ML073370384

Request for Additional Information on the Stretch Power Uprate Amendment Request

ML073370384
Person / Time
Site:	Millstone
Issue date:	12/14/2007
From:	John Lamb NRC/NRR/ADRO/DORL/LPLI-2
To:	Christian D Virginia Electric & Power Co (VEPCO)
Lamb J, 415-1727
References
TAC MD6070
Download: ML073370384 (19)

Text

December 14, 2007 Mr. David A. Christian President and Chief Nuclear Officer Virginia Electric and Power Company Innsbrook Technical Center 5000 Dominion Boulevard Glen Allen, VA 23060-6711

SUBJECT:

MILLSTONE POWER STATION, UNIT NO. 3 - REQUEST FOR ADDITIONAL INFORMATION ON THE STRETCH POWER UPRATE AMENDMENT REQUEST (TAC NO. MD6070)

Dear Mr. Christian:

By letter dated July 13, 2007, as supplemented on September 12 and November 19, 2007, Dominion Nuclear Connecticut, Inc. submitted a stretch power uprate license amendment request for Millstone Power Station, Unit No. 3. The proposed license amendment would allow an increase in the maximum authorized core power level from 3,411 megawatts thermal (MWt) to 3,650 MWt, and would make changes to the Technical Specifications, as necessary, to support operation at the stretch power level.

In order to complete its review of the reports, the U.S. Nuclear Regulatory Commission staff has determined that additional information is required, and requires a response to each of the enclosed questions. The questions were sent by e-mail on November 16, 2007, and were discussed via teleconference on November 20, 27, and 29, 2007, with your staff to ensure that the questions were understandable, the regulatory basis was clear and to determine if the information was previously docketed. Mr. Ron Thomas of your staff agreed to respond within 30 days of the date of the letter.

Please note that if you do not respond to this letter within the prescribed response times or provide an acceptable alternate date in writing, we may reject your application for amendment under the provisions of Title 10 of the Code of Federal Regulations, Section 2.108. If you have any questions, I can be reached at (301) 415-3100.

Sincerely,

/ra/

John G. Lamb, Senior Project Manager Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-423

Enclosure:

As stated cc w/encl: See next page

ML073370384 OFFICE LPL1-2/PM LPL1-2/LA LPL1-2BC NAME JLamb ABaxter HChernoff DATE 12/10/07 12/10/07 12/14/07 REQUEST FOR ADDITIONAL INFORMATION MILLSTONE POWER STATION, UNIT NO. 3 STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST TAC NO. MD6070 DOCKET NO. 50-423 By letter dated July 13, 2007, as supplemented on September 12 and November 19, 2007, Dominion Nuclear Connecticut, Inc. (DNC or licensee) submitted a stretch power uprate (SPU) license amendment request for Millstone Power Station, Unit No. 3 (MPS3). The proposed license amendment would allow an increase in the maximum authorized core power level from 3,411 megawatts thermal (MWt) to 3,650 MWt, and would make changes to the Technical Specifications (TS), as necessary, to support operation at the stretch power level.

The U.S. Nuclear Regulatory Commission (NRC) staff has been reviewing the submittal and has determined that additional information is needed to complete its review.

Steam Generator Integrity & Chemical Engineering Branch CSGB-07-0010 (2.1.8-1)

The flow accelerated corrosion (FAC) program at MPS incorporates years of field data including wear rates and actual thickness measurements under current operating conditions. Under SPU conditions, however, MPS does not have data to inform the CHECWORKS model. Since the accuracy of the CHECWORKS program is dependant on field data, there is a potential that the changes in process variables (temperature, velocity, moisture content) resulting from SPU will lead to an unanticipated wear rate and therefore under-prediction of component thickness loss.

How does the MPS3 FAC program account for this potential effect? How is the license renewal aging management program for FAC impacted by this potential effect? Identify the components that are expected to experience the greatest increase in wear as a result of power uprate and discuss the relative reduction in service life for those components. In addition, discuss any changes made to the MPS3 FAC program (i.e., criteria used for selecting components for inspection following the power uprate, criteria for repair and replacement, increased inspection scope, etc.) due to power uprate conditions.

CSGB-07-0011 (2.1.8-2)

Increased secondary side flow rates will result in increased particulate matter in the steam generators (SG). CHECWORKS is unable to account for this material when analyzing FAC for the SG blowdown system. Are inspections of the SG blowdown system triggered solely by CHECWORKS, or is this system subject to inspections in a similar manner to non-CHECWORKS modeled systems as described in Section 2.1.8 of the SPU Licensing Report?

If the SG blowdown system is treated as a CHECWORKS modeled system, describe why the inability of CHECWORKS to model increased particulate matter is acceptable.

Enclosure

Accident Dose Branch AADB-07-0012 The staff notes that Table 1.0-1 refers to a modification to the control building for auto initiation of pressurized filtration following control building isolation signal for the purpose of control room dose following a fuel handling accident. The staff notes that section 2.9.2.2.1.5, Control Room, states that: The control room emergency ventilation system (CREVS) is assumed to be in the filtered recirculation mode of operation within 30 minutes of a fuel handling accident involving a spent fuel assembly. A modification will be developed to implement this assumption.

Please provide additional information describing all planned modifications to the CREVS related to credit taken in the revised dose consequences analyses.

Reactor Systems Branch SRXB-007-0013 (2.8.3-1)

Briefly describe the statistical combination process used to obtain the overall departure from nucleate boiling ratio (DNBR) uncertainty factor in accordance with the reactor technology development plan.

