrates through rusty surfaces and provides a means of reinforcing rusty steel substrates and thus insures adhesion of the Devran 184. The sealer was recommended by its manufacturer for use in areas where, due to restrictions or economics, blasting or a thorough hand cleaning was not feasible. (Ref[I 7])

The Devran 184 epoxy coating was designed for coating of tank bottoms, including water tanks, fuel tanks, and selected chemical tanks. (Ref [17])

Before the coating was used, a set of tests was performed outside the sandbed using a mock-up of the sandbed space and lighting. The purpose of these tests was to establish and qualify the painting process considering the limited space and visibility in the sandbed region. Each set of tests was performed on rusted carbon steel test panels that were prepared using tools to resemble asclosely as possible the expected condition of the drywell exterior surface. To further simulate the condition of the drywell exterior, the test panels were cleaned with DEVOE DevPrep 88 cleaner and then washed with high-pressure water (Ref [20])

DEVOE Pre-Prime 167 and Devran 184 coatings were applied to the test panel surfaces using brushes and rollers. The wet and dry film thickness of each coat was measured and used to determine the expected ranges of the coating thickness for the drywell exterior surface. Tests were performed to determine if holidays or pinholes were present in the coatings. (Ref [20])

3.

Repair of Sandbed Floor to improve Drainage The unfinished floor in the sandbed regions was built up using the same epoxy that was used to coat the shell, and reshaped to allow drainage through the sandbed floor drain of any water that may leak into the region. At that time, the joint between the sandbed floor and the external drywell shell was sealed with a caulk compatible with the epoxy coating to prevent any water from coming in contact with any portion of the drywell shell embedded below the level of the sandbed floor. See Section 7 of this Enclosure for additional information.

4.

Validation of Corrective Actions Effectiveness UT inspections of the sandbed region were conducted in 1992, 1994, and 1996 from inside the drywell. The results of these inspections showed that the corrective actions had been effective in arresting corrosion of the outer drywell shell in the sand bed region. (See Table-6). After 1996, additional UT measurements were not taken in the sandbed region; instead, the epoxy coating in critical bays was inspected for cracking, flaking, blistering, peeling, discoloration, and other signs of distress.

Inspections conducted in 1994 (Bays 3, 11), 1996 (Bays 11, 17), 2000 (Bays 1, 13), and 2004 (Bays 1,13) show that the coating was in good condition and there were no indications that the outer drywell shell was undergoing further corrosion (Ref [34]). Furthermore the periodic UT thickness measurements of the shell in the upper regions of the drywell could be used conservatively as an indicator of the condition of the outer drywell shell in the sandbed region. This was because the operating environment was similar in the sandbed region and the upper region of the drywell and the shell in the upper region does not have an epoxy coating. The 2004 upper region UT results showed that the highest corrosion rate is less than 1 mil/year.

Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Table 5 - Sandbed Region Drywell Shell 95% Confidence Level Average Thickness!

Page 6-15 Bay Dec-Febb-Apr-May-Aug Sep-Jul-Oct-8 Jun-Sep-Feb-Apr-Mar-May-Nov-May-Sep-Sep-Sep-Oct-L 8 6

8 78 87878788 89 89 90 90 91 91 91 92 92 94 962006 ID 111-1 1101 1151 112 3D 1178 1184 1175 118 5D 117 4

1168 1173 1181 7D 1135 1136 1138 1133 9A 1155=

1157 1155 1154 9D 1 1072 1021 1054 1020 1026 1022 993 1008 992 1000 1004 992 1008 993 11A 919,905 922 905 913 888 881 892 881 870 845 844 833 842 825 820 830 822 11C Btm 917 954 916 906 891 877 891 870 865 858 863 85Q 882 859 850 883 85!

Top 1046 1109 10791045 1009 1010 1005 952 977 982 1002 964 1010 970 982 1042 958 13A 919 905 8831 883 8621 853

.855 853 8491 865 858 837 853 846 13D Btm 962-909 901 900 931 906 895 933 904 Top-93 1072 1049 1048 1088 1055 103A 1059 1047 13C 11491140 1154 1142 15A 1120 1114 1127 1121 15D 1089 1058 1060 1061 1059 1057 1060 1050 1042 1065 1058 1053 1066 1053 17A Btm 999

957, 965 956 954 951 935 942 933 94 941 934 997 93 TOP 999 1133 1130 1131 1128 1128 1131 1129 1123 1125 1125 1129 1144 11 17D 922 895 891 895 878 862 857 847 836 829 825 829 82Z 823 817 810 848 81 17119 Btmn 98; 101c 113'1 99*

98t 975 969 95 972' 976 963.967 96 T-o 1004 999 9551010 1006 987 982 971 990 989 975 991 97 19A 8841 873 859 858 849 837 829 825 81 808 817 803 80 809 800 806 815 80 19B 89 892 888 864 857 826 84584083 853 844 846 847 841 824 837 848 19C 901 888 888 873 856 845I 8451 831 825 843 823 822 832 819] 820 854 82 Source: Ret47 Section 6 Corrosion of Containment Outer Drywell Page 6-16 Shell in the Sandbed Region Table 6 - Minimum Available Thickness Margin Based on Minimum 95% Confidence Level Average Thickness.

(Thickness In mils)

Location Pre-May T Sept 1992 1994'1996' 200 Min.

Nominal Margin 1992 19921 1996W I__I_

Required Thick.

Thick Std Error Thick Std Error Thick Std Error Thick Std Error i

1U 1110 "t 10.0 II1151

+/- 13.b1. 1122

+/-.4 3D 1178 1184

+/-4.9 5

+/-7.5 1180

.+5.7 5D 1174

-6t1W

+/- 2.6 1173

+/- 2.2 1185

+/- 2 7D 1135 1136

+/-4.3 1138

+/-5.9 1133**

.5 9A 1155 1157

+/-4.5 1155

+/-4.8 11 154:

+/-4,2 9D992 10-164,00 92

+1.

1008

+/-E 10.6 993

+/-11.T "11A 833 11C 842 882 10101 865 825

+/-8.2 j 8,*2C

+/- 7.71 830

+/- 8.71 822

ý+/-6.4 a860' 7

+/- 8.0

.4 855

+/-4.5

.4 958 l+/-

24.7

+/-23.81 982 13A 849 858

+/- 7.8 853

+/-8.81 8461

+/-8.2 130 Bot I900 931 905

+/-8.2 933

+/-9.61 9041

+/-8.9 oT toB 900 1088 100955 1+/-14.1 Vý403V

+/- 13.61 1059

+/-11.2 1 1047 1

+/- 13.7 736 1154 432 397 418 256 84 114 216 101 159 196 196 378 306 197 263 74 218 219 64 88 83 13C i

2 1149 15A 1_

1154

+/-3.2 1142

+/-3.1 1127

+/-10.8 1121

+/-16.6 15D i',042~

17A 170 1 822 1065 948 1125 823 972 990 609 10581 t8.7 1 1053

+/-9.01 1066

+/-8.5 1053 8171

+

17/19 Frame T

+/- 9.5

+/- 4.9

+/- 7.8

+/- 9.9 848

+/-:8.9 818

+/- 8.9

+/- 10.5

+/- 7.2

+/- 9.5

+/-4.8

+/- 8,9 967 19A 803

.J00'm

+/-84 1 806 815

+/- 9.6 807 19B 1 9C 1.Source - Refere.ce 21

2. Source - Reference 25

3. Sourc- - Referec 27

4. Source-Reference 31.47 Note: Shaded cells indicate thickanes value used to conservatively calculate the margin

Section 6 Corrosion of Containment Outer Drywall Shell in the Sandbed Region Page 6-17 Section 6 Corrosion of Containment Outer Drywall Shell in the Sandbed Region Page 6-18 Ii.

2006 Confirmatory Actions During the 2006 refueling outage (1 R21), AmerGen performed UT of the drywell shell in the sandbed region from inside the drywell, at the same 19 grid locations where UT was performed in 1992, 1994, and 1996. Location of the UT grid is centered at elevation 11' 3" In an area of the drywell shell that corresponds to the sandbed region. The 2006 UT measurements were made in accordance with the enhanced Oyster Creek ASME Section XI, Subsection IWE (B1.27) Aging Management Program. The data was statistically analyzed using the methodology described in section 3 to determine the 95% confidence level mean thickness. The results of the statistical analysis of the 2006 UT data were compared to the 1992, 1994 and 1996 data statistical analysis results. Some of the 1996 data contained anomalies that are not readily explained, but the anomalies did not significantly change the results. The comparison confirmed that corrosion on the exterior surfaces of the drywell shell in the sandbed region has been arrested.

Analysis of the 2006 UT data, at the 19 grid locations indicates that the minimum measured 95% confidence level mean thickness In any bay Is 807 mils (bay

1. 19A). This Is compared to the 95% confidence level minimum measured mean thickness in bay #19 of 606 mils and 800 mils measured in 1994 and 1992 respectively. Considering the instrument accuracy of +/-lOmils these values are considered equivalent. Thus no statistically observable corrosion has occurred since 1992 and the minimum drywell shell mean thickness at the grid locations remains greater than 736 mils as required to satisfy the worst case buckling analysis, and the minimum available margin of 64 mils for any bay reported prior to taking 2006 UT thickness measurements remains bounded. (Ref [47])

In its statistical analysis of drywell corrosion data, AmerGen has used the F-ratio test as part of Its method to determine whether there Is ongoing corrosion. In analysis of the data from this outage, AmerGen determined that different statistical treatment of the data would be appropriate to estimate bounding corrosion rates in the sandbed region. Using this updated statistical test of the data, AmerGen cannot statistically confirm that the sandbed region has a corrosion rate of zero. This Is because of the high variance In UT data within each 49-point grid (standard within a range of deviation 60 to 100 mils), the relatively limited number of data sets that have been taken and the time frame over which data has been collected since the sand was removed in 1992. The high variance in UT data within the grids is a result of the drywell exterior surface roughness caused by corrosion that occurred prior to 1992. However, AmerGen continues to believe that corrosion of the exterior surface of the drywell shell in the sandbed region has been arrested as evidenced by little change In the mean thickness of the 19 monitored (grid) locations and the observed good condition of the epoxy coating during the 2006 inspection.

In addition to the UT measurements at the 19 grid locations, a total of 294 UT thickness measurements were taken In the bay #5 trench and 290 measurements were taken in the bay #17 trench during the 2006 refueling outage. The computed mean thickness value of the drywell shell taken within the two trenches Is 1074 mils for bay #5 and 986 mils for bay #17. These values, when compared to the 1986 mean thickness values of 1112 mils for the bay #5 trench and 1024 mils for the bay #17 trench, indicated that wall thinning of approximately 38 mils has taken place In each trench since 1986. Engineering evaluation of the results concluded that considering that the exterior surface of bay #5 had experienced a corrosion rate of up to 11.3 mils/yr between 1986 and 1992 and the exterior surface of bay #17 had experienced a corrosion rate of up to 21.1 mlls/yr in the same period, the 38 mils wall thinning measured in 2006 is due to corrosion on the exterior surface of the drywall between 1986 and 1992.

(Ref [47])

Additionally the 95% confidence level minimum computed drywall shell mean thickness based on 2006 UT measurements within the two trenches is greater by a margin of 250 mils than the minimum required thickness of 736 mils for buckling. Also this margin is significantly greater than the minimum computed margin at other monitored locations outside the trenches (64 mils). Individual points within the two trenches met the local thickness acceptance criterion of 490 mils for pressure computed based on ASME Section I11, Subsection NE, Class MC Components, Paragraph NE-3213.2 Gross Structural Discontinuity, NE-3213.10 Local Primary Membrane Stress, NE 3332.1 Openings not Requiring Reinforcement, NE-3332.2 Required Area of Reinforcement and NE-3335.1 Reinforcement of Multiple Openings. The individual points also met a local buckling criterion of 536 mils previously established by engineering analysis. (Ref

[47])

The above UT thickness measurements were supplemented by additional UT measurements taken at 106 points from outside the drywell in the sandbed region, distributed among the ten bays. The locations of these measurements were established in 1992 as being the thinnest local areas based on visual inspection of the exterior surface of the drywell shell before it was coated. The thinnest location measured in 2006 is 602 mils versus 618 mils measured in 1992. The difference between the two measurements does not necessarily mean a wall thinning of 16 mils has taken place since 1992. This is because the 2006 UT data could not be compared directly with the 1992 data due to the difference In UT instruments and measurement technique used in 2006, end the uncertainty associated with precisely locating the 1992 UT points. A review of the 2006 data for the 106 external locations indicated that the measured local thickness is greater than the local acceptance criteria of 0.490" for pressure and 536 mils for local buckling. (Ref [47])

As stated above, the 2006 UT data of the locally thinned areas (106 points) could not be correlated directly with the corresponding 1992 UT data. This is largely due to using a more accurate UT instrument and the procedure used to take the measurements.. In addition the inner drywell shell surface could be subject to some insignificant corrosion due to water intrusion onto the embedded shell (see discussion below).

For these reasons the Oyster Creek ASME Section XI, Subsection ]WE Program (8.1.27) will be further enhanced to require UT measurements of the locally thinned areas in 2008 and periodically during the period of extended operation. (Ref [47])

mm

=

M M-Mn m

m m

-I m M

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Sm m

m m

m

-m m-m m

m mmm...

Section 6 Corrosion of Containment Outer Drywell Shelt in the Sandbed Region Page 6-19 Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-20 During the 2006 refueling outage (1 R21), AmerGen conducted VT-1 inspections of the epoxy coating in all ten bays in accordance with ASME Section XI, Subsection IWE, and AmerGen's Protective Coating Monitoring and Maintenance Program. These inspections would have documented any flaking, blistering, peeling, discoloration, and other signs of degradation of the coating. The VT-1 inspections found the coating to be in good condition with no degradation.

Based on these VT-1 inspections, AmerGen has confirmed that no further corrosion of the drywell shell is occurring from the exterior of the epoxy-coated sandbed region. Monitoring of the coating in accordance with the ASME Section XI, Subsection IWE and AmerGen's Protective Coating Monitoring and Maintenance Program will continue to ensure that the drywell shell maintains its intended function during the period of extended operation. (Ref [47])

A.

