ML051790103

RAI Proposed Use of Alternate Source Term

ML051790103
Person / Time
Site:	Limerick
Issue date:	06/30/2005
From:	Tate L NRC/NRR/DLPM/LPD1
To:	Crane C Exelon Generation Co, Exelon Nuclear
Tate T, NRR/DLPM, 415-8474
References
TAC MC2295, TAC MC2296
Download: ML051790103 (19)

Text

June 30, 2005 Mr. Christopher M. Crane President and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 200 Exelon Way, KSA 3-E Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION, UNITS 1 AND 2 - RECOMMENDED ITEMS FOR DISCUSSION REGARDING PROPOSED USE OF ALTERNATE SOURCE TERM (TAC NOS. MC2295 AND MC2296)

Dear Mr. Crane:

By letter dated February 27, 2004, you submitted a request for amendment for the Limerick Generating Station, Units 1 and 2 (Limerick 1 and 2). The amendment would allow for the use of an alternate source term (AST) in the Limerick design basis radiological accident analysis.

We are scheduled to meet with members of your staff to discuss your proposed AST amendment on July 14, 2005. Thus far in our review of the proposed Limerick AST amendment, we have encountered several technical issues that must be resolved before we can complete our safety evaluation (SE).

Enclosed please find a draft list of questions that we believe must be addressed in order for us to complete our SE. Please note that this enclosure is neither a formal request for additional information nor is it an exhaustive list of all questions that must be resolved before completing action on the proposed amendment. We hope, however, that this list will help your staff to prepare for the upcoming meeting; we intend to use these questions to guide our discussion.

The enclosed questions were forwarded electronically to Mr. Doug Walker of your staff on June 29, 2005. If you have any questions, I can be reached at (301) 415-8474.

Sincerely,

/RA by GWunder for/

Travis L. Tate, Project Manager, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-352 and 50-353

Enclosure:

As stated cc w/encl: See next page

Mr. Christopher M. Crane President and Chief Nuclear Officer Exelon Nuclear Exelon Generation Company, LLC 200 Exelon Way, KSA 3-E Kennett Square, PA 19348

SUBJECT:

LIMERICK GENERATING STATION, UNITS 1 AND 2 - RECOMMENDED ITEMS FOR DISCUSSION REGARDING PROPOSED USE OF ALTERNATE SOURCE TERM (TAC NOS. MC2295 AND MC2296)

Dear Mr. Crane:

By letter dated February 27, 2004, you submitted a request for amendment for the Limerick Generating Station, Units 1 and 2 (Limerick 1 and 2). The amendment would allow for the use of an alternate source term (AST) in the Limerick design basis radiological accident analysis.

We are scheduled to meet with members of your staff to discuss your proposed AST amendment on July 14, 2005. Thus far in our review of the proposed Limerick AST amendment, we have encountered several technical issues that must be resolved before we can complete our safety evaluation (SE).

Enclosed please find a draft list of questions that we believe must be addressed in order for us to complete our SE. Please note that this enclosure is neither a formal request for additional information nor is it an exhaustive list of all questions that must be resolved before completing action on the proposed amendment. We hope, however, that this list will help your staff to prepare for the upcoming meeting; we intend to use these questions to guide our discussion.

The enclosed questions were forwarded electronically to Mr. Doug Walker of your staff on June 29, 2005. If you have any questions, I can be reached at (301) 415-8474.

Sincerely,

/RA by GWunder for/

Travis L. Tate, Project Manager, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-352 and 50-353

Enclosure:

As stated cc w/encl: See next page DISTRIBUTION:

PUBLIC PDI-2 R/F DRoberts TTate MOBrien OGC ACRS GHill (4) TBoyce RDennig MShanbaky DLPM DPR MBlumberg Accession Number: ML051790103 OFFICE PDI-2/PM PDI-2/LA PDI-2/SC NAME GWunder for TTate MOBrien DRoberts DATE 6/30/05 7/01/05 6/30/05 Official Record Copy

The following questions apply to both units unless otherwise noted. References to Attachments of the cover letter refer to your February 27, 2004, application:

1. What design-basis parameters, assumptions or methodologies (other than those provided in the February 27, 2004, submittal) were changed in the radiological design-basis accident analyses as a result of the proposed change? If there are many changes it would be helpful to compare and contrast them in a table. Also, please provide a justification for any changes.

2. Based upon a preliminary review of the proposed amendment we are unable to match the calculated doses to the accident analyses. It would be helpful if the licensee would provide their design-basis accident calculations.

3. Attachment 8 to the application, Table 11b does not appear to include a leakage pathway currently in the LGS design basis. Per the Limerick UFSAR Section 15.6.5.5.1.2, Fission Product Transport to the Environment, states that:/*

In accordance with this guidance, and as explained in Section 6.5.3, the LGS [Limerick Generation Station] evaluation assumes that the mechanisms discussed above will ensure the assumed 50% mixing within the large reactor enclosure at all times during the period when the reactor enclosure pressure is above minus 1/4 inch, as well as when it is below. However, it will also be conservatively assumed that there is unfiltered exfiltration at 2500 cfm, in addition to the SGTS exhaust, during periods when the pressure is above minus 1/4 inch wg.

a) This pathway does not appear to be considered. Please include this pathway or provide adequate justification for not including it.

4. Attachment 1, page 42 of 76, Table A provides a list of sections within Regulatory Guide 1.183 and states the licensees conformance to those sections. For Regulatory Guide Section 4.1.2 it states that the licensee conforms with this section. A review of what the licensee proposes indicates that strict conformance with the regulatory guide for this section does not appear to be correct. The regulatory guide states:

"4.1.2 The exposure-to-CEDE factors for inhalation of radioactive material should be derived from the data provided in ICRP Publication 30, Limits for Intakes of Radionuclides by Workers (Ref. 19). Table 2.1 of Federal Guidance Report 11, Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion (Ref. 20), provides tables of conversion factors acceptable to the NRC staff. The factors in the column headed effective yield doses corresponding to the CEDE."

