ML073440208

Request for Additional Information, License Amendment Request 07-004, Changes to Technical Specifications to Revise Thermal Power from 3458 Mwt to 3612 Mwt (TACs MD6615 & MD6616)

ML073440208
Person / Time
Site:	Comanche Peak
Issue date:	12/11/2007
From:	Balwant Singal NRC/NRR/ADRO/DORL/LPLIV
To:	Blevins M Luminant Generation Co
Singal, Balwant, 415-3016, NRR/DORL/LPL4
References
TAC MD6615, TAC MD6616
Download: ML073440208 (12)

Text

December 11, 2007 Mr. M. R. Blevins Executive Vice President

& Chief Nuclear Officer Luminant Generation Company LLC ATTN: Regulatory Affairs P. O. Box 1002 Glen Rose, TX 76043

SUBJECT:

COMANCHE PEAK STEAM ELECTRIC STATION, UNITS 1 AND 2 - REQUEST FOR ADDITIONAL INFORMATION, LICENSE AMENDMENT REQUEST 07-004, CHANGES TO TECHNICAL SPECIFICATIONS TO REVISE RATED THERMAL POWER FROM 3458 MWT TO 3612 MWT (TAC NOS. MD6615 AND MD6616)

Dear Mr. Blevins:

By letter to the U.S. Nuclear Regulatory Commission (NRC) dated August 28, 2007, TXU Generation Company LP (subsequently renamed Luminant Generation Company LLC) submitted Technical Specification changes to revise the rated thermal power for Comanche Peak Steam Electric Station, Units 1 and 2, from 3458 megawatts thermal (MWT) to 3612 MWT for NRC review in accordance with Section 50.90 of Title 10 of the Code of Federal Regulations.

The NRC staff has determined that additional information is required to complete the review of the application. The specific information requested is addressed in the enclosure to this letter. It should be noted that not all of the technical branches have completed their review of the application; therefore, this is a partial request for additional information (RAI). Additional RAIs will be transmitted as the rest of the technical branches complete their review. The enclosed RAI was also sent to Mr. Jimmy Seawright via e-mail on December 5, 2007. You are requested to provide your response to the RAI by January 11, 2008.

The NRC staff considers that timely responses to RAIs help ensure sufficient time is available for NRC staff to complete its review and contribute toward the NRCs goal of efficient and effective use of staff resources.

M.

If you have any questions, please contact me at (301) 415-3016.

Sincerely,

/RA/

Balwant K. Singal, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-445 and 50-446

Enclosures:

Request for Additional Information cc w/encls: See next page

ML073440208

• Memo dated OFFICE LPL4/PM LPL4/LA CPNB/BC EEEB/BC SRXB/BC AFPB/BC LPL4/BC NAME BSingal JBurkhardt TChan*

GWilson*

GCranston*

AKlien*

THiltz DATE 12/11/07 12/11/07 11/30//07 11/21/07 12/02/07 11/28/07 12/11/07

Comanche Peak Steam Electric Station cc:

Senior Resident Inspector U.S. Nuclear Regulatory Commission P.O. Box 2159 Glen Rose, TX 76403-2159 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 Mr. Fred W. Madden, Director Regulatory Affairs Luminant Generation Company LLC P.O. Box 1002 Glen Rose, TX 76043 Timothy P. Matthews, Esq.

Morgan Lewis 1111 Pennsylvania Avenue, NW Washington, DC 20004 County Judge P.O. Box 851 Glen Rose, TX 76043 Environmental and Natural Resources Policy Director Office of the Governor P.O. Box 12428 Austin, TX 78711-3189 Mr. Richard A. Ratliff, Chief Bureau of Radiation Control Texas Department of Health 1100 West 49th Street Austin, TX 78756-3189 Mr. Brian Almon Public Utility Commission William B. Travis Building P.O. Box 13326 1701 North Congress Avenue Austin, TX 78701-3326 Ms. Susan M. Jablonski Office of Permitting, Remediation and Registration Texas Commission on Environmental Quality MC-122 P.O. Box 13087 Austin, TX 78711-3087 Anthony P. Jones Chief Boiler Inspector Texas Department of Licensing and Regulation Boiler Division E.O. Thompson State Office Building P.O. Box 12157 Austin, TX 78711