Aging Management Program for the Extended Period of Operation:

AmerGen is committed to a comprehensive aging management program to ensure that significant corrosion is detected and corrected prior to impacting the intended functions of the drywell (Ref [47]). The program elements for the sandbed region include:

I. A strippable coating will be applied to the reactor cavity liner to prevent water intrusion into the gap between the drywell shield wall and the drywell shell during periods when the reactor cavity is flooded.

2. The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored for leakage during refueling outages and during the plant operating cycle:

The sand bed region drains will be monitored daily during refueling outages.

If leakage is detected, procedures will be in place to determine the source of leakage and investigate and address the impact of leakage on the drywell shell, including verification of the condition of the drywell shell coating and moisture barrier (seal) in the sand bed region and performance of UT examinations of the shell in the upper regions. UTs will also be performed on any areas in the sand bed region where visual inspection indicates the coating is damaged and corrosion has occurred.

UT results will be evaluated per the existing program. Any degraded coating or moisture barrier will be repaired. These actions will be completed prior to exiting the associated outage.

The sand bed region drains will be monitored quarterly during the plant operating cycle. If leakage is identified, the source of water will be investigated, corrective actions taken or planned as appropriate. In addition, if leakage is detected, the following items will be performed during the next refueling outage:

o Inspection of the drywell shell coating and moisture barrier (seal) in the affected bays in the sand bed region o

UTs of the upper drywell region consistent with the existing program o

UTs will be performed on any areas in the sand bed region where visual inspection indicates the coating is damaged and corrosion has occurred o

UT results will be evaluated per the existing program Any degraded coating or moisture barrier will be repaired

3. The Inservice Inspection (ISI) Program will be enhanced to require inspection of 100% of the epoxy coating every 10 years during the period of extended operation. These inspections will be performed in accordance with ASME Section Xl, Subsection IWE. Performance of the inspections will be staggered such that at least three bays will be examined every other refueling outage.

Inspection of the coating is accomplished through the Protective Coating Monitoring and Maintenance Program (B.1.33)

4. When the sand bed region drywell shell coating inspection is performed, the seal at the junction between the sand bed region concrete and the embedded drywell shell will be inspected

5.

The reactor cavity seal leakage concrete trough drain will be verified to be clear from blockage once per refueling cycle.

6. UT thickness measurements will be taken from outside the drywell in the sandbed region during the 2008 refueling outage on the locally thinned areas examined during the October 2006 refueling outage. The locally thinned areas are distributed both vertically and around the perimeter of the drywell in all ten bays such that potential corrosion of the drywell shell would be detected.

7.

Starting in 2010, drywell shell UT thickness measurements will be taken from outside the drywell in the sandbed region in two bays per outage, such that inspections will be performed in all 10 bays within a 10-year period, The two bays with the most locally thinned areas (bay #1 and bay #13) will be inspected in 2010. If the UT examinations yield unacceptable results, then the locally.

thinned areas in all 10 bays will be inspected in the refueling outage that the unacceptable results are identified.

8. Perform visual inspection of the drywell shell inside the trench in bay #5 and bay

1. 17 and take UT measurements inside these trenches in 2008 at the same locations examined in 2006. Repeat (both the UT and visual) inspections at refueling outages during the period of extended operation until the trenches are restored to the original design configuration using concrete or other suitable material to prevent moisture collection in these areas.

After each inspection, UT thickness measurements results will be evaluated and compared with previous UT thickness measurements. If unsatisfactory results are identified, then additional corrective actions will be initiated, as necessary, to ensure the drywell shell integrity is maintained throughout the period of extended operation (Ref [47]).

m m

m m

m

-m m m

Section 6 Corrosion of Containment Outer Drywell Page 6-21 Shell in the Sandbed Region III.

Conclusion a

Corrosion of the Oyster Creek outer drywell shell has been investigated since the C

early 1980's. Corrective actions, implemented beginning in 1986, have arrested corrosion. AmerGen conducted UT thickness inspections of the shell in the sandbed region in 2006 (1R21) to confirm corrosion has been arrested in the outer dryweli shell. The results showed that corrosion of the exterior drywell shell has been arrested. AmerGen also conducted VT-1 inspections of the epoxy coating in all ten bays in accordance with ASME Section XI, Subsection IWE, and AmerGen's Protective Coating Monitoring and Maintenance Program. The VT-1 inspections found the coating to be in good condition with no degradation.

Engineering analysis of the drywell using a conservative uniform general thickness of 736 mils for the entire sandbed region concluded that the drywell meets its design requirements during the current term with adequate margin.

a Lu AmerGen is committed to implementing a comprehensive aging management 0n program during the extended period of operation to preserve the existing margin.

i z

M The program is designed to detect, mitigate, and correct drywell shell degradations.

S M, These activities provide reasonable assurance that wall thinning of the drywell will be a

detected and corrected prior to impacting the intended function of the drywell.

."1 z

0 Eo LU 0 o

C.

._0.

ca 0 U C-)

In00 0)

(0

Figure 1. Sandbed Bay # 1D 1154 Mil Nominal Shell Plate Thickness 1200 1000 365 Mils mrin Margin 800 736 Mil General Required Shell Thicknes 600 Ba 15 B

ay 17 StarteSand N

y 4 Removal Complete Bayl 1Bay I

O 400 Sand Removal and apply Drain tines Epoxy Coating BaWN Bay3 Cleaned BaW 7

B -y 6

200 N ey~aNe 00-I Strippable Strippable l,~,-*Strippable Coating Coating Coating Added 0.

Added to Rx Cavity Not Used to Rx Cavity C~~~~~~~~

C 6

Source: Raw Data -AmerGen Calculation C-1302-187-Date 5300-1121 12-1302-15,7-53Dn-t19 C-13fl2.187-8511t0-30 5300-021 C-1302-187-5300-028 C-1302-187-8610-030 Figure 2. Sandbed Bay #3D 1

1154 Mil Nominal Shell Plate Thickness t200

_iU 1000 -

442 Mils min. Margin

= 800 V

==

i 600600 736 Mil General Required Shell Thickness Bay'1s Bay 17 Start SandI Removal Complete I

l 0

400 -Sand Drain Removal and aayN Lines apply Epoxy Cleaned CoBting e7 Bap 200 Shippable Strppable Strppable Coating Added -,

4 Coating

.4-Coating Added

to Rx Cavity

4. Not Used 4 to Rx Cavity 0t Source: Raw Data - Amergen Calculation C-1302-187-5300-021, Date C-1 302-187-5300-028, C-1 302-187-8610-030

Figure 3. Sandbed Bay # 5D 1154 Mil Nominal Shell Plate Thickness 1200

\\

A__A A

1000 449 Mils min. Margin 800 736 Mil General Required Shell

"* 600 -

is BW 17 Start N

lw1 W1

~Sand Removal W1 ill

) BwI 400 Drain Lines Complete Sand

. \\,

Cleaned Removal and apply Epoxy Coating Bay7 OWS 200 eia lIStrippable Strippable iable 1-Coating Coating Added Addeto a

Not Used to Rx Cavity e Source: Raw Data - Amergen Calculation C-1302-187-5300-021, C-Data 1302-187-5300-028, C-1302-187-8610-030 I

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Figure 4. Sandbed Bay # 7D 1154 Mil Nominal Shell Plate Thicknes\\

1200 1000 o

397 Mils min.Margin S800 736 Mil General Required Shell Bay 15 Bay17 0

400 Start Sand 0I Removal Complete Sand Removal and apply Epoxy Coating m

3 Drain Lines Bay?7 Bt 5 200 Cleaned

IIKyI, 2

Strippable I

Strippable~

~

fotn C<

oating -- bI*

Strippable Coating I

Added to Rx Cavity Not Used.

Added to Rx Cavity Source: Raw Data - Amergen Calculation C-1 302-187-Date 5300-021. C-1i302-187-5300-028, C-1302-187-8610-030

Figure 5. Sandbed Bay # 9A 1200 1154 Mil Nominal Shell Plate Thickness 1000 418 Mils min.Margin 736 Mil General awis 0., 17 600 Required J,-

Shell Thickness Start Sand I

Removal aB 3

t 2

1 R

o400 Complete Sand Drain Lines Removal and apply Cleaned Epoxy Coaling Y

K.YPIin 200 Strippable Sppable Strippable eating Added

- Coaling -T to Re Cavty Not Used Coating Added C

to 80x Cavity Source: Ra~w Data - Amergen Calculation C-1302-187-Date 5300-021. C-1302-187-5300-028. C-1302-187-8610-030 Figure 6. Sandbed Bay # 9D 1154 Mil Nominal Shell Plate Thickness 1200 1000

.g 800 736 Mil General Required 8o0 Start Sand Shell Thickness

• sw i as,17

" Removal owl Complete Sand Removal and apply Epoxy Drain Lines Coating Cleaned B.i Nayn Soi1 KWPlan 200 1

Stippable Coating Added Strippable Sbippable Coating Added to Rx Cavity

• 1-Coating --

to Rx Cavity I

I Not Used n

n in o

i i

i 0

0 0

0 in

-4 in n

0=

i*

i4 in in

-4 in in 0

r

)

in Source: Raw Data - Amergen Calculation C-1302-187-Date 5300-021, C-1302-187-5300-028, C-1302-187-8610-030

Figure 7. Sandbed Bay #IA 1154 Mil Nominal Shell Plate Thickness 1200

-17.1 Mils/Yr 1000 900

(

I 736 Mil General Required

~

600 (Shell Thickness 600 SStart Sand Removal 400 Removal and XW I.

apply Epoxy Coating Strippable i

Sippable Stnpa Coating L

Coating Strippable Coating

-Added to Rx CaviltyNot Use"o 4

Added to Rx Cavity Source: Raw Data - Amergen Calculation C-1302-187-Date 5300-021, C-i302-187-5300-028, C-1302-187-8610-030 I

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I Figure 8. Sandbed Bay #11C Top 1154 Mil Nominal Shell Plate Thickness 1200 N.

8

-17.1 Mils/Yr*

222 Mils rain. Margin 0736 Mil General Required ext 600 *Shell Thickness a

Ix Bu 7 Start Sand Removal O

40' Complete Sand awl n

Drain Lines Removal and Cleaned apply Epoxy BDu Ou3 Coating RW7 Bs KWPh.

200 *

]SJ*

Strippable SRppable Coating Coating Strippable Coating Idded to Rx Cav ity T

Not Use Added to Rx Cavity Source: Raw Data - Amergen Calculation C-1302-187-Date

\\.5300-021, C-1302-187-5300-028, C-1302-187-8610-(*Maximum calculated rate -35,2 milslyr 4191, C-1302-187-5300-011 Rev. 1)

Figure 9. Sandbed Bay #11C Bottom 1154 Mil Nominal Shell Plate 1200 Thickness 1000

-14.3 Mils/Yr*

goo A

119 Mils min. Margin 736 Mil General Required 600 Shell Thickness Bay is BaV 1 Start Sand Removal 40t0o Complete Sand Drain Lines Removal and apply Cleaned Epoxy Coating ewag Z 3

S dadedt Rx Cavity Coatng 4

Added to Rn Cavity 0 C CNt Used Source: Raw Data - Amergen Calculation C-1302-187-5300-Date (*Maximum calculated rate -22.4milslyr 4/91,C-1302-187-5300-011 Rev.1) 021. C-1302-187-5300-028, C-1302-187-8610-030 Figure 10. Sandbed Bay #13A 1154 Mil Nominal Shell Plate Thickness WuU 600 O400 Strippable Coating Stippable Strippable Coating Added s1 Coating Added to Rx Cavity

'I Not Used to R. Cavity Source: Raw Data - Amergen Calculation C-1302-187-5300-021, Date (Maximum Calculated rate.39.1 milslyr 4/91, C-1302-187-5300O28, C-1302-187-8610-030 C-1302-187-5300-011 Rev. 1)

Figure 11. Sandbed Bay #13D Top 1154 Mu Nominal Shell Plate Thickness 1200-

-14.6 MilstYr 1000-Start Sand 600 -

4--

Removal 736 Mil General Required

.2 Shell Thickness Drain Lines Complete Sand o

400 M....

nA Removal and apply Epoxy Coating oIngd Sippable eCoating Added to I-Coating Rx Cavity 4,

Not Used

?

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 Source: Raw Data - Amergen Calculation C-1302-187-5300-Date 021. C-1302-187-5300-028. C-1302-187-861D-030 I

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Figure 12. Sandbed Bay #13 D Bottom 1154 Mil Nominal Shell Plate Thickness 1200 1000

-10 Mil/Yr C736 Mil General Required--."

aShell Thickness e*,*

S600 0

Start Sand

~Removal j

Drain Complete Sand I

400 Removal and S400 "

Lines a

I E W1 Coating BW as Strippable Strippable Coating Added___,

4 CoatingLI.

Strippable Coating to Rx Cavitiy Not Used Added to Rx Cavity

?

?

0

?

?00 0

0.

Source: Raw Data - Amergen Calculation C-1302-187-Date 5300-021, C-1302-187-5300-028, C-1302-187-8610-030

Figure 13. Sandbed Bay # 13C 1154 Mil Nominal Shell Plate Thickness 12o00,,

1000 406 Mils min. Margin e00 736 Mil General Required Shell Thickness 600 -

Bs B;17 Start Sand q

/

BO Removal 400 Complete Sand Drain Lines Removal and apply 3

Cleaned Epoxy Coating,7 a,

Y 200 Stippable Strippable Coating Coating Strippable A

to g

P'

-- a"o t U s e d

• 4

- C o a tin g A d d e d Source: Raw Data - Amergen Calculation C-1302-187-Date 5300-021, C-1302-187-5300-028. C-1302-187-8610-030 Figure 14. Sandbed Bay # 15A 1154 Mil Nominal Shell Plate Thickness 1200 4

A I20 A

1000 8OO 600 400 200 385 Mils min. Margin

-1.-i 736 N Start Sand Complete Sand Removal Removal and apply Epoxy Coating Ul General Required Shell Thickness BayS 15 v'1 BW 3

BW I Aw.V1 Drain Lines BaW \\/Bay 3

Cleared -7 Bay 5 Shrppable Strippable Strippable 4-Coating Added P-4*-Coating 4-Coating Added to Rx Cavity c

Not Used

• to Rx Cavity C

C o?