Reference 20 is K.F. Eckerman et al., Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion, Federal Guidance Report 11, EPA-520/1-88-020, Environmental Protection Agency, 1988.

The licensee proposed new definition is:

Enclosure DOSE EQUIVALENT I-131 shall be that concentration of I-131, microcuries per gram,

2 which alone would produce the same inhalation committed effective dose equivalent (CEDE) as the quantity and isotopic mixture of I-131, I-132, I-133, I-134, and I-135 actually present. The inhalation committed effective dose equivalent (CEDE) conversion factors used for this calculation shall be those listed in Table 2.1 of Federal Guidelines Report 11, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion," ORNL, 1989, as described in Regulatory Guide 1.183. The factors in the column headed "effective" yield doses corresponding to the CEDE.

Provide an explanation of why this conforms if the ORNL 1989 report is different from the Reference 20 in the regulatory guide. Provide justification for the values used and provide the values.

5. Attachment 1, page 57, Section 6.1, states that the activity released through the MSIVs is the same concentration as that used for evaluating Primary to Secondary Containment leakage. Regulatory Guide 1.183, Section 6.1 states that the leakage should be assumed to be that activity determined to be in the drywell. These assumptions appear to be inconsistent. Previously, when using the TID source term an assumption that the mixing between the drywell and wetwell is instantaneous and not mechanistically modeled may have been found acceptable. Using the AST non-mechanistic modeling is likely not to be found acceptable.

The staff does not believe the explanation provided in the comments section of page 57 are compatible with the timing assumptions modeled with the AST. Please provide more information sufficient to model the time dependent activity used as a source term for the MSIV leakage.

a. Explain whether the free space in the suppression pool is used to dilute this activity. If so provide justification for using this volume and also provide the drywell to suppression pool free space flow rates versus time and the basis for the flow rate used.

b. Is any drywell to wetwell flow based on the results of thermal-hydraulic analyses performed for the duration of the release? If so, provide a summary of the analyses for staff review, or

c. Provide justification for this assumption for the duration of the release.

6. Attachment 1, page 25, Section 4.4.3 provides conflicting information. Throughout the submittal it is stated that the suppression pool pH is maintained greater than 7. Page 37, Table 15 states that the initial suppression pool pH is 5.3 and that the SLC injection is assumed to occur within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Please justify how with an initial pH at 5.3 and SLC initiation at 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> the statement can be made that throughout the 30 day accident that the suppression pool pH is greater than 7?

7. Attachment 1, page 11 of 76 states that the LGS post-LOCA direct shine dose from the Unit 1 14" diameter core spray pipe can be managed using administrative controls within the 0.22 rem. Attachment 1, Page 12 of 76 states that "other sources such as reactor

3 enclosure airborne and external cloud and RERS, SGTS, and CREFAS filters are negligible because of shielding, distance or both." Provide the assumptions, methods, inputs for these analyses, a quantified value for what is considered negligible, and the results of the shielding analyses.

8. In Attachment 6, page 1 Exelon makes a commitment to NUMARC 93-01, Revision 3, Section 11.3.6.5, rather than Section 11.2.6 as specified in TSTF-51, Revision 2. While these sections appear to be similar please describe why Section 11.3.6.5 is a valid substitution for the section stated within the TSTF.

9. Attachment 1, page 12, Section 4.3.1 states that the releases for the radiological consequences analyses are evaluated at full power conditions. Justify why other conditions were not evaluated to determine the most limiting release conditions.

10. Appendix B to Title 10 of the Code of Federal Regulations (10 CFR), Part 50, establishes quality assurance requirements for the design, construction, and operation of those structure, system, and components (SSCs) that prevent or mitigate the consequences of postulated accidents that could cause undue risk to the health and safety of the public. Appendix B, Criterion III, Design Control, requires that design control measures be provided for verifying or checking the adequacy of a design.

Appendix B, Criterion XVI, Corrective Action, requires measures to be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, defective material and equipment, and nonconformances are promptly identified and corrected. GL 2003-01, Control Room Habitability, addresses current issues with respect to previously assumed values of unfiltered inleakage. Generally, these issues can only be resolved by inleakage testing.

Exelon requested a change in the design basis of the control room HVAC system.

Exelon requests no longer to credit the automatic initiation of the radiation isolation mode. With no credit for this initiation, during the initial 30 minutes of the accident, the control room HVAC operates in the normal mode rather than in the radiation isolation mode. The licensee assumed that in this mode 525 cfm of unfiltered inleakage in addition to the normal 2100 cfm of unfiltered inleakage is transferred into the control room. According to the Limerick 1 and 2 response to GL-2003-01, this mode of operation does not appear to have been tested for inleakage. In light of the Appendix B requirements and GL 2003-01, provide sufficient justification to explain why the value assumed for your control rooms unfiltered inleakage is appropriate for this proposed license amendment. Provide details regarding control room, design, maintenance and assessments or tests to justify the use of this number. Because of the high percentage of control rooms that have historically been unable to successfully predict the amount of unfiltered inleakage, the staff will generally only accept a measured value.

11. Starting on page 17 of Attachment 1 of their application, Exelon describes the methodology used to calculate the leakage from the primary containment into the Main Steam Lines. At upstream conditions the flow rate out of the MSIVs is adjusted by the MSIV surveillance pressures. This method does not appear to be appropriate since it does not consider the accident conditions in the drywell. Methods acceptable for calculating the accident pressures in the drywell typically use the design pressure for

4 this calcualtion. Please justify the methodology used.

