ML091900037

2009/06/24 PINGP Lr - PINGP Letter Responding to Refueling Cavity Leakage RAIs and Revising Vessel Internals Program Commitment

ML091900037
Person / Time
Site:	Prairie Island
Issue date:	06/24/2009
From:	- No Known Affiliation
To:	Division of License Renewal
References
Download: ML091900037 (64)

Text

1 PrairieIslandNPEm Resource From: Vincent, Robert [Robert.V incent@xenuclear.com]

Sent: Wednesday, June 24, 2009 5:44 PM To: Plasse, Richard; Goodman, Nathan Cc: Eckholt, Gene F.

Subject:

PINGP Letter Responding to Refueling Cavity Leakage RAIs and Revising Vessel Internals Program Commitment Attachments:

20090624 Response to Follow-up RAI B2.1.38 & Commitment Change.pdf; 20090624 Response to Follow-up RAI B2.1.38 & Commitment Change.docAttached are pdf and WORD copies of a letter responding to the latest Refueling Cavity leakage Follow-up RAIs and changing the PWR Vessel Internals Program as we discussed in the June 10 telecon. The letter was signed out today.

Let me know if you have any problems with the files.

Bob Vincent Licensing Lead, License Renewal Project 651-388-1121 X7259 (office)

651-267-7207 (fax)

Hearing Identifier: Prairie_Island_NonPublic Email Number: 1068 Mail Envelope Properties (9FA1D9F2F220C04F95D9394E3CF02DAB013A72F9)

Subject:

PINGP Letter Responding to Refueling Cavity Leakage RAIs and Revising Vessel Internals Program Commitment Sent Date: 6/24/2009 5:43:47 PM Received Date: 6/24/2009 5:43:53 PM From: Vincent, Robert Created By: Robert.Vincent@xenuclear.com Recipients: "Eckholt, Gene F." <Gene.Eckholt@xenuclear.com> Tracking Status: None "Plasse, Richard" <Richard.Plasse@nrc.gov> Tracking Status: None "Goodman, Nathan" <Nathan.Goodman@nrc.gov>

Tracking Status: None Post Office: enex02.ft.nmcco.net

Files Size Date & Time MESSAGE 413 6/24/2009 5:43:53 PM 20090624 Response to Follow-up RAI B2.1.38 & Commitment Change.pdf 462442 20090624 Response to Follow-up RAI B2.1.38 & Commitment Change.doc 421440 Options Priority: Standard Return Notification: No Reply Requested: No Sensitivity: Normal Expiration Date: Recipients Received:

1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1121 June 24, 2009 L-PI-09-082 10 CFR 54 U S Nuclear Regulatory Commission

ATTN: Document Control Desk

Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306

License Nos. DPR-42 and DPR-60 Response to NRC Request for Additional Information Regarding Application for Renewed Operating Licenses By letter dated April 11, 2008, Northern States Power Company, a Minnesota Corporation, (NSPM) submitted an Application for Renewed Operating Licenses (LRA) for the Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2. During the Aging Management Audit, the NRC was briefed on water seepage from the refueling cavity

into the containment sumps that had been detected during refueling outages. In a letter dated November 5, 2008, the NRC issued RAI AMP-B2.1.38-2 regarding that seepage, and PINGP responded on December 5, 2008.The matter was discussed in a public meeting on March 2, 2009. An additional Follow-up RAI was issued on March 31, 2009, and the PINGP response was provided on April 6, 2009. On May 28, 2009 the NRC visited the PINGP site to review documents related to refueling cavity leakage. On June

4, 2009, the NRC issued the Safety Evaluation Report With Open Items Related to the

License Renewal of the Prairie Island Nuclear Generating Plant Units 1 and 2 (SER).

The SER identified the refueling cavity seepage as Open Item 3.0.3.2.17-1, pending completion of the NRC review of the April 6, 2009, Follow-up RAI response.

Subsequently, in a letter dated June 10, 2009, an additional Follow-up RAI was issued

regarding that seepage. The PINGP response to that Follow-up RAI is provided in

.

As a separate matter, in a conference call on June 10, 2009, the PINGP PWR Vessel Internals Program was discussed. During that call, PINGP agreed to clarify Part B of

the associated License Renewal Commitment No. 25 to indicate that the vessel internals inspection plan submittal would also include any LRA changes to the scoping, screening, and AMR results, and the description of the PWR Vessel Internals Program, that are necessary to reflect the final NRC-approved Inspection and Evaluation

guidance. Accordingly, License Renewal Commitment No. 25 is being revised as noted below to incorporate this clarification.A complete listing of PINGP License Renewal Commitments, updated to reflect NSPM correspondence to date, is provided in

.

If there are any questions or if additional information is needed, please contact Mr. Eugene Eckholt, License Renewal Project Manager.

Response to Follow-up RAI B2.1.38 1NRC Follow-up RAI B2.1.38In letter L-PI-08-098, dated December 5, 2008, "Responses to NRC Requests for Additional Information Dated November 5, 2008 Regarding Application for Renewed

Operating Licenses," the applicant submitted responses to the staff's RAIs. In addition, the applicant provided information during a public meeting on March 2, 2009, and a previous follow-up RAI in letter L-PI-09-047, April 6, 2009. On May 28, 2009, the NRC staff performed an audit at the Prairie Island Nuclear Generating Station (PINGP), Units 1 and 2, related to the supporting documentation for the reactor cavity leakage. The staff reviewed the following documents:

References:

1. Dominion Energy Incorporated, "Evaluation of Effects of Borated Water Leaks on Concrete Reinforcing Bars and Carbon Steel Plate of the Containment Vessels at

Prairie Island Units 1 and 2," Report No. R-4448-00-01, Rev. 0. 2. Prairie Island Nuclear Generating Station, "Refueling Cavity leakage, Event Date 1988-2008," Report No. RCE 01160372-01, Volumes 1 and 2. In order to complete our review of issues related to the PINGP reactor cavity leakage discussed in the above referenced reports, the staff requests the following additional

information:

[Note: To assist the reader, the NSPM response to each part (a through i) of the RAI is provided immediately after the statement of each part. References applicable to all

responses are listed after the response to part i.]Follow-up RAI Part a a) Section 2.2 of Reference 1 recommends that a test be performed to determine if there is high assurance that the pH present in the water between the containment steel plates and concrete is more than 12.5. Please provide a schedule for

performing this test.

NSPM Response to Part a It is well established that boric acid will be neutralized by contact with concrete. Tests of the effects of boric acid in contact with concrete have shown a rapid rise in pH of the boric acid solution. (Page 3-2 of Reference 5) It has also been shown by calculations using the EPRI MULTEQ program that the equilibrium pH will be about 12.5 with excess quantities of calcium present, as would be the case with the large amounts of calcium

hydroxide in concrete. Evidence that neutralization of boric acid has occurred in

concrete at Prairie Island is provided by the pH values of 7 and 7.8 that have been

measured in the active leakage. (Page 4-2 of Reference 1) To provide additional confirmation of this behavior, a simple laboratory test has been performed, as discussed

below. Response to Follow-up RAI B2.1.38 2To provide background for the process which results in boric acid being neutralized

when in contact with concrete, the materials that form concrete and their chemical

properties are summarized below.

Concrete is a composite material consisting of a binder (cement paste) and a filler of fine and/or course aggregate particles that combine to form a synthetic conglomerate.

The cement is a mixture of compounds made by grinding crushed limestone, clay, sand, and iron ore together to form a homogeneous powder that is then heated at very high

temperatures to form a clinker. After the clinker cools, it is ground and mixed with a small amount of gypsum to regulate setting and facilitate placement. This produces the general-purpose portland cement that is mixed with water to produce cement paste that

binds the aggregate particles together. Portland cements are composed primarily of four chemical compounds: tricalcium silicate, dicalcium silicate, tricalcium aluminate, and tetracalcium aluminoferrite. The calcium silicate hydrates constitute about 75% of

the mass. (Section 3, Reference 4) The hardened cement paste consists mainly of calcium silicate hydrates, calcium hydroxide, and lower proportions of calcium sulphoaluminate hydrate. About 20% of the hardened cement paste volume is calcium hydroxide. The pore solution is normally a saturated solution of calcium hydroxide within which high concentrations of potassium

and sodium hydroxides are present. (Section 3, Reference 4) Hardening of concrete occurs as a result of hydration, which is a chemical reaction in which the major compounds in the cement form chemical bonds with water molecules and become hydrates. Since cement is the most expensive ingredient in concrete, it is

desirable to utilize the minimum amount necessary to produce the desired properties and characteristics. Aggregate typically occupies 60 to 75% of the volume of concrete, with the balance of the concrete mix generally consisting of 10 to 15% cement, 15 to 20% water, and 5 to 8% air, if entrained. (Section 3, Reference 4) Tests reported in Reference 3 indicate that water of neutral pH placed in small holes drilled into concrete reaches an equilibrium pH of about 12.8 to 13.3 after one to two

weeks. This is consistent with general industry information that indicates that pore

water in concrete generally has a pH of about 12.5 or higher. This pH is fully protective of rebar (Section 4.3.2 of Reference 4). These results indicate that normal fresh water in contact with concrete will reach an equilibrium pH of 12.5 or more and be protective of steel (i.e., result in insignificant corrosion). However, these results do not address the possible effects of the boron in the water on the pH. This is discussed further in the

following paragraphs.

In order to more firmly establish the pH that will develop in small volumes of borated water in contact with large amounts of concrete, a simple laboratory test was performed.The test was performed by adding chemicals representative of those in concrete to an open beaker with a volume of one liter of deionized water at room temperature. After

each chemical addition, the solution was stirred and the pH was measured. The steps

of the test and the pH values measured are shown in Table 1. Comments regarding

the solutions tested and the results are as follows: Response to Follow-up RAI B2.1.38 3 Solution 1 involved the addition of calcium oxide alone, and represents the case of water in contact with the calcium hydroxide that is present in large quantities in concrete. Calcium oxide forms calcium hydroxide when dissolved in water. The measured pH of 12.05 was slightly below the normally reported equilibrium value of 12.5 for a saturated solution of calcium hydroxide, which is expected to contain

approximately 1,000 ppm calcium ions (as calcium hydroxide). The slightly

lower-than-expected pH is attributed to the fact that full equilibrium had not been

reached when the pH measurement was made (i.e., the pH was measured

before the calcium oxide was completely dissolved). Solution 2 reflects the addition of sodium, albeit at lower concentrations than

calcium. The concentration of sodium added to the test solution was consistent with that anticipated based on information reported in Reference 3 and is consistent with Reference 4 which notes that high concentrations are present in

pore water. As shown in Table 1, the sodium increased the measured pH by a

small amount. Solution 3 reflects the addition of the equivalent of 3000 ppm boric acid, which is

representative of the concentration present during refueling. The measured pH of 8.85 is in the expected range indicated by calculations for a case where some

boron remains in solution. Solutions 4 through 8 reflect the addition of increasing amounts of calcium oxide. This simulates exposure over time to the excess amounts of calcium hydroxide that are present in the concrete. Initially, the excess boric acid present in solution buffers the solution pH, and calcium oxide additions have only a small effect on the resulting pH.However, the pH increases rapidly to the 12.3 range after the concentration of calcium oxide exceeds the

stoichiometric amount needed to react with the boric acid that was initially

present.Table 1 pH of Simulated Boric Acid Leakage in Contact with Chemicals From Concrete Mass (g) SolutionCaO ppm Ca NaOH H 3 BO 3 pH1 1.3992 1,000 12.05 2 1.3992 1,000 3.3061 12.39 3 1.3992 1,000 3.3061 17.1585 8.85 4 6.3992 4,573 3.3061 17.1585 8.94 5 11.4016 8,149 3.3061 17.1585 9.01 6 24.7441 17,684 3.3061 17.1585 9.74 7 29.7456 21,259 3.3061 17.1585 12.28 8 34.7469 24,833 3.3061 17.1585 12.30 Response to Follow-up RAI B2.1.38 4 The primary conclusion that can be drawn from the test results summarized in Table 1 is that a high protective pH is reached by borated water that is in contact with excess amounts of calcium oxide. This indicates that a similar high pH will develop in borated

water trapped between the steel containment vessel and the concrete since there are excess amounts of calcium hydroxide in the concrete. The test discussed above was performed in accordance with written instructions, and the results were documented following normal laboratory practice. However, it was not performed in accordance with formal nuclear QA requirements. Nevertheless, the results are considered to be consistent with theoretical values and provide strong supporting evidence that high protective pH values will be reached in borated water

trapped between the steel containment vessel and the concrete. Follow-up RAI Part b b) Section 2.2 of Reference 1 recommends removal of concrete inside the containment at the following locations: i. Sump C ii. Through the wall at elevation 695 closer to the transfer tube However, Northern States Power Company, Minnesota (NSPM) in a letter dated April 6, 2009, committed to remove concrete from Sump C only. Please clarify. In addition, please explain why removal of concrete from Sump C is not planned during the next scheduled outages at PINGP, Units 1 and 2.

NSPM Response to Part b In reviewing the recommendations from Reference 1 to determine the appropriate Corrective Actions to be assigned within the Corrective Action Program, engineering

management considered the value, need and sufficiency of each recommendation provided. The review concluded that there is limited value in removing concrete from the inside diameter of the containment vessel at the 697' floor elevation, as it is not

known whether this area is wetted and has a potential for corrosion to exist. The site

has instead removed the grout in the RHR suction sump of both units as these areas are lower in containment elevation and consistently show wetting when refueling cavity

leakage occurs. It is also believed the RHR sumps would be more likely than the 697'

elevation to show any corrosion due to repeated wetting and close proximity to ambient oxygen. In addition, much of the area between the transfer tube at the 715' elevation and annulus floor at the 706' elevation can be monitored by ultrasonic thickness measurement from the exterior of the containment vessel, further diminishing the value of removing concrete from the interior wall. Therefore, the Corrective Action assignments did not include removal of concrete at elevation 697'.