C C

C C

C C

C C~~~~~

C C6 C

6 Source: Raw Data - Amergen Calculation C-13 02-187-5300-021, C-1302-187-5300-028. C-1302-187-8610-030 Date

I Figure 15. Sandbed Bay #15 D I

1154 Mil Nominal Shell Plate Thickness 1200 1

I

-1.0 Mils/Yr-

____m_

U, 1000 317 Mils min. Margin

.R 900 toe 736 Mil General Required Shell Thickness 2f 600 Start Sand awl B'1 I-Removal Complete Sand O1 awl Removal and I

400 apply Epoxy a

Drain Lines Coating Cleaned e

n m

200 Strippable Coating

[

Stnppable

_t_

__ab S~Addto e*

Coating* ~-1 Strippable, Coating 0.ooed to x Cay Not Used Added to Rx Cavity 0

Source: Raw Data - Amergen Calculation C-1302-187-Date 530D-021, D-1302-187-5300-028, C-1302-187-8610-030 I

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Figure 16. Sandbed Bay #17A 1154 Mil Nominal Shell Plate Thickness 1200 1000 1I

-1.7 M il/Yr 8 M m

m 356 Mils rein. Margin 800 I/n Str and Removal 736 Mil General Required Shell 600.

Complete Sand Thickness BOi,,

m17 Removal and apply BW3 BeW Epoxy Coating awil 8W1 400 Cathodic Protection Cathodic Protection System Removed aWe 8%3 System Installed Drain Lines sW7 as SStrippable Coatin Strippable Strippable Coating Added to Rx Cavity ICoating Added to Re Cavity 4

4Not Use 0

I Source: Raw Data - Amergen Calculation C-1302-187-5300-D 021, C-1302-187-5300-028, C-1302-187-8610-030 Date w

I

Figure 17. Sandbed Bay #17A Bottom 1154 Mil Nominal Shell Plate Thickness 1200

-5.8 Mil/Yr*

1000 80199 Mils rain.Margin

.9800 736 MH General Required

" 600 Shell Thickness 8

I IStart Sand lW swig I

Removal SICathodicProtection awl 400 -Cathodic Protection System Removed System Installed Complete Sand i

W1 MWO Drain Lines Removal and apply By7 9.15 Cleaned Epoxy Coating m

2D0 Caing trippable Sippable Coating Added to I Cavi

-,,,ating UsdAdded to Rx Cavity I

11'r Not Used

/'

Source: Raw Data - Amergen Calculation C-1302-187-5300-Date

(*Maximum calculated rate -0.3miVyr 9/94, 021, C-1302-187-5300-028, C-1302-187-8610-030 C-1302-187-5300-028 Rev. 0)

Figure 18. Sandbed Bay #17D 1154 Mil Nominal Shell Plate Thickness 1200 1000

-18 Mil/Yr*

o00 74 Mios nin\\Margin B td736 MiP General Required StShell Thickness Bayc 1

OW S600 Start Sand ft Bo,3j 51-Y 9 Drain Unes mvSystem Removed Kayla 200 CleanedSand Reoa andappypabl wl 4-Stzippable Coating -

l----

Coati-pp a

Strippable Coating A dded to Rx Cavity, Not Used-Added to Rx K

Not sed cavity 0CaCatyty Source: Raw Data -Amergen Calculation C-1302-187-5300-Date

('Maximum calculated rate -23.7mils/yr 4/91, 021. C-1302-187-5300-028, C-1302-187-8610-030 C-1302-187-5300-011 Rev. 1)

Figure 19. Sandbed Bay #17/19 Frame Top 1154 Mil Nominal Shell Plate Thickness 1200 -

-Z

-10.7 Mils/Yr 1000 i

=**

m

• m 0 0 A

218 Mils min. Margins Stt Sd

/736 Mill General Required Shell I--

5 600 Start Sand Thickness 2

l ITM Removal awl

=

/-

Complete Sand Removal Cathodi Pr and apply Epoxy Coating awl

- 400- Cathodic Prtection Cathodic Protection System Installed system Removed

/

MWI Drain Unes aw, B" 5 20- Cleaned Strippable Strippable KYm C-Coating Added to Coating Strippable Coating 0x RCavity Not Used Added to Rx Source: Raw Data - Amergen Calculation C-1 302-187-5300-021, Date C-1302-187-5300-028, C-1302-187-8610-030 I

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Figure 20. Sandbed Bays # 17/19 Frame Bottom 1200 1154 Mil Nominal Shell Plate Thickness

-8.7 MilsYr*

too0

__m---m---____m_-_____

235 Mils rain. Margin I"

600 no1 ol 736 Mil General Required Shell Thickness 600 -

B.

mi*s

aWV, Start Sand

-~~~a RmvlI no13 swig1 RmvlComplete Sand A-C Removal and apply l

S i

ti 400 Cathodic Protection Epoxy Coating I

Ba"ySl=

lSysem Installed Epoxy

/

Bay Cathodic Protection\\

\\

/

Drain Lines System Removed 200 Strippable Shdppable Coating Coating-.

4-Stippable Coating Added to Rx Cavity Not Used, AddedtoRxCavity C0 C

C*

C C

C C

C C

C*,

Cde Co C

CaCviCtyC Source: Raw Data - Amergen Calculation C-1302-187-Date

(*Maximum calculated rate -13.1mil/yr 4/90, 5300-021, C-1302-187-5300-028, C-1302-187-8610-030 C-1302-187-5300-011 Rev. 0)

Figure 21 Sandbed Bay # 19A 1154 Mil Nominal Shell Plate Thickness 1200 1000

-15 MilsWyr 800 600 0

400 200 64 Mils min. Margin d Shell Thicknes, Cathodic Protection Complete Sand System Installed Removal and apply Epoxy Coating Bay 7 aw8 Drain Lin Cleaned 11i es Cathodic Protection System Removed Stiippable I

NCoating NtUsed Shippable Coating i StIppable Added to R.x Cavi y 1

0 Co Add*d to Rx Cavity Source: Raw Data - Amergen Calculation C-1302-187-5300-021, C-1302-187-5300-028, C-1302-187-8610-030 C

Date (Maximum calculated rate -21.4miltyr 4/91, C-1302-187-5300-011 Rev. 1)

C Figure 22. Sandbed Bay #19 B 1154 Mil Nominal Shell Plate Thickness 1200 1000

-9.9 MiVYr" 000 76 Mils min. Margin 736 Mil General Required Shell ayis e*-17 600 -Thickness 1

ae.

Start Sand Thcns w

13as1 Removal Complete Sand 3

zRemoval and apply t'

Epoxy Coating 8W aw 9

400 Cathodic Protection System Installed Cathodic Protection System Removed Drain Lines I

aW7 Days Cleaned MY Fq-200 Strippalble Strippable Coating_________________

Coating 1

Added to Rx u

0 Used C1 C

C C

C C

C C

C Source: Raw Data - Amergen Calculation C-1302-187-Date

(*Maximum calculated rate -19.0 mils/yr 4/91, 0300-021 C-1302-187-5300-028 C-1302-187-8610-030 C-1302-187-5300-011 Rev. 1)

I Figure 23. Sandbed Bay # 19C 1154 Mil Nominal Shell Plate Thickness 1200 1000 a

t~t a

736 Mil General Required Shell

" 600 Start Sand awls B.17 Complete Sand 400 h

i rRenmoval and apply i

awl 40 Cathodic Protecti.on Epo xy Coating WM 3

System Installed Cathodic Protection U

Drain Lines System Removed W

Bay5 200 Cleaned I

_K__

P_ _

V I Strippable Strippable Strippable Coating Added to Coating 4

Coating

~~ ~Added to Rx

~D Source: Raw Data - Amergen Calculation C-1C302-187-5300 Date 021. C-1302-167-5300-026. C-1302-187-8610-030

(*Maximum calculated rate-24.3rils/yr 4/91, C-1302-187-5300-011 Rev.1)

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I Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region ATTACHMENT 2 LOCATION OF UT MEASUREMENTS Page 6-23 I

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Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-24 7

Section 6 Corrosion of Containment Outer Drywell Shell in the Sandbed Region Page 6-25 - Sandbed Region Epoxy Coating Specification DEVOE Epoxy Coating System P P-Prime 167 (Epoxy Primer)

Devran 184 (Epoxy paint)

Demat 124S (Epoxy caulk)

DevPrep 88 (Cleaner)

Service Life The specification requirement for ideal service life is at least 20 years. However, it was recognized that practical coatings may require maintenance sooner than 20 years. The service life is determined by periodic inspection to ensure degradations are detected and corrected before failure of the coating.

Environmental Conditions The coating is qualified for temperature Up 250 degree F Wetting & Drying Abrasion Resistance The material should be sufficiently abrasion resistant to avoid damage from video cameras, temperature probes, radiation monitors, and other similar devices.

Adhesion The coating should remain intact and attached to the drywell for the full range of general operating conditions and for the expected light abrasion during inspections and maintenance Direct Impact Resistance The coating should remain intact and attached to the drywell for the full range of general operating conditions and for the expected light abrasion during inspections and maintenance Weathering Resistance N/A. The area to be coated is not exposed to weathering or direct light Decontaminability N/A Thermal Conductivity N/A Maintenance Periodic inspection to determine if maintenance is required Repairability Repairable in the limited access area using equipment available on site Color Color or tint for one coat should provide a good visual contrast with previous coat or substrate Light gray to provide good light reflectance and easy detection of surface contamination and color changes indicating deterioration, and to make the need to repair a damaged or abraded area more-evident Gamma Radiation DEVOE coatings have not been tested for resistance to gamma radiation. Degradation due to exposure to Gamma radiation is determined by periodic inspection.

Source: Ref [19]

M M

M

-m m

M Mmm M M-M--

-n Section 7 Embedded External Drywall Shell Page 7-1 Section 7 Embedded External Drywall Shell Page 7-2 This discussion addresses the embedded external Oyster Creek drywell shell

("embedded shell"). Part I, below, provides an overview of commitment information regarding the embedded shell prior to the October 2006 outage. The discussion in Part II sets forth Information discovered and analyzed as a result of the October 2006 outage.

Overall conclusions about the embedded shell, and continued performance of its Intended function during the proposed twenty-year renewal term, are summarized in Part Ill.

A question regarding the embedded shell was posed to AmerGen at a June 1, 2006 NRC public meeting, and later documented In Ref [36]:

"Inspection of Inaccessible Regions:

It Is not clear to the NRC whether the junction between the 1.154 Inch plate and the 0.676 Inch plate at the elevation 6 foot 10/ Inches Is represented In the UT sampling plan.

This area is below the bottom of the sand-pocket area, and is in contact with the concrete alkaline environment.

However in the past, before seating of the junction between the steel and the concrete, this area would have been subjected to the same type of contaminated water as the drywall shell In the sand-pocket area. The NRC considers this junction to be an area for possible corrosion.

The NRC requested the applicant to incorporate this area In the sampling plan or Justify why it should not be part of the sampling plan."

In October 2006, the ACRS License Renewal Subcommittee also asked about possible corrosion In the embedded region and AmerGen's confidence that corrosion there would be no greater than In the sandbed region, due to the Inability to inspect the shell embedded in the concrete. (Ref [44], Pages 84 & 85)

In answer to these Inquiries, AmerGen provides the historical information In Part I of this document.

I.

Historical Summary - The Embedded Shell The condition of the embedded shell was communicated in a response to the NRC dated June 20, 2006 (Ref [371):

"Response:

A review of the drywell construction and fabrication details shows that the drywell skirt Is welded to the 1.154 Inch thick plate below the sand bed floor before the and of the 1.154" thick plate. This thick plate is welded to the 0.676" plate at elevation 6 foot 10 114 inches. One of the purposes of the skirt, which is also now embedded in concrete, was to support the drywell during construction. The presence of the skirt prevents moisture intrusion into the 0.676" plate. Reference Figure 7 in Section 3 of this Enclosure.

Both the 1.154" thick plate and the 0.676" thick plate are embedded in concrete and are inaccessible for Inspection as recognized by ASME Section XI, Subsection IWE-1 232 and NRC Guidance (NUREG-1 801 Rev. 1) for license renewal. These documents credit pressure testing performed in accordance with 10 CFR Part 50 Appendix J, Type A test, for managing aging effects of Inaccessible portions of the drywell shell. NUREG-1801 and Ref [30] indicate that corrosion of embedded steel Is not significant If the following conditions are satisfied:

1. Concrete meeting the specifications of ACI 318 or 349 and the guidance of 201.2R was used for the containment shell or liner.

2. The concrete is monitored to ensure that it is free of cracks that provide a path for water seepage to the surface of the containment shell or liner.

3. The moisture barrier, at the junction where the shell or liner becomes embedded, is subject to aging management activities in accordance with ASME Section XI, Subsection IWE requirements.

4. Water ponding on the containment concrete floor are not common and when detected are cleaned up in a timely manner.'

The Response also indicated:

'The corrosion of the drywall shell In the sand bed region was caused by the moisture trapped in the sand bed due to water leakage into the region. The source of leakage was determined to be the reactor cavity, which Is filled with demineralized water during refueling outages. 'The water passed over the Firebar-D coating that was applied to the drywell shell to allow for formation of the required seismic gap between the drywell shell and the encircling concrete shield wall. The Firebar-D material is a magnesium oxychloride compound. The drywall was erected onsite and exposed to salt air environment during construction, which could also introduce contaminants to the sandbed environment. Chemistry test results on wet sand conducted In 1986 indicated that the leachate from the moist sand had a pH of 8.46 and contained only 45 ppb chlorides and <17 ppb sulfates.

As noted in Ref [30], this water is not aggressive to concrete since the pH is greater than 5.5, the chlorides are less than 500 ppm and sulfates are less than1500 ppm. This means that the wetted concrete environment will provide a high pH environment that will protect the embedded shell from corrosion. Additionally, the corrosion rates calculated for the carbon steel plugs removed from the drywall shell In the sand bed region were comparable to carbon steel exposed to typical waters over a similar temperature range.