12. Page 18 of Attachment 1 states that the inboard steam line, outboard steam line and condenser effective filter efficiencies are calculated using AEB-98-03 formulations and settling and deposition velocities. The discussion and the data provided are insufficient to support an NRC staff confirmation. Please provide the following information.

a. On page 19 of Attachment 1 of your submittal, you state that your submittal is in "based" upon the methodology used in AEB-98-03.

If the analysis is based upon, but did not use the entire methodology, please describe what differences there are between the model used and the AEB-98-03 model. Please justify any differences between the two models.

b. A single-line sketch of the four main steamlines and the isolation valves.

Annotate this sketch to identify each of the control volumes assumed by Exelon in the deposition model.

c. A tabulation of all of the parameters input into the AEB-98-03 model for each control volume shown in the sketch (and time step) for which Exelon is crediting deposition. This includes:

• Flow rate

• Gas pressure

• Gas temperature

• Volume

• Inner surface area

• Total pipe bend angle Note: Attachment 8, Table 4 provides some of this information but neither the paper or the electronic copy of this file are legible.

d. For each of the bulleted parameters in this question, provide a brief derivation and an explanation of why that assumption is adequately conservative for a design-basis calculation. Address changes in parameters over time, e.g., plant cooldown.

e. Page 46 of Attachment 1, Table A, Section 5.1.2 states that the Exelon analysis conforms to Regulatory Position 5.1.2. Clarify if your analysis addresses a single failure of one of the MSIVs. Such a failure could change the control volume parameters that are input in the deposition model. Previous implementations of main steam deposition have been found acceptable only if the licensee had modeled a limiting single failure. Confirm that the limiting MSIV single failure has been modeled and describe which failure was taken and justify why this is the limiting failure.

f. Since the crediting of main steamline deposition effectively establishes the main steam piping as a fission product mitigation system, the staff expects the piping

5 to meet the requirements of an ESF system, including seismic and single failure considerations. Please confirm that the main steam piping, condenser and the isolation valves that establish the control volumes for the modeling of deposition were designed and constructed to maintain integrity in the event of the safe shutdown basis earthquake for Limerick. If the design basis for the piping and components does not include integrity during earthquakes, please provide an explanation of how the Limerick design satisfies the prerequisites of the staff-approved NEDC-31858P-A, BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems.

If piping systems and components at Limerick were previously found by the staff to be seismically qualified using the methodology of this BWROG report, please provide a specific reference to the staffs approval.

g. Page 19 of Attachment 1 states: "For aerosol settling, only horizontal piping runs are credited, and only the bottom surface area is considered available." If only horizontal piping runs are credited, justify using the surface area of the bottom half of the pipe for aerosol deposition when the cross sectional edges of this piping are essentially vertical or inclined.

h. Page 10 of Attachment 8 states: For the two bounding steam lines modeled, two nodes are used. Please specify which two steamlines are bounding and specify how they were chosen and why they are bounding.

i. Table B contained on page 53 of Attachment 1 states that a previous analysis based upon TID-14844 based source terms assumed a recirculation line break.

The design Loss of Coolant Accident (LOCA) analyses are required by regulation to consider a spectrum of break locations and break sizes. Proposals to credit deposition in the main steam lines need to consider the impact of the break location on steam line deposition. In light of crediting this deposition justify why a break of a main steam line is not considered and why the recirculation line remains bounding or consider the break in the most limiting reactor coolant system location. Note that although thermodynamic analyses may show that significant cored damage is unlikely for a reactor coolant system break in the steam line, a LOCA involving a recirculation piping break is similarly unlikely to cause significant core damage. Nonetheless, the regulatory guidance for a design basis LOCA assume a substantial release of fission products as a means of assessing the ability of the containment design to mitigate the consequences of a LOCA in the unlikely event the Emergency Core Cooling System should fail.

As such, the break location and size are not determinants for the amount of fuel damage assumed to occur in the stylized design basis analysis.

j. Page 20 of Attachment 1 states: "Iodine resuspension from settled or deposited iodines is not calculated. Historically, this phenomena increased organic iodine release by about a factor of two based on resuspension of TID-14844 based elemental iodine fractions. The presence of this phenomenon is questionable with aerosols with significant cesium loadings. Furthermore, while deposition on condenser tubing is not formally credited, test cases have shown that substantial

6 removal of elemental and even organic iodine would be predicted that would more than offset any resuspension. Flow rates out of the condenser are assumed to be at 120 deg. F and atmospheric pressure. A factor of 1.25 is applied, as is done with leakage and flow through steam lines. This leak rate is also reduced by 50% after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, consistent with the change in Containment conditions."

The staff believes that the above information does not provide adequate justification for changing the historical basis for organic iodine resuspension.

Provide additional information to justify not utilizing the historical resuspension.

This information should provide the mechanics for changing the current methodology. As a minimum the information previously used to determine the factor of two should be examined and LGS should provide a complete assessment of why the previous assessment is no longer applicable.

If reliance on the condenser tubing is being used to offset the change in methodology then provide a justification that this is conservative. Please confirm that the condenser piping credited is designed and constructed to maintain integrity in the event of the safe shutdown basis earthquake for Limerick. If the design basis for the piping and components does not include integrity during earthquakes, please provide an explanation of how the Limerick design satisfies the prerequisites of the staff-approved NEDC-31858P-A, BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems. If the condenser piping systems and components at LGS were previously found by the staff to be seismically qualified using the methodology of this BWROG report, please provide a specific reference to the staffs approval.