REQUEST FOR ADDITIONAL INFORMATION RELATED TO REVIEW ASSOCIATED WITH REVISION OF TECHNICAL REQUIREMENTS SURVEILLANCE FREQUENCY FOR THE TURBINE STOP AND CONTROL VALVES LUMINANT GENERATION COMPANY LLC COMANCHE PEAK STEAM ELECTRIC STATION, UNITS 1 AND 2 DOCKET NOS. 50-445 AND 50-446 By letter to the U.S. Nuclear Regulatory Commission (NRC) dated August 28, 2007, TXU Generation Company LP (subsequently renamed Luminant Generation Company LLC) submitted Technical Specification (TS) changes to revise the rated thermal power for Comanche Peak Steam Electric Station (CPSES), Units 1 and 2, from 3458 megawatts thermal (MWT) to 3612 MWT for NRC review.

The NRC staff has determined that the following additional information is required to complete the review of the application. It should be noted that not all of the technical branches have completed their review of the application; therefore, this is a partial request for additional information (RAI) based on the review performed by the following branches:

Reactor Systems Branch Electrical Engineering Branch Fire Protection Branch Piping and NDE Branch Additional RAIs will be transmitted as the rest of the technical branches complete their review.

This RAI was also sent to Mr. Jimmy Seawright via e-mail on December 5, 2007.

REACTOR SYSTEMS BRANCH Section 2.8.2

1.

The Stretch Power Uprate Licensing Report (SPULR) discusses CPSESs use of the VANTAGE+ fuel design. Describe the content of each units current fuel system makeup and that proposed for the first uprated cycle. Provide a summary of the hydraulic and mechanical compatibility features of each type of fuel assembly used in the uprated core.

2.

Summarize how the Stretch Power Uprate (SPU) core design differs, from the current core design, to support the higher energy requirements of the uprated core. Include a discussion on integral fuel burnable absorber use, fuel enrichment, burnup, and batch loading.

Section 2.8.3

3.

Explain why the pressure drop across the core decreases as a result of the power uprate analysis

Section 2.8.4.1

4.

How is the capability of the Control Rod Drive Mechanism (CRDM) cooling system affected by the planned power uprate?

5.

How will the scram response times of the CRDMs be affected by the planned power uprate?

Section 2.8.4.2

6.

Provide the results, including transient plots and sequence-of-events tables, for the loss of external electrical load/turbine trip event performed for CPSES, Units 1 and 2, which demonstrate that the overpressure criteria continue to be met for the SPU program when the second, safety-grade reactor trip signal is credited (Standard Review Plan (SRP) 5.2.2 II.3.B.iii).

7.

Describe the method (e.g., analyses or calculations) that was used to determine the allowable power levels corresponding to 1, 2, and 3 inoperable main steam safety valves (MSSVs), as specified in TS 3.7.1.1 and in License Amendment Request (LAR)

Table 2.8.4.2-1.

8.

This section alludes to the CPSES Final Safety Analysis Report Section 5.2.2, which states that overpressure protection is provided for the loss of electrical load and/or turbine trip, the uncontrolled rod withdrawal at power, the loss of reactor coolant flow, the loss of normal feedwater, and the loss-of-offsite power to the station auxiliaries. Then it states that, [t]hese events bound those credible events that could lead to overpressure of the reactor coolant system (RCS) if adequate overpressure protection were not provided. Explain this statement.

9.

Explain how demonstrating compliance with Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Appendix A, General Design Criterion (GDC) 15, "Reactor coolant system design," and GDC 31, "Fracture prevention of reactor coolant pressure boundary," would satisfy the intent of SRP 5.2.2.

Section 2.8.5.0

10.

Discuss the differences between steam generators at each CPSES unit and how these differences are accounted for in the safety analyses.

11.

Confirm the statement that none of the non-LOCA [loss-of-coolant accident] transients are limiting with minimum setpoints by showing an acceptable departure from nucleate boiling (DNB) reduction resulting from an analyzed decrease in MSSV lift setpoints.

