proprietary information – withhold under …joseph donahue vice president nuclear engineering 526...

JOSEPH DONAHUE Vice President Nuclear Engineering 526 South Church Street, EC-07H Charlotte, NC 28202

980-373-1758 [email protected]

PROPRIETARY INFORMATION - WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ATTACHMENT 3 THIS LETTER IS UNCONTROLLED

PROPRIETARY INFORMATION – WITHHOLD UNDER 10 CFR 2.390

UPON REMOVAL OF ATTACHMENT 3 THIS LETTER IS UNCONTROLLED Serial: RA-17-0043 10 CFR 50.90 October 9, 2017 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 DOCKET NO. 50-400 / RENEWED LICENSE NO. NPF-63 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 / RENEWED LICENSE NO. DPR-23 SUBJECT: RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION (RAI)

REGARDING APPLICATION TO REVISE TECHNICAL SPECIFICATIONS FOR METHODOLOGY REPORT DPC-NE-3009, REVISION 0

REFERENCES: 1. Duke Energy letter, Supplemental Information for License Amendment Request

Regarding Methodology Report DPC-NE-3008-P, dated October 3, 2016 (ADAMS Accession No. ML16278A080)

2. NRC letter, Duke Energy Progress, LLC, For Shearon Harris Nuclear Power Plant, Unit 1, and H. B. Robinson Steam Electric Plant, Unit No. 2 - Request For Additional Information Regarding Application to Adopt DPC-NE-3008-P, Revision 0, "Thermal-Hydraulic Models for Transient Analysis," and DPC-NE -3009-P, Revision 0, "FSAR / UFSAR Chapter 15 Transient Analysis Methodology" (CAC Nos. MF8439 and MF8440), dated September 8, 2017 (ADAMS Accession No. ML17226A264)

Ladies and Gentlemen:

In Reference 1, Duke Energy Progress, LLC (formerly referred to as Duke Energy Progress, Inc.), referred to henceforth as “Duke Energy,” submitted a supplemental request for an amendment to the Technical Specifications (TS) for Shearon Harris Nuclear Power Plant, Unit 1 (HNP) and H. B. Robinson Steam Electric Plant, Unit No. 2 (RNP). In part, Duke Energy requested NRC review and approval of DPC-NE-3009-P, Revision 0, “FSAR / UFSAR Chapter 15 Transient Analysis Methodology,” and adoption of the methodology into the TS for HNP and RNP. In Reference 2, the NRC requested additional information (RAI) regarding DPC-NE-3009.

Attachment 3 provides Duke Energy’s response to a portion of the Reference 2 RAI’s. The specific RAI’s included are: RAI-3, 5, 6, 8-13, 15-17, 21, 22, 24, 25, 28, 29, 31-35, 37-39, 42,

WJD1

Cross-Out

WJD1

Cross-Out

PROPRIETARY INFORMATION -WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ATTACHMENT 3 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission RA-17-0043 Page2

45-47, 49, and 53-57. Responses to the remaining RAl's will be provided at a later date. Attachment 3 contains information that is proprietary to Duke Energy. In accordance with 1 O CFR 2.390, Duke Energy requests that Attachment 3 be withheld from public disclosure. An affidavit is included (Attachment 1) attesting to the proprietary nature of Attachment 3. A nonproprietary version of Attachment 3 is included in Attachment 2.

This submittal contains no new regulatory commitments. Duke Energy is notifying the states of North Carolina and South Carolina by transmitting a copy of this letter to the designated state officials. Should you have any questions concerning this letter, or require additional information, please contact Art Zaremba, Manager- Nuclear Fleet Licensing, at 980-373-2062.

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

Executed on October 9, 2017.

Sincerely,

~v:i~~ Joseph Donahue Vice President - Nuclear Engineering

JBD

Attachments: 1. Affidavit of Joseph Donahue 2. Response to NRC Request for Additional Information (Redacted) 3. Response to NRC Request for Additional Information (Proprietary)

cc: (all with Attachments unless otherwise noted)

C. Haney, Regional Administrator USNRC Region II J. Zeiler, USNRC Senior Resident Inspector - HNP J. Rotton, USN RC Senior Resident Inspector - RNP M. C. Barillas, NRR Project Manager - HNP D. J. Galvin, NRR Project Manager - RNP W. L. Cox, Ill, Section Chief, NC DHSR (Without Attachment 3) S. E. Jenkins, Manager, Radioactive and Infectious Waste Management Section (SC)