SRXB-07-0014 (2.8.3-5)

For the steam line break (SLB) accident analyses, provide initial assumed DNBRs for hot full power (HFP), both core average and minimum assumed.

SRXB-07-0015 (2.8.3-6)

For the SLB accident analysis, the Licensing Report (LR) states, Both HFP and HZP [hot zero power] steam line break are typically reanalyzed for each reload. Please clarify what the language, typically, means. Under what conditions would these events not be re-analyzed?

What determines the need to re-analyze these events? Based on past experience at MPS3, how often are these events re-analyzed?

SRXB-07-0016 (2.8.3-8)

N For the determination of F , describe the process used to determine the fraction of full power H

for analytical purposes. Does the thermal power include flow measurement uncertainty? Does the rated power include flow measurement uncertainty?

SRXB-07-0017 (2.8.3-10)

In Table 2.8.3-2, limiting parameter directions for departure from nucleate boiling (DNB) are presented. However, moving any of these parameters in a limiting direction could have an effect on other parameters used in the analysis. For instance, assuming a decreased value of the nominal vessel/core inlet temperature would have the effect of increasing the reactor core heat output and the average heat flux. Discuss the intent of providing the information in this table.

Provide additional information showing the effects that changing each parameter in a conservative direction would have on each other parameter listed in the table.

SRXB-07-0018 (2.8.4.1-1)

Verify that the reactor cavity cooling systems (RCCAs) will continue to meet the reactivity control requirements of the uprated core design.

SRXB-07-0019 (2.8.4.2-1)

Please provide transient plots and sequence of events tables for the analysis cases of Section 2.8.4.2. Please identify the reactor scram signals that are credited in the analyses (i.e., the second safety-grade signals).

SRXB-07-0020 (2.8.4.3-1)

Note the typo in Section 2.8.4.3.2.3. The inadvertent startup of a reactor coolant pump (RCP) is the limiting heat addition transient, not the limiting mass addition transient.

SRXB-07-0021 (2.8.4.3-2)

Which is the more limiting transient, the mass addition or the heat addition?

SRXB-07-0022 (2.8.4.4-1)

The cooldown analysis for safety grade cold shutdown shows significant improvements in analyzed performance from pre- to post-SPU. Explain what differences in the analysis performed cause this effect.

SRXB-07-0023 (2.8.4.4-2)

Explain why the initial power level for normal cooldown analysis does not include power measurement uncertainty.

SRXB-07-0024 (2.8.4.4-3)

Explain why a zero uncertainty decay heat model is acceptable for safety grade cold shutdown analysis.

SRXB-07-0025 (2.8.4.4-4)

Discuss the design details of the residual heat removal system heat exchanger to show that a 15 °F increase in heat exchanger outlet temperature is acceptable.

SRXB-07-0026 (2.8.4.4-5)

Confirm the capability of the plant to remove the increased heat load from the component cooling water.

SRXB-07-0027 (2.8.4.4-6)

Explain why the auxiliary heat load is reduced.

SRXB-07-0028 (2.8.5.0-2)

Regarding the steady-state initial condition uncertainties listed on Page 2.8-74 of the LR, specifically explain how these uncertainties are applied to the analyses. Despite the information provided in the preceding paragraph, the list items employ +/- uncertainties, suggesting that sensitivity studies were performed. Confirm whether this was the case.

SRXB-07-0029 (2.8.5.1-1)

For the major steam line rupture analysis, why is only the two-out-of-four pressurizer low-pressure signal credited for safety injection actuation? It seems that the safety injection actuation signal (SIAS) would be generated first by the two-out-of-three low-pressure signals in any steam line.

SRXB-07-0030 (2.8.5.3.1-1)

Loss of Forced Reactor Coolant Flow - For the loss of power to one RCP, the times assumed in the current licensing basis (CLB) analysis sequence are less than those in the SPU Licensing Report (SPULR). This could be intuitive, considering that the pumps are delivering more mass to the reactor core at SPU power levels. However, the timing assumptions for the loss of power to all RCPs do not change from current licensed power (CLP) to SPULR. Explain this inconsistency.

SRXB-07-0031 (2.8.5.3.1-2)

Loss of Forced Reactor Coolant Flow - Discuss any conservatism with respect to the 2.8-230 selection of feedwater temperature assumptions used in the loss of forced coolant flow analysis.

SRXB-07-0032 (2.8.5.3.2-2)

RCP Rotor Seizure/Shaft Break - The updated final safety analysis report presents an analysis that assumes remaining pumps lose power 2 seconds after reactor trip and the SPU analysis assumes loss of power to pumps and coastdown simultaneous with reactor trip initiation at 1.1 seconds. Given that peak RCS pressure and peak cladding temperature occur on fairly short timescale, these apparent differences could be significant. Explain these differences and account for the acceptability of the new method/SPU analysis.

SRXB-07-0033 (2.8.5.3.2-4)

RCP Rotor Seizure/Shaft Break - Figure 2.8.5-1 illustrates a slight decrease in lower plenum pressure prior to 2 seconds, and prior to the ultimate increase to the observed peak vessel pressure. The cause of this increase is not readily discernible from the listed initial conditions.

Please explain.

SRXB-07-0034 (2.8.5.4.1-1)

RCCA Withdrawal from Subcritical - Explain why the progression of this transient is delayed 4 seconds from that in the final safety analysis report (FSAR).