While an increase in the salinity and impurity of the water will increase the kinetics of the corrosion reaction by increasing the electrolyte conductivity and can alter the form of corrosion experienced by steel (e.g., from general corrosion to pitting corrosion),

impurities such as chloride and sulfate are not fundamentally involved in the corrosion anodic and cathodic reactions. In fact, Increasing the salinity of the water decreases the dissolved oxygen content of the water and, thus, reduces the concentration of cathodic reactant present for the corrosion reaction." (Ref [37])

m

-mmn Section 7 Embedded External Drywell Shell Page 7-3 Section 7 Embedded External Drywell Shell Page 7-4 The removal of the sand from the sandbed region in 1992 afforded the first opportunity to inspect the sandbed floor and evaluate its condition. There were a number of bays in which the sandbed floor was noted as being unfinished (i.e., the floor lacked a smooth surface with appropriate slope that would direct any water entering the sandbed region away from the drywell shell to the drain). This was documented in Update 10 (4/97) to the Oyster Creek FSAR, Section 3.8.2.8 (Drywell Corrosion) (Ref [46]).

The condition of the sandbed floor also was noted in a May 5, 1993 meeting between GPU Nuclear Corporation and the NRR Staff on the Oyster Creek Drywell Corrosion Mitigation Program (Ref [24)). The presentation slides used during that meeting identified the sandbed floor in some bays to be "cratered with some craters adjacent to the shell. A few craters were big, about 12-13 feet long, 12-20 inches deep and 8-12 inches wide." AmerGen believes that the small quantity, low velocity and non-aggressive chemistry of the water that entered the sandbed region while the sand was present could not have eroded concrete to the extent Identified and, therefore, the craters have existed since original construction. (Ref [48])

Several corrective actions were implemented to mitigate corrosion of the drywall shell.

These mitigative actions were designed to minimize water intrusion into the sand bed region, provide for an effective drainage of the region in the event of water leakage, and monitor the drains to detect leakage. (See Sections 4 & 6 of this Enclosure).

Specifically, as part of the corrosion mitigation activities performed in 1992, the outer shell of the drywell was cleaned and then coated with an epoxy coating.including portions of the shell below the current level of the sandbed floor in those bays where the floor was unfinished. The unfinished floors in the sandbed regions were then built up using the same epoxy that was used to coat the shell, and reshaped to allow drainage through the sandbed floor drain of any water that may leak into the region. At that time, the joint between the sandbed floor and the external drywell shell was sealed with a caulk compatible with the epoxy coating to prevent any water from coming in contact with any portion of the drywell shell embedded below the level of the sandbed floor. (Ref

[19], Section 6.12).

ti.

Confirmatory Actions Durino The 2006 Outage AmerGen visually inspected the sandbed regions in all 10 bays during the 2006 outage.

As part of these inspections, the integrity of the epoxy floor and the caulk sealant between the external drywell shell and the floor of the sandbed region were inspected.

No degradation of the caulking between the coated drywell shell and the epoxy coating on the sand bed regions floors was observed. Accordingly, no repairs were required.

(Ref [47])

AmerGen observed in 8 of 10 bays separation/cracking of the floor epoxy coating.

These areas had no impact on the exterior drywell shell epoxy coating or the caulk seal between the drywell shell and the sand bed floors because the cracks were in areas of the floor away from the shell. The separation/cracking was repaired prior to the conclusion of the October, 2006 outage.

The 1.154 inch thick plate of the external drywell shell between the embedded support skirt and the floor of the sandbed region likely experienced some historical corrosion.

However, AmerGen expected such corrosion to be bounded by the corrosion in the non-embedded regions due to the formation of a thin protective oxide passive film over the shell from the highly alkaline concrete. (Ref [29]). During the October 2006 outage, AmerGen implemented a commitment to inspect the drywell shell from the inside of the drywell in two trenches excavated in 1986 in the concrete floor (Discussed in more detail in Section 8 of this Enclosure). An additional portion of one of the trenches was further excavated to expose a small portion of the drywell shell that had, up until October 2006.

been embedded in concrete on both sides. An average thickness of 1.113 inches was ultrasonically measured which, when compared with a nominal wall thickness of 1.154 inches, indicates an average total wall loss of 41 mils since construction in the late 1960s (approximately 40 years). AmerGen assumes that the majority of this wall loss occurred from the exterior of the shell and prior to 1992 (Ref [471), when the sand and standing water was removed from the sandbed region. However, assuming that the 41 mils wall loss occurred over the first 40 years, and that there is an ongoing corrosion of about I mil per year, there is still adequate margin for the proposed 20-year period of extended operation.

For the reasons stated below, the exterior of the 0.676 inch thick plate embedded in the concrete below the attachment point of the steel support skirt has been protected from contact with water on the outside of the drywell shell and, therefore, likely did not (and does not now) experience corrosion. The weld that attaches the skirt to the drywell shell is continuous around the exterior of the drywell shell preventing water on the exterior of the drywell from continuing into the 0.676 inch plate region. Although there are cutouts in the skirt to facilitate initial construction, these cutouts are at least 2 feet below the attachment weld. Notes on installation drawings indicate that other openings in the skirt were closed as concrete placement proceeded. For water on the outside of the shell to contact the 0.676 inch plate, it would need to migrate downward through the concrete, through the opening in the skirt and then over two feet upward to the shell. The water on the outside of the shell that may have entered the space between the exterior drywell shell and the sandbed floor prior to the joint being caulked lacks the driving force (including wicking) necessary to navigate such a tortuous path through the concrete.

Also, although the bottom of the drywell is below the level of the groundwater table, it Is not credible that groundwater could have migrated through the concrete under this portion of the shell and caused external corrosion in the 0.676 inch plate. The Reactor Building Foundation floor is a 10 ft thick reinforced concrete slab. The bottom elevation of the slab is minus 29' 6" and its top elevation is minus 19' 6". There is a waterproof membrane at the bottom of the mat that extends up the outside of the exterior walls to an Elevation of 5' 0". The concrete pedestal that supports the Containment shell is located at the center of the mat. The containment shell is spherical in shape at the base and has a bottom elevation of 2' 3". The Torus Room completely surrounds this concrete pedestal with a floor elevation of minus 19' 6" (top of mat). (A more detailed description of the drywell is provided in Section 3 of this Enclosure)

In order for ground water to reach the lowest point of the containment shell it would need to penetrate the waterproof membrane then migrate through the 10 ft concrete mat then

M--mmn--

M-M Section 7 Embedded External Drywell Shell Page 7-5 Section 7 Embedded External Drywell Shell Page 7-6 migrate through the pedestal concrete. Since there is no waterproofing on this interior concrete pedestal, or other interior walls, any water contained or migrating in the pedestal would seek the path of least resistance and flow into the Torus Room. This path would be through the concrete itself or along construction joints in the pedestal. If water was able to make its way along the path outlined above, and actually reach the base of the containment shell, the Torus Room would be flooded. There are sumps in the basement of the Reactor Building that collect any water in leakage and would prevent significant accumulation of water in the Torus Room.

Periodic testing of the drywell integrity is required by I0CFR50, Appendix J. In particular, the Type A test measures the containment system overall integrated leakage rate and must be conducted under conditions representing design basis loss-of-coolant accident containment peak pressure. The most recent Appendix J, Type A test of the drywell shell (Nov. 2000) confirmed the integrity of the shell in the embedded region and satisfied all Code acceptance criteria.

Ill.

Conclusions From the above discussion, the conclusions are as follows:

The corrosion of the external embedded drywell shell is bounded by the corrosion in the sandbed region. This is a reasonable conclusion for two primary reasons:

1. "The carbon steel in the embedded region is in contact with high pH concrete that allows the creation of a passive film on the steel surface. That is, the presence of abundant amounts of calcium hydroxide and relatively small amounts of alkali elements, such as sodium and potassium, gives concrete a very high alkalinity (e.g., pH of 12 to 13). In fact, thermodynamic calculations reveal no corrosion of iron (steel) above pH 10 at room temperature.

2.

Uniform corrosion will tend to occur when some surface regions become anodic for a short period, but their location and that of the cathodic regions constantly change. For example, general corrosion/rusting of mild steel will occur when there is a uniform supply of oxygen available across the surface of the steel and there is a uniform distribution of defects in the oxide film as is usually the case in the non-protective films formed on unalloyed steel. In the absence of areas of high internal stress (e.g., cold-worked regions) or segregated zones (e.g., non-uniform distributions of sulfide inclusions), a number of anodic regions will develop across the surface. Some areas will become less active while new anodic regions become available. Therefore, overall attack takes place at a number of anodic sites whose positions may change, leading to general rusting across the surface.

If the supply of oxygen is not uniform across a surface, then any regions that are depleted in oxygen will become anodic as the case of moist sand in contact with the drywell steel. The remainder of the drywell surface including the embedded steel has oxygen available to it and therefore acts as a large cathodic area. When the cathodic area is larger, local attack will occur in the smaller anodic region. This phenomenon is referred to as differential aeration.

Therefore, due to the creation of a differential aeration cell, the adjacent carbon steel in contact with the moist sand bed acts as an anode that sacrifices itself to the benefit of the steel in the embedded region. That is, the corrosion of the sand cushion steel preferentially corrodes as galvanically coupled to the embedded steel." (Ref [37])

"Craters" identified in the sandbed region floors when the sand was initially removed were created during initial construction (pre-1969). (Ref [48])

" Measures taken to prevent water from entering the sandbed region and any further water intrusion into the area between the concrete and the external drywell shell are effective because they preclude "two of the four necessary fundamental parameters necessary for any form of corrosion to occur, an electrolyte, (i.e., moisture) and the cathodic reactant (i.e., oxygen), while only the lack of one fundamental parameter is sufficient to prevent corrosion. Sealing off the embedded steel prevents refreshment of moisture in the embedded region."

(Ref [37]) The ultrasonic measurements taken during the October, 2006 outage of a section of the drywell shell previously embedded on both sides since initial construction indicate the effectiveness of preventive measures in that, on average, in excess of 96% of the nominal wall remains in the embedded portion of the drywell shell immediately below the sandbed region.

Any oxygen trapped by the caulk sealant would most likely have been consumed and a thin protective oxide passive film would have been formed from contact with the highly alkaline concrete thereby minimizing further corrosion because "residual moisture will not support any subsequent corrosion once all the dissolved oxygen is consumed in the cathodic corrosion reaction. The cessation of the corrosion reaction will occur regardless of the presence of contaminants that may be dissolved in the water (e.g., chloride, sulfate, etc.) since although these impurities can affect the kinetics of the corrosion reaction, they do not participate in the cathodic reduction reaction. Once the cathodic reaction is stopped, corrosion is stopped. Intermittent wetting and aeration of the embedded steel would produce only minimal additional corrosion." In addition, "[t]he presence of concrete in contact with the embedded steel will mitigate corrosion even if sufficient moisture and oxygen are available due to the spontaneous formation of a thin protective oxide passive film on the embedded steel surface in the highly alkaline solution of the concrete. As long as this film is not disturbed, it will keep the steel passive and protected from corrosion." (Ref [37])

The sandbed floor was reshaped in 1992 to route water to the sandbed drains and away from the drywell shell and caulk sealant.

Continued inspections of the caulk sealant have confirmed its integrity.

mmmmmmm~~inm Section 7 Embedded External Drywell Shell Page 7-7 Section 8 Interior Embedded Drywell Shell Page 8-1 Appendix J, Type A testing confirmed the integrity of the drywell shell in the embedded region.

"In summary, AmerGen has extensively investigated drywell corrosion, including the embedded shell. A review of plant operating and industry experience indicates that corrosion of embedded steel in concrete is not significant because it is protected by the high alkalinity in concrete. Corrosion could only become significant if the concrete environment is aggressive. Historical data shows that the environment in the sand bed region is not aggressive, and thus any water in contact with the embedded shell is not aggressive. The data also shows that corrosion of the drywell shell in the sand bed region is due to galvanic corrosion and impurities such as chlorides and sulfates are not fundamentally involved in the corrosion anodic and cathodic reactions. Thus, only limited corrosion would be anticipated for the drywall embedded shell AmerGen has also committed to a comprehensive drywell corrosion-monitoring program for the period of extended operation. The program includes mitigative measures to prevent water intrusion into the sand bed region. The sand bed region concrete floor is sealed with epoxy coating. The junction between the sand bed region concrete floor and the drywell shell was sealed in 1992 to prevent moisture from impacting the embedded shell. Thus, additional significant corrosion of the embedded shell is not expected because of lack of moisture and depleted oxygen. AmerGen is committed to taking specific corrective actions, described in item 3 of Enclosure 1 to Ref. [39], prior to exceeding any design requirements, if water leakage is detected in the sand bed region drains.

For all of the above reasons, the corrosion rate for the embedded drywell shell is less than the corrosion rate of the sand bed region of the drywell shell. Also, direct monitoring of the drywell shell in the sand bed region adequately bounds any corrosion in the drywell embedded shell." (Ref [37])

This discussion addresses the potential for corrosion of the interior surface of the drywell shell that is embedded in the concrete floor inside the drywell (i.e., below the concrete floor at Elevation 10' 3"). See Figure 4 in Section 3 of this Enclosure. This area includes the shell behind the concrete curt6 at the edge of the concrete floor.

All elevations of the interior drywell shell were presumed to be coated with primer (except those areas to be embedded in concrete) that was applied following fabrication of the material to protect the steel prior to and during installation.

Part I, below, provides an overview of historic information pre-dating the October 2006 outage. The discussion in Part II sets forth information discovered and analyzed as a result of the October 2006 outage. Overall conclusions about the drywell, and its continued operation during the proposed twenty-year renewal term, are summarized in Part Ill.

I.

Historical Summary The drywell is described in Section 3 of this Enclosure. Figure 1 (Section 3) shows a cross-section of the drywell. Figure 4 (Section 3) shows an elevation view of the construction of the drywell foundation including the configuration of the Torus Room.

Figure 5 (Section 3) provides the details of the dryweal floor including the drainage trough located in the area under the reactor vessel (referred to as the Sub-Pile Room). The two areas addressed in this discussion are the embedded portions of the 1.154" thick section internal to the drywell and the 0.676" thick section at the bottom of the drywell all of which is embedded internally (See Figure 4 in Section 3). Section 6 of this Enclosure identifies the minimum required average general thickness of the 1.154" thick section as 0.736". Since the 0,676" thick section is completely encased in concrete, It is only required to contain the maximum drywell pressure (44 psig) and is not required to withstand buckling or membrane stresses. The minimum required thickness for this section required due to the maximum drywell pressure is 0.479" per Reference [42].