(Without Attachment 3) A. Wilson, Attorney General (SC) (Without Attachment 3) A. Gantt, Chief, Bureau of Radiological Health (SC) (Without Attachment 3)

PROPRIETARY INFORMATION -WITHHOLD UNDER 10 CFR 2.390 UPON REMOVAL OF ATTACHMENT 3 THIS LETTER IS UNCONTROLLED

WJD1

Cross-Out

WJD1

Cross-Out

Attachment 1 RA-17-0043

Attachment 1

Affidavit of Joseph Donahue

Attachment 1 RA-17-0043 Page 1 of 3

AFFIDAVIT of Joseph Donahue

1. I am Vice President of Nuclear Engineering, Duke Energy Corporation, and as such have

the responsibility of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear plant licensing and am authorized to apply for its withholding on behalf of Duke Energy.

2. I am making this affidavit in conformance with the provisions of 10 CFR 2.390 of the

regulations of the Nuclear Regulatory Commission (NRC) and in conjunction with Duke Energy’s application for withholding which accompanies this affidavit.

3. I have knowledge of the criteria used by Duke Energy in designating information as

proprietary or confidential. I am familiar with the Duke Energy information contained in Attachment 3 to Duke Energy RAI response letter RA-17-0043 regarding application to revise technical specifications for report DPC-NE-3009-P.

4. Pursuant to the provisions of paragraph (b) (4) of 10 CFR 2.390, the following is furnished

for consideration by the NRC in determining whether the information sought to be withheld from public disclosure should be withheld.

(i) The information sought to be withheld from public disclosure is owned by Duke

Energy and has been held in confidence by Duke Energy and its consultants.

(ii) The information is of a type that would customarily be held in confidence by Duke Energy. Information is held in confidence if it falls in one or more of the following categories.

(a) The information requested to be withheld reveals distinguishing aspects of a

process (or component, structure, tool, method, etc.) whose use by a vendor or consultant, without a license from Duke Energy, would constitute a competitive economic advantage to that vendor or consultant.

(b) The information requested to be withheld consist of supporting data, including

test data, relative to a process (or component, structure, tool, method, etc.), and the application of the data secures a competitive economic advantage for example by requiring the vendor or consultant to perform test measurements, and process and analyze the measured test data.

(c) Use by a competitor of the information requested to be withheld would reduce

the competitor’s expenditure of resources, or improve its competitive position, in the design, manufacture, shipment, installation assurance of quality or licensing of a similar product.

(d) The information requested to be withheld reveals cost or price information,

production capacities, budget levels or commercial strategies of Duke Energy or its customers or suppliers.


(e) The information requested to be withheld reveals aspects of the Duke Energy funded (either wholly or as part of a consortium ) development plans or programs of commercial value to Duke Energy.

(f) The information requested to be withheld consists of patentable ideas.

The information in this submittal is held in confidence for the reasons set forth in paragraphs 4(ii)(a) and 4(ii)(c) above. Rationale for this declaration is the use of this information by Duke Energy provides a competitive advantage to Duke Energy over vendors and consultants, its public disclosure would diminish the information’s marketability, and its use by a vendor or consultant would reduce their expenses to duplicate similar information. The information consists of analysis methodology details, analysis results, supporting data, and aspects of development programs, relative to a method of analysis that provides a competitive advantage to Duke Energy.

(iii) The information was transmitted to the NRC in confidence and under the

provisions of 10 CFR 2.390, it is to be received in confidence by the NRC.

(iv) The information sought to be protected is not available in public to the best of our knowledge and belief.

(v) The proprietary information sought to be withheld is that which is marked in

Attachment 3 to Duke Energy RAI response letter RA-17-0043 regarding application to revise technical specifications for report DPC-NE-3009-P. This information enables Duke Energy to:

(a) Support license amendment requests for its Harris and Robinson reactors.

(b) Support reload design calculations for Harris and Robinson reactor cores.

(vi) The proprietary information sought to be withheld from public disclosure has

substantial commercial value to Duke Energy.

(a) Duke Energy uses this information to reduce vendor and consultant expenses associated with supporting the operation and licensing of nuclear power plants.

(b) Duke Energy can sell the information to nuclear utilities, vendors, and consultants for the purpose of supporting the operation and licensing of nuclear power plants.

(c) The subject information could only be duplicated by competitors at similar expense to that incurred by Duke Energy.