SRXB-07-0035 (2.8.5.4.2-1)

Uncontrolled RCCA Bank Withdrawal at Power - Explain why a change from 75 pcm/sec to 100 pcm/sec occurred from CLB to SPULR. Discuss this change with respect to current RCCA nuclear design and mechanical withdrawal capability. Confirm that a 100 pcm/sec withdrawal remains conservative and bounding based on expected operating parameters at the plant.

SRXB-07-0036 (2.8.5.4.2-2)

Uncontrolled RCCA Bank Withdrawal at Power - Provide the same information requested above justifying a transition from 3pcm/sec slow withdrawal to 1 pcm/sec.

SRXB-07-0037 (2.8.5.4.2-3)

Uncontrolled RCCA Bank Withdrawal at Power - Why does the rapid withdrawal analysis assume a lower volume in the pressurizer than that assumed in the CLB analysis?

SRXB-07-0038 (2.8.5.4.2-5)

Uncontrolled RCCA Bank Withdrawal at Power - Figure 2.8.5.4.2-5 illustrates the assumption that pressurizer sprays and relief valves are assumed to be operational. Provide a table that describes the pressurizer performance during the progression of this transient. Include the operation of the sprays and relief valves.

SRXB-07-0039 (2.8.5.4.3-1)

RCCA Misalignment - Regarding the statement on Page 2.8-287 of the SPULR, Steady-state power distributions are analyzed using the appropriate nuclear physics computer codes, these codes are typically named in other sections of the SPULR. What codes are used in this case?

SRXB-07-0040 (2.8.5.4.5-2)

Chemical and Volume Control System (CVCS) Malfunction that results in a decrease in boron concentration in the reactor coolant - Throughout this section, the staff noted that assumed volumes of the RCS inventory are different than those listed in the FSAR. Explain why these values changed.

SRXB-07-0041 (2.8.5.4.5-3)

CVCS Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant -

During Mode 3, it is noted that rod withdrawal and boron dilution may not occur simultaneously.

How is this prevented?

SRXB-07-0042 (2.8.5.4.5-4)

CVCS Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant -

The staff noted that, in Modes 1 and 2, initial boron concentrations are assumed to be less than those assumed in the CLB analysis. Therefore, the resulting change from initial condition is less. Explain why this change occurred.

SRXB-07-0043 (2.8.5.4.6-1)

Spectrum of Rod Cluster Control Assembly Ejection Accidents - On page 2.8-307, the typical effective delayed neutron fraction values are discussed in comparison to the conservative values assumed in the safety analysis. What are limiting values, and how do they compare to the safety analysis assumptions?

SRXB-07-0065 (2.8.5.4.6-3)

Spectrum of Rod Cluster Control Assembly Ejection Accidents - Confirm that the analyzed initial power level for the full power accidents included a 2 percent measurement uncertainty increase to the assumed 3650 MWt power level.

SRXB-07-0045 (2.8.5.4.6-4)

Spectrum of Rod Cluster Control Assembly Ejection Accidents - Regarding the changes in conservative assumptions from current licensed thermal power (CLTP) to the uprated power level analyses, address the statement that SPU analyses remain conservative and are revalidate as conservative for each subsequent reload. How is this revalidation performed?

SRXB-07-0046 (2.8.5.5-2)

MPS3 proposes to add a permissive (P-19) that requires the coincidence of a SIAS and a low pressurizer pressure reactor trip signal to allow the automatic opening of the cold leg injection valves. An SIAS, alone, will result only in the delivery of RCP seal cooling water from the charging pumps.

a. Please provide a logic diagram, typical of the diagrams found in Chapter 7 of the FSAR, that depicts the P-19 permissive: its inputs, outputs, and connecting logic.

b. An SIAS can be generated by any of the following:

- Two-out-of-four pressurizer low-pressure signals;

- Two-out-of-three low-pressure signals in any steam line;

- Two-out-of-three high-containment pressure signals.

Please explain how the P-19 permissive would prevent the cold leg injection valves from opening, while the RCS is at nominal pressure, if the spurious SIAS were to originate in the pressurizer low-pressure logic.

SRXB-07-0047 (2.8.5.5-3)

a. The results of the CVCS malfunction analysis cases indicate that the pressurizer would become water-solid in 761 seconds (one charging pump in operation), and 503 seconds (two charging pumps in operation). The pressurizer safety valve (PSV) opening setpoint is reached in 1156.2 seconds, and 601.4 seconds, respectively. Describe the process that is used to verify that the operators can terminate the CVCS malfunction (or make at least one power operated relief valve (PORV) available), after they are alerted by the pressurizer level deviation signal, and before the PSV opening setpoint is reached.

b. Are any of the pressurizer level alarms that are assumed to alert the operators to a CVCS malfunction (e.g., the pressurizer level deviation signal) qualified safety-related signals? If not, then how much time is available from receipt of the pressurizer high water level reactor trip signal? Are the operators capable of terminating the CVCS malfunction (or making at least one PORV available) after they are alerted by the pressurizer high water level reactor trip signal, and before the PSV opening setpoint is reached?