Removal of the concrete in sump C (under the reactor vessel) will be performed in the next refueling outages following the outages during which the refueling cavity liners are repaired. This is primarily for logistical reasons. The estimated thickness of the Response to Follow-up RAI B2.1.38 5concrete at the thinnest location in the floor of sump C is 16 inches with reinforcing bar both near the top of the proposed excavation and near the containment vessel inside diameter. The work area is relatively small and in close proximity to the reactor vessel thimble tubes which provide an ASME Class 1 pressure boundary. As such, performing the excavation safely requires considerable planning and specialized tooling. The site

will use the upcoming refueling outage in each Unit to survey the excavation sites, and

the time between outages to plan the excavations and secure the appropriate tools.Follow-up RAI Part c c) Section 4.2 of Reference 1 has identified an upper bound loss of 0.25 inch in the 1.50 inch steel containment due to borated water corrosion over a 36 year period.

Please advise if the stresses in the steel containment remain within the American Society of Mechanical Engineers Code allowable values for this loss of 0.25 inches.

According to Section 4.1 of Reference 1, minimum thickness required for the steel containment for all loading conditions is 1.4908 inches. In addition, please clarify if

NSPM has considered the potential of continued reactor cavity leakage over the life extension period of 60 years.

NSPM Response to Part c The evaluation estimates the likely corrosion of the containment vessel to date at no more than 0.010". This estimate accounts for the neutralization of borated water in concrete. Recent ultrasonic thickness measurements, including measurements of

known wetted areas in the RHR suction sump, showed no corrosion with all thickness readings above the nominal plate thickness. If any significant loss were identified, an

ASME code evaluation would be required.As discussed in section 4.2 of Reference 1, the 0.25" value of corrosion assumes continuous wetting with aerated, concentrated, boric acid over a period of 36 years.

This value does not consider the buffering effect of the concrete or the consumption of oxygen dissolved in the water. Therefore, the long term environment that could lead to this level of corrosion would not exist.The report's reference to 0.25" as an upper bound does not clearly convey its meaning.This value was provided for comparison purposes only to provide further support for the low corrosion rates expected, and does

not represent an expected condition in a PINGP containment vessel. Therefore, an ASME Code analysis of the containment vessel which assumes loss of 0.25" of vessel wall has not been performed. Reference 1 does not suggest that a wall loss of this magnitude would leave the vessel capable of meeting code allowables. Indeed, the

report states that any observed wall loss that reduced the vessel below the nominal 1.5" thickness would have to be evaluated in accordance with ASME Section XI. Reference

1 only provides the judgment that even with a wall loss of 0.25", the containment vessel would still be able to withstand accident pressure without a loss of containment integrity. The areas of the steel containment vessel that are potentially subject to borated water exposure from refueling cavity leakage are the bottom head and sections of the shell behind concrete at the end of the refueling cavity and transfer pit (referred to in the Response to Follow-up RAI B2.1.38 6 USAR as the "cold spot"). Both the shell and bottom head are fabricated from SA-516-

70 material with a minimum tensile strength of 70 ksi. The Pioneer Service &

Engineering Company containment vessel stress report shows the shell and bottom

head were designed in accordance with ASME section VIII with a design pressure of 41.4 psig and a corresponding required thickness of 1.5 inch.

In accordance with ASME section VIII the design allowable membrane stress is limited to 25% of the material minimum tensile strength, or 17.5 ksi. Allowable stresses during a Design Basis Accident (DBA) are considerably higher. As indicated in USAR table

12.2-22, total stresses under a DBA with Design Basis Earthquake range from 24.48 ksi to 27.86 ksi. These stresses are approximately one half the DBA allowable stress of 52.5 ksi. Stresses are generally proportional to thickness. As such, even with thinning

of 0.25 inch of the 1.5 inch shell thickness, total stresses would still be well below the

stress limits for the load combinations that combine stresses from a DBA with those

from a Design Basis Earthquake.The site fully expects that leakage will be stopped during the next refueling outage of each unit. During the outage following the outage of repair, any water observed in Sump C will be evacuated. However, any residual water behind concrete that may not be able to be evacuated would have a very small stagnant volume with its pH elevated by the alkalinity in concrete. Any potential corrosion in such regions would be similar in magnitude to (or lower than) the 0.010" conservatively estimated for 36 years to date.

With this level of corrosion, the overall conclusion remains valid that containment vessel integrity would be unaffected.

The site will continue to monitor the containment vessel and internal structures through the ASME section XI, IWE program and the Structures Monitoring program. If any new leakage is identified that indicates the refueling cavity leakage has recurred, the issue will be entered into the Corrective Action Program for evaluation and identification of

corrective actions. Follow-up RAI Part d d) In Section 5.2.3 of Reference 1, the rate of degradation estimated for PINGP concrete is two times that used previously for Salem/Connecticut Yankee plants to account for the difference in the type of concrete aggregates at PINGP. Please advise if NSPM has performed or intends to perform any tests to confirm the use of

this assumption for the degradation rate.

NSPM Response to Part d The acceleration factor of 2.0 for the increased rate of degradation resulting from the presence of about 5% carbonate-based aggregate at Prairie Island relative to the 0%

carbonate-based aggregate at the cited plants was based on engineering judgment.Tests of the effects of acids on reinforced concrete show that acids weaken concrete by dissolving cement and carbonate-based aggregate (Page 29 of Reference 4 and page 4 Response to Follow-up RAI B2.1.38 7of Reference 6). Tests discussed in Reference 7 indicate that the weight loss experienced by cubes of concrete immersed in acid increases as the volume fraction of cement in the concrete increases. These tests were performed on concrete that had

non-soluble aggregate (i.e., only siliceous aggregate and no calcium carbonate-based aggregate). This increased weight loss is attributed to the fact that, as the volume

fraction of cement increases, the volume fraction of the concrete that is soluble in acids increases. Based on this result, it is reasonable to assume that the effect of boric acid

on concrete containing soluble aggregates will follow a similar pattern; i.e., the degradation of concrete due to boric acid will increase as the total fraction of material in the concrete that is soluble in acids increases, whether that soluble material is cement

or aggregate.

Quantitative data in Reference 7 for weight loss of concrete cubes when exposed to an acid concentration of 3% is shown in Figure 1. A trend line is shown on the figure that provides an equation for quantifying this dissolution behavior. As can be seen, the weight loss increases somewhat more strongly than linearly as the volume fraction of

cement, (i.e., of soluble material), increases.

Figure 1 Weight Loss in Acid vs. Volume Fraction of Cement (based on data from Reference 7) TrendLineEquation y=0.02012x 2+1.38346x R²=0.84673 0 5 10 15 20 25 30 3505101520LossinWeight%VolumeFractionofCementDataPointsTrendLine Response to Follow-up RAI B2.1.38 8A footnote on page 10 of Reference 4 indicates that concrete normally contains 10 to 15% of cement, or an average of about 12.5%. As noted on page 2-2 of Reference 1, the amount of carbonaceous aggregate in the concrete used at Prairie Island was about 5%. Adding this 5% to the average 12.5% cement results in a total of 17.5% soluble material in the concrete at Prairie Island as compared to the 12.5% in a concrete with all

igneous (no carbonate) based aggregate such as was used at the cited plants. (Section 8.1.3 of Reference 8) Using the trend line equation shown in Figure 1, increasing the fraction of soluble material (cement in the figure, cement plus soluble aggregate in this

case) from 12.5% to 17.5% increases the weight loss by a factor of 1.49. This indicates

that the assumed factor of 2.0 increase in severity of acid attack to account for the

presence of 5% carbonate-based aggregate is conservative by a significant margin (2

vs. 1.49).Based on this result, it is considered that there is no need for additional tests to evaluate the effects of the carbonate-based aggregate used at Prairie Island. Follow-up RAI Part e e) Section 5.2.6 of Reference 1 states, "-concrete is not relied upon for tensile strength (tensile strength provided by rebar)." Please explain how formation of large

thru thickness cracks will affect the transverse shear capacity of concrete slabs and walls. Shear strength of concrete is directly related to the tensile strength.

NSPM Response to Part e The nominal shear strength of reinforced concrete is based on the combination of the nominal shear strength provided by the concrete and the nominal strength provided by shear reinforcement (steel rebar). If a reinforced concrete member were postulated to

have a large idealized crack along the entire shear plane, the reinforcement would need to carry the shear force. However, there is no indication that such a crack might exist at

PINGP.The existence of a wide crack in the refueling cavity floor or walls that has traveled through the entire thickness of a concrete section along a single shear plane is highly unlikely. Plant operating experience has not identified any large cracks in either the Unit 1 or Unit 2 reactor containment concrete structures. The cracks that have been identified are often characterized as hairline or normal shrinkage cracks. Large

through-member cracks are not reasonable to postulate at PINGP based on the plant's adherence to good design and construction practices. The refueling pool floor slab, at

its minimum, is 4'-0" thick (3'-8" of reinforced concrete and 4" of leveling grout) and contains both top and bottom reinforcement in each direction. Where water seepage from cracks has occurred during flood up of the refueling cavity, the cracks have never been described as large or wide, which is consistent with the small amount of water that seeps from the cracks, estimated at no more than 1-2 gallons per hour. Additionally, no evidence of significant washout of material has been identified, a condition that could be indicative of the development of a widening crack. Response to Follow-up RAI B2.1.38 9Follow-up RAI Part f f) Section 5.2.6 of Reference 1 states, "Degradation of concrete by exposure to borated water can also occur at cracks in the concrete. This could lead to loss of

strength of concrete in a narrow band through thickness of material." A crack across thickness of material may expose rebars to corrosion. Please explain how this effect is considered in determining the structural integrity of concrete walls and slabs.

NSPM Response to Part f The quotation above is from Section 5.2 of Reference 1, "Degradation of Concrete Due to Chemical Attack." This section deals with concrete degradation, and does not address rebar corrosion. Rebar corrosion is addressed in the following section, Section 5.3, "Corrosion of Rebar Caused by Exposure to Borated Water." The specific question asked in Part f is addressed by the second bullet in Section 5.3 of Reference 1. This section indicates that the dissolution of calcium hydroxide from the concrete around rebar at cracks in the concrete might be assumed to develop conditions that might lead to increased rates of corrosion of the rebar. However, tests performed for the cited plants and other tests described in the open literature indicate that corrosion in such

situations has been negligible, even when the low pH borated water reaching the cracks

was regularly refreshed. It appears that conditions at the rebar remain sufficiently alkaline in such situations to passivate the surface, despite the presence of refreshed

borated water.

Reference 5 documents tests performed using steel coupons in a refreshed boric acid solution. The relevant conclusion from the report reads as follows: "The short-term corrosion rate of reinforcing steel was observed to be about 4.2 mils/year (0.0042-inch/year) based on an exposure time of up to 56-days in an aerated boric solution with a pH in the range of 5.2 to 6.4. The corrosion rate should decrease as pH increases and oxygen content decreases under long-term conditions in the field." The tests

documented in Reference 9 were two year tests of samples using refreshed boric acid in which the rebar was exposed to the boric acid at cracks. The main conclusion was as follows: "For a penetration period of 2 years, there were weakenings of the cross

section of the reinforcing bars not worth being mentioned by reinforcement corrosion in separation cracks penetrated by deionised water (neutral, pH 7.0) and boric acid treatment deionised water of the pH-values 5.2 and 6.1 with crack widths of up to

approximately 0.4 mm."

The tests documented in Reference 9 are considered to be the most relevant since they were long term (2 year) and used realistic cracked specimens with the rebar exposed to the boric acid in a crack. As noted in Reference 9, the corrosion of the rebar was "not worth being mentioned." The total exposure time of rebar cracks in the reinforced concrete under the refueling cavity at Prairie Island is conservatively estimated as 15 days per outage for 25 outages or 375 days or 1.03 years. This is significantly less than the two year test period of Reference 9 which resulted in no significant corrosion.

Accordingly, it is concluded that no significant corrosion of rebar at cracks in the structural concrete under the refueling cavity has occurred at Prairie Island, and that effects of rebar corrosion at cracks in the concrete on structural integrity are insignificant. Response to Follow-up RAI B2.1.38 10Follow-up RAI Part g g) Section 5.2.3 of Reference 1 estimated the upper bound loss of concrete depth over a 36 year period to be 0.31 inches. Please address the impact of this loss of 0.31 inch of concrete behind the stainless steel liner plate on the load carrying capacity of the stainless steel liner plate.