12.

Describe how the moderator temperature coefficient is calculated. Confirm that the behavior described in Bullet 3 of Section 2.8.5.0.4 is an analyzed and expected value.

Section 2.8.5.3

13.

Identify and explain any changes in the loss of flow sequences that occur (i.e., sequence timing) as a result of the proposed power uprate.

Section 2.8.5.4.1

14.

How will the increase in fuel duty and power level affect startup transients and the negative reactivity from doppler effects? Will any of the trip setpoint functions be changed (source range neutron flux reactor trip, intermediate range neutron flux reactor trip, power range neutron flux reactor trip (low setting), power range neutron flux reactor trip (high setting), high nuclear flux rate reactor trip)?

15.

In the Low Power Startup analysis, boron concentration does not appear to have been considered. Explain why.

16.

In the results, the maximum power level, peak fuel rod temperature, and maximum heat flux was included but the peak reactor temperature and pressure were not. Justify the reason for omitting these results from the analysis.

Section 2.8.5.4.2

17.

In Section 2.8.5.4.2.2.2, a conservatively small value of the doppler coefficient is assumed and a conservatively large positive moderator density coefficient and a large negative doppler coefficient are assumed. Provide these values and explain how they were determined.

18.

Explain how rod configurations and power distributions were considered in this analysis.

19.

The SPULR states that two cases for minimum and maximum reactivity feedback were analyzed. The staff was unable to locate the results for the maximum reactivity feedback case. Provide these results.

Section 2.8.5.4.3

20.

Conditions of first-order importance for any time in cycle are initial power level and distribution, initial rod configuration, reactivity addition rate, moderator temperature, fuel temperature, and void reactivity coefficients. Verify that these parameters were taken into consideration when conducting the analyses.

21.

Provide supporting results to show that an upper bound of the number of fuel rods experiencing DNB is 5 percent of the total number of fuel rods in the core.

22.

Clarify why DNB calculations were not performed for the rod cluster control assemblies (RCCAs) missing from other banks and how power shape calculations for the RCCA ejection analysis accounts for the previously stated analysis.

Section 2.8.5.4.5

23.

This section of the SPULR states that for at-power, Modes 1 and 2, the dilution accident erodes the shutdown margin made available through reactor trip. For shutdown mode initial conditions, Modes 3, 4, 5, and 6, the dilution accident erodes the shutdown margin inherent in the borated RCS inventory and that which may be provided by control rods (control and shutdown banks) made available through reactor trip. Clarify how, in Modes 1 and 2, the reactor is shut down through a reactor trip (control rods, boron, etc.).

24.

The Chemical and Volume Control (CVCS) System malfunction analysis was not performed for Mode 6 refueling because a boron dilution event is prevented by administrative control of valves in the possible dilution paths. Clarify whether the 30-minute limit is still obtainable between the time that an alarm annunciates an unplanned moderator dilution and the time that shutdown margin is lost.

25.

Explain whether CVCS malfunction analyses accounted for any malfunctions or equipment out-of-service.

26.

Clarify what, if any, operator actions are credited in the transient sequence addressed by Section 2.8.5.4.5.

27.

When running the CVCS malfunction analyses, were the power level, core pressure, and minimum DNB ratio specifically stated for the input parameters?

Section 2.8.5.4.6

28.

Provide the results of this analysis for cladding oxidation and hydrogen formation.

Section 2.8.5.5

29.

Verify that the RETRAN N-16 model, which provides the CPSES OTN-16 and OPN-16 reactor trips (functionally equivalent to the overtemperature and overpower T (delta temperature) reactor trips of other Westinghouse plants), have been reviewed and approved by the NRC staff, particularly for use in analyses of the RCCA withdrawal at-power and RCS depressurization events.

30.

For the inadvertent operation of the emergency core coolant system (ECCS) event, show that the operators, following applicable emergency procedures, can open at least three of the four steam generator atmospheric relief valves (ARVs) within 7 minutes and 30 seconds after a safety-grade alarm (e.g., the reactor trip or safety injection signal).

Similarly, show that the operators, following applicable emergency procedures, can secure the ECCS within 13 minutes after a safety-grade alarm.