13. Page 46 of Attachment 1, Table A, Section states that the Exelon analysis conforms to Regulatory Position 5.1.2. For each design basis accident analyzed please provide:

a. The single active component failure that results in the most limiting radiological consequences and justify why it is the most limiting.

b. The assumptions regarding the occurrence and timing of a loss of offsite power and justify why it provides the most limiting radiological consequences.

14. Based on information provided in the application, the licensee has assumed an MSIV leakage rate of 0.668 cfm for the 100 scfh lines (0.834 cfm with 25% designer margin included). The leakage rate is reduced after 24 and 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> based upon changing steam line temperatures. The staff believes that these values are understated. When the proposed MSIV leakage, in scfh, at test conditions (typically 70 degrees and 25 psig) are scaled to peak drywell pressure and temperature (typically 40-50 psig and about 340 degrees) the TS leakage past the inboard MSIV has been shown to be 2.0 cfm, about double the value they have assumed. However, the temperature of the fluid in the steam lines is based on the steam piping temperatures, typically 500-600 degrees (558 degrees F for 0-24 hours for Limerick). At the steam piping conditions, the flow is even higher. Likewise a pressure gradient will exist from the first closed MSIV to the end of the last deposition. The gradient would depend on the actual leakage through each MSIV. As such the deposition nodes downstream of the first MSIV conservatively may be assumed to be at atmospheric pressure. Therefore, these flow rates would be even higher. While the trend of increasing flowrates is reflected in Table 4 of the submittal

7 (Attachment 8, page 12) the absolute values calculated by the licensee are smaller than expected when compensating for the changes in temperature and pressure. The equation provided in Attachment 8, page 9 does not adequately compensate for the leakages in the steam line nodes and is not acceptable to the NRC staff. Likewise the arbitrary 25% designer margin added, while conservative, does not compensate for the expected flow rates.

a. Please provide the methodology used to calculate the flow rates in each steamline node and the parameters used. Justify how these parameters conservatively model the changing conditions in the steam line or provide calculations that conservatively account for these steam line condition changes.

b. Attachment 1 page 18 states: "However, to provide design margin, the above leak rate is increased by 25% for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to a value of 0.834 cfm. This margin also allows MSIV leakage to be reduced by 50% at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />." Please explain how the design margin allows the MSIV leakage to be reduced by 50% at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. Page 11 of Attachment 8 provides a generic assessment of the steam line temperatures following a LOCA. Provide justification why this generic assessment is applicable and conservative for Limerick. Provide the references 28 and 29 and verify whether these are actually references 7.28 and 7.29 as stated in the amendment request.

15. Attachment 1, page 24, a value for the ECCS flash fraction is given as 1.39% as opposed to 10% in the RG 1.183 Section 5.5. LGS states that a smaller amount (than the RG) was determined using a method approved for the Clinton Power Station.

Please explain why this method is acceptable for Limerick. Is this value in your current licensing basis or is this a new value? If the value is new please provide the details used to calculate this value. Also please provide the following:

a. Although the analysis includes a limiting pH, no specific details regarding the pH history versus time are provided. Please provide the iodine concentration in the sump versus time. Provide the pH vs. time or the pH assumed for the duration of the accident. Justify the pH and iodine concentration used. Provide the area ventilation rates that the ECCS leakages are exposed to.

b. The ORNL study cited in the Clinton AST submittal is based upon theoretical calculations for the design of reactor containment spray systems. The staff questions the applicability of this methodology. Many of the release mechanisms and other plant-specific issues have not been addressed. These issues create notable uncertainties in how much iodine is available for release. Major uncertainties exist to what extent the chemicals within the leakage will interact with the release environment and lead to a great reduction in its vapor pressures.

The production of elemental iodine is related to the pH of the water pools. A major uncertainty in fixing the production of volatile iodine chemical forms is due to uncertainty in the extent of evaporation to dryness. Experts believe that up to 20% of the iodine in water pools that has evaporated would be converted to a

8 volatile form (most likely as elemental iodine). Uncertainties also depend upon the environment where the fluid is leaked and the way the fluid is leaked (misting etc.). Fluid pH shifts may occur due to interactions with components, cable jackets, concrete and radiation. None of these issues has been addressed for Limerick.

16. From the Limerick UFSAR, Table 6.2-4a, (stated as Rev. 11), the minimum suppression pool free airspace is given as 147,670 cubic feet. Typically, a Mark II suppression pool free volume is on the order of hundreds of thousands of cubic feet so the staff has taken the UFSAR number to be a typo and the decimal to be a comma.

Justify the use of 159,540 cubic feet provided in Table 3, on page 31 of Attachment 1.

Why is the more conservative UFSAR value not valid for the LOCA analysis?

17. Page 61 of Attachment 1, Table C, contains a comparison of the Limerick analysis to Section 2.0 of RG 1.183. The LGS analysis column of this table states that it conforms with RG 1.183, but this RG does not find the use of a Decontamination Factor (DF) of 200 acceptable for less than 23 feet of water covering a damaged fuel assembly.

a. Please provide the DF used for 21.6 and 22.6 feet of water and the parameters, methodology and justification used to calculate this value.

b. Justify the statement: "The conservatively determined damage over the spent fuel pool is 70% of the reactor vessel." Provide the analysis used to justify this statement.

c. The UFSAR Fuel Handling analysis states that 212 are assumed damaged as the result of the fuel handling accident. Attachment 1, page 60 states that based upon a generic evaluation of GE11 and GE14 fuel, with heavy mast yields 172 failed rods. Is this a change? If so, please justify. If not, where is it substantiated?