In 1986, as part of an ongoing effort at the Oyster Creek Generating Station to investigate the impact of water on the outer drywell shell, concrete was excavated at two locations inside the drywell (referred to as trenches) to expose the drywell shell below the Elevation 10' 3" concrete floor level to allow ultrasonic (UT) measurements to be taken to characterize the vertical profile of corrosion in the sand bed region outside the shell. The trenches (approximately 18 inches wide) were located in Bays 5 and 17 (See Figure 3 in Section 3 of this Enclosure) with the bottom of the trenches at Elevations 8' 9" and 9' 3" respectively (The elevation of the sand bed region floor outside the drywell is approximately 8' 11").

Following UT examinations in 1986 and 1988, the exposed shell in the trenches was prepped and coated and the trenches were filled with Dow Corning 3-6548 silicone RTV foam covered with a protective layer of promatic low density silicone elastomer to the height of the concrete floor (Elevation 10' 3").

At that time, it was expected that these materials would prevent water that might be present on the drywell concrete floor from entering the trenches. Before the 2006 outage (discussed in Part II below), these materials had not been removed from the trenches since 1988.

M M

=

-m-m--

==

-M m-- m m

Section 8 Interior Embedded Drywell Shell Page 8-2 Section 8 Interior Embedded Drywell Shell Page 8-3 During the preparation of a response to an NRC question (Ref [33]) during the Aging Management Review Audit, an internal memo was identified that indicated the intermittent presence of water in the two trenches inside the drywell. This was not an expected condition. That memo, dated January 3, 1995 was referenced in a 1996 Structural Walkdown Report but was not entered into the Corrective Action Process and was not considered as Operating Experience input to the Aging Management Program reviews.

Based on activities performed under the Structures Monitoring Program and IWE inspection program, and the reviews performed in support of the License Renewal Application, the water on the drywall floor and potentially inside the trenches was previously considered a temporary outage condition and not an operating environment for the embedded shell. However, in its response to an NRC Aging Management Review Audit question (Ref 133]), AmerGen committed to inspect the condition of the drywell interior shell in the trench areas and to evaluate any identified degradations prior to entering the period of extended operation (Commitment 27.5 in Ref. [39]). The results of these inspections and associated corrective actions are described In Section II below.

II.

Confirmatory Actions During the October 2006 Refueling Outage As noted above, AmerGen planned visual and ultrasonic (UT) inspections of the drywell shell in the trench areas during the 2006 refueling outage. The filler material in the trenches was removed and water was identified in the trenches (Bay 5 had 5 inches of standing water and Bay 17 had dampness but no standing water). (Ref: [47]) This condition was entered into the Corrective Action Process.

The presence of water in the trenches was indicative of water beneath the drywell floor surface, being in contact with both the drywell shell and drywell concrete. Following removal of the water from the trenches, visual inspections and UT measurements were performed in each trench. AmerGen has concluded (Ref. [47)) that most of the material loss occurred between 1986 and 1992 when sand and water remained in the sandbed region located adjacent to the exterior of the drywell shell and significant corrosion of the external shell was known to have occurred.

The following additional corrective/confirmatory actions related to the discovery of water in the trenches were taken during the October, 2006 Refueling Outage (Details may be found in Reference [47] transmitting a supplement to the License Renewal Application):

Walkdowns, drawing reviews, tracer testing and chemistry samples were performed to identify the potential sources of water in the trenches.

An engineering analysis was performed to evaluate the impact of the water on the drywell shell integrity.

Field repairs/modifications were Implemented to mitigate/minimize future water intrusion into the area between the shell and the concrete floor. These repairs/modifications consisted of (1) Repair of the trough concrete In the area under the reactor vessel to prevent water from potentially migrating through the concrete and reaching the drywell shell, (2) Caulking the interface between the drywell shell and the drywell concrete floor/curb to prevent water from reaching the embedded shell and (3) Grouting/caulking the concrete/drywell shell interface in the trench areas.

Additional concrete was removed from the Bay 5 trench to expose an additional 6 inches of drywell shell to allow visual inspection and UT measurements to be performed in the area of the shell that had been embedded in concrete (on both sides) until the 2006 outage.

III.

Conclusions An engineedng evaluation of the Oyster Creek inner drywell shell condition was prepared by a structural engineer and reviewed by an industry corrosion expert and independent third-party expert to determine the impact of the as-found water on the continued integrity of the drywell shell. The evaluation utilized water chemical analysis, visual inspections and UT examinations to conclude that the measured water chemistry values and the lack of any indications of rebar degradation suggest that the protective passive film established during concrete installation at the embedded steel/concrete interface is still intact and significant corrosion of the interior embedded drywell shell would not be expected as long as this benign environment is maintained. Therefore, since the concrete environment complies with the EPRI (Ref [30]) concrete structure guidelines, corrosion would not be considered "an applicable aging mechanism for nuclear power plant concrete structures and structural members" at Oyster Creek. The industry corrosion expert concluded that the water could remain in contact with the interior drywell shell indefinitely without adverse impacts.

More specifically, the results of this engineering evaluation indicate that no significant corrosion of the inner surface of the embedded drywell shell would be anticipated for the following reasons:

The existing water in contact with the drywell shell has been in contact with the adjacent concrete. The concrete is alkaline which increases the pH of the water and, in turn, inhibits corrosion. This high pH water contains levels of impurities that are significantly below the EPRI embedded steel guidelines action level recommendations. (See Section 7 of this Enclosure)

Any new water (such as reactor coolant) entering the concrete-to-shell interface (now minimized by repairs/modifications implemented during the 2006 outage) will also increase pH due to its migration through and contact with the concrete creating a non-aggressive, alkaline environment.

Minimal corrosion of the wetted inner drywell shell surface in contact with the concrete is only expected to occur during outages since the drywell is inerted with nitrogen during operations. Even during outages, shell corrosion losses are expected to be insignificant since the exposure time to oxygen is very limited and the water pH is expected to be relatively high. Also, repairs/modifications Implemented during the 2006 outage will further minimize exposure to oxygen.

Based on the UT measurements taken during the 2006 outage of the shell area in the trench in Bay 5 that has not been exposed since it was encased in concrete during initial construction (pre-1969), It was determined that the total

m

-I l

I m

Section 8 Interior Embedded Drywell Shell Page 8-4 Section 9 References Page 9-1 metal lost based on a current average thickness measurement of 1.113" versus a nominal plate thickness of 1.154" is only 0.041" (total wall loss for both inside and outside of the drywell shell). Although no continuing corrosion is expected, but conservatively assuming that a similar wall loss could occur between now and the end of the period of extended operation, a margin of 336 mils to the 0.736" required wall thickness would exist. Using a similarly conservative approach for the 0.676" embedded bottom head plate (0.479" required thickness for pressure retaining capability only as noted above) provides a margin of 115 mils to the end of the period of extended operation.

The engineering evaluations summarized above confirmed that the condition identified during the 2006 outage will not impact safe operation during the next operating cycle.

Also, a conservative projection (noted above) of wall loss for the 1,154 and 0.676 inch thick embedded shell sections indicates that margin is provided in both sections through the period of extended operation.

Although a basis is established that ongoing corrosion of the shell embedded in concrete should not be expected and repairs/modifications have been performed to limit or prevent water from reaching the internal surface of the drywell shell, AmerGen has now established that the existence of water in contact with the internal surface of the drywell shell and concrete at and below the floor elevation will be assumed to be a normal operating environment. Therefore, aging management reviews have now been performed and new aging management activities are being specified to confirm that corrosion that could impact the ability of the drywell shell to perform its design functions for the period of extended operation is appropriately managed (Details may be found in Ref. [47]).

Ref.

Document Document No.

Date VOLUME )

I Letter 5000-86-I 116, GPU to NRC, Oyster Creek Drywell Containment 12/18/86.

with attached SE No. 000243-002 Rev. 0 2

Restart Analysis Report - Drywell Analysis Sand Transition Zoone 2/9/87 3

GE Report No. 87-178-003, GE report "Corrosion Evaluation of the Oyster 3/6/87 Creek Drywell" Rev. I 4

Drawings a) 3E-SK-S-85, Drywell Plan Elev.

1'- 3" 1986 Plots 12/16/86 b) 3E-SK-S-89, Ultrasonic Testing Drywell Level 50' 2" & 87' 5" 10/16/87 c) 3E-SK-M-275, Ultrasonic Testing Drywell Level 50' 2" March 1990 4/8/90 d) 3E-SKM-358, Ultrasonic Testing Drywell Level 51' 10" April 1990 12/27/90 5

Memo, Oyster Creek Reactor Cavity Leakage 1/28/88 6

SE No. 328257-002, Temporary Repair of Reactor Cavity 10/19/88 7

TDR-85 1, Rev 0, Assessment of Oyster Creek Drywell Shell 12/27/88 8

Calculation C-1302-187-5300-005, "Statistical Analysis ofDrywell 1/31/89 Thickness Data Thru 12-31-88" Rev. 0 9

TDR-948, "Statistical Analysis of Drywell Thickness Data," Revision 1 2/1/89 10 Calculation C-1302-187-5300-01 I, "Statistical Analysis ofDrywell 6/13/90 Thickness Data Thru 4/24/90" VOLUME 2 11 IS-402950-001, "Functional Requirement for Augmented 10/4/90 Drywell Inspection," Rev. 0 12 TDR-1027, "Design ofa UT Inspection Plan for the Drywell Containment I1/1/90 Using Statistical Inference Methods," Rev. I 13 Letter 5000-90-1995, GPU to NRC, Oyster Creek Drywell Containment 12/5/90 14 Letter, GPU to NRC, Oyster Creek Drywell Containment, dated November 11/26/90 26, 1990 15 Calculation GE Index 9-3 "An ASME Section VIII Evaluation of Oyster 2/91 Creek Drywell for Without Sand Case Part I Stress Analysis" 16 Calculation GE Index 9-4 "An ASME Section VIII Evaluation of Oyster 2/91 Creek Drywell for Without Sand Case Part 2 Stability Aralysis"

M--

M M--

M M--

M-M-

M-Section 9 References Page 9-2 Section 9 References Page 9-3 Ref.

Document Document No.

Date 17 MPR Report 1275, Selection of Candidate Coatings and Steel 3/10/92 Cleaning/Preparation Methods for the Oyster Creek Drywell Exterior in the Sand Bed Area 18 MPR-TP-83161-00 l, Test Plan for Qualifying the Painting Process for the 6/19/92 Exterior Surface of the Drywell, Rev. 2 19 OC-MM-402950-010, "Cleaning and Coating the Drywell Exterior in the 7/29/92 Sand Bed Area," Rev. 0 20 MPR Report 1322 - Results of Painting Process Qualification Tests for the 8/7/92 Drywell Exterior in the Sand Bed Area at Oyster Creek, Rev. 0 VOLUME 3 21 Calculation C-1302-187-5300-021, "Statistical Analysis ofDrywell 8/26/92 Thickness Data Thrn May 1992" Rev. 0 22 Letter from H.S. Mehta (GE) to Dr. S. Tumminelli (GPU), "Sandbed Local 12/11/92 Thinning and Raising the Fixity Height Analyses (Line Items 1 and 2 in Contract # PC-0391407)"

23 SE No. 402950-011, "Clean and Coat Drywell Ext. in Sand Bed," Revision 1/5/93 2

24 NRC Letter, "Summary of May 5, 1993, Meeting with GPU Nuclear 5/17/93 Corporation (GPUN) to Discuss Matters Related to the Oyster Creek Drywell Corrosion Mitigation Program 25 Calculation C-1302-187-5300-028, "Statistical Analysis ofDrywell 12/2/94 Thickness Data Thni September 1994" Rev. 0 26 SE No. 000243-002, "Drywell Steel Shell Plate Thickness Reduction,"

8/2/95 Rev. 14 27 Calculation C-1302-187-8610-030, "Statistical Analysis ofDrywell 7/12/00 Thickness Data Thru September 1996" Rev. I 28 SE No. 320006-003, Application of Strippable Coating on Equipment Pool 8/16/00

& Rx Cavity Liner, Rev. 2 29 S. J~iggi, H. BOisni and B. Elsener, "Macrocell Corrosion of Steel in 10/1/01 Concrete - Experiments and Numerical Modeling," paper presented at Eurocorr 2001, Riva di Gardi, Italy 30 EPRI 1002950, "Aging Effects for Structures and Stnrctural Components 8/03 (Structural Tools), Revision I 31 Calculation C-t302:187-E3 10-037, Revision 2 (includes raw data) 6/10/05 Ref.

Document Document No.

Date VOLUME 4 32 Letter 2130-06-20289, Response to RAI 4.7.2-1 4/7/06 33 Response to NRC Aging Management Review Inspection Team Question 4/19/06 No. AMR-164 34 Response to NRC Aging Management Review Inspection Team Question 4/20/06 No. AMP-071

35.