Piping and Non-Destructive Examination Branch CPNB-007-0048 Section 2.1.5.2.3 of the licensees submittal discusses, in part, degradation of nickel base Alloy 600/82/182 materials. The licensees evaluation based on 4.3°F increase temperature for Alloy 600/82/182 components exposed to the hot leg temperature shows a reduction of approximately 18 percent in the remaining nozzle lifetimes before primary water stress-corrosion cracking (PWSCC) initiation. Please discuss how the inspections in MRP-139, tables 6-1 and 6-2 are adequate to detect PWSCC in a timely fashion, and any impact the increased temperature has on crack growth rate and inspection frequency of the welds. Also, discuss what mitigative actions and associated inspections are planned for Alloy 600/82/182 materials subject to the higher temperatures.

Electrical Engineering Branch EEEB-07-0049 The license amendment request indicates that MPS3 will provide, as required, additional reactive power based on the generator capabilities by reducing output power. For the current SPU of 7 percent, please identify the nature and quantity of megavolt amperes relative (MVAR) support necessary to maintain post-trip loads and minimum voltage levels. Also, address how the power uprate affects MVAR support.

EEEB-07-0050 Provide details on the changes to the 6.9 kV and 4.16 kV systems. Specifically, for the .9 kV system, indicate the increase in loading (in kW) due to the condensate pump and the feedwater pump motors. For the 4.16 kV system, provide the increase in loading (in kW) due to the heater drain pump and moisture separator drain pump motors.

EEEB-07-0051 In the Main Steam Valve Building, the total integrated dose increased from 1.1 E4 to 4.0 E4 Rads. If there are any electronics containing complementary metal-oxide semiconductor or p-type metal-oxide semiconductors circuits or any other components affected by the increase in radiation dose in the Main Steam Valve Building, then provide the complete environmental qualification (EQ) evaluation for the affected components.

EEEB-07-0052 For the Main Steam Valve Building, Engineered Safety Features Building, and Auxiliary Building, the license amendment request, in Section 2.3.1, indicates that SPU conditions may affect the

EQ of electrical equipment. Provide the complete evaluations of the affected equipment, including an in-depth discussion of the assumptions and methodology.

EEEB-07-0053 The license amendment request states in Section 2.3.1.2.3.1, that the total integrated dose (forty year normal plus accident, gamma, and beta) inside containment is 2.4 E8 Rads. Specify each of the individual doses separately (i.e. the forty year normal dose, the gamma dose and the beta dose).

EEEB-07-0054 In the SPULR (Attachment 5 of the license amendment request), on page 2.3-6 under the license renewal heading, it is stated that the SPU has no impact on the EQ program. Describe why the SPU has no impact on the EQ program in regards to license renewal.

EEEB-07-0055 In Attachment 5 of the license amendment request, the licensee has repeatedly referenced EQ documentation for the 40 year qualification. Since MPS3 has been licensed for 60 years, the EQ documentation should indicate a 60 year qualification. Explain this discrepancy.

EEEB-07-0056 of the license amendment request (page 2.3-10) states that only two components were removed from the EQ program. Table 3.6-5 of MPS3 FSAR identifies that isolation valves 3ASS-AOV102A and 3ASS-AOV102B were removed, yet Sections 5.10 and 6.1.10 of indicate that pressure transmitters PT 505 and 506, which measure first stage pressure, as well as position switches MSS ZS59, 60, 61, and 62, which measure main steam turbine stop valve positions, will be removed from the EQ Master List. Clarify which components are to be removed from the EQ Program, describe their functions, and provide a detailed explanation on why they are no longer required to be in the EQ program.

EEEB-07-0057 , Section 5.10, Turbine Building Temperature Monitoring, addresses two sets of equipment in the Turbine Building that have been environmentally qualified and are maintained on the Master Equipment List (MEL) for environmentally qualified equipment. One of which is the Pressure transmitters PT 505 and 506 that measure first stage pressure. The evaluation states that they are currently on the MEL because they provide input into the rod control system and modifications to the rod control system being made to eliminate the capability for automatic rod withdrawal by the rod control system. Hence the licensee wants to remove these transmitters from the MEL. However, these transmitter also provide inputs to other safety features, e.g., AMSAC - arm/disarm circuit permissive C-20 at first stage pressure equivalent to 40 percent reactor power, P-7 Permissive- in conjunction with P-10, bypasses low pressurizer pressure, high pressurizer water level, low reactor coolant system (RCS) flow, and RCP low shaft speed reactor trips, Rod Control power mismatch and non-linear gain controls, SG level control, Load reject steam dump control, Reactor control Tref, Block auto rod withdrawal C-5 permissive. Evaluate all the functions provided by these pressure transmitters to ensure it is appropriate to remove from the MEL.

Containment and Ventilation Branch SCVB-07-0058 LAR Attachment 5, Section 2.7.7.2.3, second paragraph states, As a result of SPU, there will only be minor temperature changes in the process fluids contained in these systems. The minor increase in heat loads can be adequately compensated for by the existing automatic temperature controllers within the cooling systems. Thus no changes are required for the cooling system as a result of SPU.

Please verify that analysis was done for SPU that confirms that there is no impact on the cooling and control capability of the cooling equipment. Also please explain why there will be a minor temperature change in the process fluids contained in the cooling equipment due to SPU heat load which has resulted in about 1o F increase in the containment bulk operating temperature during normal power operation.

SCVB-07-0059 LAR Attachment 5, Section 2.7.7.2.3, first paragraph states, The results of the evaluation determined that an increase in the containment bulk air temperature of less than 1°F from current observed level will occur at SPU conditions.