NSPM Response to Part g As discussed in section 5.2.3 of the Reference 1, the upper bound loss of 0.31 inch is conservative as it assumes leakage every outage for 25 outages over a period of 36 years. There is no evidence of leakage prior to 1987 and leakage has only been

observed in about half the outages due to intermittent successful leak mitigation with

caulking or spray-on liner. The impact of a potential loss of 0.31" of concrete on the load carrying capacity of the liner is minimal. The liner is effectively a membrane that is backed under the bottom

and around the sides with concrete that is generally four to five feet thick. As a result, the impact on the load carrying capacity of the refueling cavity pool structure is negligible as the material loss is, at most, less than 1% of the concrete thickness. Large areas of washout or dissolution under the liner are not expected as leak rates are small (on the order of 1-2 gallons per hour) and only occur while the refueling cavity is flooded. However, even if large areas of washout or dissolution on the order of square feet and 0.31" depth were to occur, they would only be expected to result in shallow depressions in the liner and not in a failure such as tearing of the liner plate. The liner was constructed with the seams welded to stainless steel structural shapes embedded in the concrete. As such, the seams are reinforced and are not subject to loss of

concrete directly under a seam. The liner plates are 3/16" and 1/4" thick Type 304 stainless steel. Stainless steel is generally very ductile and can withstand significant

elongation and deformation before failure. The site has not experienced any observable depressions on either the floors or walls of the refueling cavities. Follow-up RAI Part h h) NSPM in a letter dated April 6, 2009, committed to visual inspections during the consecutive refueling outages of the areas where reactor cavity leakage has been observed following refueling cavity leak repairs in each unit. Which aging

management program (AMP) will be used to address this issue?

NSPM Response to Part h License Renewal Commitment Number 42 from the April 6, 2009 letter reads as follows:During the two consecutive refueling outages following refueling cavity leak repairs in each Unit (scheduled for refueling outages 1R26 and 2R26), visual inspections will be performed of the areas where reactor cavity leakage had been

observed previously to confirm that leakage has been resolved. The inspection Response to Follow-up RAI B2.1.38 11results will be documented. If refueling cavity leakage is again identified, the

issue will be entered into the Corrective Action Program and evaluated for identification of additional actions to mitigate leakage and monitor the condition of

the containment vessel and internal structures.The inspections of the locations which previously showed signs of refueling cavity leakage are special inspections assigned as corrective actions within the Corrective

Action Program. The inspections will invoke the methodology, documentation requirements and acceptance criteria of the Structures Monitoring Program. The Structures Monitoring Program is the appropriate program since the locations where

leakage has been observed are in containment interior structures. Thereafter, as discussed in the April 6, 2009, letter, general monitoring for leakage and degradation will be performed in all areas of containment in accordance with the ASME

Section XI, Subsection IWE Program and the Structures Monitoring Program. In

addition, the Boric Acid Corrosion Program and the 10 CFR Part 50, Appendix J Program include inspections inside containment. These programs contain provisions to

identify, evaluate, and correct degraded conditions prior to loss of function, ensuring the effects of aging for plant SSCs are adequately managed. Periodic visual inspections are performed, and inspection schedules are prescribed, ensuring timely identification of

any degraded condition. The ASME Section XI, Subsection IWE Program also incorporates the requirements of 10 CFR 50.55a(b)(2)(ix) for the examination of metal containments, including the requirement in 10 CFR 50.55a(b)(2)(ix)(A) to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in degradation to, such inaccessible areas.During the current license period as well as the period of extended operation, degradation identified by these programs will be entered into the PINGP Corrective Action Program for evaluation and identification of corrective actions.Follow-up RAI Part i i) Page 52 of Reference 2 identified five recommendations to address reactor cavity leakage. Please provide NSPM's action plan and schedule for completing these five

recommendations.

NSPM Response to Part i Page 52 of the Root Cause Evaluation (RCE) recommended a repair plan that includes the following steps: 1. Unbolt and set aside all mechanically fastened fixtures (RCC Change Fixture, internals stands, and guide tube supports). 2. Vacuum Box penetrations and embedment plates to locate existing leaks. Weld repair and vacuum box completed welds3. Preemptively seal weld and vacuum box all penetrations. Response to Follow-up RAI B2.1.38 124. Vacuum Box, and/or PT weld seams and repair as needed to ensure no leakage due to stress corrosion cracking. 5. Pressure test or PT transfer tube bellows attachment welds and weld repair as needed.The RCE also states that alternate approaches can also be considered provided the final repair plan permanently and completely mitigates future leakage. The RCE concluded that the most likely refueling cavity leakage points are where the anchor studs for the reactor internals stands and the Rod Control Cluster (RCC)

Change Fixture penetrate the associated embedment plates. The studs for these fixtures pass through holes in the embedment plates and are seal welded on the underside for the internals storage stands, and on top (then ground flush) for the RCC Change Fixture.Pinhole leaks or small cracks in one or more of the seal welds would result in a leak path through the embedment plate along the threads of the studs, allowing water under the cavity liner.The plant management review of the Root Cause Evaluation considered the value, need and sufficiency of each recommendation. The current repair plan that emerged

from these reviews is to replace the existing anchor nuts with new fabricated blind nuts

that are seal welded to the existing baseplates. In addition, the existing baseplates will be seal welded to the embedment plates. The new welds will be readily accessible for

examination to ensure the existing anchors and baseplates are leak tight. The following sketch depicts a typical RCC change fixture support showing the planned repairs.

Similar repairs will be made to the internals stands supports.

General Arrangement of Change Fixture SupportsExisting seal weld to embedment plate not accessible. Failure of weld would result in leak.Replace existing nuts with fabricated blind nuts seal welded to baseplate.

Side ViewExisting 1/4" thk stainless steel cavity linerNew seal weld between baseplate and embedment plate.Existing cavity liner fillet weld to embedment plate Response to Follow-up RAI B2.1.38 13This repair strategy effectively accomplishes the goals of recommended steps 1 through 3, the intent of which is to permanently repair refueling cavity leakage, but in a more

focused and dose-effective manner. The guide tube supports which are mounted to the refueling cavity wall were concluded to be unlikely sources of leakage and will not be

sealed in a similar manner. Although the guide tube supports are of similar construction, past success at mitigating leakage by sealing the supports of the internals

stands and RCC change fixture suggests that leakage occurs only at those locations. Recommended step 4 is to vacuum box and/or dye penetrant test refueling cavity liner weld seams to ensure no leakage due to stress corrosion cracking. The site performed vacuum box and/or dye penetrant test of accessible seams of both units in 1998 and

1999 with no indications of cracking. NSPM does plan to examine a sample of accessible seams to ensure no cracking has occurred since the last inspection. Recommended step 5 is to pressure test or dye penetrant test the transfer tube bellows attachment welds and perform weld repairs as needed. NSPM believes these welds are leak tight as past refueling cavity leakage has been completely mitigated through

sealing only the internals stands and change fixture anchors. As a precaution, NSPM does plan to perform pressure testing or dye penetrant testing of accessible portions of

the transfer tube bellows welds to preclude the possibility of water leaking along the

transfer tube to the inside surface of the containment vessel. All actions discussed above are planned for the next refueling outage for each unit, currently scheduled for fall 2009 for Unit 1 and spring 2010 for Unit 2. References for NSPM Responses to Follow-up RAI B2.1.38 Parts a through i 1. Dominion Engineering, Inc. report "Evaluation of Effects of Borated Water Leaks on Concrete Reinforcing Bars and Carbon Steel Plate of the Containment Vessels at Prairie Island Units 1 and 2," report R-4448-00-01, Rev. 0. 2. Prairie Island Nuclear Generating Station, "Refueling Cavity leakage, Event Date 1988-2008," Report No. RCE 01160372-01, Volumes 1 and 2. 3. A. A. Sagües, et al., "Evolution of pH During In-Situ Leaching in Small Concrete Cavities," Cement and Concrete Research , Vol. 27, No. 11, pp. 1747-1759, 1997. 4. D. J. Naus, Primer on Durability of Nuclear Power Plant Reinforced Concrete Structures - A Review of Pertinent Factors, NUREG/CR-6927 - ORNL/TM-2006/529, Feb. 2007. 5. MPR Associates report "Boric Acid Attack of Concrete and Reinforcing Steel," MPR-2634, Revision 2, February 2009. 6. B. Kerkhoff, "Effects of Substances on Concrete and Guide to Protective Treatments,"

Portland Cement Association, Item Code: IS001, 2007. 7. N. I. Fattuhi and B. P. Hughes, "Ordinary Portland Cement Mixes with Selected Admixtures Subjected to Sulfuric Acid Attack,"

ACI Materials Journal, Technical Paper, Title no. 85*M50, Nov. Dec. 1988, p512-518. 8. MPR Associates report "Salem Generating Station Fuel Handling Building Evaluation of Degraded Condition," MPR-2613, Revision 3, February 2009. 9. W. Ramm and M. Biscoping, "Autogenous healing and reinforcement corrosion of water-penetrated separation cracks in reinforced concrete," Nuclear Engineering and Design, p191-200, v179 (1998). Prairie Island Nuclear Generating Plant License Renewal Commitments 15 Pages Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 1The following table provides the list of commitments included in the Application for Renewed Operating Licenses (LRA) for Prair ieIsland Nuclear Generating Plant (PINGP) Units 1 and 2, as updated in subsequent correspondence.

The commitments in this list are anticipated to be the final commitments which will be confirmed in the NRC's Safety EvaluationReport (SER) for the renewed operating licenses. These commitments, as confirmed in the SER, will become effective upon NRC issuance of the renewed licenses. In addition, as stated in the LRA, the final commitments will be incorporated into the Updat ed Safety Analysis Report (USAR).

Commitment Number Commitment Implementation Schedule Related LRA Section Number 1Each year, following the submittal of the PINGP License Renewal Application and at least three months before the scheduled completion of the NRC review, NMC will submit amendments to the PINGP application pursuant to 10 CFR

54.21(b). These revisions will identify any changes to the Current Licensing Basis that materially affect the contents of the License Renewal Application, including the USAR supplements.

12 months after LRA submittal date

and at least 3

months before

completion of NRC

review Annual Update was submitted by letter

dated 4/13/09 1.42 Following the issuance of the renewed operating license, the summary descriptions of aging management programs and

TLAAs provided in Appendix A, and the final list of License Renewal commitments, will be incorporated into the PINGP USAR as part of a periodic USAR update in accordance with 10

CFR 50.71(e). Other changes to specific sections of the PINGP USAR necessary to reflect a renewed operating license will also be addressed at that time.

First USAR update in accordance with 10 CFR 50.71(e) following issuance

of renewed

operating licenses A1.03 An Aboveground Steel Tanks Program will be implemented.

Program features will be as described in LRA Section B2.1.2.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.24 Procedures for the conduct of inspections in the External Surfaces Monitoring Program, Structures Monitoring Program, U1 - 8/9/2013 B2.1.6 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 2 Commitment Number Commitment Implementation Schedule Related LRA Section Number Buried Piping and Tanks Inspection Program, and the RG

1.127 Inspection of Water-Control Structures Associated with

Nuclear Power Plants Program will be enhanced to include

guidance for visual inspections of installed bolting.

U2 - 10/29/2014 5 A Buried Piping and Tanks Inspection Program will be implemented. Program features will be as described in LRA Section B2.1.8.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.8 6 The Closed-Cycle Cooling Water System Program will be enhanced to include periodic inspection of accessible surfaces

of components serviced by closed-cycle cooling water when the systems or components are opened during scheduled

maintenance or surveillance activities. Inspections are

performed to identify the presence of aging effects and to confirm the effectiveness of the chemistry controls. Visual inspection of component internals will be used to detect loss of

material and heat transfer degradation. Enhanced visual or

volumetric examination techniques will be used to detect

cracking.[Revised in letter dated 1/20/2009 in response to RAI 3.3.2 01]U1 - 8/9/2013 U2 - 10/29/2014 B2.1.9 7 The Compressed Air Monitoring Program will be enhanced as follows: Station and Instrument Air System air quality will be monitored and maintained in accordance with the instrument air quality guidance provided in ISA

S7.0.01-1996. Particulate testing will be revised

to use a particle size methodology as specified in

ISA S7.0.01.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.10 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 3 Commitment Number Commitment Implementation Schedule Related LRA Section Number The program will incorporate on-line dew point

monitoring.[Revised in letter dated 2/6/2009 in response to Region III License Renewal Inspection] 8 An Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be

completed. Program features will be as described in LRA Section B2.1.11.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.11 9An Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented. Program features will be as described in LRA Section B2.1.12.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.1210 An Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in

Instrumentation Circuits Program will be implemented.

Program features will be as described in LRA Section B2.1.13.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.13 11 The External Surfaces Monitoring Program will be enhanced as follows: The scope of the program will be expanded as necessary

to include all metallic and non-metallic components within

the scope of License Renewal that require aging

management in accordance with this program. The program will ensure that surfaces that are inaccessible or not readily visible during plant operations will be inspected during refueling outages. The program will ensure that surfaces that are U1 - 8/9/2013 U2 - 10/29/2014 B2.1.14 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 4 Commitment Number Commitment Implementation Schedule Related LRA Section Number inaccessible or not readily visible during both plant operations and refueling outages will be inspected at

intervals that provide reasonable assurance that aging effects are managed such that the applicable components will perform their intended function during

the period of extended operation. The program will apply physical manipulation techniques, in addition to visual inspection, to detect aging effects in elastomers and plastics. The program will include acceptance criteria (e.g.,

threshold values for identified aging effects) to ensure

that the need for corrective actions will be identified

before a loss of intended functions. The program will ensure that program documentation

such as walkdown records, inspection results, and other records of monitoring and trending activities are auditable

and retrievable.[Revised in letter dated 2/6/2009 in response to RAI B2.1.14-1 Follow Up question] 12 The Fire Protection Program will be enhanced to require periodic visual inspection of the fire barrier walls, ceilings, and floors to be performed during walkdowns at least once every refueling cycle. [Revised in letter dated 12/5/2008 in response to RAI B2.1.15-3]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.15 13 The Fire Water System Program will be enhanced as follows:

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.16 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 5 Commitment Number Commitment Implementation Schedule Related LRA Section Number The program will be expanded to include eight additional yard fire hydrants in the scope of the annual visual inspection and flushing activities. The program will require that sprinkler heads that have been in place for 50 years will be replaced or a

representative sample of sprinkler heads will be tested using the guidance of NFPA 25, "Inspection, Testing and

Maintenance of Water-Based Fire Protection Systems" (2002 Edition, Section 5.3.1.1.1). Sample testing, if

performed, will continue at a 10-year interval following the initial testing.