18. Attachment 1, page 45, Section 4.2.3 states that the models used to transport radioactive material into and through the control room, and the shielding models used to determine radiation dose rates from external sources, should be structured to provide suitably conservative estimates of the exposure to control room personnel. It states that the Limerick analysis conforms to this guidance.

a. Attachment 8, page 7 states that RADTRAD was used to determine the core spray line dose rates. The 60 radionuclides that are contained in the RADTRAD code were selected based upon a study that determined that those 60 radionuclides have the greatest impact on offsite dose. Confirm that the most conservative radionuclides were used to determine the source for the Limerick shielding studies for the shine doses from external sources to the control room.

Provide the source terms used and the geometry and materials used in these shielding studies.

b. Attachment 8, page 6 states that a zone is identified where controls are practical and suggests that the maximum boundary dose (at the inside control room wall)

9 from outside sources should not be used to determine the limiting control room dose. Administrative controls and occupancy factors within zones seem to be credited. The value added to the control room dose from gamma shine is .22 Rem, which appears to correlate to a dose 18 feet from the wall.

The above described methods and assumptions are inconsistent with your current licensing bases. UFSAR Section 6.4.2.5 states that shielding is designed for continuous occupancy. Section 12.3.2.3 states:

The shielding thicknesses are selected to reduce the aggregate radiation level from all contributing sources below the upper limit of the radiation zone specified for each plant area. Shielding requirements are evaluated at the point of maximum radiation dose through any wall. Therefore, the actual anticipated radiation levels in the greater region of each plant area are below this maximum dose and therefore below the radiation zone upper limit.

The staff does not find the proposed practice acceptable. Access is needed to these locations. Administrative controls within the control room boundary are not an adequate substitute for potentially inadequate shielding. The staff believes that this is not consistent with the licensees stated conformance with Regulatory Position 4.2.3 of Regulatory Guide 1.183. Please include the maximum doses from these external sources consistent with your current licensing basis or provide additional justification why such deviations from standard shielding practices are unavoidable and necessary.

c. The licensee states that MicroShield was used to determine the doses from the external piping. How is the impact of scattering considered? Justify not modeling scattering off piping, air, etc... if this is not considered or include the impact of scattering in your assessment.

d. Provide the information necessary to model the shine from this pipe. This should include the geometry (drawings, piping, etc), source term, materials, and assumptions used to determine the doses given on page 7 of Attachment 8. A copy of the calculation would be helpful.

e. UFSAR Section 6.4.4.1 states: Control room shielding design, based on the most limiting radiological accident (design basis LOCA) is discussed in Section 12.3. The evaluations in Chapter 12 demonstrate that radiation exposures to control room personnel originate from containment shine, external cloud shine, and containment airborne radioactivity sources. Total exposures resulting from the worst radiological accident are below the dose limits specified by GDC 19; the portion contributed by containment shine and external cloud shine is reduced to a small fraction of the walls which surround the control room.

Page 6 of Attachment 8 to the application states that historically the dose due to the core spray piping and other lesser piping contributors is 4.2 rem whole body.

The licensee also states that the "Other sources such as reactor enclosure airborne and external cloud and RERS, SGTS, and CREFAS filters are negligible because of shielding, distance or both.

10 The staff is uncertain if the licensee is requesting a change to the bases for current shine analysis for piping and sources other than the containment spray piping. If parameters or assumptions have changed, please provide the bases for the sources used, the parameters used for this reevaluation, any assumptions used and the results of the analyses.

19. Table 11c, page 24, of Attachment 8 to the application indicates that pathway 6" provides a flow path from node 5 to node 3. Table 11a does not provide a description of node 5. Please provide a description of node 5 (as is done with nodes 1 through 4) and describe how this is different from node 2. If node 5 is the same as the node 5 described in Table 13a of Attachment 8, justify the use of a node for the SGTS.

Typically, the SGTS is modeled as a transfer pathway rather than a node. Confirm this model yields conservative results.

20. More detail regarding the main steam line break (MSLB), fuel handling, and control rod drop accidents is needed. Please provide all assumptions, inputs, models and methodologies used to calculate the offsite and control room doses. Please include answers to the following questions:

What is the reactor coolant system (RCS) activity used for the MSLB analysis? Provide the assumptions, input and methods used to determine this activity.

The second bulleted item on page 20 of Attachment 1 to the application states that the activity in the steam cloud is based on the total mass of water released from the break.

Confirm that the total activity released for this accident is the RCS specific activity times the break discharge mass (103, 785 lbm). If this is not the methodology used, please provide more detail regarding the model utilized. Also, provide the input parameters used to calculate and justify the fraction of liquid water contained in the steam and the flashing fraction of liquid water released.

21. In Attachment 1, page 35, Table 8, a value of 0.77% damaged fuel with melt is provided for the control rod drop accident (CRDA). The value typically used for fuel melt with General Electric 14 fuel is 1% for the CRDA. Please confirm this value of 0.77% and justify the value if this is a change to your licensing bases.

22. Please provide the equivalent atmospheric dispersion factors used for the Main Steamline Break Accident.

23. Attachment 1, page 16 states that: "Infiltration following isolation is assumed to be 525 cfm of unfiltered inleakage, which includes impacts of ingress and egress." Confirm that the 525 cfm includes 10 cfm for the ingress and egress into the control room after a LOCA.

24. Comments provided for Section 5.1.3 in Attachment 1, page 47 state that "conservative assumptions are used."

a. Confirm that the control room and SGTS HVAC flow rates assumed in the

11 accident analysis (including control room doses) are conservative, and use the range of flow rates allowable by Technical Specifications to make this determination.

25. The proposed change to Technical Specification 3.6.5.1.2 (Refueling Area Secondary Containment Integrity) will no longer require that the secondary containment be operable during the movement of fuel assemblies that have a decay period of at least 24-hours.

The FHA analysis assumes the release to the control room intake and the environment is through the turbine building/reactor building (TB/RB) ventilation south stack. Please justify that a FHA release through the TB/RB ventilation south stack is an appropriately conservative assumption given that the secondary containment may be inoperable.