Response to NRC Aging Management Review Inspection Team Question 4/20/06 No. AMP-210 36 NRC Letter, Summary of June 1, 2006 Meeting 6/9/06 37 Letter 2130-06-20353, Supplemental Information Related to the Aging 6/20/06 Management Program for the Oyster Creek Drywell Shell, Associated with AmerGen's License Renewal Application 38 Letter 2130-06-20354, Updated FSAR Supplement Information Supporting 6/23/06 the Oyster Creek Generating Station License Renewal Application 39 Letter 2130-06-20358, Additional Information Concerning FSAR 7/7/06 Supplement Supporting the Oyster Creek Generating Station License Renewal Application 40 Letter 2130-06-20360 (CB&I drawing 9-0971 sheet 1) 7/7/06 41 IS-328227-004, "Functional Requirements for Drywell Containment 9/15/06 Vessel Thickness Examination," Rev. 13 42 Calculation C-1 302-187-5320-024, "OC Drywell Ext. UT Evaluation in 9/21/06 Sandbed," Revision 1 43 Calculation C-1302-243-5320-071, Revision 2, "Drywell Thickness 9/21/06 Margins" 44 ACRS Subcommittee Transcript Excerpts 10/3/06 45 Letter 2130-06-20414, AmerGen Response to Open Items Associated with 10/20/06 the NRC Draft Safety Evaluation for the Oyster Creek Generating Station Application for License Renewal 46 Oyster Creek FSAR Section 3.8.2.8 Rev. 14 47 Letter 2130-06-20426, Information from October 2006 Refueling Outage 12/3/2006 Supplementing AmerGen Energy Company, LLC (AmnerGen) Application fora Renewed Operating License for Oyster Creek Generating Station 48 MNCR 92-0188, Sandbed Floor 12/28/92 49 MNCR 87-0240, Cavity Liner Defects 11/2/87

Exhibit ANC 3

Turnover 10/21/06 Night to 10/22/06 Day: JFOR to JGH Completed today

1. Completed computation to determine how long it would take the trickle of water from the 2 1/2 inch pipe into the 1-8 sump (measured at 200 ml/min) to fill the sump to 8 inches (7 gallons per inch sump capacity).

2. Completed Excel spreadsheet to compare the chemistry data from the latest chemistry samples of Reactor Water, Condensate, RBCCW and TBCCW with the six samples that were taken of water in the drywell (1-8 sump, CRD leakage, Trench in #5 Bay, DW Trough).

3. Completed Excel spreadsheet to document the inspections of the water in the Bay 5 Trench area. Activities concluded pending fluorescent dye test.

4. Completed computation to determine how much water was being removed from the Bay 5 trench based on the vacuum container being emptied at 1715 on 10/21/06. Based on 2 1/z inches of water in container and a capacity of 0.8 gallons per inch for the container, about 2 gallons of water was removed in a 30 minute period. A subsequent check based on a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, 23 minute period, about 1 1/4 inches of water was removed or 1 gallon. This indicates the rate of water flow into the trench has slowed (0.067 gpm for the first check versus 0.005 gpm for the second check).

5. Action Plan for fluorescent dye test drafted by Ralph Larzo. Sent to Chemistry (Michelle Mura and Leanne Birkmire) for review.

6. Provided Chemistry with AR Number A2133635 to document evaluation of fluorescent dye for use in tracer test (IR 545422 that documented the water in the trenches was completed and an AR could not be created under this IR per Rick Skelskey so A2133635 was used (C2013479 under this AR is for the UT inspection of the trenches.

Turnover to next shift

1. Maintain Communications requirements

2. Orientate Day Shift tomorrow to Status report on the K Drive, Engineer/1R21 Drywell Inspections/Specs Data Sheets/ Excel Spreadsheet with Status Report. E-mail in the morning to normal e-mail distribution from previous days.

3. Discuss documents list that Howie Ray asked Tom to put together and see what he still needs (Howie and I did not have time to discuss before he had to leave).

4. Check to see that chemistry samples results were received. They were supposed to go to Howie. I tried to get John Diletto on the phone to reroute to OC Chemistry but was not successful (left urgent message).

5. Confirm with EOM that scaffold was built to support inspections in upper areas of drywell and that Venture support was provided to lift scaffold at 23' elevation to support plate transition UT's.

6. Implementation of Tracer Test by Chemistry. Need observation of the trench at 15 minute intervals (need to determine who to do this).

OCLROO14242

Exhibit ANC 4

CORRO-CONSULTA 8081 Diane Drive Rudolf H. Hausler Kaufman, TX 75142 Tel: 972 962 8287 (office) rudyhau@msn.com Fax: 972 932 3947 Tel: 972 824 5871 (mobile)

MEMORANDUM To:

Richard Webster, Esq December 19, 2006 Rutgers Environmental Law Clinic Newark, NJ, 07102 From: Rudolf H. Hausler Corro-Consulta

Subject:

General Discussion of the Assessment of the Serviceability of the Oyster Creek Nuclear Generating Station Drywell Liner in Light of New Information Contained in recent AmerGen Submissions to the NRC and the ASLB.

I.

Background

The AmerGen Company, Operator of Oyster Creek Nuclear Generating Station (Oyster Creek), is applying for a license to allow continued operation of the 40-year-old Oyster Creek Plant for another 20 years. An integral and vital part of the operating license extension is the assessment of the integrity of the drywell liner, (the primary containment of the nuclear reactor}, and the assessment and monitoring of its aging management process. A number of concerns involving the integrity of the drywell had been discussed before (Ref. 1 - 6). In particular, the following notions had been brought forward:

• The integrity of the epoxy coating in the former sandbed area should not be assessed visually only since holidays and pinholes can hardly be expected to be seen in the confined space. Furthermore, it cannot be assumed that the rate of deterioration of an epoxy coating is "linear" with time, rather, once flaws have been initiated, the "cancerous area" grows exponentially, and the rate of such growth cannot be predicted. Hence much more frequent inspections must be planned. Standard methods for detecting pinholes and holidays had been put forth. Apparently, according to the newest information (see below), the anticipated life of the coating of 8 to 10 years, as specified by the vendor, was quite well predicted.

" There are various structural integrity criteria used to assess the continued serviceability of the drywell shell. Some relate to the average thinning over a given area and define a "buckling" limit. Others relate to localized pit penetration and define containment pressure limits. It was an objective of the

2006 refueling outage to assess the degree of deterioration, which may have taken place over the period of from 1996 to 2006, particularly in the former sandbed area. This new information coming forth from the 2006 NDT effort puts into question the entire corrosion monitoring data both new and historical. In particular, it has become quite clear now that the scope of the aging management as it applies to the drywell liner is totally inadequate.

• This is due to the fact that the floor inside the drywell has experienced significant standing water, the consequences of which need detailed discussion. AmerGen just recently recognized the fact that corrosion may have occurred on the inside embedded region defined as the region where the curb and the inside floor meet the drywell liner. Such corrosion would reinforce the outside bathtub ring (sandbed region) with an inside bathtub ring (essentially behind the curb) and significantly lower the margin of safety or negate it completely. The current monitoring scheme could not possibly assess these realities if in fact they were to exist.

" A second embedded region exists between the sandbed floor and the outside of the drywell liner. If the floor, the coating of the floor and the sealer at the crevice between the floor and the wall of the liner were in good condition corrosion in that embedded region would likely not be a concern. However, attempts to deal with the problem, as inept as they were, have not been able to resolve the question.

II.

General Comments There appears to be a tendency on part of AmerGen to present certain conditions and facts in milder terms (euphemisms) than had been done earlier and than reality truly merits. This contention is illustrated below with just one example of many:

0 It had been well established that after removal of the sandbed the sandbed floor had been found in a state of significant deterioration (Ref 7).

o The drainage channel, as shown in the drawing, was completely missing o Drain pipes were 6 to 8 inches above thefloor level and some were clogged o Thefloor was cratered with some craters adjacent to the shell. Afew craters were big, about 12 to 13feet long and 12 to 20 inches deep and 8 to 12 inches wide.

o Concrete reinforcement bars could be seen bare in many bays.

However, more recent characterizations of the sandbed floor following removal of the sand are: "concrete surface was found to be unfinished with improper provisions for water drainage" (Ref 8 pg 12 of 74) and "the sandbed floor was found to be cratered and unfinished" (Ref. 9 pg 4-3).

Clearly these latter characterizations of the sandbed floor do not exactly reflect the severity of the deterioration reported earlier. The concern with the 2

sandbed floor is important since it is the only direct indication one has regarding the possible aggressiveness of the water and the resistance of the concrete to breaking up (see discussion below)

To a large extent one also finds that monitoring work performed during various outages is presented as much more than it actually is in order to create the impression of great due diligence. Thus one reads for instance on pg 6-2 of Ref. 9 that "prior to applying the coating the entire surface of the outside of the drywell liner in the sandbed area was visually inspected to validate the UT thickness measurements previously made from inside the drywell, and to identify local areas thinner than the minimum average general thickness of 736 mils. 125 such areas were identified by visual inspection ". One has to ask the question how a man in a confined space of 15" wide, 3'3" high and several feet long can examine a surface visually and select areas of corrosion where the penetration would have been more than 0.415 inches. It stretches credulity particularly when in the end 125 such location were identified and they were all located in the sandbed area below the various vent lines, and in essence close to the areas of the measurements from the inside. Hardly a reflection of the random nature of corrosion.

" Additional instances of vague reporting or poorly substantiated conclusions will be discussed below. Suffice it to state here that the entire aging management plan as outlined by AmerGen for Oyster Creek, as extensive as it may appear, is poorly conceived, poorly executed, and the results are poorly interpreted.

III.

Details

1. The Embedded Areas AmerGen has recently recognized (or admitted to the fact) that corrosion of the embedded areas is at least a concern, if not a problem. There are three kinds of embedded areas where the drywell liner may be subject to corrosion. The first of these concerns the steel in contact with the concrete of curb and the inside drywell floor. This area is essentially at the same elevation as the sandbed area (see attached Fig. 1). The second embedded area focuses on the steel of the liner in contact with the concrete of the sandbed floor, i.e. the outside embedded area. The third, more general class of embedded steel surfaces are all those in contact with concrete of the foundations where intrusion of groundwater could lead to degradation of the concrete and subsequent corrosion.

In order to begin to deal with these questions two trenches were dug inside the drywell opposite bays 5 and 17. The depth of these trenches originally (in 1986) nominally reached to the elevation of the sandbed floor. In actuality the trench in Bay 5 was 2 inches below the nominal elevation of the sandbed floor while in Bay 17 the depth of the trench was two to 4 inches above the sandbed floor. At this time UT 3

measurements confirmed corrosion in the sandbed area (bathtub ring corrosion).

Specifically "measurements inside the trenches (579 individual UT measurements in the two trenches) showed that the reduction in shell thickness below the drywell concrete floor level (10'3") was no greater than indicated above the floor level". In order to fully understand this statement, please refer to Fig. 1. The UT measurements "above the drywell floor" made from the inside of the drywell (by means of the "grid") at the elevation of 11', i.e. at locations were the curb was lowered due to the attachment of the vent lines to the drywell liner. Inside the trenches, i.e. were the curb was the normal height of 2'3" corrosion could be assessed essentially over the full depth of the sandbed. Because these measurements reflected the measurements above the sandbed floor (see Fig. 1), the trenches were subsequently filled in with synthetic resin foam and covered up. No further measurements were made in the trenches until the outage of 2006.

In passing, I note that AmerGen did not present any discussion regarding corrosion of the shell from the inside of the drywell at the sandbed elevation.. This is likely because potential corrosion of the drywell liner on the inside opposite the sandbed region could not have been distinguished by UT measurements from the corrosion on the outside in the sandbed area. Second, the trenches at first were not deep enough to assess the outside embedded areas. However, in 2006 the trench in Bay 5 was dug deeper by 6 inches and would at that point in time have been 8 inches below the sandbed floor. While in 2006 a large number of measurements were made in both trenches, only average wall thicknesses were reported (see also pg 20 of Ref 8 -

0.041" loss in embedded region). The wall thickness below the sandbed floor was not separated out from the wall thickness in the sandbed region. Moreover, Bay 5 was and is the least corroded, and is not the one where the trench should have been deepened to assess the outside embedded area corrosion. As a consequence, one does at this point not have any valid information with respect to the corrosion of steel (containment of structural) in concrete embedded area.

In 2006, when the two trenches were opened again water was found in both of them.

It appears that there is enough leakage inside the inaptly named drywell to at times generate standing water. It is not known how high the water may get. However, it was found necessary to seal off the gap atop the curb where the concrete meets the steel of the inside of the drywell liner. (Much of the water may have been condensation running down the inside walls of the liner). Clearly, corrosion behind the concrete of the curb was reasonably being suspected. If in fact water had entered that gap the same type of differential aeration cell would have been formed and would have lead to corrosion rates comparable to the rates found in the sandbed. In fact a new bathtub ring might have formed a few inches below the top of the curb. The dangers of such a ring, we suggest are significant and AmerGen must conduct further UT testing to discover whether interior corrosion below the concrete curb is significant..

(It should be noted that all the measurements regarding the depth of the trenches relative to the sandbed floor are nominal, i.e. according to the drawings (Fig. 1).

Since it had been found that the sandbed drains were 6 to 8 inches above the floor one 4

might justifiably ask the question whether the floor was at the correct elevation to begin with. Data like these have never been properly verified even after the sandbed had been removed and the floor had been found to be in a bad condition.)

AmerGen of course realized lack of quantitative factual information regarding the embedded region and proceeded to structure an elaborate argument in order to demonstrate and "verify" that steel in contact with concrete will not corrode. This argument is based in essence on an EPRI advisory report (see Ref. 9 subref. 30). The EPRI report states: "The high alkalinity of concrete (pH>12.5) provides an environment around embedded steel and steel reinforcement which protects them from corrosion. If the pH is lowered to about 10 or less, corrosion may occur, however, the corrosion rate is still insignificant until a pH of 4 is reached. (Please note that the term insignificant has not been quantified and clearly depends on the expected life of the structure in question). A reduction in pH can be caused by leaching of alkaline products through cracks, the entry of acidic materials, or carbonation. Chlorides may be present in constituent materials of the original concrete mix (i.e. cement, aggregates, admixtures, water, etc.), or they may be introduced environmentally. The severity of corrosion is influenced by the properties and type of cement, and aggregates as well as moisture content (again, non of this terminology is quantified).

The aging effects due to corrosion of embedded steel (e.g. inserts, embedded plates, and channels, and steel reinforcements are visible concrete degradation and steel corrosion. The presence of corrosion products on embedded steel subjects the concrete to tensile stress that eventually cause hairline cracking, rust staining, spalling and more cracking".

Now EPRI specifies a water composition necessary for significant concrete degradation: pH < 5.5, Cr > 500 ppm, SW4 >1500 ppm. However, this limiting composition does not apply to corrosion as indicated above.