14 The Flux Thimble Tube Inspection Program will be enhanced as follows: The program will require that the interval between inspections be established such that no flux thimble tube is predicted to incur wear that exceeds the established

acceptance criteria before the next inspection. The program will require that re-baselining of the examination frequency be justified using plant-specific

wear rate data unless prior plant-specific NRC acceptance for the re-baselining was received. If design changes are made to use more wear-resistant thimble tube materials, sufficient inspections will be conducted at an adequate inspection frequency for the new materials. The program will require that flux thimble tubes that cannot be inspected must be removed from service.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.18 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 6 Commitment Number Commitment Implementation Schedule Related LRA Section Number 15 The Fuel Oil Chemistry Program will be enhanced as follows: Particulate contamination testing of fuel oil in the eleven fuel oil storage tanks in scope of License Renewal will be

performed, in accordance with ASTM D 6217, on an annual basis. One-time ultrasonic thickness measurements will be performed at selected tank bottom and piping locations prior to the period of extended operation.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.1916 A Fuse Holders Program will be implemented. Program features will be as described in LRA Section B2.1.20.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.20 17 An Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented. Program features will be as described in LRA Section B2.1.21 U1 - 8/9/2013 U2 - 10/29/2014 B2.1.21 18 An Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be implemented. Program

features will be as described in LRA section B2.1.22.

Inspections for stress corrosion cracking will be performed by

visual examination with a magnified resolution as described in 10 CFR 50.55a(b)(2)(xxi)(A) or with ultrasonic methods. [Revised in letter dated 2/6/2009 in response to RAI B2.1.22-1 Follow Up question]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.22 19 The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be enhanced as follows:

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.23 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 7 Commitment Number Commitment Implementation Schedule Related LRA Section Number Program implementing procedures will be revised to ensure the components and structures subject to inspection are clearly identified. Program inspection procedures will be enhanced to include the parameters corrosion and wear where omitted.20A Metal-Enclosed Bus Program will be implemented. Program features will be as described in LRA Section B2.1.26.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.26 21 Number Not Used

[Revised in letter dated 3/27/2009]

22 Number Not Used

[Revised in letter dated 4/13/2009]

23 A One-Time Inspection Program will be completed. Program features will be as described in LRA Section B2.1.29.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.29 24A One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program will be completed. Program features will be as described in LRA Section B2.1.30.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.30 25 A. A PWR Vessel Internals Program will be implemented.Program features will be as described in LRA Section B2.1.32.B. An inspection plan for reactor internals will be submitted for NRC review and approval at least twenty-four months prior to

the period of extended operation. In addition, the submittal will include any necessary revisions to the PINGP PWR Vessel A. U1 - 8/9/2013 U2 - 10/29/2014 B. U1 - 8/9/2011 U2 - 10/29/2012 B2.1.32 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 8 Commitment Number Commitment Implementation Schedule Related LRA Section Number Internals Program, as well as any related changes to the

PINGP scoping, screening and aging management review

results for reactor internals, to conform to the NRC-approved

Inspection and Evaluation Guidelines.

[Revised in letter dated 5/12/2009]

[Revised in letter dated 6/24/09 in response to Follow-up RAI B2.1.38]26The Reactor Head Closure Studs Program will be enhanced to incorporate controls that ensure that any future procurement of reactor head closure studs will be in accordance with the material and inspection guidance provided in NRC Regulatory Guide 1.65.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.33 27The Reactor Vessel Surveillance Program will be enhanced as follows: A requirement will be added to ensure that all withdrawn and tested surveillance capsules, not discarded as of August 31, 2000, are placed in storage for possible future reconstitution and use. A requirement will be added to ensure that in the event spare capsules are withdrawn, the untested capsules are placed in storage and maintained for future insertion.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.34 28 The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be enhanced as follows: The program will include inspections of concrete and steel components that are below the water line at the Screenhouse and Intake Canal. The scope will also U1 - 8/9/2013 U2 - 10/29/2014 B2.1.35 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 9 Commitment Number Commitment Implementation Schedule Related LRA Section Number require inspections of the Approach Canal, Intake Canal, Emergency Cooling Water Intake, and Screenhouse immediately following extreme environmental conditions

or natural phenomena including an earthquake, flood, tornado, severe thunderstorm, or high winds. The program parameters to be inspected will include an inspection of water-control concrete components that are

below the water line for cavitation and erosion degradation. The program will visually inspect for damage such as cracking, settlement, movement, broken bolted and

welded connections, buckling, and other degraded conditions following extreme environmental conditions or natural phenomena.

29 A Selective Leaching of Materials Program will be completed.Program features will be as described in LRA B2.1.36.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.36 30 The Structures Monitoring Program will be enhanced as follows: The following structures, components, and component supports will be added to the scope of the inspections:

o Approach Canal o Fuel Oil Transfer House o Old Administration Building and Administration Building Addition o Component supports for cable tray, conduit, cable, tubing tray, tubing, non-ASME vessels, exchangers, pumps, valves, piping, mirror U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 10 Commitment Number Commitment Implementation Schedule Related LRA Section Number insulation, non-ASME valves, cabinets, panels, racks, equipment enclosures, junction boxes, bus

ducts, breakers, transformers, instruments, diesel equipment, housings for HVAC fans, louvers, and

dampers, HVAC ducts, vibration isolation

elements for diesel equipment, and miscellaneous electrical and mechanical equipment items o Miscellaneous electrical equipment and instrumentation enclosures including cable tray, conduit, wireway, tube tray, cabinets, panels, racks, equipment enclosures, junction boxes, breaker housings, transformer housings, lighting

fixtures, and metal bus enclosure assemblies o Miscellaneous mechanical equipment enclosures including housings for HVAC fans, louvers, and

dampers o SBO Yard Structures and components including SBO cable vault and bus duct enclosures.

o Fire Protection System hydrant houses o Caulking, sealant and elastomer materials o Non-safety related masonry walls that support equipment relied upon to perform a function that

demonstrates compliance with a regulated

event(s). The program will be enhanced to include additional inspection parameters. The program will require an inspection frequency of once every five (5) years for structures and structural Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 11 Commitment Number Commitment Implementation Schedule Related LRA Section Number components within the scope of the program. The

frequency of inspections can be adjusted, if necessary, to

allow for early detection and timely correction of negative trends. The program will require periodic sampling of groundwater and river water chemistries to ensure they remain non-aggressive.

31A Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program will be implemented. Program features will be as described in LRA Section B2.1.39.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.39 32 The Water Chemistry Program will be enhanced as follows: The program will require increased sampling to be performed as needed to confirm the effectiveness of corrective actions taken to address an abnormal chemistry condition. The program will require Reactor Coolant System dissolved oxygen Action Level limits to be consistent with

the limits established in the EPRI PWR Primary Water Chemistry Guidelines." [Revised in letter dated 12/5/2008 in response to RAI B2.1.40-3]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.40 33 The Metal Fatigue of Reactor Coolant Pressure Boundary Program will be enhanced as follows: The program will monitor the six component locations identified in NUREG/CR-6260 for older vintage

Westinghouse plants, either by tracking the cumulative number of imposed stress cycles using cycle counting, or U1 - 8/9/2013 U2 - 10/29/2014 B3.2 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 12 Commitment Number Commitment Implementation Schedule Related LRA Section Number by tracking the cumulative fatigue usage, including the

effects of coolant environment. The following locations

will be monitored:

o Reactor Vessel Inlet and Outlet Nozzles o Reactor Pressure Vessel Shell to Lower Head o RCS Hot Leg Surge Line Nozzle o RCS Cold Leg Charging Nozzle o RCS Cold Leg Safety Injection Accumulator Nozzle o RHR-to-Accumulator Piping Tee Program acceptance criteria will be clarified to require corrective action to be taken before a cumulative fatigue usage factor exceeds 1.0 or a design basis transient

cycle limit is exceeded. [Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

34 Reactor internals baffle bolt fatigue transient limits of 1835 cycles of plant loading at 5% per minute and 1835 cycles of plant unloading at 5% per minute will be incorporated into the

Metal Fatigue of Reactor Coolant Pressure Boundary Program and USAR Table 4.1-8.

U1 - 8/9/2013 U2 - 10/29/2014 B3.2 35NSPM will perform an ASME Section III fatigue evaluation of the lower head of the pressurizer to account for effects of insurge/outsurge transients. The evaluation will determine the

cumulative fatigue usage of limiting pressurizer component(s)

through the period of extended operation. The analyses will

account for periods of both "Water Solid" and "Standard

Steam Bubble" operating strategies. Analysis results will be incorporated, as applicable, into the Metal Fatigue of Reactor U1 - 8/9/2013 U2 - 10/29/2014 4.3.1.3 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 13 Commitment Number Commitment Implementation Schedule Related LRA Section Number Coolant Pressure Boundary Program. [Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

36 NSPM will complete fatigue calculations for the pressurizer surge line hot leg nozzle and the charging nozzle using the methodology of the ASME Code (Subsection NB) and will

report the revised CUFs and CUFs adjusted for environmental effects at these locations as an amendment to the PINGP LRA. Conforming changes to LRA Section 4.3.3, "PINGP EAF Results," will also be included in that amendment to reflect analysis results and remove references to stress-based

fatigue monitoring.

[Added in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

April 30, 2009 Commitment closed by letter

dated 4/28/09 4.3.3 37NSPM will revise procedures for excavation and trenching controls and archaeological, cultural and historic resource

protection to identify sensitive areas and provide guidance for ground-disturbing activities. The procedures will be revised to

include drawings and illustrations to assist users in identifying culturally sensitive areas, and pictures of artifacts that are prevalent in the area of the Plant site. The revised procedures

will also require training of the Site Environmental Coordinator

and other personnel responsible for proper execution of excavation or other ground-disturbing activities. [Added in ER revision submitted in letter dated 3/4/2009] 8/9/2013 ER 4.16.1 38NSPM will conduct a Phase I Reconnaissance Field Survey of the disturbed areas within the Plant's boundaries. In addition, NSPM will conduct Phase I field surveys of areas of known archaeological sites to precisely determine their boundaries. 8/9/2013 ER 4.16.2 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 14 Commitment Number Commitment Implementation Schedule Related LRA Section Number NSPM will use the results of these surveys to designate areas for archaeological protection. [Added in ER revision submitted in letter dated 3/4/2009]

39NSPM will prepare, maintain and implement a Cultural Resources Management Plan (CRMP) to protect significant historical, archaeological, and cultural resources that may currently exist on the Plant site. In connection with the preparation of the CRMP, NSPM will

conduct botanical surveys to identify culturally and medicinally important species on the Plant site, and

incorporate provisions to protect such plants into the

CRMP.[Added in ER revision submitted in letter dated 3/4/2009] 8/9/2013 ER 4.16.2 40NSPM will consult with a qualified archaeologist prior to conducting any ground-disturbing activity in any area

designated as undisturbed and in any disturbed area that is described as potentially containing archaeological resources (as determined by the Phase I Reconnaissance Field Survey

discussed in Commitment Number 38). [Added in ER revision submitted in letter dated 3/4/2009] 8/9/2013 ER 4.16.2 41During the first refueling outage following refueling cavity leak repairs in each Unit (scheduled for refueling outages 1R26 and

2R26), concrete will be removed from the sump C pit to expose

an area of the containment vessel bottom head. Visual examination and ultrasonic thickness measurement will be

performed on the portions of the containment vessels exposed

by the excavations. An assessment of the condition of exposed U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 15 Commitment Number Commitment Implementation Schedule Related LRA Section Number concrete and rebar will also be performed. Degradation

observed in the exposed containment vessel, concrete or rebar

will be entered into the Corrective Action Program and evaluated for impact on structural integrity and identification of

additional actions that may be warranted.

[Added in letter dated 4/6/09 in response to Follow Up RAI B2.1.38]42During the two consecutive refueling outages following refueling cavity leak repairs in each Unit (scheduled for refueling outages

1R26 and 2R26), visual inspections will be performed of the

areas where reactor cavity leakage had been observed

previously to confirm that leakage has been resolved. The inspection results will be documented. If refueling cavity leakage is again identified, the issue will be entered into the

Corrective Action Program and evaluated for identification of additional actions to mitigate leakage and monitor the condition of the containment vessel and internal structures.

[Added in letter dated 4/6/09 in response to Follow Up RAI B2.1.38]U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 43Preventive maintenance requirements will be implemented to require periodic replacement of rubber flexible hoses in the

Diesel Generators and Support System and in the 122 Diesel Driven Fire Pump that are exposed to fuel oil or lubricating oil

internal environments.