Include general arrangement drawings in your response showing the potential release points.

26. Please explain in detail the methodology used to model steam cloud transport for the MSLB accident. Please also provide the resulting control room P/Q values provided as input to the RADTRAD model.

27. The inleakage of unfiltered air into the control room (which can occur through the control room boundary, system components, and backflow at the control room doors) was modeled using the control room intake P/Q values. Please verify that there are no potential unfiltered inleakage pathways during the normal operation mode, radiation isolation mode, and chlorine isolation mode that could result in P/Q values that are higher than the control room intake P/Q values.

28. Provide a curve of containment pressure as a function of time for the large break LOCA to verify that the containment pressure decreases to less than 50% of its peak value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

29. In Technical Specification (TS) Section Tables 3.3.2-1, Isolation Actuation Instrumentation Action Statements and TS Section Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Requirements does the instrumentation referenced in the proposed change provide protection for an area that is common to both units and as such would still be required when either unit was operating even though the other unit is in refueling? Would the alarm capability of this instrument be available even if the actuation function were removed? Does the removal of this function support the monitoring requirements of GDC-64? Are procedures available that will manually isolate in lieu of the automatic isolation that is to be removed?

30. In TS Section Table 3.3.7.1-1, Radiation Monitoring Instrumentation and TS Section Table 4.3.7.1-1, Radiation Monitoring Instrumentation Surveillance Requirements, would this instrumentation still be operable if either unit were operating since the control room is common to both units? Would the alarm and isolation functions still be required since an accident at the operating unit could affect the habitability of the main control room?

31. In TS Section 3.6.5.2.2, Refueling Area Secondary Containment Automatic Isolation Valves, although the TSTF-51 program allows certain engineered safety feature (ESF) functions to be inoperable, such as the automatic isolation feature, it still requires the

12 ability to isolate the secondary containment in order to meet the objectives of NUMARC 93-01. Will the ability to isolate the containment be retained if the automatic feature is disabled? If the secondary cannot be isolated, how will the station meet the intent of GDC-64 in monitoring releases and GDC 61 intent of controlling releases through containment, confinement, or filtering.

32. In TS Section 4.6.5.3, Standby Gas Treatment System - Common System, the staff notes that the technical specification cited references Regulatory Guide 1.52, Revision

2. Revision 2 states the maximum penetration for a 2-inch carbon adsorber should be less than 1%. The staff has issued Revision 3 which allows a penetration of 2.5% for a 2-inch bed filter. The staff would accept either of these penetration if the appropriate Regulatory Guide Revision was referenced and all other conditions of the Regulatory Guide 1.52 are met. Are there extenuating circumstances where the conditions of the Regulatory Guide are not being met? Is this filter larger than a 2-inch bed filter? Is there a specific need to retain Regulatory Guide 1.52, Revision 2 and exceed the maximum penetration limits shown in Table 2?

33. In SR 4.6.5.4.a, how does this reactor enclosure recirculation system flow rate compare to the design flow rate of the system used in the evaluation of design basis accidents?

Are there any reasons why the design flow rate (rated flow) of the system should not be specified? Would this allow testing at a flow rate that was significantly lower than the design flow rate for its intended service?

34. In SR 4.6.5.4.b.1, SR 4.6.5.4.d.1, SR 4.6.5.4.e, and SR 4.6.5.4.f, the changes appear to be editorial. Do they provide for doing anything different from the way it is done now?

35. In SR 4.6.5.4.b.2 and in SR 4.6.5.4.c, the existing penetration of 2.5% is the maximum allowable penetration for a 2-inch filter based the conditions of Regulatory Guide 1.52, Revision 3. The TS references Revision 2. Increasing the value to 15% would be unacceptable to the staff without additional justification. The 15% penetration indicates that the carbon adsorber is in a degraded state. Regulatory Guide 1.52 values are based on clean carbon adsorbers. The staff does not have data to show how quickly carbon adsorbers degrade once they are in a degraded state. Although the analysis may show that a 15% penetration would be acceptable, there is an increased uncertainty that the filters would still be acceptable at the end of the inspection interval. The fact that the filters have reached the degraded state may indicate that some operational changes need to be made to prevent filter degradation. Please provide data to justify the filter performance from a 15% degraded state for the entire inspection interval or justify this change by other information.

36. In SR 4.6.5.4.b.3, the subsystem flow rate affects the clean up rate for filtration and should be established at the flow rate credited for the subsystem in any analyses.

Please clarify why a large range is needed and why the flow rate cannot be closely tied to the values used in the design basis analyses.

37. In TS Section 3.7.1.2, Emergency Service Water System - Common System, and TS Section 3.7.1.3, Ultimate Heat Sink, the staff is concerned that the proposed change does not expand the definition as stated. In reality, it narrows the definition by excluding fuel that is not recently irradiated. This has the effect of eliminating

13 applicability after the time recently has passed (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). The relaxations that have been granted through TSTF-51 were based on satisfying the requirements of the fuel handling accident. Have other potential transients that would require the use of either the emergency service water or ultimate heat sink been evaluated to assure that eliminating this applicability is justified? Please provide additional justification for this change.

38. In TS Section 4.7.2, Control Room Emergency Fresh Air Supply System - Common System, the existing penetration of 2.5% is the maximum allowable penetration for a 2- inch filter based the conditions of Regulatory Guide 1.52, Revision 3. The TS references Revision 2. Increasing the value to 10% would be unacceptable to the staff without additional justification. The 10% penetration indicates that the carbon adsorber is in a degraded state. Regulatory Guide 1.52 values are based on clean carbon adsorbers. The staff does not have data to show how quickly carbon adsorbers degrade once they are in a degraded state. Although the analysis may show that a 10%

penetration would be acceptable, there is an increased uncertainty that the filters would still be acceptable at the end of the inspection interval. The fact that the filters have reached the degraded state may indicate that some operational changes need to be made to prevent filter degradation. Please provide data to justify the filter performance from a 10% degraded state for the entire inspection interval or justify this change by other information. Please provide additional justification for changing to a manual initiation of the radiation mode of the control room emergency fresh air system.