5. Public disclosure of this information is likely to cause harm to Duke Energy because it would

allow competitors in the nuclear industry to benefit from the results of a significant development program without requiring a commensurate expense or allowing Duke Energy to recoup a portion of its expenditures or benefit from the sale of the information.


Joseph Donahue affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

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

Executed on October 9, 2017.

~~~~ JQSePhOnahue

Attachment 2 RA-17-0043

Attachment 2

Response to NRC Request for Additional Information (Redacted)

Note: Text that is within double brackets (original NRC RAI wording) or brackets with an “a,c” superscript (Duke Energy response) is proprietary to Duke Energy and has been

removed.


NRC RAI 3

Duke Energy proposed in DPC-NE-3008 that “[l]icensing applications of the RETRAN-3D

models for HNP and RNP may incorporate other uses of non-conducting heat exchangers to

model, for example, ambient heat losses.” While Section 5.0 of DPC-NE-3009 proposed

potential applications for this model, these uses were not described in sufficient detail for the

NRC staff to review them. The issue is not that the model is suspect – indeed, being able to add

heat to a fluid volume without using a heat conductor is a standard feature of thermal-hydraulic

systems analysis codes. However, the future uses were not specified in sufficient detail for the

NRC staff to determine whether or not they are acceptable. Please provide additional detail for

the NRC staff to complete the review. (SRP 15.0.2)

Duke Energy RAI 3 Response

Non-conducting heat exchangers may be used to model ambient losses from the primary

system (including the pressurizer) in certain long-term transients such as Loss of Non-

Emergency AC Power to the Station Auxiliaries, Loss of Normal Feedwater Flow and Feedwater

System Pipe Break. The HNP/RNP RETRAN-3D base models assume that all heat conductors

in contact with the containment atmosphere have a perfectly insulated boundary at that side

such that no heat transfer occurs from the metal surfaces of the primary system to the

containment atmosphere. To account for the fact that some energy is transferred from the metal

surfaces through the insulation and into the containment atmosphere, non-conducting heat

exchangers may be attached to the primary system. [

]a,c


Non-conducting heat exchangers may also be used when a more detailed feedwater system

model is desired for transients such as Steam System Piping Failure. Additional volumes and

junctions are used to model the feedwater piping, with the feedwater heaters simulated using

non-conducting heat exchangers. The heat addition rates from each feedwater heater are

determined using plant design data and are adjusted to conservatively bound expected system

alignments of the condensate and main feedwater systems, consistent with the initial condition

of the event.

When the simplified steam generator secondary model is used for transients that are initiated

from hot zero power, it may be desirable to use non-conducting heat exchangers to remove the

heat generated by the operating reactor coolant pumps during the steady-state initialization.

When this method is employed, there is no flow modeled in the secondary side during the

steady-state initialization. The non-conducting heat exchangers are added to the [

]a,c This method simplifies the

steady-state initialization process and results in initial conditions equivalent to those obtained

using feedwater addition for RCS heat removal during the steady-state initialization.


NRC RAI 5

Duke Energy proposed in Section 5.0 to use the RETRAN-3D decay heat model. In specifying

how this model will be used, Duke Energy did not specify which transients would use low,

nominal, or high decay heat assumptions. Please clarify the decay heat assumptions for the

transients considered in DPC-NE-3009. (SRP 15.0.2)


Most of the non-LOCA transients covered by DPC-NE-3009 are short in duration and reach the

limiting conditions prior to or near the time of reactor trip. For these transients, the decay heat

assumption is not important and is assumed to be nominal (1979 ANS Standard with a multiplier

of 1.0).

There are only five long-term transients in DPC-NE-3009 for which the decay heat assumption

is important. Decay heat for these transients will be treated as follows:

Transient Decay Heat Assumption

Steam System Piping Failure Low decay heat is conservative in order to maximize the

overcooling of the primary system.

Loss of Non-Emergency AC

Power to the Station Auxiliaries

High decay heat is conservative in order to maximize the

post-trip heatup of the primary system.

Loss of Normal Feedwater Flow