31.

How does the analysis of the inadvertent operation of the ECCS during power operation (LAR Section 2.8.5.5) bound the CVCS malfunction that results in an increase in reactor coolant inventory? (This is not simply a comparison of flow rates.)

32.

During an inadvertent operation of the ECCS event, fully opening at least three of four ARVs would cool the RCS to temperatures below 557 degrees Fahrenheit (oF). How would the operators control the RCS temperature to 557 oF?

ELECTRICAL ENGINEERING BRANCH

1.

In Section 2.3.1.2.2 of the SPULR, Inside Containment, it is stated that at SPU, the containment analysis of design-basis accidents (DBAs) demonstrates that the equipment qualification (EQ) for peak temperature remains bounded by the current EQ profile.

However, the long-term temperature slightly exceeds the current profile at a limited time later in the transient after the peak temperature has been reduced.

Provide details of the long-term temperature impact and the temperature evaluation done for DBA conditions.

2.

In Section 2.3.1.2.2 of the SPULR, Inside Containment, it is stated the following:

Where the increase in radiation exceeds the current EQ limits, additional analysis will be [emphasis added] performed to document that the affected components specific dose is bounded by the specific component EQ qualification.

Provide the results of the additional radiation analysis performed on the affected components.

3.

In Section 2.3.1.2.2 of the SPULR, Outside Containment, it is stated that there is a small temperature increase from existing high energy line break temperatures in the main steam and feedwater penetration areas. The licensee further stated the following:

Where the increase in temperature exceeds the current EQ limits, additional analysis will be [emphasis added] performed to document that the affected components specific qualification bounds the affect of the temperature increase.

Provide the results of the additional temperature analysis performed on the affected components.

4.

In Section 2.3.2.2.3.1 of the SPULR, it is stated the Electric Reliability Council of Texas (ERCOT), through the transmission service provider evaluated steady-state and stability studies for the impact of the SPU on the reliability of the CPSES 345 kilovolt switchyard.

Provide a copy of the evaluation of steady-state and stability studies carried out by ERCOT.

5.

In Section 2.3.3.2.3 of the SPULR, it is stated that the main generator capability curve has been revised based on a Siemens generator uprate study. The licensee further

stated that the new uprate main generator nameplate rating will be 1410 megavolts ampere at 0.9 power factor.

Provide the nominal or approximate megawatt generation of the CPSES units before and after the SPU. Provide a copy of the updated main generator capability curve.

6.

In Section 2.3.3.2.3 of the SPULR, it is stated that its evaluation confirmed that the existing main transformers, with existing administrative limits, are adequate for the SPU.

Provide details of the analysis that was performed to determine the adequacy of the main transformers and the administrative limits of main transformers. Also, provide details of the analysis that was performed to determine the adequacy of the connected iso-phase buses.

7.

In Section 2.3.3.2.3 of the SPULR, it is stated that the existing isolated phase bus duct main generator and main transformer tap busses are inadequate to support unit operation at SPU conditions. Modifications will be implemented to support SPU conditions.

Provide details of the modifications and assurance that the modifications will be implemented before operation at SPU.

8.

In Section 2.3.2.2.1 of the SPULR, it is stated that the existing protective system relay settings will be adjusted as required to reflect the increase in the load flow in the tie lines connecting the Unit 1 and Unit 2 main transformers to the switchyard.

Provide assurance that the adjustment of above relay settings will be implemented before operation at SPU.

9.

In Section 2.3.3.2.3 of the SPULR, it is stated that its evaluation of the main generator protection confirmed that the main generator total and partial loss of field and negative sequence relays settings are affected by the SPU conditions. The settings for these relays will be adjusted to support the SPU.

Provide assurance that the adjustment of above relay settings will be implemented before operation at SPU.

10.

In Section 2.3.3.2.3 of the SPULR, it is stated that the applied protective relaying schemes and setpoints for reactor coolant pumps (RCPs) hot and cold loop motor operation and reactor electrical penetrations are affected as a result of the increase of the brake horsepower of RCP motors to support unit operation at SPU conditions.