Regulatory Guide 1.183 states that modifications proposed for the facility generally should not create a need for compensatory programmatic activities, such as reliance on manual operator actions.

39. Please provide a description of the analysis assumptions, inputs, methods, and results that show that a sufficient quantity of sodium pentaborate can be injected to raise and maintain the suppression pool greater than pH 7 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the start of the event.

(See also Position 2 of Appendix A to RG 1.183.) In your response, please discuss the adequacy of recirculation of suppression pool liquid via emergency core cooling system (ECCS) through the reactor vessel and the break location and back to the suppression pool in meeting the transport and mixing assumptions in the chemical analyses.

Assume a large break loss-of-coolant accident (LOCA).

In responding to this question, please indicate the source and volume flow rate of water that mixes with the sodium penetaborate and washes it from the vessel to the suppression pool. A diagram showing the injection point of the sodium pentaborate, the flow path through the core, and the exit path from the vessel would be helpful. The staff is interested in assuring that the core ECCS flow does not bypass the region of the vessel that contains sodium pentaborate and that sufficient sodium pentaborate will be transported to the suppression pool.

40. The submittal states that Limerick is committing to NUMARC 93-01 which requires prompt closure of containment and control of releases from fuel handling accidents (FHA). NUMARC 93-01 states in part that, these prompt methods need not completely block the penetrations nor be capable of resisting pressure, but are to enable the ventilation systems to draw from the postulated FHA such that it can be treated and monitored. Please describe the prompt methods and the degree of closure that will be

14 achieved. How much of an open area to the environment would be permitted? Also describe the ventilation systems that would be used to draw the release from the postulated FHA. Specifically, are the ventilation systems ESF systems, do they have carbon adsorber filters and HEPA filters, are they tested in accordance with Regulatory Guide 1.52 or other standards, and do they have sufficient drawing capacity to assure that air flow is from environment to the containment?

Would there be a test to determine that all air flow was into the containment in the event that the Limerick procedure allows partial closure?

41. Limerick has proposed to credit control of the pH in the suppression pool following a LOCA by means of injecting sodium pentaborate into the reactor core with the SLC system. The SLC system design was not previously reviewed for this safety function (pH control post-LOCA). Licensees proposing such credit need to demonstrate that the SLC system is capable of performing the pH control safety function assumed in the AST LOCA dose analysis. The following questions are from a set of generic questions developed by the staff and are being provided to all boiling water reactor licensees with pending alternate source term (AST) license amendment requests. In responding to questions regarding the SLC system, please focus on the proposed pH control safety function. The reactivity control safety function is not in question. For example, the SLC system may be redundant with regard to the reactivity control safety function, but lack redundancy for the proposed pH control safety function. If you believe that the information was previously submitted to support the license amendment request to implement AST, you may refer to where that information may be found in the documentation.

42. Please state whether or not the SLC system is classified as a safety-related system as defined in 10 CFR 50.2, and whether or not the system satisfies the regulatory requirements for such systems. If the SLC system is not classified as safety-related, please provide the information requested in Items 1.1 to 1.5 below to show that the SLC system is comparable to a system classified as safety-related. If any item is answered in the negative, please explain why the SLC system should be found acceptable for pH control agent injection.

a. Is the SLC system provided with standby AC power supplemented by the emergency diesel generators?

b. Is the SLC system seismically qualified in accordance with Regulatory Guide 1.29 and Appendix A to 10 CFR Part 100 (or equivalent used for original licensing)?

c. Is the SLC system incorporated into the plants American Society of Mechanical Engineers Code inservice inspection and inservice testing programs based upon the plants code of record (10 CFR 50.55a)?

d. Is the SLC system incorporated into the plants Maintenance Rule program consistent with 10 CFR 50.65?

e. Does the SLC system meet 10 CFR 50.49 and Appendix A to 10 CFR 50 (GDC- 15 4, or equivalent used for original licensing)?

43. Please describe proposed changes to plant procedures that implement SLC sodium pentaborate injection as a pH control additive. In addition, please address Items 2.1 to 2.5 below in your response. If any item is answered in the negative, please explain why the SLC system should be found acceptable for pH control additive injection.

a. Are the SLC injection steps part of a safety-related plant procedure?

b. Are the entry conditions for the SLC injection procedure steps symptoms of imminent or actual core damage?

c. Does the instrumentation cited in the procedure entry conditions meet the quality requirements for a Type E variable as defined in RG 1.97 Tables 1 and 2?

d. Have plant personnel received initial and periodic refresher training in the SLC injection procedure?

e. Have other plant procedures (e.g., ERGs/SAGs) that call for termination of SLC as a reactivity control measure been appropriately revised to prevent blocking of SLC injection as pH control measure. (For example, the override before Step RC/Q-1, If while executing the following steps: ....it has been determined that the reactor will remain shutdown under all conditions without boron, terminate boron injection and....)

44. Please provide a description of the analysis assumptions, inputs, methods, and results that show that a sufficient quantity of sodium pentaborate can be injected to raise and maintain the suppression pool greater than pH 7 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the start of the event.

(See also Position 2 of Appendix A to RG 1.183.) In your response, please discuss the adequacy of recirculation of suppression pool liquid via ECCS through the reactor vessel and the break location and back to the suppression pool in meeting the transport and mixing assumptions in the chemical analyses. Assume a large break LOCA.