Feedwater System Pipe Break

Steam Generator Tube Rupture For the overfill analysis, sensitivity studies will be performed

to determine if high or low decay heat is limiting. For the

thermal-hydraulic input analysis, high decay heat is

conservative in order to maximize the post-trip heatup of the

primary system.


NRC RAI 6

Section 3.3, “VIPRE-01,” proposes the use of the “Modified Barnett” correlation for critical heat

flux evaluations of off-rated conditions in VIPRE-01. The cited basis for approval of this

correlation is Section 15.3.1.2.5 of DPC-NE-3005, “UFSAR Chapter 15 Transient Analysis

Methodology,” (Reference 13). The NRC staff found no mention of the Modified Barnett

correlation in the version of the referenced topical report it reviewed (Revision 2). However,

Section 8.0, “References,” lists DPC-NE-3005, Revision 5, which has not been submitted to the

NRC. Please provide additional justification for the use of the Modified Barnett correlation or

provide evidence that it has been reviewed and approved by the NRC staff for similar

applications. (SRP 4.4)

NRC RAI 6 Reference

13. DPC-NE-3005-PA, “UFSAR Chapter 15 Transient Analysis Methodology,” Revision 2,

Duke Power Co., May 2005 (ADAMS Accession No. ML051740176 (proprietary) and

ML051740156 (non-proprietary)).


DPC-NE-2015-PA, Revision 0 (Reference RAI-6-1), describes the methodology for transitioning

to the Mark-B-HTP fuel assembly design at the Oconee Nuclear Station. Section 7.3 of

Reference RAI-6-1 describes a new Appendix D for DPC-NE-3000-PA, which describes

thermal-hydraulic models and benchmark analyses for the Catawba, McGuire and Oconee

Nuclear Stations. One of the changes described in the new Appendix D was to incorporate the

Modified Barnett critical heat flux correlation into the Main Steam Line Break analysis

methodology. Section 3.4 of the Safety Evaluation Report (SER) for DPC-NE-2015-PA,

Revision 0 (Reference RAI-6-2), addresses the new Appendix D and acknowledges the use of

the Modified Barnett correlation for the Main Steam Line Break analysis. According to the SER,

“The NRC staff concludes that Appendix D is acceptable to incorporate into approved

methodology report DPC-NE-3000-PA.”


Duke Energy RAI 6 Response References

RAI-6-1. “Mark-B-HTP Fuel Transition Methodology,” DPC-NE-2015-PA, Revision 0, October

2008.

RAI-6-2. Olshan, L. N., to Baxter, D., “Oconee Nuclear Station, Units 1, 2, and 3, Issuance of

Amendments Regarding Use of AREVA NP Mark-B-HTP Fuel (TAC Nos. MD7050,

MD7051, and MD7052),” October 29, 2008. (ADAMS Accession No. ML082800408)


NRC RAI 8

In Section 4.0, “Safety Analysis Physics Parameters,” Duke Energy proposed that the bounding

nature of the safety analysis can be determined by comparing key physics parameter values

from previous, “similar” core reload designs to the safety analysis values. How does the

proposed method determine that one core reload design is “similar” to another core reload

design? Additionally, how does such an approach demonstrate the amount of margin available

between the proposed core design and the safety analysis? (SRP 15.0.2)


A core design is considered similar if its [

]a,c


An example where this option could be used is for a core redesign resulting from the

identification of a damaged fuel assembly during refueling. In this scenario, the energy

requirements (in terms of the number and enrichment of fresh fuel assemblies) and burnable

absorber requirements are already established. An exchange of the damaged fuel assembly

with one of similar reactivity is typically performed with minimal or no reinsert fuel shuffling

required. In this instance, the similarity of the loading patterns would be determined based on

the comparisons described above, and the [

]a,c


NRC RAI 9

In Section 4.1, “Generic Parameters,” Duke Energy proposed the use of a “conservative

relationship between rod position (percent inserted) and normalized reactivity worth.” Please

identify how this relationship is determined. (SRP 4.3)


The position-dependent negative reactivity insertion following a reactor trip is calculated at HFP

assuming the highest-worth stuck rod remains in its fully withdrawn position. The calculation is

performed assuming a bottom-peaked power distribution to conservatively delay the amount of

negative reactivity inserted following initial control rod movement. Both the inserted worth and

rod position domains are normalized to produce the normalized worth versus normalized rod

position curve. Conservatism introduced by the bottom-peaked power distribution is dependent

upon the magnitude of the axial flux difference operating limits. An example normalized trip

reactivity worth versus normalized rod position curve for Harris is shown in Figure RAI-9-1. The