[Added in letter dated 4/6/09 in response to RAI 3.3.2-8-1]

[Revised in letter dated 6/5/09]

U1 - 8/9/2013 U2 - 10/29/2014 Table 3.3.2-8 1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1121 June 24, 2009 L-PI-09-082 10 CFR 54 U S Nuclear Regulatory Commission

ATTN: Document Control Desk

Washington, DC 20555-0001

Prairie Island Nuclear Generating Plant Units 1 and 2

Dockets 50-282 and 50-306

License Nos. DPR-42 and DPR-60

Response to NRC Request for Additional Information Regarding Application for Renewed Operating Licenses

By letter dated April 11, 2008, Norther n States Power Company, a Minnesota Corporation, (NSPM) submitted an Application for Renewed Operating Licenses (LRA) for the Prairie Island Nuclear Generating Plan t (PINGP) Units 1 and 2. During the Aging Management Audit, the NRC was briefed on wa ter seepage from the refueling cavity into the containment sumps that had been detect ed during refueling outages. In a letter dated November 5, 2008, the NRC issued RA I AMP-B2.1.38-2 regarding that seepage, and PINGP responded on December 5, 2008.

The matter was discussed in a public meeting on March 2, 2009. An additional Follow-up RAI was issued on March 31, 2009, and the PINGP response was provided on April 6, 2009. On May 28, 2009 the NRC visited the PINGP site to review documents related to refueling cavity leakage. On June 4, 2009, the NRC issued the Safety Evaluati on Report With Open Items Related to the License Renewal of the Prairie Island Nucl ear Generating Plant Units 1 and 2 (SER).

The SER identified the refueling cavity seepage as Open Item 3.0.3.2.17-1, pending completion of the NRC review of the April 6, 2009, Follow-up RAI response.

Subsequently, in a letter dated June 10, 2009, an additional Follow-up RAI was issued regarding that seepage. T he PINGP response to that Fo llow-up RAI is provided in .

As a separate matter, in a conference ca ll on June 10, 2009, the PINGP PWR Vessel Internals Program was discussed. During that call, PINGP agreed to clarify Part B of the associated License Renewal Commitment No. 25 to indicate that the vessel internals inspection plan submittal would also include any LRA changes to the scoping, screening, and AMR results, and the description of the PWR Vessel Internals Program, that are necessary to reflect the final NRC-approved Inspec tion and Evaluation guidance. Accordingly, Li cense Renewal Commitment No. 25 is being revised as noted below to incorporate this clarification.

A complete listing of PINGP License Renewal Commitments, updated to reflect NSPM correspondence to date, is provided in .

If there are any questions or if additional information is needed, please contact Mr. Eugene Eckholt, License Renewal Project Manager.

Document Control Desk Page 2 Summary of Commitments This letter contains no new commitment

s. License Renewal Commitment No. 25 is revised to read as follows:

A. A PWR Vessel Internals Program will be implemented. Progr am features will be as described in LRA Section B2.1

.32. The program will be implemented prior to the period of extended operation.

B. An inspection plan for reactor internals will be submitted for NRC review and approval at least twenty-four months pr ior to the period of extended operation.

In addition, the submittal will include any necessary revisions to the PINGP PWR Vessel Internals Program, as well as any related changes to the PINGP scoping, screening and aging management review results for reactor internals, to conform to the NRC-approved Inspection and Evaluation Guidelines.

The implementation schedules for Part s A and B of this commitment are unchanged: 8/9/2013 (Unit 1) and 10/29/2014 (U nit 2) for Part A, and 8/9/2011 (Unit 1) and 10/29/2012 (Unit 2) for Part B.

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

Executed on June 24, 2009.

/S/ Michael D. Wadley

Michael D. Wadley

Site Vice President, Prairie Island Nu clear Generating Plant Units 1 and 2 Northern States Power Company - Minnesota

Enclosures (2)

cc:

Administrator, Region III, USNRC License Renewal Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC

Prairie Island Indian Communi ty ATTN: Phil Mahowald Minnesota Department of Commerce

Response to Follow-up RAI B2.1.38 1NRC Follow-up RAI B2.1.38 In letter L-PI-08-098, dated December 5, 2008, "Responses to NRC Requests for Additional Information Dated November 5, 2008 Regarding Application for Renewed Operating Licenses," the applic ant submitted responses to t he staff's RAIs. In addition, the applicant provided information during a public meeting on March 2, 2009, and a previous follow-up RAI in lette r L-PI-09-047, Ap ril 6, 2009.

On May 28, 2009, the NRC staff performed an audit at the Prairie Island Nuclear Generating Station (PINGP), Units 1 and 2, related to the supporting documentation for the reactor cavity leakage. The staff reviewed the following documents:

References:

1. Dominion Energy Incor porated, "Evaluation of Effe cts of Borated Water Leaks on Concrete Reinforcing Bars and Carbon Steel Plate of the Containment Vessels at Prairie Island Units 1 and 2," R eport No. R-4448-00-01, Rev. 0. 2. Prairie Island Nuclear Generating Station, "Refueling Cavity leakage, Event Date 1988-2008," Report No. RCE 01160372-01, Volumes 1 and 2.

In order to complete our review of issues related to the PINGP reactor cavity leakage discussed in the above referenced reports, t he staff requests the following additional information:

[Note: To assist the reader, the NSPM response to each part (a through i) of the RAI is provided immediately after t he statement of each part. References applicable to all responses are listed after the response to part i.]

Follow-up RAI Part a a) Section 2.2 of Reference 1 recommends that a test be performed to determine if there is high assurance that the pH present in the wa ter between the containment steel plates and concrete is more t han 12.5. Please provide a schedule for performing this test.

NSPM Response to Part a

It is well established that boric acid will be neutralized by contact with concrete. Tests of the effects of boric acid in contact with c oncrete have shown a rapid rise in pH of the boric acid solution. (Page 3-2 of Reference

5) It has also been shown by calculations using the EPRI MULTEQ program that the equilibrium pH will be about 12.5 with excess quantities of calcium present, as would be th e case with the large amounts of calcium hydroxide in concrete. Evidence that neut ralization of boric acid has occurred in concrete at Prairie Island is provided by the pH values of 7 and 7.8 that have been measured in the active leakage. (Page 4-2 of Reference 1) To provide additional confirmation of this behavior, a simple laboratory test has been performed, as discussed below.

Response to Follow-up RAI B2.1.38 2 To provide background for the process whic h results in boric acid being neutralized when in contact with concrete, the material s that form concrete and their chemical properties are summarized below.

Concrete is a composite material consisting of a binder (cement past e) and a filler of fine and/or course aggregate parti cles that combine to form a synthetic conglomerate.

The cement is a mixture of compounds made by grinding crushed limestone, clay, sand, and iron ore together to form a homogeneous pow der that is then heated at very high temperatures to form a clin ker. After the clinker cool s, it is ground and mixed with a small amount of gypsum to regulate setting and facilitate placement. This produces the general-purpose portland cement that is mixed with water to produce cement paste that binds the aggregate particles together. Port land cements are com posed primarily of four chemical compounds: tricalcium silicate, dicalcium silicate, tricalcium aluminate, and tetracalcium aluminoferrite. The calcium silicate hydrates constitute about 75% of the mass. (Section 3, Reference 4)

The hardened cement paste consists mainly of calcium silicate hydrates, calcium hydroxide, and lower proportions of calcium sulphoaluminate hydrate.

About 20% of the hardened cement paste volume is calcium hydroxide. The pore solution is normally a saturated solution of calcium hydroxide with in which high concentrations of potassium and sodium hydroxides are pres ent. (Section 3, Reference 4)

Hardening of concrete occurs as a result of hydration, which is a chemical reaction in which the major compounds in the cement form chemical bonds with water molecules and become hydrates. Since cement is the most expensive ingredient in concrete, it is desirable to utilize the minimum amount necessary to produce the desired properties and characteristics. Aggregate typically occupi es 60 to 75% of the volume of concrete, with the balance of the concrete mix generally consisting of 10 to 15% cement, 15 to 20% water, and 5 to 8% air, if ent rained. (Section 3, Reference 4)

Tests reported in Reference 3 indicate that water of neutral pH placed in small holes drilled into concrete reaches an equilibrium pH of about 12.8 to 13.3 after one to two weeks. This is consistent with general indus try information that indicates that pore water in concrete generally has a pH of about 12.5 or higher. This pH is fully protective

of rebar (Section 4.3.2 of Refe rence 4). These results indicate that normal fresh water in contact with concrete will reach an equilibr ium pH of 12.5 or more and be protective of steel (i.e., result in insignificant corrosion). However, these results do not address the possible effects of the boron in the water on the pH. This is discussed further in the following paragraphs.

In order to more firmly establish the pH t hat will develop in sma ll volumes of borated water in contact with large amounts of concrete , a simple laboratory test was performed.

The test was performed by adding chemicals representative of those in concrete to an open beaker with a volume of one liter of deionized water at room temperature. After each chemical addition, the solution was sti rred and the pH was measured. The steps of the test and the pH values measured are shown in Tabl e 1. Comments regarding the solutions tested and the results are as follows:

Response to Follow-up RAI B2.1.38 3 Solution 1 involved the addition of calciu m oxide alone, and represents the case of water in contact with the calcium hydroxide that is pr esent in large quantities in concrete. Calcium oxide forms calcium hydroxide when dissolved in water. The measured pH of 12.05 was slightly below the normally reported equilibrium value of 12.5 for a saturated solution of calcium hydroxide, which is expected to contain approximately 1,000 ppm calcium ions (as calcium hydroxide). The slightly lower-than-expected pH is attributed to the fact that full equilibrium had not been reached when the pH measurement wa s made (i.e., the pH was measured before the calcium oxide wa s completely dissolved). Solution 2 reflects the addition of sodium, albeit at lower concentrations than calcium. The concentration of sodium adde d to the test solution was consistent with that anticipated based on informa tion reported in Reference 3 and is consistent with Reference 4 which notes that high concentrations are present in pore water. As shown in Table 1, the sodium increased the measured pH by a

small amount. Solution 3 reflects the addition of the equi valent of 3000 ppm boric acid, which is representative of the concentration present during refueling. The measured pH of 8.85 is in the expected range indicated by calculations for a case where some boron remains in solution. Solutions 4 through 8 reflect the addi tion of increasing amounts of calcium oxide. This simulates exposure over time to the exce ss amounts of calcium hydroxide that are present in the concrete. Initiall y, the excess boric acid present in solution buffers the solution pH, and calcium oxide additions have only a small effect on the resulting pH. However, the pH increases rapidly to the 12.3 range after the concentrati on of calcium oxide exceeds the stoichiometric amount needed to react with the boric acid that was initially present. Table 1 pH of Simulated Boric Acid Leakage in Contact with Chemicals From Concrete Solution Mass (g) pH CaO ppm Ca NaOH H 3 BO 3 1 1.3992 1,000 12.05 2 1.3992 1,000 3.3061 12.39 3 1.3992 1,000 3.3061 17.1585 8.85 4 6.3992 4,573 3.3061 17.1585 8.94 5 11.4016 8,149 3.3061 17.1585 9.01 6 24.7441 17,684 3.3061 17.1585 9.74 7 29.7456 21,259 3.3061 17.1585 12.28 8 34.7469 24,833 3.3061 17.1585 12.30 Response to Follow-up RAI B2.1.38 4 The primary conclusion that can be drawn fr om the test results summarized in Table 1 is that a high protective pH is reached by borated water that is in contact with excess amounts of calcium oxide. This indicates t hat a similar high pH will develop in borated water trapped between the steel containmen t vessel and the concrete since there are excess amounts of calcium hydroxide in the concrete.

The test discussed above was performed in accordance with wri tten instructions, and the results were documented following normal l aboratory practice. However, it was not performed in accordance with formal nuclear QA requirements. Nevertheless, the results are considered to be consistent with theoretical val ues and provide strong supporting evidence that high protective pH values will be reached in borated water trapped between the steel containm ent vessel and the concrete.

Follow-up RAI Part b b) Section 2.2 of Reference 1 recommends re moval of concrete inside the containment at the following locations:

i. Sump C ii. Through the wall at elevation 69 5 closer to the transfer tube

However, Northern States Power Com pany, Minnesota (NSPM) in a letter dated April 6, 2009, committed to remove concrete from Sump C only. Please clarify. In addition, please explain why removal of conc rete from Sump C is not planned during the next scheduled outages at PINGP, Units 1 and 2.

NSPM Response to Part b In reviewing the recommendations from Re ference 1 to determine the appropriate Corrective Actions to be assigned within th e Corrective Action Program, engineering management considered the value, need and sufficiency of each recommendation

provided. The review concluded that there is limited value in removing concrete from the inside diameter of the cont ainment vessel at the 697' floor elevation, as it is not known whether this area is wetted and has a pot ential for corrosion to exist. The site has instead removed the grout in the RHR su ction sump of both units as these areas are lower in containment elevation and consistently show wetting when refueling cavity leakage occurs. It is also believed the RHR sumps would be more likely than the 697' elevation to show any corrosion due to r epeated wetting and close proximity to ambient oxygen. In addition, much of the area between the transfer tube at the 715' elevation and annulus floor at the 706' elevation can be monitored by ultrasonic thickness measurement from the exterior of the contai nment vessel, further diminishing the value of removing concrete from the interior wall. Therefore, the Corrective Action assignments did not include removal of concrete at elevation 697'.

Removal of the concrete in sump C (under the reactor vessel) will be performed in the next refueling outages following the outages duri ng which the refueling cavity liners are repaired. This is primarily for logistical reasons. The estimated thickness of the Response to Follow-up RAI B2.1.38 5 concrete at the thinnest location in the floor of sump C is 16 inches with reinforcing bar both near the top of the proposed excavati on and near the containment vessel inside diameter. The work area is relatively small and in close proximity to the reactor vessel thimble tubes which provide an ASME Class 1 pressure boundary. As such, performing the excavation safely requires considerable planning and specialized tooling. The site will use the upcoming refueling outage in each Unit to survey the excavation sites, and the time between outages to plan the excava tions and secure the appropriate tools.