Please explain what is current observed level and how does it relate to the current licensing basis containment average operating temperature given in FSAR Section 9.4.7.2.3 which states:

Two of the three containment air recirculation unit coolers are required to maintain the containment average temperature below 95°F. If one unit fails, the remaining two units maintain the average temperature below 95°F during normal operation.

Please explain what the SPU impact on the containment average temperature is during loss of offsite power in reference to FSAR Section 9.4.7.2.3 which states: During a loss of offsite power, these unit coolers can operate with emergency power maintaining an average air temperature of the containment below 135°F.

Mechanical and Civil Engineering Branch EMCB-07-0060 The postulated pipe break acceptance criteria inside and outside containment are described in FSAR Sections 3.6.1 and 3.6.2 and reflect the approach and methodology contained in the Branch Technical Positions ASB 3-1 and MEB 3-1. SPULAR Attachment 5 Section 2.2.1.2.2 states that The SPU evaluations performed for applicable piping systems did not result in any new or revised break/crack locations, and the design basis for pipe break, jet impingement, pipe whip and environmental considerations remain valid for SPU and Pipe stresses for break exclusion zones were demonstrated to be within acceptable limits.

a) Confirm whether these analyses included reactor coolant loop (RCL) branch line break, pressurizer surge line break, main SLB and feedwater line break. If not, provide technical justification for not including these pipe breaks.

b) Provide a summary description of the evaluations, explaining how the evaluations were performed. Include assumptions and load combinations along with summaries of results that show that you meet the FSAR pipe break acceptance criteria when SPU conditions are included.

EMCB-07-0061 Section 2.2.2.1.2.2 states that By virtue of LBB [leak before break], breaks are not postulated for the RCL loop hot leg, cold leg and crossover leg piping.

a) Confirm whether the current licensing basis is based on LBB methodology.

b) Provide justification that the basis for using LBB methodology is still valid under the proposed SPU conditions.

EMCB-07-0062 Section 2.2.2.1.2.2 states that For the SPU program, the loop LOCA [loss-of-coolant accident]

hydraulic forcing function forces and associated loop LOCA RPV [reactor pressure vessel]

motions from applicable RCL branch line breaks were reconciled as part of the RCL and associated branch piping and support evaluations. Identify RCL branch line breaks used for loop LOCA analysis and describe the method used for reconciliation.

EMCB-07-0063 Section 2.2.2.1.2.3 indicates that the stress results shown in Table 2.2.2.1-1 have incorporated the hydraulic LOCA forces.

a) Provide the basis for the allowable values and the loading combinations used for the calculated stresses in Table 2.2.2.1-1.

b) Footnote 5 of the table states that the allowable levels are well below material yield.

Provide the corresponding yield values that confirm this statement.

c) Provide the basis for the allowable stress of 25,050 pounds per square inch (psi) for the 10 safety injection cold leg Loop D line.

d) For the cumulative usage factor (CUF) values that exceed 0.1, verify that these location are postulated pipe breaks.

e) Also confirm whether the CUF values in the SPU and Current columns are to the end of the 60 year plant life in accordance with the licensing renewal of the plant.

EMCB-07-0044 Section 2.2.2.2.2.2 states that The BOP [balance of plant] piping and support systems listed in Section 2.2.2.2.2.1 (Introduction) have been evaluated relative to the impact of SPU. Thermal, pressure and flow change factors equal to the ratio of SPU to actual analyzed value were determined. For change factors greater than 1.00, an additional evaluation was performed to address the specific increase in temperature, pressure and/or flow rate in order to determine piping and support system acceptability, as well as nozzle load and containment penetration acceptability.

a) List all systems (inside and outside containment) with change factors greater than 1.00.

b) For systems with change factors greater than 1.00, provide the method of your evaluation. Provide a quantitative summary of the maximum stresses and fatigue usage factors (if applicable) for original and SPU conditions with a comparison to code of record allowable stresses. Include only maximum stresses and data at critical locations (i.e.

nozzles, penetrations, etc). List all pipe system modifications (for pipe supports see (d) below) required due to SPU and schedule of completion. For affected nozzles and containment penetrations, provide a summary of loads compared to specific allowable

values for nozzles and penetrations.

c) For systems with a thermal change factor greater than 1.00, provide a description of preoperational measures taken to ensure that thermal expansion will not impose an unanalyzed condition that could potentially overstress piping and supports. In addition, confirm that a program will be in place for monitoring thermal expansion at the startup of the SPU.

d) For systems in (b), state the method used for evaluating pipe supports when considering SPU conditions and confirm that the supports on affected piping systems will remain structurally adequate to perform their intended design function. Provide detail descriptions of all pipe support modifications needed to meet design basis at SPU conditions. Also list type, size, loading (current and SPU) and location of supports that need to be modified and added due to SPU conditions.

e) Provide schedule of completion for all piping and pipe support modifications and additions.

EMCB-07-0065 Section 2.2.2.2.2.2 states that applicable feedwater system pipe supports were evaluated and demonstrated to be within design basis limits. Section 2.2.2.2.2.3 states that The piping evaluations also concluded that the feedwater system can withstand water hammer loads associated with SPU conditions (resulting from a feedwater isolation valve closure/pump trip event) although several pipe support modifications will be required. Provide explanation for the apparent discrepancy between these statements.

EMCB-07-0066 Margin, as defined for values in Table 2.2.2.2-1 (and in Table 2.2.2.1-1 as stated in second line of Section 2.2.2.1.2.3), is not clear. For instance, the example mentioned in Note 2 of Table 2.2.2.2-1 defines margin as the ratio of the calculated value to the allowable value. Typically, margin is defined by the difference between the allowable value and the calculated value divided by the allowable value. Provide justification for the margin definition used for these tables.