45. Please show that the SLC system has suitable redundancy in components and features to assure that for onsite or offsite electric power operation its safety function of injecting sodium pentaborate for the purpose of suppression pool pH control can be accomplished assuming a single failure. For this purpose, the check value is considered an active device since the check valve must open to inject sodium pentaborate. If the SLC system cannot be considered redundant with respect to its active components, the licensee should implement one of the three options described below, providing the information specified for that option for staff review.

a. Option 1 Show acceptable quality and reliability of the non-redundant active components and/or compensatory actions in the event of failure of the non-redundant active components. If you choose this option, please provide the following information to justify the lack of redundancy of active components in the SLC system:

a.1 Identify the non-redundant active components in the SLC system and

16 provide their make, manufacturer, and model number.

a.2 Provide the design-basis conditions for the component and the environmental and seismic conditions under which the component may be required to operate during a design-basis accident. Environmental conditions include design-basis pressure, temperature, relative humidity and radiation fields.

a.3 Indicate whether the component was purchased in accordance with Appendix B to 10 CFR Part 50. If the component was not purchased in accordance with Appendix B, provide information on the quality standards under which it was purchased.

a.4 Provide the performance history of the component both at the licensees facility and in industry databases such as EPIX and NPRDS.

a.5 Provide a description of the components inspection and testing program, including standards, frequency, and acceptance criteria.

a.6 Indicate potential compensating actions that could be taken within an acceptable time period to address the failure of the component. An example of a compensating action might be the ability to jumper a switch in the control room to overcome its failure. In your response, please consider the availability of compensating actions and the likelihood of successful injection of the sodium pentaborate when non-redundant active components fail to perform their intended functions.

b. Option 2 Provide for an alternative success path for injecting chemicals into the suppression pool. If you chose this option, please provide the following information:

b.1 Provide a description of the alternative injection path, its capabilities for performing the pH control function, and its quality characteristics.

b.2 Do the components which make up the alternative path meet the same quality characteristics required of the SLC system as described in Items 1.1 to 1.5, 2, and 3 above?

b.3 Does the alternate injection path require actions to be taken in areas outside the control room? How accessible will these areas be? What additional personnel would be required?

c. Option 3 Show that 10 CFR 50.67 dose criteria are met even if pH is not controlled. If you chose this option, demonstrate through analyses that the projected accident doses will continue to meet the criteria of 10 CFR 50.67 assuming that the suppression pool pH is not controlled. The dissolution of CsI and its re-evolution from the suppression pool as elemental iodine must be evaluated by a suitably conservative methodology. The analysis of iodine speciation should be provided for staff review. The analysis documentation

17 should include a detailed description and justification of the analysis assumptions, inputs, methods, and results. The resulting iodine speciation should be incorporated into the dose analyses. The calculation may take credit for the mitigating capabilities of other equipment, for example the standby gas treatment system, if such equipment would be available. A description of the dose analysis assumptions, inputs, methods, and results should be provided.

Licensees proposing this approach should recognize that this option will incur longer staff review times and will likely involve fee-billable support from national laboratories.

46. Page 16 of Attachment 1 states the transfer of radioactive gases into the control room are minimized by maintaining the control room at a positive pressure of 0.1 inch water column with respect to adjacent areas during emergency pressurized modes. Unit 1 technical specification 3.7.2 states that the control room is maintained at 1/8" water gauge positive pressure. This is equivalent to 0.125 inch water column. Verify that the 0.1 inch water gauge was inadvertently truncated and that LGS is not requesting to change its license bases to 0.1 inch water gauge or provide justification for your proposed change.

Limerick Generating Station, Unit Nos. 1 and 2 cc:

Site Vice President Exelon Generation Company, LLC Limerick Generating Station 4300 Winfield Road Exelon Generation Company, LLC Warrenville, IL 60555 P.O. Box 2300 Sanatoga, PA 19464 Correspondence Control Desk Exelon Generation Company, LLC Plant Manager P.O. Box 160 Limerick Generating Station Kennett Square, PA 19348 Exelon Generation Company, LLC P.O. Box 2300 Regional Administrator, Region I Sanatoga, PA 19464 U.S. Nuclear Regulatory Commission 475 Allendale Road Regulatory Assurance Manager - Limerick King of Prussia, PA 19406 Exelon Generation Company, LLC P.O. Box 2300 Senior Resident Inspector Sanatoga, PA 19464 U.S. Nuclear Regulatory Commission Limerick Generating Station Senior Vice President - Nuclear Services P.O. Box 596 Exelon Generation Company, LLC Pottstown, PA 19464 4300 Winfield Road Warrenville, IL 60555 Library U.S. Nuclear Regulatory Commission Vice President - Operations, Mid-Atlantic Region I Exelon Generation Company, LLC 475 Allendale Road 200 Exelon Way, KSA 3-N King of Prussia, PA 19406 Kennett Square, PA 19348 Chief-Division of Nuclear Safety Vice President PA Dept. of Environmental Resources Licensing and Regulatory Affairs P.O. Box 8469 Exelon Generation Company, LLC Harrisburg, PA 17105-8469 4300 Winfield Road Warrenville, IL 60555 Chairman Board of Supervisors of Limerick Township Director 646 West Ridge Pike Licensing and Regulatory Affairs Linfield, PA 19468 Exelon Generation Company, LLC 200 Exelon Way, KSA 3-E Dr. Judith Johnsrud Kennett Square, PA 19348 National Energy Committee Sierra Club Manager Licensing 433 Orlando Avenue Limerick Generating Station State College, PA 16803 Exelon Generation Company, LLC 200 Exelon Way, KSA 3-E Kennett Square, PA 19348 Associate General Counsel