Follow-up RAI Part c c) Section 4.2 of Reference 1 has ident ified an upper bound loss of 0.25 inch in the 1.50 inch steel containment due to borated water corrosion over a 36 year period. Please advise if the stresses in the steel containment remain within the American Society of Mechanical Engineers Code allowable values for this loss of 0.25 inches.

According to Section 4.1 of Reference 1, minimum thickness r equired for the steel containment for all loading conditions is 1.4908 inches. In addition, please clarify if NSPM has considered the potential of cont inued reactor cavity leakage over the life extension period of 60 years.

NSPM Response to Part c The evaluation estimates the likely corrosion of the containment vessel to date at no more than 0.010". This estimate accounts for the neutralization of borated water in concrete. Recent ultrasonic thickness measurements, includ ing measurements of known wetted areas in the RHR suction sump, showed no corrosion with all thickness

readings above the nominal plate thickness. If any significant loss were identified, an ASME code evaluation w ould be required.

As discussed in section 4.2 of Reference 1, the 0.25" value of corrosion assumes continuous wetting with aerated, concentrated, boric acid ov er a period of 36 years.

This value does not consider the buffering effe ct of the concrete or the consumption of oxygen dissolved in the water. Therefore, the long term environment that could lead to this level of corrosion would not exist.

The report's reference to 0.25" as an upper bound does not clearly convey its meaning.

This value was provided for comparison purposes only to provide further support fo r the low corrosion rates expected, and does not represent an expected condi tion in a PINGP containment vessel. Therefore, an ASME Code analysis of the containment vessel which assumes loss of 0.25" of vessel wall has not been performed. Reference 1 does not suggest that a wall loss of this magnitude would leave the ve ssel capable of meeting code allowables. Indeed, the report states that any observ ed wall loss that reduced the ve ssel below the nominal 1.5" thickness would have to be evaluated in acco rdance with ASME Section XI. Reference 1 only provides the judgment that even with a wall loss of 0.25", the containment vessel would still be able to withstand a ccident pressure without a loss of containment integrity.

The areas of the steel containment vessel that are potentially subject to borated water exposure from refueling cavity leakage ar e the bottom head and sections of the shell behind concrete at the end of the refueling cavity and transfer pit (referred to in the Response to Follow-up RAI B2.1.38 6 USAR as the "cold spot"). Both the she ll and bottom head are f abricated from SA-516-70 material with a minimum tensile str ength of 70 ksi. The Pioneer Service & Engineering Company containm ent vessel stress report shows the shell and bottom head were designed in accor dance with ASME section VIII with a design pressure of 41.4 psig and a corresponding required thickness of 1.5 inch.

In accordance with ASME section VIII the design allowable membrane stress is limited to 25% of the material minimu m tensile strength, or 17.5 ksi. Allowable stresses during a Design Basis Accident (DBA) are considerabl y higher. As indicated in USAR table 12.2-22, total stresses under a DBA with Design Basis Eart hquake range from 24.48 ksi to 27.86 ksi. These stresses are approximately one half the DBA allowable stress of 52.5 ksi. Stresses are generally proportional to thickness. As such, even with thinning of 0.25 inch of the 1.5 inch shell thickness, total stresses would still be well below the stress limits for the load comb inations that combine stre sses from a DBA with those from a Design Basis Earthquake.

The site fully expects that leakage will be stopped during the next refueling outage of each unit. During the outage fo llowing the outage of repair, any water observed in Sump C will be evacuated. However, any re sidual water behind conc rete that may not be able to be evacuated would have a very sma ll stagnant volume with its pH elevated by the alkalinity in concrete. Any potential corrosion in such regions would be similar in magnitude to (or lower than) t he 0.010" conservatively estima ted for 36 years to date.

With this level of corrosion, the overall c onclusion remains valid that containment vessel integrity would be unaffected.

The site will continue to monitor the contai nment vessel and internal structures through the ASME section XI, IWE progr am and the Structures Monito ring program. If any new leakage is identified that indicates the ref ueling cavity leakage has recurred, the issue will be entered into the Corrective Action Prog ram for evaluation and identification of corrective actions.

Follow-up RAI Part d d) In Section 5.2.3 of Re ference 1, the rate of d egradation estimated for PINGP concrete is two times that used previously for Salem/Connecticut Yankee plants to account for the difference in the type of concrete aggregates at PINGP. Please advise if NSPM has performed or intends to perform any tests to confirm the use of this assumption for the degradation rate.

NSPM Response to Part d The acceleration factor of 2.0 for the increased rate of degradation resulting from the presence of about 5% carbonate-based aggregate at Prairie Island relative to the 0% carbonate-based aggregate at the cited plan ts was based on engineering judgment.

Tests of the effects of acids on reinforced c oncrete show that acids weaken concrete by dissolving cement and car bonate-based aggregate (Page 29 of Reference 4 and page 4 Response to Follow-up RAI B2.1.38 7 of Reference 6). Tests discussed in Reference 7 indicate that the weight loss experienced by cubes of concrete immersed in acid increases as the volume fraction of cement in the concrete increases. Thes e tests were performed on concrete that had non-soluble aggregate (i.e., only siliceous aggregate and no calcium carbonate-based aggregate). This increased weight loss is attr ibuted to the fact t hat, as the volume fraction of cement increases, the volume fracti on of the concrete that is soluble in acids increases. Based on this result, it is reasonabl e to assume that the effect of boric acid on concrete containing soluble aggregates will follow a similar pattern; i.e., the degradation of concrete due to boric acid will increase as the total fraction of material in the concrete that is soluble in acids increas es, whether that solubl e material is cement or aggregate.

Quantitative data in Reference 7 for weight loss of concrete cubes when exposed to an acid concentration of 3% is shown in Figure

1. A trend line is show n on the figure that provides an equation for quantifying this diss olution behavior. As can be seen, the weight loss increases somewhat more strongl y than linearly as the volume fraction of cement, (i.e., of solubl e material), increases.

Figure 1 Weight Loss in Acid vs. Volume Fraction of Cement (based on data from Reference 7)

TrendLineEquation y=0.02012x 2+1.38346x R²=0.84673 0 5 10 15 20 25 30 3505101520LossinWeight%VolumeFractionofCementDataPointsTrendLine Response to Follow-up RAI B2.1.38 8 A footnote on page 10 of Reference 4 indicates that concrete normally contains 10 to 15% of cement, or an average of about 12.5%.

As noted on page 2-2 of Reference 1, the amount of carbonaceous aggregate in the c oncrete used at Prairie Island was about 5%. Adding this 5% to the average 12.5% ce ment results in a total of 17.5% soluble material in the concrete at Prairie Island as compared to the 12.5% in a concrete with all igneous (no carbonate) based aggregate such as was used at the cited plants. (Section 8.1.3 of Reference 8) Usi ng the trend line equation shown in Figure 1, increasing the fraction of soluble material (cement in the figure, cement plus soluble aggregate in this case) from 12.5% to 17.5% increases the weight loss by a factor of 1.49. This indicates that the assumed factor of 2.

0 increase in severity of acid attack to account for the presence of 5% carbonate-based aggregate is c onservative by a significant margin (2 vs. 1.49).

Based on this result, it is considered that there is no need for additional tests to evaluate the effects of the carbonate-based aggregate used at Prairie Island.

Follow-up RAI Part e

e) Section 5.2.6 of Refe rence 1 states, "-concrete is not relied upon for tensile strength (tensile strength pr ovided by rebar)." Please explain how formation of large thru thickness cracks will affect the transve rse shear capacity of concrete slabs and walls. Shear strength of concrete is di rectly related to the tensile strength.

NSPM Response to Part e The nominal shear strength of reinforced conc rete is based on the combination of the nominal shear strength provi ded by the concrete and the nominal strength provided by shear reinforcement (steel rebar). If a re inforced concrete member were postulated to have a large idealized crack al ong the entire shear plane, the reinfo rcement would need to carry the shear force. However, there is no indication that such a crack might exist at PINGP.

The existence of a wide crack in the refuelin g cavity floor or walls that has traveled through the entire thickness of a concrete section along a single shear plane is highly unlikely. Plant operating experience has not identified any large cracks in either the Unit 1 or Unit 2 reactor containment concrete structures. The cracks that have been identified are often characterized as hairline or normal shrinkage cracks. Large through-member cracks are not reasonable to postulate at PINGP based on the plant's adherence to good design and construction practices.

The refueling pool floor slab, at its minimum, is 4'-0" thick (3'-8" of rein forced concrete and 4" of leveling grout) and contains both top and bottom reinforcement in each direction. Where water seepage from cracks has occurred during flood up of the refueling cavity, the cracks have never been described as large or wide, which is cons istent with the small amount of water that seeps from the cracks, estimated at no more than 1-2 gallons per hour. Additionally, no evidence of significant washout of material has been identified, a condition that could be indicative of the developm ent of a widening crack.

Response to Follow-up RAI B2.1.38 9Follow-up RAI Part f f) Section 5.2.6 of Reference 1 states, "Degradation of concrete by exposure to borated water can also occur at cracks in th e concrete. This could lead to loss of strength of concrete in a narrow band thr ough thickness of material." A crack across thickness of material may expose rebars to corrosion. Please expl ain how this effect is considered in determining the structural integrity of concrete walls and slabs.

NSPM Response to Part f The quotation above is from Section 5.2 of Reference 1, "Degradation of Concrete Due to Chemical Attack." This section deals with concrete degradation, and does not address rebar corrosion. Rebar corrosion is addressed in the following section, Section 5.3, "Corrosion of Rebar Caus ed by Exposure to Borated Wa ter." The specific question asked in Part f is addressed by the second bullet in Section 5.3 of Reference 1. This section indicates that the dissolution of calcium hydroxide from the concrete around rebar at cracks in the concrete might be assu med to develop conditi ons that might lead to increased rates of corrosion of the rebar. However, tests performed for the cited plants and other tests described in the open literature indicate that corrosion in such situations has been negligible, even when the low pH borated water reaching the cracks was regularly refreshed. It appears that c onditions at the rebar remain sufficiently alkaline in such situations to passivate the surface, despite the presence of refreshed borated water.

Reference 5 documents tests performed usi ng steel coupons in a refreshed boric acid solution. The relevant conclusion from the report reads as follows: "The short-term corrosion rate of reinforcing steel was observed to be about 4.2 mils/year (0.0042-inch/year) based on an exposure time of up to 56-days in an aerated boric solution with a pH in the range of 5.2 to 6.4. The corrosion rate should decrease as pH increases and oxygen content decreases under long-term conditions in the field." The tests

documented in Reference 9 were two year te sts of samples using refreshed boric acid in which the rebar was exposed to the boric acid at cracks. The main conclusion was as follows: "For a penetration period of 2 y ears, there were weak enings of the cross section of the reinforcing bars not worth bei ng mentioned by reinforcement corrosion in separation cracks penetrated by deionised water (neutral, pH 7.0) and boric acid treatment deionised water of the pH-values 5.2 and 6.1 wit h crack widths of up to approximately 0.4 mm."

The tests documented in Reference 9 are cons idered to be the most relevant since they were long term (2 year) and used realistic cracked specimens with the rebar exposed to

the boric acid in a crack. As noted in Refe rence 9, the corrosion of the rebar was "not worth being mentioned." The total exposure time of rebar cracks in the reinforced concrete under the refueling cavity at Prairi e Island is conservatively estimated as 15 days per outage for 25 outages or 375 days or 1.03 years. This is significantly less than the two year test period of Reference 9 which resulted in no significant corrosion.

Accordingly, it is concluded that no significant corrosion of rebar at cracks in the structural concrete under the refueling cavi ty has occurred at Prairie Island, and that effects of rebar corrosion at cracks in the concrete on structural integrity are insignificant. Response to Follow-up RAI B2.1.38 10Follow-up RAI Part g g) Section 5.2.3 of Reference 1 estimat ed the upper bound loss of concrete depth over a 36 year period to be 0.31 inches. Please address the impact of this loss of 0.31 inch of concrete behind the stainless steel liner plate on the load carrying capacity of the stainless steel liner plate.

NSPM Response to Part g As discussed in section 5.2.3 of the Referenc e 1, the upper bound loss of 0.31 inch is conservative as it assumes leakage ever y outage for 25 outages over a period of 36 years. There is no evidence of leakage prior to 1987 and leakage has only been observed in about half the outages due to in termittent successful leak mitigation with caulking or spray-on liner.

The impact of a potential loss of 0.31" of concrete on the load carrying capacity of the liner is minimal. The liner is effectiv ely a membrane that is backed under the bottom and around the sides with concrete that is generally four to five feet thick. As a result, the impact on the load carryi ng capacity of the refueling cavity pool structure is negligible as the material loss is, at most, le ss than 1% of the concre te thickness. Large areas of washout or dissoluti on under the liner are not expected as leak rates are small (on the order of 1-2 gallons per hour) and only occur while the refueling cavity is flooded. However, even if large areas of washout or dissolution on the order of square feet and 0.31" depth were to occur, they would only be expected to result in shallow depressions in the liner and not in a failure such as tearing of the li ner plate. The liner was constructed with the seams welded to st ainless steel structural shapes embedded in the concrete. As such, the seams ar e reinforced and are not subject to loss of concrete directly under a seam. The liner plates are 3/16" and 1/4" thick Type 304 stainless steel. Stainless steel is generally very ductile and can withstand significant elongation and deformation before failure. T he site has not experienced any observable depressions on either the floors or walls of th e refueling cavities.