EMCB-07-0067 Section 2.12.1.2.3.2, Vibration Monitoring, states that SPU implementation will result in higher flow rates for piping systems within the main power cycle. Secondary system piping and supports evaluated included the following: main steam, extraction steam, feedwater, condensate, feedwater heater vents and drains and moisture separator vents and drains. The evaluations concluded that piping systems remain acceptable and will continue to satisfy design basis requirements. Piping vibration reviews, including system walk-downs, will be performed during power ascension to the SPU level, to ensure piping system and component vibrations remain acceptable. Section 2.2.2.2.2.3 also indicates that these systems will be reviewed for flow induced vibration (FIV) issues at a later time. These statements are confusing since in one place they imply that piping evaluations for FIV for the higher SPU flow rate have been completed and in another place it is indicated that piping reviews for FIV will be performed at a later date. In addition, during a telecon between the staff and DNC, DNC indicated that an evaluation for FIV due to higher SPU flow rates on affected BOP systems (see above) will be performed after a collection of vibration data at 100 percent current licensed thermal power (CLTP) to establish a baseline has been completed, which is scheduled to be performed in November 2007. Provide a clear description of the planned activities and evaluation methodology. Also, provide the acceptance criteria for the evaluation of FIV for these piping

systems as well as evaluation summaries which show that the acceptance criteria have been met for SPU conditions.

EMCB-07-0068 a) Identify any pressure retaining systems (besides the ones listed in EMCB-07-0067) that would experience higher flow rates due to the SPU implementation.

b) Describe the methodology and provide the acceptance criteria for the evaluation of FIV for these systems along with evaluation summaries which show that the acceptance criteria have been met.

EMCB-07-0069 Describe the vibration monitoring program at the startup for the SPU implementation, its basis and acceptance criteria. Confirm whether it is in accordance with the ASME OM Code Part 3.

EMCB-07-0070 Section 2.2.3.2.1 states that Changes in the primary coolant system operating conditions (e.g.,

increase in power) also produce changes in the boundary conditions; this includes loads and temperatures experienced by the reactor internals structures or components. Ultimately, this results in changes in the stress levels in these components and changes in the relative displacement between the reactor vessel and the reactor internals. To ensure that the reactor internal components maintain their design functions, and to ensure safety questions have been reviewed, a systematic evaluation of the reactor components has been performed to assess the impact of increased core power on the reactor internal components. Table 2.2.3-3 contains a summary of stresses and fatigue usage factors for core support structures. Confirm that these values are for SPU conditions and provide corresponding values at current conditions.

EMCB-07-0071 Table 2.2.3-3 states that for the case of the Core Barrel Outlet Nozzle Section A-A, which exceeded the code allowable limit of 3 Sm, the simplified elastic-plastic analysis was performed to calculate fatigue strength, as allowed by ASME, B&PV Code,Section III, NB 3228.5. These conditions have been met and the fatigue usage is less than 1.0. Provide a summary of the evaluation which shows that the special rules for exceeding 3Sm as provided by (a) through (f) of Subparagraph 3228.5 have been met.

EMCB-07-0072 In addition to Table 2.2.3-3, various components listed in Tables 2.2.2.3-1,2.2.2.5.2.2-1 and 2.2.2.7.2-2 of LAR Attachment 5, which contain stress summaries, have failed to meet the NB-3222.2 primary plus secondary stress intensity requirement of 3Sm. Attachment 5 states that these components have been qualified by passing the simplified elastic-plastic analysis of NB 3228.5.

a) Provide a summary of the evaluations which shows that the special rules for exceeding 3Sm as provided by (a) through (f) of subparagraph 3228.5 have been met.

b) Tables 2.2.2.5.2.2-1 and 2.2.2.7.2-2 also provide acceptability of components, that failed to meet the 3Sm allowable, through NB-3228.3. Discuss the basis and show that you meet the requirements for using the NB-3228.3 criteria. Also provide a summary of the

analysis results which shows that the requirements of NB-3228.3 have been met.

EMCB-07-0073 Section 1.2 identifies that the current thermal design flow was maintained for the analyses of the six SPU cases summarized in Tables 1-1 and 1-2. Section 2.2.3.2.4 indicates that the design core bypass flow is maintained for the SPU conditions. Section 2.2.3.2.3 contains a paragraph titled Flow-Induced Vibrations in which it states that The results of FIV analyses for the MPS3 SPU are provided in Table 2.2.3-1 and Table 2.2.3-2. Provide an explanation of incore changes due to SPU that would affect FIV on vessel internals and core support structures.

EMCB-07-0074 For FIV on the reactor internals, Section 2.2.3.2.3 states that Based on the analysis performed for MPS3, reactor internals response due to FIV is extremely small and well within the allowable based on the high cycle endurance limit for the material. The results of FIV analyses for the MPS3 SPU are provided in Table 2.2.3-1 and Table 2.2.3-2.

a) Describe the methodology and acceptance criteria for assessing FIV on vessel internals.

b) In Tables 2.2.3-1 and 2.2.3-2, include other reactor internals susceptible to FIV such as, lower internals assembly (core barrel, thermal shield support flexures, thermal shield support bolts and the dowel pins), lower support plate, upper internals guide tubes, and upper support plate. For both tables (2.2.3-1 and 2.2.3-2) provide current, SPU and allowable values.

c) Provide the basis that established the 101.5 1n/1n x 10-6 endurance limit strain in Table 2.2.3-2.