Analysis of the Facts: The water draining from the sandbed was analyzed in 1986 as follows: pH = 8.46, C1- = 45 ppb, and SW4 = 17 ppb. This is the only available analysis of sand bed water. Clearly this composition reflects highly "polished" water originating from steam generation. It is hard to believe that water, which has run down the outside of the drywell liner through the compressible material separating the drywell liner from the reactor housing, which material is said to a magnesium oxy chloride, should not contain chlorides in at least the ppm range if not hundreds of ppm. In the absence of duplicate analysis it may be fair to suggest that this analysis is atypical. We believe it to be because the corrosion rate of the drywell liner in the sandbed area was of the order of tens of mpy varying from bay to bay prior to the application of the epoxy coating, hence quite outside EPRI's characterization of "low". Furthermore, the concrete floor in the sandbed region clearly was more than just unfinished. Along with the sand copious corrosion products were removed as well. It may be argued that these originated from the outside of the liner exclusively, however, it is clearly stated that rebar was exposed.

5

Now it may be quite possible that indeed the floor was "unfinished". Meaning that that theconcrete after pouring had not been properly degassed and that therefore crevices and craters remained and rebar remained exposed because a) concrete was poured short or b) rebar was built up to high. We think the former may be the case because it has also been said that the drains in the sand bed were several inches above the floor. Nevertheless, there were cracks and craters and crevices observed, some rather large and located between the concrete and the liner. First, we know that the water was corrosive, second we can reasonable infer that the rebar corroded as well and caused the concrete to spall, and third, water in the crevices near the drywell liner would have caused corrosion in the embedded area.

AmerGen brings forth a convoluted argument to demonstrate that this should not have happened. First, Amergen explains correctly that the drywell liner in the sandbed region corroded because of a differential aeration cell in which the oxygen starved area becomes anodic and corrodes while the cathodic reaction occurs at the oxygen rich area, i.e. outside the sand bed. Now, the cracks in the embedded area are at the lowest level of the sandbed and hence most oxygen starved and should therefore corrode the most. However, AmerGen maintains that the embedded areas were "somehow protected by the anodic reaction in the sandbed area". The reason why possibly corrosion in the crevices in the embedded areas may have been less than in the region of the bathtub ring is related to the conductivity of the water present. At low conductivity of the water in the sand bed, the differential aeration cell would have been confined to the top of the sand bed. However, a gradual decrease of the extent of the corrosion attack with'increasing depth in the sandbed has not been demonstrated. Rather, there are indications that the corrosion rate (pitting rate) was evenly distributed over the height of the sandbed.

Therefore, there remains great uncertainty with respect to the extent of the corrosion attack in the embedded region of the drywell below the sandbed floor, and therefore great uncertainty with respect to the integrity of that part of the drywell liner.

There are other embedded areas, which are of some concern. These deal with the possible intrusion of groundwater toward the lower part of the drywell. The groundwater analysis indicates that the pH is of the order of 5.6 to 6.4 with low chlorides (3 to 138 ppm) and low sulfates (7 - 73 ppm). On the face of it this water is certainly corrosive toward carbon steel, but probably only mildly aggressive toward concrete.

In discussing the impact of this (these) analysis one needs to also take into consideration a number of facts:

The plant started operating in 1968 and was no doubt designed under specifications and guidelines predating the start-up date. These guidelines have changed over the 40 years past. It is therefore inappropriate in our opinion to quote a 2003 EPRI document with respect to water quality and its 6

aggressiveness upon concrete structures without at the same time presenting the nature of the concrete with which the water is in contact. Reason: concrete specifications have changed as well over the past 40 years. The emphasis on monitoring ground water composition must be matched with emphasis on the chemical composition of the concrete. 40 years ago nobody could predict the deterioration of a given concrete structure in contact with a given water composition 40 years into the future, let alone 60 years.

AmerGen is well aware of these difficulties. For this reason AmerGen attempts to demonstrate that a) the groundwater is not aggressive to the below ground level concrete structures, and b) that there is virtually no possibility for groundwater to reach the embedded steel structures. However, in reading the protracted arguments we find them studded with unsubstantiated assumptions.

The real concern here is that if indeed the concrete structures surrounding the lower part of the drywell liner and the foundations on which the entire housing rests were in equally poor condition as the sandbed floor had been found in, then all arguments toward water not being able to penetrate the concrete barrier and reach the embedded steel structures would be voided.

AmerGen has argued that water in contact with concrete would become alkaline and that "thermodynamic calculations demonstrate that iron cannot corrode in the region of pH 12". This argument is patently false. A review of the Pourbaix Potential diagram for iron (standard in the industry) shows clearly the opposite. In fact detailed studies by Lorenz and others in Germany and Denmark have shown that the O-ion catalyses the corrosion reaction.

The fact that the corrosion reaction rate decreases at higher pH is based on the formation of a corrosion product layer (rust - iron oxide - iron oxy-hydroxide

- or wustite) and it is the inherent protectiveness of these layers which governs the corrosion rate.

In conclusion it must be said that very little, if nothing, is known about the integrity of the embedded regions (both concrete and steel). AmerGen has taken the approach of arguing themselves out of any concerns using at times questionable assumptions.

However, what little facts are available would indicate that the concrete surrounding the below grade steel structures is not in the best of conditions.

2. The Epoxy Coating in the Former Sandbed Area After the removal of the sandbed the sandbed floor was "built up" and then both the floor and the drywell liner in that are were coated with epoxy. Indications are that the "build-up" of the floor was accomplished with the same epoxy product as later the coating. It is hard to understand how 6 to 8 inches of epoxy coating were applied to the floor in order to bring the floor level up to the lever of the drains.

Prior to applying the coating, extensive test were conducted in order to determine the, best method of application which would result in about a 10 mil coat with a minimum of holidays, cracks, and/or blisters. While during these extensive tests test panels were routinely examined for pinholes etc. Surprisingly there does not seem to be any 7

documentation to such examination once the coating had been put in place in the former sandbed region.

The coating, being a primary barrier to continued corrosion in the sandbed area, was an important part of the aging management and was "visually inspected" at intervals during refueling outages. All reports indicated that the coating was in pristine condition. On December 3, 2006 AmerGen reports to the NRC (Ref. 8, pg. 13 of 74) that the VT-1 inspection program would have documented any flaking, blistering, peeling, discoloration, and other signs of deterioration of the coating. The VT-1 inspections (during the 2006 outage) found the coating to be in good condition with no degradation.

However, in the submission to the ACRS (Ref. 9 pg. 7-3) AmerGen states that:

"AmerGen observed in 8 of 10 Bays separation/cracking of the floor epoxy coating". The comments continue to say that: "these areas had no impact on the exterior drywell shell epoxy coating or the caulk seal between the drywell shell and the sandbed floors because the cracks were in areas of the floor away from the shell".

Now the sandbed floor is only 15" wide. Even if the cracks/separation in the coating were removed from the wall, it is not a stretch of the imagination that water seepage in the cracked concrete to the drywell wall most certainly did take place. However, AmerGen did not concern itself with this possibility.

December 19, 2006 8

References

1. Memorandum: Corro-Consulta to Paul Gunter, President NIRS, Nov. 10, 2005, Oyster Creek Drywell Liner Corrosion

2. Memorandum: Corro-Consulta to Paul Gunter, November 12, 2005, Outlines areas of concern re. drywell liner corrosion, not heretofore emphasized.

3.

Memorandum: Corro-Consulta to Richard Webster, Esq., March 16, 2006, Oyster Creek Drywell Corrosion, Additional Evidence for Continued Corrosion

4. Memorandum: Corro-Consulta to Richard Webster, Esq, June 9, 2006, Statistical Analysis ofAmergen-Exelon UT Data; Drywell Corrosion

5. Memorandum: Corro-Consulta to Richard Webster, Esq., June 12, 2006, Discussion of Corrosion Monitoring Methodologies At Oyster Creek Nuclear Plant Drywell

6. Memorandum: Corro-Consulta to Richard Webster, Esq., June 22, 2006, Discussion of Corrosion Monitoring Methodologies At Oyster Creek Nuclear Plant Drywell.

7. Letter: GPU Nuclear Corp to NRC, Sept. 15, 1995, Drywell Corrosion Monitoring Program.

8.

Letter: AmerGen to US NRC, Dec. 3, 2006; Information from October 2006 Outage Supplementing AmerGen Energy Company, LLC (AmerGen) Application for Renewed Operating License for Oyster Creek Generating Station (TAC No.

MC 7624)

9. ACRS Information Package, Submitted by AmerGen to NRC Dec. 8, 2006 9

Schematic Cross Section through Sandbed Area (not to size)

Dimensions of Sandbed Area 15" by 3'3 1/4" IFigure 1 I

Concrete 20 " Diameter Access Hole through concrete containment for Sandbed removal Area of UT Measurements Below and to the Side of Vent Lines about 6" to 8" Sandbed Floor Elev. 8'11 3/4" 1

10

Exhibit ANC 5

• • • ACTION REQUEST ***

PAGE:

04 A/R TYPE

CM ECR A/R NUMBER : A2152754 REQUEST ORG : OED A/R STATUS : ASIGND REQUEST DATE: 21OCT06

-STATUS DATE: 230CT06 REQUESTED BY: TAMBURRO LAST UPDATE:

25OCT06 PRINT DATE 25OCT06 EVALUATION NBR:.

01 EVALUATING ORG:

OEDM EVAL ASIGND TO:

TAMBURRO, PETE

-EVAL REQUEST ORG: OEDM EVAL REQUESTOR:

RAY, H

EVAL RETURNED BY: HUTCHINS, SP ORIG DATE ASSIGNED:

EVAL DUE DATE: 23OCT06 DATE ASSIGNED:

220CT06 EVAL STATUS

RETURN IMPORTANCE CODE:

OEAP:

SCHEDULE CODE:

DATE FIXED:

EVAL. DESC: DETERMINE PROPER SEALANT FOR DW SANDBED FLOOR VOIDS TANG 230CT06' DETERMINE/EVALUATE THE PROPER FILLER (SEALER,

CAULK, ETC)

TANG 23OCT06 MATERIAL TO USE ON THE VOIDS/SEAMS IN THE DW SANDBED BAYS TAN0 23OCT06 AS DESCRIBED IN IR/AR # 00546932.

TANG 230CT06 TANG 230CT06 TANG 230CT06 THE SUBJECT EVALUATION (QUESTION)

REQUIRES TECHNICAL PXTO 23OCT06 (DIRECTION,

GUIDANCE, INTERPRETATION, EVALUATION)

TO BE PXT0 23OCT06 GIVEN TO THE REQUESTOR (MAINTENANCE).

AS SUCH, THE PXTO 230CT06 RESPONSE WILL BE TREATED AS A TECHNICAL EVALUATION IAW PXT0 23OCT06 PROCEDURE CC-AA-309-101.

PXTO 230CT06 PXTO 22OCT06 THE RESOLUTION OF THIS TECH EVAL WAS REVIEWED IN

'TAN0 23OCT06 ACCORDANCE WITH HU-AA-1212 AND FOUND TO HAVE A RISK PXTO 23OCT06 RANK OF 3.

THEREFORE A THIRD PARTY REVIEW BY AN PXTO 230CT06 INDUSTRY COATING EXPERT IS RECOMMENDED.

PXTO 230CT06 PXTO 23OCT06 A. REASON FOR EVALUATION / SCOPE:

PXTO 230CM06 PXTO 230CT06.

-DURING VISUAL INSPECTIONS OF THE DRYWELL VESSEL PXTO 23OCT06 EXTERIOR COATING IN THE SANDBED REGIONS (BAYS 1.7,9.&15)

TANG 230CT06 AREAS WERE OBSERVED TO HAVE SEAMS/VOIDS.

SPECIFICALLY, PXTO 230CT06 THE AREAS WHERE THE EPOXY COATING REPAIRS WERE APPLIED PXTO 230CT06 TO THE ORIGINAL CONCRETE FLOOR-OR THE SIDE OF THE PXTO 230CT06 BIOSHIELD'HAVE SEPARATED IN SPOTS.

TO PREVENT WATER

'PXTO 23OCT06 FROM SEEPING UNDER.THE EPOXY, AN EXPANDABLE FILLER

-PXTO 23OCT06 MATERIAL IS REQUIRED FOR THE SEAMS/VOIDS.

PXTO 23OCT06 PXTO 230CT06 THE SCOPE OF THIS TECH EVAL IS-TO PROVIDE GUIDANCE ON PXTO 230CT06

-FILLING THE SUBJECT SEAMS/VQIDS.

PXTO 23OCT06 PXTO 23OCT06 B. DETAILED EVALUATION:

PXTO 23OCT06 PXTO 23OCT06 IN 1992, THE EPOXY COATING WAS APPLIED TO THE FLOOR IN PXT0 23OCT06

-AREAS WHERE IT WAS UNEVEN.

SO THAT ANY WATER ENTERING PXT0 230CT06 THE SANDBED WOULD FLOW AWAY FROM THE VESSEL AND BE PXTO 230CT06 ROUTED TO THE DRAINS.~- SINCE-1996,.i -INSPECTIONS HAVE PXTO,.23OCT06 FOUND INDICATIONS OF THE EPOXY SEPARATING FROM THE PXTO 23OCT06 CONCRETE.

THIS SEPARATION COULD BE CAUSED BY THE PXT0 23OCT06 CONCRETE SWELLING (EXPANDING AND CONTRACTING)

OVER PXTO 23OCT06 TIME.

PXTO 23OCT06 PXTO 23OCT06 OCLROO14655

• • • "ACTION REQUEST ***

PAGE: 05 A/R TYPE

CM ECR A/R NUMBER : A2152754 REQUEST ORG : OED A/R STATUS ASIGND REQUEST DATE: 21OCT06 STATUS DATE: 230CT06 REQUESTED BY: TAMBURRO LAST UPDATE: 25OCT06 PRINT DATE.: 25OCT06 THE DRYWELL IS CLASSIFIED 0 (SAFETY RELATED).

THE PXTO 230OCT06 CONCRETE FLOOR IN QUESTION DOES NOT HAVE A SAFETY RELATED TANO 230CT06 FUNCTION.

THE FUNCTION OF THE FLOOR IS TO ROUTE WATER PXTO 230CT06 THAT MAY ENTER THE SANDBED TO THE FIVE EQUALLY SPACED.

PXTO 230CT06 DRAIN LINES AND KEEP THE WATER AWAY FROM THE DRYWELL PXTO 230CT06 VESSEL.