Provide assurance that the adjustment of above relay settings will be implemented before operation at SPU.

FIRE PROTECTION BRANCH

1. to Matrix 5 (Supplemental Fire Protection Review Criteria, Plant Systems), of NRR RS-001, Revision 0, Review Standard for Extended Power Uprates, states that power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown. In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire.

However, the licensees LAR should confirm that these elements are not impacted by the CPSES SPU.

The staff notes that SPULR, Section 2.5.1.4 Fire Protection, specifically addresses only item (1) above. Provide additional information to address items (2) through (5), and a statement confirming no increase in the potential for a radiological release resulting from a fire.

2. to Matrix 5 (Supplemental Fire Protection Review Criteria, Plant Systems), of NRR RS-001, Revision 0, Review Standard for Extended Power Uprates, states that...where licensees rely on less than full capability systems for fire events the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability...

The licensee should identify the impact of the SPU on the plants post-fire safe-shutdown procedures. The staff notes that Section 2.5.1.4.2.2, Description and Analyses and Evaluations, of the SPULR does not address items (1) and (2) above. Provide additional information addressing items (1) and (2).

3.

SPULR, Section 2.5.1.4.2.2, states that time critical tasks are identified in the thermal/hydraulic analysis of the fire safe-shutdown scenario. Operations procedures implement the time critical tasks to:

Transfer power-operated relief valve (PORV) control to hot shutdown panel within five minutes Establish seal return flow within 30 minutes Start plant cooldown prior to two hours or pressurizer level exceeding 92 percent Do the above time critical operator actions result from the SPU? Discuss any assumptions, especially those of a potentially non-conservative nature that may have

been made in determining that the operator actions can confidently be accomplished within the available time.

4.

Some plants credit aspects of their Fire Protection System for other than fire protection activities, e.g., utilizing the fire water pumps and water supply as backup cooling or inventory for non-primary reactor systems. If CPSES, Units 1 and 2, credits its fire protection system in this way, the SPULR should identify the specific situations and discuss to what extent, if any, the SPU affects these non-fire-protection aspects of the plant's Fire Protection System. If CPSES, Units 1 and 2, does not take such credit, it should also be addressed in the SPULR.

PIPING AND NDE BRANCH

1.

In Section 2.1.5 of the SPULR, an equation for the susceptibility of Alloy 600 material is provided for determining the change in susceptibility due to the increase in hot-leg temperature. The gas constant, R, is provided as 1.987. The ideal gas constant is typically expressed as 1.103 E-3 kcal/mole-R, or 1.103 cal/mole-°R, where °R is the Rankine temperature scale. Clarify the units of the gas constant listed in Section 2.1.5 and recalculate the value for the change in susceptibility as appropriate.

2.

Discuss the basis for the estimated susceptibility to primary water stress-corrosion cracking at the Alloy 82/182 weld locations to be ~10-11 failure probability as specified in Section 2.1.5.2.3 of the SPULR.

3.

Discuss what is meant by chemistry changes in Section 2.1.5.2.3 SCC [Stress Corrosion Cracking] of Austenitic Stainless Steel, as Section 2.1.5.2.2 implies there are no changes to the chemistry program, at least in regard to lithium addition.

4.

SPULR, Section 2.1.5.2.3, Description of Analyses and Evaluations, states that the change in the service temperature on thermal aging has been considered. Discuss how the change in the service temperature on thermal aging has been considered. This section also references WCAP-14575 and states that any potential affect on thermal aging due to the SPU would be contained within the proposed programs of WCAP-14575. Discuss how any potential affect on thermal aging due to the SPU would be contained within the proposed programs of WCAP-14575. Include in the discussion whether those programs have already been implemented or the plan for future implementation.

5.

Discuss the projected wear rates in the extraction steam piping to the second point heater. Include in the discussion the current wear rates and the changes that may result from implementation of the SPU for both units. Clarify if the piping sections listed in Tables 2.1.8-1 and 2.1.8-2 of the SPULR indicate the largest increases in projected wear rates for the systems in the flow-accelerated corrosion program. If these do not represent the largest increases in wear rate, discuss those with the largest increases in wear rate.