EMCB-07-0075 Section 2.2.2.5.2.5 indicates that the effects of SPU on the fluid-elastic stability ratio and amplitudes of tube vibration due to turbulences including vortex shedding have been accounted for. Section 2.2.2.5.2.5 also states that the analysis of the MPS3 Model F SGs indicates that significant levels of tube vibration do not occur from either the fluid-elastic, vortex shedding or turbulent mechanisms as a result of the SPU conditions. It also states that the turbulence would increase by as much as 49.6 percent, which will result in induced amplitude of 2 mils. Show quantitatively that the additional induced tube bending stresses have been accounted for and are acceptable. Provide an evaluation of FIV including fluid-elastic stability, turbulent and vorticity effects on tubes.

EMCB-07-0076 Section 2.2.2.5 provides an evaluation summary at critical locations of the primary and secondary side SG components in Tables 2.2.2.5.2.2-1 and 2.2.2.5.2.2-2. The results indicate that, at several critical locations, the fatigue cumulative usage factor limit is determined to be very close to the allowable value of 1.0.

a) Confirm that the fatigue evaluations have been carried out to the 60 year plant life in accordance with the plant licensing renewal operating license.

b) Provide a description of the analytical evaluation (including cycles considered) for components with a fatigue usage factor greater than 0.90.

c) In addition, discuss the fatigue monitoring and/or other mitigating measures relative to

the secondary manway bolts and any other locations where the calculated fatigue limit does not meet the 60-years design plant life limit.

EMCB-07-0077 Section 2.2.2.5.2.2, Structural Integrity Evaluation, states that: The SG internal components, other than the U-tubes, are not part of the pressure boundary and, therefore, are not governed by the ASME Code. However, ASME Code Section III, Subsections NB and NF were adopted as guidelines for performing the structural analysis of these components. These components were reviewed and it was determined that they satisfy the ASME Code requirements for components not requiring an analysis for cyclic operation. As a result, a fatigue analysis was not performed for the internals. The feedwater ring was analyzed for fatigue since it is the most highly loaded of all the internals due to rapid feedwater flow and temperature changes.

a) Provide a summary of the evaluation which shows that a fatigue evaluation for the internals is not required.

b) Provide a summary of the analytical evaluation for the internals (including flow distribution baffle, steam dryer and flow-reflector) and their supports.

c) Provide a summary of the analytical evaluation for the feedwater ring that includes stresses, CUFs and allowable values.

d) Identify the Code and Code edition for the evaluation of the proposed SPU. If different from the Code of record, provide justification.

e) Provide an evaluation of FIV of the steam dryer, dryer supports and flow-reflector with respect to the fluid-elastic instability, acoustic loads and vortex shedding due to steam flow for the SPU.

EMCB-07-0078 Discuss in detail the method for avoiding adverse flow effects during power ascension and after achieving SPU conditions. Include systems to be monitored, data to be collected and methods of data collection. Specify hold points and duration, inspections, plant walkdowns, vibration data locations, and planned data evaluation.

EMCB-07-0079 Discuss the evaluation of potential FIV effects due to the increase in steam flow resulting from SPU conditions. The evaluation should include the SG internals, steam and feedwater systems and their associated components. Include impact on structural capability and performance during normal operations, anticipated transients (initiation and response), and design-basis conditions. Discuss procedure in place for preparation and response to the potential occurrence of loose parts as a result of the SPU. The evaluations should also include calculations, when applicable, of the fluid-elastic stability ratio, and stresses due to turbulent and vortex shedding.

EMCB-07-0080 Provide a summary of the evaluation of thermowells in the main steam (MS), feedwater (FW) and Condensate piping systems for increased vibrations due to the increased SPU flow rate.

EMCB-07-0081 Section 2.2.2.4, Control Rod Drive Mechanism (CRDM), identifies that the CRDM was designed in accordance with the ASME B&PV Code,Section III, Division 1, 1974 edition through summer 1974 addenda, for normal, upset, emergency and faulted conditions. It also contains a summary of the results of the evaluations performed for the SPU which is presented in Table 2.2.2.4-1 through 2.2.2.4-5.

a) Confirm that the fatigue evaluations have been carried out to the 60 year plant life in accordance with the plant licensing renewal operating license.

b) In Table 2.2.2.4-1 through 2.2.2.4-4, provide corresponding values for the current licensed power.

c) In Table 2.2.2.4-1 (upper joint), for the Bell mounting threaded area, provide the basis of the allowable values of 19,479 psi and 21,755 psi for the normal and upset conditions respectively. Also, provide the component material designation in the first column of Table 2.2.2.4-1 through 2.2.2.4-3. The allowable values (shown for design temperature) for the Bell mounting threaded area are different for the upper joint, the middle joint and the lower joint. Provide a justification for the difference in allowable values.

d) Table 2.2.2.4-3 (lower joint) in the first column in the upper hand corner is marked Middle Joint. Verify that the stress summary of Table 2.2.2.4-3 is for the Lower Joint components.