TANO 230CT06 PXT0 230CT06 THE SEPARATED SEAMS-COULD POTENTIALLY ALLOW SOME WATER' PXTO 230CT06 TO GET UNDER THE EPOXY COATING REPAIR.

PLEASE NOTE PXTO 23OCT06-INSPECTION OF THESE BAYS SHOWS NO DEGRADATION DRYWELL PXTO 23OCT06..

VESSEL COATING-OR THE CAULKING BETWEEN THE VESSEL PXTO 230CT06-

• COATING AND THE FLOOR.

SEPARATED SEAMS ARE LOCATED PXTO 230CT06

" AWAY FROM THE DRYWELL VESSEL AND ARE LOCATED NEAR PXTO 230CT06

.CONCRETE BI0 SHIELD.

PXTO 230CT06 TAN0 23OCT06 THE EPOXY THAT WAS USED IN THE EARLIER REPAIR IS DEVRON PXTO 23OCT06__

184 EPOXY COATING-WITH A PXTO 230CT06 DEVOE. PREPRIME 167 SEALER.

PXTO 230CT06 PXTO 23OCT06 BASED ON THE CONDITIONS AND MATERIALS, THE TAN0 23OCT06 RECOMMENDED FILLER SEALANT TO USE IS SIKAFLEX PXTO 230CT06 TEXTURED SEALANT.

THIS PRODUCT IS RECOMMENDED BY THE PXTO. 230CT06 WILLIAM COATINGS.GROUP AND IS TYPICALLY USED TO SEAL PXTO.23OCT06 CONCRETE TO EPOXY JOINTS.

PXTO 23OCT06 PXTO 23OCT06 THE SEALANT SHALL BE APPLIED PER THE MANUFACTURERS PXTO 230CT06

-INSTRUCTIONS.

ATTACHED IS THE TECHNICAL DATA SHEET FOR PXTO 23OCT06 THE PRODUCT (SEE EVAL ATTACHMENT.1).

TAN0 230CT06____

ALSO ATTACHMENT 2 PROVIDES THE MSDS SHEET FOR THE PXT0 23OCT06 PRODUCT.

PXTO 230CT06 TANO 230CT06 AS PER ENGINEERING STANDARD ES-027, THE ENVIRONMENTAL PXTO 23OCT06

-PARAMETERS OF THE DRYWELL (ZONE 1) ARE AS FOLLOWS:

PXTO 23OCT06 PXTO 23OCT06

-1) NORMAL PLANT OPERATING:

PXTO 23OCT06 AGING TEMP= 139.DEG F-PXTO 230CT06 RADIATION = 20 E06 RADS PXTO 23OCTO6 HUMIDITY 50%

PXTO 23OCT06 PRESSURE = 16 PSIA PXT0 23OCTO6 PXTO 230CT06

2)

DESIGN BASIS ACCIDENT; PXTO 23OCTO6 AGING TEMP = 317 DEG F PXTO 23OCT06 RADIATION = 32 E06 RADS PXTO 23OCT06 HUMIDITY = SUBMERGENCE PXTO 23OCT06 PRESSURE = 53.1 PSIA PXTO 23OCT06 PXTO 23OCT06

• . THE TECHNICAL-DATA SHEET (ATTACHMENT 1) INDICATES THAT PXTO 23OCT06 SEALANT IS ACCEPTABLE FOR A SERVICE RANGE OF -40F TO PXTO 2-OCT06

.170F AND IS WHETHER RESISTANT.

THEREFORE THE SEALANT PXTO 23OCT06, WILL NOT DEGRADE OVER TIME DUE TO TEMPERATURE AND TANO 230CT06 HUMIDITY.

THE SEALANT IS NOT REQUIRED TO*PERFORM ITS PXTO 23OCT06 FUNCTION DURING THE DESIGN BASIS ACCIDENT.

THEREFORE PXTO 23OCT06 OCLROO014656

• • • ACTION REQUEST ***

PAGE: 06 A/R TYPE

_CM ECR A/R NUMBER : A2152754 REQUEST ORG 0ED A/R STATUS : ASIGND REQUEST DATE: 21OCT06 STATUS DATE: 230CT06 REQUESTED BY: TAMBURRO LAST UPDATE: 25OCT06 PRINT DATE 25OCT06 THE DESIGN BASIS ACCIDENT PARAMETERS-IN ES-027 ARE'NOT PXTO 230CT06 APPLICABLE.

PXTO 230CT06 PXTO 230CT06

..THE MATERIAL IS A POLYURETHANE BASED PRODUCT MATERIAL PXTO 230CT06 AND IS EXPECTED TO HOLD UP WELL UNDER ABOVE NORMAL PXTO 230CT06 OPERATING'RADIATION EXPOSURE.

PXT0 230CT06 TANO 230CT06 C-CONCLUSION I FINDINGS:

PXTO 230CT06 PXTO 230CT06

-BASED ON THE.ABOVE.EVALUATION, SIKAFLEX TEXTURED PXTO 230CT06 SEALANT IS AN ACCEPTABLE FILLER MATERIAL FOR THE PXTO 23OCT06' SEPARATIONS/VOIDS IN THE BAYS.

PXTO 230CT06 TANO 230CT06 IT IS NOTED THAT THE SIKAFLEX TEXTURED SEALANT IS TANO -23OCT06 DESIGNED FOR ALL-TYPES OF JOINTS, WHERE THE MAX AND'MIN TANO 23OCT06 DEPTHS DO NOT EXCEED 1/2" OR 1/4" RESPECTIVELY.

ANYTHING, TANO-23OCT06

-BEYOND THESE VALUES HAS THE POTENTIAL OF DEGRADING.

TAN0 230CT06 PXTO 230CT06 LIMITATIONS ARE AS FOLLOWS:

PXTO 23OCT06 TANO 23OCT06

1) AFFECTED AREAS ARE PROPERLY PREPPED AS STATED ABOVE.

PXTO 230CT06

2)

APPROPRIATE CURE TIMES ARE ADHERED TO.

PXTO 230CT06

3)

THE SEALANT IS APPLIED PER THE MANUFACTURERS PXTO 230CT06 INSTRUCTIONS..

TANO 23OCT06 PXTO 23OCT06 NOTE:

A REVIEW OF CC-AA-102 DETERMINED THAT THE PXTO 230CT06 ACTIVITY DOES NOT IMPACT THE CONFIGURATION OF THE PXTO 230CT06 SANDBED.

THE APPLICATION OF THE SEALANT IS A PREVENTIVE PXTO 23OCT06 MAINTENANCE MEASURE TO ENSURE THE EPOXY GROUT WILL NOT PXTO 230CT06 DEGRADE-OVER TIME.

PXTO 23OCT06 PXTO 23OCT06 D.

REFERENCES:

PXTO 230CT06 PXTO 230CT06

1) IR/CR

• 00546932 PXT0 230CT06

2) ENG STD ES-027 REV.4 PXTO 230CT06

3)

SPECIFICATION # SP-1302-32-035 REV.

0 PXTQ 230CT06 PXTO 23OCT06.

E.

LIST OF ATTACHMENTS (TO BE CMT'D WITH EVAL TO RM):

TANU.230CT06 PXTO 23OCT06

1) SIKAFLEX PRODUCT DATA SHEET (2

PAGES)

PXTO 230CT06

.2) SIKAFLEX MSDS SHEET (5 PAGES)

PXTO 230CT06 PXTO 23OCT06 RESPONSE PREPARED BY: PETE TAMBURRO PXT0 230CT06-CO-PREPARED BY:.TEDD NICKERSON 10/23/06 TANO 230CT06 TANO 230CT06 S-** * ******* ******************************** ********

TAN0 230CT06 INDEPENDENT REVIEWER BY,: HOAT HO (TMI) 10/23/06 HDHO 240CTO6 HDHO 240CTO 6 THE TECH.

EVAL WAS REVIEWED TO DETERMINE WAS HUHO 240CT06 CORRECT INPUT USED.

THE RESULTS ARE REASONABLE.

HDH0 24OCTO6 ANY CONCERNS WERE DISCUSSED WITH CO-ORIGINATOR OF THIS HDH0 240CTO6 TECH.

EVAL AND RESOLUTIONS HAVE BEEN INCORPORATED.

HDHO 240CTO 6 OCLROO14657

• • • ACTION REQUEST **

PAGE: 01 A/R TYPE CM ECR A/R NUMBER : A2152754 REQUEST. ORG : OED A/R STATUS : ASIGND REQUEST DATE: 21OCT06 STATUS DATE: 230CT06 REQUESTED BY: TAMBURRO LAST UPDATE:

25OCT06 PRINT DATE : 25OCT06 VERIFIER CONCURS WITH ORIGINATOR.

HDH 240CT06 BASED ON THIS EVALUATION, THE TECH.EVAL.

IS VERIFIED TO HDHO 24OCT06 BE ACCEPTABLE HDHO 24OCT06 HDHO 24OCT06 THIS TECH EVAL WAS REVIEWED BY JON CAVALLO (THIRD PXTO 24OCT06 PARTY REVIEW)

AND FOUND TO BE ACCEPTABLE.

ATTACHMENT PXTO 24OCT06 3 PROVIDES AN EMAIL DOCUMENTING HIS REVIEW.

PXTO 240CT06 SPHI 250CT06 THIS TECHNCIAL EVALUATION HAS BEEN REVIEWED AND APPROVED SPH1 250CT06 BY ENGINEERING MANAGEMENT.

IT MEETS THE REQUIREMENTS OF SPHI 25OCT06 CC-AA-309-101 AND HU-AA-1212.

S.

HUTCHINS (10/25/06)

SPHI 250CT06 7

OCLROO014658

Exhibit ANC 6

REE*Z,.

UNITED STATES 0%

NUCLEAR REGULATORY COMMISSION REGION I 475 ALLENDALE ROAD XKING OF PRUSSIA, PA 19406-1415 November 9, 2006 Mr. Richard Webster Staff Attorney Rutgers Environmental Law Clinic 123 Washington Street Newark, NJ 07102

Dear Mr. Webster:

In an e-mail dated September 26, 2006, addressed to Michael Modes, Team Lead for the Oyster Creek License Renewal Inspection, you posed a number of questions about the integrity of the former sandbed area of the Oyster Creek drywell. Information related to this subject can be found in NRC Inspection Report 05000219/2006007, dated September 21, 2006 (ADAMS Accession No. ML062650059) and the NRC "Safety Evaluation Report With Open Items Related to the License Renewal of Oyster Creek Generating Station" issued in August 2006 (ADAMS Accession No. ML062300330). In addition, you were present at the public exit meeting concerning this inspection, which was held on September 13, 2006, in Lacey Township, NJ, during which this subject was discussed and you asked numerous questions.

The following responds to your September 26 e-mail.

The subject of emptying of the sandbed drain collection bottles (i.e., 5 gallon poly bottles or jugs) during the March 2006 license renewal inspection was discussed in the September 21, 2006 Inspection Report, on pages 23-24. During the inspection, the NRC inspection team overheard an Amergen technician talking about clearing the torus room for the NRC walkdown and emptying some bottles of water he found. Amergen told the NRC that a member of Amergen's staff was sent into the torus room, on the day before the NRC inspection team entered, in order to make sure the area was safe for the NRC team inspection walkdown. The Amergen staff took it upon themselves to empty the collection bottles into the floor drains provided for the purpose of catching water overflow, before the team entered the torus room.

The overflow drains route liquid to the sump where it is then processed.

Because the bottles were emptied prior to any sampling or analysis, the source of the water was not determined and there was no determination about whether the water contained any radioactivity. The team inspected the bottles during their walkdown and noted there was no evidence of overflow from the bottles because there were no water stains or residue on the floors around the bottles. The technician responsible for emptying the bottles was asked about over-flow and indicated that only two of the five bottles were filled with water, and that no water was flowing out of the filled bottles.

During the NRC walkdown of the torus room, the NRC determined there was no discernable residue that could be analyzed. The NRC examined the bottles and concluded the high heat in the room dried the water bottles such that no usable residue was present. In addition, during the torus room walkdown, the NRC noted that, in one location, water was leaking from the

2 ceiling onto the torus. Amergen indicated that this leak was from a known condenser leak in the room above.

As noted in our inspection report, Amergen indicated that the bottles were improperly emptied without measurement or analysis and that it was unable to locate any documentation that showed prior surveillance of the water drains had been completed. Amergen also took corrective actions to ensure that, in the future, the drains would be monitored.

The NRC did evaluate the incident for enforcement action based on the commitment made by the licensee in 1996 to monitor leakage from the former sandbed drains. Using the guidance contained in NRC Manual Chapter 612 "Significance Determination Process," Appendix A (www.nrc.gov/reading-rm/doc-collections/insp-manual/manual-chapter/index.html),

we determined this was a performance deficiency of minor significance because the performance deficiency had no impact on the safe operation of the plant. The failure to fulfill a commitment is not, by itself, a violation of our regulations. As noted in our inspection report, the performance deficiency related to the monitoring of leakage from the former sand bed region of the drywell was deemed not to be safety significant and was entered into the applicant's ongoing corrective action system.

Ten bays in the former sand bed region of the drywell were excavated and coated with an epoxy paint in 1992. Although Amergen has been performing regular visual inspections, prior to October 2006, five of the bays had not been visually inspected, but were inspected during the October 2006 outage. Each inspection is performed by an individual trained and qualified for visual inspection who enters the sand bed cavity. This individual inspects all accessible areas of the surface and documents the results of the survey. The NRC does not have a schedule of the inspections performed by Amergen prior to October of 2006 and has not received any Amergen reports or data related to these prior inspections.

As noted in our report, the NRC inspection of Amergen's aging management programs, including for the sand bed region, was conducted in accordance with NRC Manual Chapter 2516 and NRC Inspection Procedure 71002. The results of that team inspection are documented in Inspection Report 05000219/2006007, and are not based on the expertise of one individual.

The NRC continues to evaluate Amergen's proposed aging management programs related to the sand bed, including the embedded region. NRC staff conclusions about Amergen's aging management programs for the drywell shell will be included in the Safety Evaluation Report that is scheduled to issue in December 2006.

I trust that you will find this information responsive.

Sincerely, Richard J. Conte, Chief Engineering Branch 1