Follow-up RAI Part h h) NSPM in a letter dated April 6, 2009, committed to visual inspections during the consecutive refueling outages of the ar eas where reactor cavity leakage has been observed following refueling cavity leak repairs in each unit. Which aging management program (AMP) will be used to address this issue?

NSPM Response to Part h License Renewal Commitment Number 42 from the April 6, 2009 letter reads as follows:

During the two consecutive refueling outages following refueling cavity leak repairs in each Unit (scheduled for refueling outages 1R26 and 2R26), visual inspections will be performed of the areas where reactor cavity leakage had been observed previously to confirm that l eakage has been resolved. The inspection Response to Follow-up RAI B2.1.38 11results will be documented. If refueling cavity leakage is again identified, the issue will be entered into the Correc tive Action Program and evaluated for identification of additional actions to miti gate leakage and monitor the condition of the containment vessel and in ternal structures.

The inspections of the locations which previously showed signs of refueling cavity leakage are special inspections assigned as corrective actions within the Corrective Action Program. The inspections will invoke the methodology, documentation requirements and acceptance criteria of t he Structures Monito ring Program. The Structures Monitoring Program is the appropriate program since the locations where leakage has been observed are in c ontainment interior structures.

Thereafter, as discussed in the April 6, 2009, letter, general monitoring for leakage and degradation will be perform ed in all areas of containment in accordance with the ASME Section XI, Subsection IWE Program and the Structures Monitoring Program. In addition, the Boric Acid Corrosion Pr ogram and the 10 CFR Part 50, Appendix J Program include inspections inside containmen

t. These programs contain provisions to identify, evaluate, and correct degraded conditi ons prior to loss of function, ensuring the effects of aging for plant SSCs are adequatel y managed. Periodic visual inspections are performed, and inspection schedules are pre scribed, ensuring timely identification of any degraded condition. The ASME Section XI, Subsection IWE Program also

incorporates the requirements of 10 CFR 50.55a(b)(2)(ix) fo r the examination of metal containments, including the requirement in 10 CFR 50.55a(b)(2)(ix)(A) to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in degradation to, such inaccessible areas.

During the current license period as we ll as the period of extended operation, degradation identified by thes e programs will be entered in to the PINGP Corrective Action Program for evaluation and identification of corrective actions.

Follow-up RAI Part i i) Page 52 of Reference 2 identified five recommendations to address reactor cavity leakage. Please provide NSPM's action plan and schedule for completing these five recommendations.

NSPM Response to Part i Page 52 of the Root Cause Evaluation (RCE) recommended a repair plan that includes the following steps:

1. Unbolt and set aside all mechanically fastened fixtures (RCC Change Fixture, internals stands, and guide tube supports). 2. Vacuum Box penetrations and embedment plates to locate existing leaks. Weld repair and vacuum box completed welds 3. Preemptively seal weld and vacuum box all penetrations. Response to Follow-up RAI B2.1.38 124. Vacuum Box, and/or PT weld seams and repair as needed to ensure no leakage due to stress corrosion cracking. 5. Pressure test or PT tr ansfer tube bellows attachment welds and weld repair as needed. The RCE also states that alternate approac hes can also be considered provided the final repair plan permanently and comple tely mitigates future leakage.

The RCE concluded that the most likely refueling cavity leakage points are where the anchor studs for the reactor internals stands and the Rod Control Cluster (RCC)

Change Fixture penetrate the associated embedment plates. The studs for these fixtures pass through holes in the embedm ent plates and are seal welded on the underside for the internals storage stands, and on top (then ground flush) for the RCC Change Fixture.

Pinhole leaks or small cracks in one or more of the seal welds would result in a leak path through the embedment plate along the thr eads of the studs, allowing water under the cavity liner.

The plant management review of the Root Cause Evaluation considered the value, need and sufficiency of each recommendation.

The current repair plan that emerged from these reviews is to r eplace the existing anchor nuts wit h new fabricated blind nuts that are seal welded to the existing baseplates. In addition, the existing baseplates will be seal welded to the embedmen t plates. The new welds wil l be readily accessible for examination to ensure the exis ting anchors and baseplates are leak tight. The following sketch depicts a typical RCC change fixture support showing the planned repairs.

Similar repairs will be made to the internals stands supports.

General Arrangement of Change Fixture SupportsExisting seal weld to embedment plate not accessible. Failure of weld would result in leak.Replace existing nuts with fabricated blind nuts seal welded to baseplate.Side ViewExisting 1/4" thk stainless steel cavity linerNew seal weld between baseplate and embedment plate.Existing cavity liner fillet weld to embedment plate Response to Follow-up RAI B2.1.38 13This repair strategy effectively accomplishes the goals of recommended steps 1 through 3, the intent of which is to permanently repair refueling cavity leakage, but in a more focused and dose-effective manner. The guide tube supports which ar e mounted to the refueling cavity wall were concluded to be unlikely sources of leakage and will not be

sealed in a similar manner. Although t he guide tube supports are of similar construction, past success at mitigating leak age by sealing the supports of the internals stands and RCC change fixture suggests that leakage occurs only at those locations.

Recommended step 4 is to vacuum box and/or dye penetrant test ref ueling cavity liner weld seams to ensure no leakage due to stre ss corrosion cracking. The site performed vacuum box and/or dye penetrant test of ac cessible seams of bot h units in 1998 and 1999 with no indications of cracking. N SPM does plan to examine a sample of accessible seams to ensure no cracking has occurred since the last inspection.

Recommended step 5 is to pressure test or dye penetrant test the transfer tube bellows attachment welds and perform weld repairs as needed. NSPM believes these welds are leak tight as past refueling cavity leakage has been completely mitigated through sealing only the internals stands and change fi xture anchors. As a precaution, NSPM does plan to perform pressure testing or dye penetrant testing of a ccessible portions of the transfer tube bellows welds to preclude t he possibility of water leaking along the transfer tube to the inside surfac e of the containment vessel.

All actions discussed above are planned for the next refueling outage for each unit, currently scheduled for fall 2009 for Unit 1 and spring 2010 for Unit 2.

References for NSPM Responses to Follow-up RAI B2.1.38 Parts a through i

1. Dominion Engineering, Inc. report "Evaluation of Effects of Borated Water Leaks on Concrete Reinforcing Bars and Carbon Steel Plate of the Containment Vessels at Prairie Island Units 1 and 2," report R-4448-00-01, Rev. 0. 2. Prairie Island Nuclear Generating Station, "Refueling Cavity leakage, Event Date 1988-2008," Report No. RCE 01160372-01, Volumes 1 and 2. 3. A. A. Sagües, et al., "Evolution of pH During In-Situ Leaching in Small Concrete Cavities," Cement and Concrete Research , Vol. 27, No. 11, pp. 1747-1759, 1997. 4. D. J. Naus, Primer on Durability of Nuclear Power Plant Reinforced Concrete Structures - A Review of Pertinent Factors, NUREG/CR-6927 - ORNL/TM-2006/529, Feb. 2007. 5. MPR Associates report "Boric Acid Attack of Concrete and Reinforcing Steel," MPR-2634, Revision 2, February 2009. 6. B. Kerkhoff, "Effects of Substances on Concrete and Guide to Protective Treatments,"

Portland Cement Association, Item Code: IS001, 2007. 7. N. I. Fattuhi and B. P. Hughes, "Ordinary Portland Cement Mixes with Selected Admixtures Subjected to Sulfuric Acid Attack,"

ACI Materials Journal, Technical Paper, Title no. 85*M50, Nov. Dec. 1988, p512-518. 8. MPR Associates report "Salem Generating Station Fuel Handling Building Evaluation of Degraded Condition," MPR-2613, Revision 3, February 2009. 9. W. Ramm and M. Biscoping, "Autogenous healing and reinforcement corrosion of water-penetrated separation cracks in reinforced concrete," Nuclear Engineering and Design, p191-200, v179 (1998).

Enclosure 2 Prairie Island Nuclear Generating Plant License Renewal Commitments

15 Pages Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 1 The following table provides the list of commitments included in the Application for Renewed Operating Licenses (LRA) for Prair ie Island Nuclear Generating Plant (PINGP) Units 1 and 2, as updated in subsequent correspondence.

The commitments in this list are anticipat ed to be the final commitments which will be confirmed in the NRC's Safety Evaluation Report (SER) for the renewed operating licen ses. These commitments, as confirmed in the SER, will become effective upon NRC issuance of the renewed licenses. In addition, as stated in the LRA, the final commitm ents will be incorporated into the Updat ed Safety Analysis Report (USAR).

Commitment Number Commitment Implementation Schedule Related LRA Section Number 1 Each year, following the submittal of the PINGP License Renewal Application and at l east three months before the scheduled completion of the NRC review, NMC will submit

amendments to the PINGP application pursuant to 10 CFR 54.21(b). These revisions will identify any changes to the Current Licensing Basis that materially affect the contents of the License Renewal Application, including the USAR supplements.

12 months after LRA submittal date

and at least 3

months before

completion of NRC

review Annual Update was submitted by letter

dated 4/13/09 1.4 2 Following the issuance of the renewed operating license, the summary descriptions of aging management programs and TLAAs provided in Appendix A, a nd the final list of License Renewal commitments, will be in corporated into the PINGP USAR as part of a periodic USAR update in accordance with 10

CFR 50.71(e). Other changes to specific sections of the PINGP USAR necessary to reflect a renewed operating license will also be addressed at that time.

First USAR update in accordance with 10 CFR 50.71(e) following issuance of renewed operating licenses A1.0 3 An Aboveground Steel Tanks Program will be implemented.

Program features will be as descr ibed in LRA Section B2.1.2.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.2 4 Procedures for the conduct of inspections in the External Surfaces Monitoring Program, St ructures Monitoring Program, U1 - 8/9/2013 B2.1.6 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 2 Commitment Number Commitment Implementation Schedule Related LRA Section Number Buried Piping and Tanks Insp ection Program, and the RG 1.127 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be enhanced to include guidance for visual inspections of installed bolting.

U2 - 10/29/2014 5 A Buried Piping and Tanks Inspection Program will be implemented. Program features will be as described in LRA Section B2.1.8.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.8 6 The Closed-Cycle Cooling Water System Program will be enhanced to include periodic inspection of accessible surfaces

of components serviced by closed-cycle cooling water when the systems or components are opened during scheduled maintenance or surveillance ac tivities. Inspections are performed to identify the pres ence of aging effects and to confirm the effectiveness of the chemistry controls. Visual inspection of component internals will be used to detect loss of

material and heat transfer degr adation. Enhanced visual or volumetric examination tec hniques will be used to detect cracking.

[Revised in letter dated 1/20/2009 in response to RAI 3.3.2 01] U1 - 8/9/2013 U2 - 10/29/2014 B2.1.9 7 The Compressed Air Monitoring Program will be enhanced as follows:

Station and Instrument Ai r System air quality will be monitored and maintained in accordance with

the instrument air quality guidance provided in ISA S7.0.01-1996. Particulat e testing will be revised to use a particle size methodology as specified in

ISA S7.0.01.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.10 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 3 Commitment Number Commitment Implementation Schedule Related LRA Section Number The program will incorpor ate on-line dew point monitoring. [Revised in letter dated 2/6/2009 in response to Region III License Renewal Inspection] 8 An Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be completed. Program features will be as described in LRA Section B2.1.11.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.11 9 An Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented. Program features will be as described in LRA Section B2.1.12.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.12 10 An Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualific ation Requirements Used in Instrumentation Circuits Program will be implemented.

Program features will be as descr ibed in LRA Section B2.1.13.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.13 11 The External Surfaces Monitoring Program will be enhanced as follows: The scope of the program will be expanded as necessary to include all metallic and non-metallic components within the scope of License Renewal that require aging management in accordance with this program.

The program will ensure that surfaces that are inaccessible or not readily visible during plant operations will be inspected durin g refueling outages.

The program will ensure that surfaces that are U1 - 8/9/2013 U2 - 10/29/2014 B2.1.14 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 4 Commitment Number Commitment Implementation Schedule Related LRA Section Number inaccessible or not readily visible during both plant operations and refueling outages will be inspected at intervals that provide reasonable assurance that aging effects are managed such that the applicable components will perform their intended function during the period of ex tended operation.

The program will apply physical manipulation techniques, in addition to visual inspection, to detect aging effects in elastomers and plastics.

The program will include acc eptance criteria (e.g., threshold values for identif ied aging effects) to ensure that the need for corrective actions will be identified

before a loss of intended functions.

The program will ensure that program documentation such as walkdown records, inspection results, and other

records of monitoring and trendi ng activities are auditable and retrievable. [Revised in letter dated 2/6/2009 in response to RAI B2.1.14-1 Follow Up question] 12 The Fire Protection Program will be enhanced to require periodic visual inspection of the fire barrier walls, ceilings, and

floors to be performed during walkdowns at least once every refueling cycle. [Revised in letter dated 12/5/2008 in response to RAI B2.1.15-3]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.15 13 The Fire Water System Program will be enhanced as follows:

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.16 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 5 Commitment Number Commitment Implementation Schedule Related LRA Section Number The program will be expanded to include eight additional yard fire hydrants in the scope of the annual visual inspection and flushing activities. The program will require that sprinkler heads that have been in place for 50 years will be replaced or a representative sample of sprinkler heads will be tested using the guidance of NFPA 25, "Inspection, Testing and Maintenance of Water-Based Fire Protection Systems" (2002 Edition, Section 5.3.1.