Balance-of-Plant Branch SBPB-07-0082 In Attachment 5, Section 2.5.6.3, Solid Waste Management Systems, the licensee states Implementation of SPU is anticipated to increase the potential for occurrence of the crud induced power shift (CIPS) phenomena. Details associated with the fuel cleaning process proposed to manage and/or preclude CIPS require finalization. Consistent with the requirements of 10 CFR 50.34a(c), describe any new equipment necessary for control of liquid effluents from the cleaning process and the effect that treatment of those effluents would have on the packaging and storage of solid waste.

SBPB-07-0083 In Attachment 1, Section 3.3, Demineralized Water Storage Tank (DWST) Licensing Basis Change, the licensee proposes to change the licensing basis for the required level in the DWST.

The existing basis is for the DWST to hold enough water for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> at hot standby. The licensee proposed to change the basis to hold enough water for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> at hot standby. To satisfy accident analysis assumptions, the DWST must contain sufficient cooling water to remove decay heat following a reactor trip, and then to cool down the reactor coolant system (RCS) to residual heat removal entry conditions, assuming a coincident loss of offsite power and the most adverse single failure. Provide an evaluation of the proposed licensing basis change, including the basis for the current 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> requirement and the basis to conclude that the proposed seven hours adequately addresses all accident analyses and requirements.

SBPB-07-0084 In Attachment 5, Section 2.8.4.4.2.2.2, Safety Grade Cold Shutdown (SGCS) Cooldown Analysis, the licensee states that TS 3.7.1.3 ensures an adequate volume in the DWST to

support hot standby conditions with subsequent RCS cooldown. The licensee proposes to change the reasonable time period to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from 76 hours8.796296e-4 days <br />0.0211 hours <br />1.256614e-4 weeks <br />2.8918e-5 months <br />, but keeps the 36-hour requirement to initiation of residual heat removal. The safety related water source is the DWST, which at SPU conditions will only have the capacity for approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, as stated in Section 2.5.4.5, Auxiliary Feed Water. Since SGCS takes credit for only safety-related equipment, not crediting the use of the non-safety-related condensate storage tank and service water, explain how the 36-hour requirement would be maintained by safety-related equipment.

SBPB-07-0085 In Attachment 5, Section 2.5.1.2, Missile Protection, under the results subsection, the licensee states: For plant areas containing safety-related Structures, Systems, and Components (SSCs), the SPU will not result in any changes to existing missile sources or add any new components that could become a new potential missile source. The SPU will also not result in any system configuration changes that would impact any existing missile barrier considerations.

However, the licensee determined the need to increase the feedwater pump turbine speed from 4900 revolutions per minute (rpm) to 5125 rpm in order to provide adequate flow, head, and net positive suction head to support SPU conditions. A potential source of missiles is high speed rotating components. Missiles generated internally to the reactor facility may cause damage to SSCs that are necessary for the safe shutdown of the reactor or for accident mitigation or for prevention of a significant release of radioactivity. Describe how equipment necessary for safe shutdown is protected from missiles generated by failure of the feedwater pump or its turbine.

Does the increased feedwater pump operating speed affect this protection?

SBPB-07-0086 In Attachment 5, Section 2.5.1, Pipe Failures, the licensee addresses impact from main steam line break, recirculation pump component cooling water piping, and flooding from the high energy line break (HELB) of an SG blowdown system line in the main steam valve building. It mentions that main feedwater lines go through this area. However, the evaluation does not specifically address the increased mass release from a HELB in the feedwater system and its effect upon internal flooding. Explain the effects of increased feedwater flow from a feedwater break at SPU conditions upon internal flooding.

SBPB-07-0087 In Attachment 5, Section 2.5.5, Table 2.5.5.1-1 describes the changes in the operating conditions in the main steam system from current operating conditions to SPU conditions.

Provide an evaluation of the change in pressure and setpoints from the high pressure turbine first stage pressure to reactor protection.

Millstone Power Station, Unit No. 3 cc:

Lillilan M. Cuoco, Esquire Mr. Joseph Roy, Senior Counsel Director of Operations Dominion Resources Services, Inc. Massachusetts Municipal Wholesale Building 475, 5th Floor Electric Company Rope Ferry Road Moody Street Waterford, CT 06385 P.O. Box 426 Ludlow, MA 01056 Edward L. Wilds, Jr., Ph.D.

Director, Division of Radiation Mr. J. Alan Price Department of Environmental Protection Site Vice President 79 Elm Street Dominion Nuclear Connecticut, Inc.

Hartford, CT 06106-5127 Building 475, 5th Floor Rope Ferry Road Regional Administrator, Region I Waterford, CT 06385 U.S. Nuclear Regulatory Commission 475 Allendale Road Mr. Chris Funderburk King of Prussia, PA 19406 Director, Nuclear Licensing and Operations Support First Selectmen Dominion Resources Services, Inc.

Town of Waterford 5000 Dominion Boulevard 15 Rope Ferry Road Glen Allen, VA 23060-6711 Waterford, CT 06385 Mr. David W. Dodson Mr. J. W. "Bill" Sheehan Licensing Supervisor Co-Chair NEAC Dominion Nuclear Connecticut, Inc.

19 Laurel Crest Drive Building 475, 5th Floor Waterford, CT 06385 Rope Ferry Road Waterford, CT 06385 Mr. Evan W. Woollacott Co-Chair Nuclear Energy Advisory Council 128 Terry's Plain Road Simsbury, CT 06070 Senior Resident Inspector Millstone Power Station c/o U.S. Nuclear Regulatory Commission P. O. Box 513 Niantic, CT 06357 Ms. Nancy Burton 147 Cross Highway Redding Ridge, CT 00870