1.1). Sample testing, if performed, will continue at a 10-year interval following the initial testing.

14 The Flux Thimble Tube Ins pection Program will be enhanced as follows: The program will require t hat the interval between inspections be established such that no flux thimble tube is predicted to incur wear that exceeds the established acceptance criteria before the next inspection. The program will require that re-baselining of the examination frequency be justif ied using plant-specific wear rate data unless prior plant-specific NRC acceptance for the re-baselining was received. If design changes are made to use more wear-resistant thimble tube materials, sufficient inspections will be conducted at an adequate inspection frequency for the new materials. The program will require that flux thimble tubes that cannot be inspected must be removed from service.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.18 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 6 Commitment Number Commitment Implementation Schedule Related LRA Section Number 15 The Fuel Oil Chemistry Progr am will be enhanced as follows: Particulate contamination test ing of fuel oil in the eleven fuel oil storage tanks in scope of License Renewal will be performed, in accordance with ASTM D 6217, on an annual basis. One-time ultrasonic thickness measurements will be performed at selected tank bottom and piping locations prior to the period of extended operation.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.19 16 A Fuse Holders Program will be implemented. Program features will be as described in LRA Section B2.1.20.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.20 17 An Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented. Program features will be as described in LRA Section B2.1.21 U1 - 8/9/2013 U2 - 10/29/2014 B2.1.21 18 An Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program will be implemented. Program features will be as described in LRA section B2.1.22. Inspections for stress corrosion cracking will be performed by visual examination with a magni fied resolution as described in 10 CFR 50.55a(b)(2)(xxi)(A) or with ultrasonic methods. [Revised in letter dated 2/6/2009 in response to RAI B2.1.22-1 Follow Up question]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.22 19 The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be enhanced as follows:

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.23 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 7 Commitment Number Commitment Implementation Schedule Related LRA Section Number Program implementing procedures will be revised to ensure the components and structures subject to inspection are clearly identified. Program inspection procedures will be enhanced to include the parameters corrosion and wear where omitted. 20 A Metal-Enclosed Bus Program will be implemented. Program features will be as described in LRA Section B2.1.26.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.26 21 Number Not Used

[Revised in letter dated 3/27/2009]

22 Number Not Used

[Revised in letter dated 4/13/2009]

23 A One-Time Inspection Program will be completed. Program features will be as described in LRA Section B2.1.29.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.29 24 A One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program will be completed.

Program featur es will be as described in LRA Section B2.1.30.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.30 25 A. A PWR Vessel Internals Program will be implemented.

Program features will be as descri bed in LRA Section B2.1.32.

B. An inspection plan for reactor internals will be submitted for NRC review and approval at least twenty-four months prior to the period of extended operation.

In addition, the submittal will include any necessary revisions to the PINGP PWR Vessel A. U1 - 8/9/2013 U2 - 10/29/2014 B. U1 - 8/9/2011 U2 - 10/29/2012 B2.1.32 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 8 Commitment Number Commitment Implementation Schedule Related LRA Section Number Internals Program, as well as any related changes to the

PINGP scoping, screening and aging management review results for reactor internals, to conform to the NRC-approved Inspection and Evaluation Guidelines.

[Revised in letter dated 5/12/2009]

[Revised in letter dated 6/24/09 in response to Follow-up RAI B2.1.38] 26 The Reactor Head Closure Studs Program will be enhanced to incorporate controls that ensure that any future procurement of reactor head closure studs will be in accordance with the material and inspection guidance provided in NRC Regulatory Guide 1.65.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.33 27 The Reactor Vessel Surveillance Program will be enhanced as follows: A requirement will be added to ensure that all withdrawn and tested surveillance capsules, not discarded as of

August 31, 2000, are placed in storage for possible future reconstitution and use. A requirement will be added to ensure that in the event spare capsules are withdrawn, the untested capsules are placed in storage and maintained for future insertion.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.34 28 The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be enhanced as follows: The program will include inspections of concrete and steel components that are bel ow the water line at the Screenhouse and Intake Canal. The scope will also U1 - 8/9/2013 U2 - 10/29/2014 B2.1.35 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 9 Commitment Number Commitment Implementation Schedule Related LRA Section Number require inspections of the Approach Canal, Intake Canal, Emergency Cooling Water Intake, and Screenhouse

immediately following extreme environmental conditions or natural phenomena includi ng an earthquake, flood, tornado, severe thunderstorm, or high winds. The program parameters to be inspected will include an inspection of water-control concrete components that are below the water line for cavitation and erosion degradation. The program will visually inspect for damage such as cracking, settlement, mo vement, broken bolted and welded connections, bu ckling, and other degraded conditions following extreme environmental conditions or natural phenomena.

29 A Selective Leaching of Material s Program will be completed.

Program features will be as described in LRA B2.1.36.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.36 30 The Structures Monitoring Program will be enhanced as follows: The following structures, components, and component supports will be added to the scope of the inspections:

o Approach Canal o Fuel Oil Transfer House o Old Administration Building and Administration Building Addition o Component supports for cable tray, conduit, cable, tubing tray, tubing, non-ASME vessels, exchangers, pumps, valves, piping, mirror U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 10 Commitment Number Commitment Implementation Schedule Related LRA Section Number insulation, non-ASME valv es, cabinets, panels, racks, equipment enclosures, junction boxes, bus

ducts, breakers, transformers, instruments, diesel equipment, housings for HVAC fans, louvers, and dampers, HVAC ducts, vibration isolation elements for diesel equipment, and miscellaneous

electrical and mechanical equipment items o Miscellaneous electrical equipment and instrumentation enclosures including cable tray, conduit, wireway, tube tray, cabinets, panels, racks, equipment enclosures, junction boxes, breaker housings, transformer housings, lighting

fixtures, and metal bus enclosure assemblies o Miscellaneous mechanical equipment enclosures including housings for HVAC fans, louvers, and dampers o SBO Yard Structures and components including SBO cable vault and bus duct enclosures.

o Fire Protection System hydrant houses o Caulking, sealant and elastomer materials o Non-safety related masonry walls that support equipment relied upon to perform a function that demonstrates compliance with a regulated

event(s). The program will be enhanced to include additional inspection parameters. The program will require an inspection frequency of once every five (5) years for structures and structural Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 11 Commitment Number Commitment Implementation Schedule Related LRA Section Number components within the scope of the program. The

frequency of inspections can be adjusted, if necessary, to

allow for early detection and timely correction of negative trends. The program will require periodic sampling of groundwater and river water c hemistries to ensure they remain non-aggressive.

31 A Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program will be impl emented. Program features will be as described in LRA Section B2.1.39.

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.39 32 The Water Chemistry Program will be enhanced as follows: The program will require increased sampling to be performed as needed to confi rm the effectiveness of corrective actions taken to address an abnormal chemistry condition. The program will require R eactor Coolant System dissolved oxygen Action Level limits to be consistent with the limits established in the EPRI PWR Primary Water Chemistry Guidelines." [Revised in letter dated 12/5/2008 in response to RAI B2.1.40-3]

U1 - 8/9/2013 U2 - 10/29/2014 B2.1.40 33 The Metal Fatigue of Reactor Coolant Pressure Boundary Program will be enhanced as follows:

The program will monitor t he six component locations identified in NUREG/CR-6260 for older vintage Westinghouse plants, either by tracking the cumulative number of imposed stress cycles using cycle counting, or U1 - 8/9/2013 U2 - 10/29/2014 B3.2 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 12 Commitment Number Commitment Implementation Schedule Related LRA Section Number by tracking the cumulative fatigue usage, including the

effects of coolant environmen

t. The following locations will be monitored:

o Reactor Vessel Inlet and Outlet Nozzles o Reactor Pressure Vessel Shell to Lower Head o RCS Hot Leg Surge Line Nozzle o RCS Cold Leg Charging Nozzle o RCS Cold Leg Safety Injection Accumulator Nozzle o RHR-to-Accumulator Piping Tee Program acceptance criteria will be clarified to require corrective action to be taken before a cumulative fatigue usage factor exceeds 1.0 or a design basis transient

cycle limit is exceeded. [Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

34 Reactor internals baffle bolt fatigue transient limits of 1835 cycles of plant loading at 5%

per minute and 1835 cycles of plant unloading at 5% per minut e will be incorpor ated into the Metal Fatigue of Reactor Coolant Pressure Boundary Program and USAR Table 4.1-8.

U1 - 8/9/2013 U2 - 10/29/2014 B3.2 35 NSPM will perform an ASME Sect ion III fatigue evaluation of the lower head of the pressurize r to account for effects of insurge/outsurge transients.

The evaluation will determine the cumulative fatigue usage of limiting pressurizer component(s)

through the period of extended operation. The analyses will account for periods of both "Water Solid" and "Standard Steam Bubble" operating strat egies. Analysis results will be incorporated, as applicable, into the Metal Fatigue of Reactor U1 - 8/9/2013 U2 - 10/29/2014 4.3.1.3 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 13 Commitment Number Commitment Implementation Schedule Related LRA Section Number Coolant Pressure Boundary Program. [Revised in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

36 NSPM will complete fatigue calc ulations for the pressurizer surge line hot leg nozzle and the charging nozzle using the methodology of the ASME Code (Subsection NB) and will

report the revised CUFs and CUFs adjusted for environmental effects at these locations as an amendment to the PINGP LRA. Conforming changes to LR A Section 4.3.3, "PINGP EAF Results," will also be included in that amendment to reflect analysis results and remove references to stress-based

fatigue monitoring.

[Added in letter dated 1/9/2009 in response to RAI 4.3.1.1-1]

April 30, 2009 Commitment closed by letter

dated 4/28/09 4.3.3 37 NSPM will revise procedures for excavation and trenching controls and archaeological, cult ural and historic resource protection to identify sensitiv e areas and provide guidance for ground-disturbing activities. The procedures will be revised to

include drawings and illustrations to assist users in identifying culturally sensitive areas, and pi ctures of artifacts that are prevalent in the area of the Plant site. The revised procedures will also require training of the Site Environmental Coordinator and other personnel responsible for proper execution of excavation or other ground-disturbing activities.

[Added in ER revision submi tted in letter dated 3/4/2009] 8/9/2013 ER 4.16.1 38 NSPM will conduct a Phase I Reconnaissance Field Survey of the disturbed areas within the Pl ant's boundaries. In addition, NSPM will conduct Phase I field surveys of areas of known archaeological sites to precisely determine their boundaries. 8/9/2013 ER 4.16.2 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 14 Commitment Number Commitment Implementation Schedule Related LRA Section Number NSPM will use the results of these surveys to designate areas for archaeological protection.

[Added in ER revision submi tted in letter dated 3/4/2009]

39 NSPM will prepare, maintain and implement a Cultural Resources Management Plan (CRMP) to protect significant historical, archaeological, and cultural resources that may currently exist on the Plant site. In connection with the preparation of the CRMP, NSPM will conduct botanical surveys to identify culturally and medicinally important spec ies on the Plant site, and incorporate provisions to protect such plants into the

CRMP. [Added in ER revision submi tted in letter dated 3/4/2009] 8/9/2013 ER 4.16.2 40 NSPM will consult with a qualif ied archaeologist prior to conducting any ground-disturbing activity in any area

designated as undisturbed and in any disturbed area that is

described as potentially containi ng archaeological resources (as determined by the Phase I Reconnaissance Field Survey

discussed in Commitment Number 38).

[Added in ER revision submi tted in letter dated 3/4/2009] 8/9/2013 ER 4.16.2 41 During the first refueling outage following refueling cavity leak repairs in each Unit (scheduled for refueling outages 1R26 and 2R26), concrete will be removed from the sump C pit to expose an area of the containment vessel bottom head. Visual

examination and ultrasonic thickness measurement will be performed on the portions of the containment vessels exposed by the excavations. An assessment of the condition of exposed U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 Prairie Island Nuclear Generating Plant License Renewal Commitments Updated through 6/24/09 15 Commitment Number Commitment Implementation Schedule Related LRA Section Number concrete and rebar will also be performed. Degradation observed in the exposed containm ent vessel, concrete or rebar will be entered into the Co rrective Action Program and evaluated for impact on structural integrity and identification of additional actions that may be warranted.

[Added in letter dated 4/6/09 in response to Follow Up RAI

B2.1.38] 42 During the two consecutive refueling outages following refueling cavity leak repairs in each Unit (scheduled for refueling outages

1R26 and 2R26), visual inspecti ons will be performed of the areas where reactor cavity leakage had been observed previously to confirm that leakage has been resolved. The inspection results will be documented. If refueling cavity leakage is again identified, the issue will be entered into the Corrective Action Program and evaluated for identification of additional actions to mitigate leakage and monitor the condition of the containment vessel and internal structures.

[Added in letter dated 4/6/09 in response to Follow Up RAI

B2.1.38] U1 - 8/9/2013 U2 - 10/29/2014 B2.1.38 43 Preventive maintenance requirements will be implemented to require periodic replacement of rubber flexible hoses in the Diesel Generators and Support S ystem and in the 122 Diesel Driven Fire Pump that are exposed to fuel oil or lubricating oil internal environments.

[Added in letter dated 4/6/09 in response to RAI 3.3.2-8-1]

[Revised in letter dated 6/5/09]

U1 - 8/9/2013 U2 - 10/29/2014 Table 3.3.2-8