trip reactivity shape curve is multiplied by the minimum trip worth to obtain trip reactivity versus

rod position. A cycle-specific reload check is performed to verify the acceptability of the

minimum trip reactivity versus rod position curve assumed in the safety analysis.

Attachment 2 RA-17-0043 Page 9of70

Figure RAl-9-1 - Example Trip Reactivity Shape (Normalized Worth vs. Normalized Rod

Position)

a,c


NRC RAI 10

In Section 4.1, Duke Energy proposed that “perturbed power distributions allowed by the AFD

[Axial Flux Difference] and rod insertion limits are considered” for transients in which the initial

power distribution significantly impacts the course of the event. It is unclear to the NRC staff

what these “perturbed power distributions” are and how they are different from the “core power

distributions permitted by AFD and rod insertion limits” discussed earlier in the same paragraph.

Please clarify. (SRP 15.0.2, values of core physics parameters in Chapter 15 sections)


The perturbed power distributions referenced in the last sentence of Section 4.1, Sub-Section

“Initial Power Distribution,” are the same as those permitted by the AFD and rod insertion limits

used to ensure the acceptability of F∆H and FQ limits. The intent of the last sentence is to convey

that for transients such as an uncontrolled RCCA bank withdrawal, the initial core power

distribution is important not only from a peaking factor perspective, but also because it

significantly impacts the course of the event by influencing the amount of reactivity available for

withdrawal and the rate of reactivity insertion.


NRC RAI 11

In Section 4.1, Duke Energy stated that the prompt neutron lifetime is not a key parameter and

typical time-in-life values would be used for it. However, in the NRC-approved methodology

described in DPC-NE-3001, “Multidimensional Reactor Transients and Safety Analysis Physics

Parameters Methodology” (Reference 14), this parameter is biased such that the ratio of beta-

effective to the prompt neutron lifetime is minimized, which increases the neutron power spike in

the event of prompt criticality. Why is this not necessary in DPC-NE-3009? (SRP 15.0.2, values

of core physics parameters in Chapter 15 sections)

NRC RAI 11 Reference

14. DPC-NE-3001-PA, “Multidimensional Reactor Transients and Safety Analysis Physics

Parameters Methodology,” Revision 0a, Duke Energy Carolinas, LLC, May 2009

(ADAMS Accession No. ML16102A168 (proprietary) and ML16102A158 (non-

proprietary)).


Section 5.0 of DPC-NE-3001-PA, Revision 0a (Reference RAI-11-1), describes the method for

analyzing the event denoted in DPC-NE-3009 as Steam System Piping Failure for the Catawba

and McGuire Nuclear Stations. According to Sub-Section 5.3.2.6 of Reference RAI-11-1, “the

prompt neutron lifetime value is chosen to minimize the ratio of beta-effective to the prompt

neutron lifetime. This ... increases the neutron power spike when prompt criticality is achieved.”

This approach represents a conservative exception to the general treatment of prompt neutron

lifetime as “typical”, as described in Section 2.2 of Reference RAI-11-1. Justification for the

general treatment was provided in the response to RAI 27 of Reference RAI-11-1 for three

events initiated by uncontrolled RCCA withdrawals. The Safety Evaluation Report

acknowledged the response and concluded that “the determination and application of the key

safety parameters in the DPC reload methodology are acceptable.” These references support

the general treatment of prompt neutron lifetime as “typical”, as proposed in Section 4.0 of DPC-

NE-3009.


In order to resolve RAI 11 on DPC-NE-3009, [

]a,c

Duke Energy RAI 11 Response Reference

RAI-11-1. “Multidimensional Reactor Transients and Safety Analysis Physics Parameters

Methodology,” DPC-NE-3001-PA, Revision 0a, May 2009.


NRC RAI 12

The methods used to determine several key physics parameters in Section 4.2, “Control Rod

Worth Calculations” (maximum differential rod worth at subcritical, maximum differential rod

worth at power, ejected rod worth) state that adverse power distributions are considered. Please

specify the range of adverse power distributions considered in the evaluation of these

parameters and how they are generated. (SRP 15.0.2, values of core physics parameters in

Chapter 15 sections)


The xenon distributions used to create adverse power distributions for use in control rod worth

calculations are developed by either performing a series of xenon transients or by using a

reference xenon distribution skewed using [

]a,c


Control rod worth calculations are performed [

]a,c This process is repeated for each time

in life where the analysis is performed. The Technical Specification AFD and rod insertion limits

that are assumed in the analysis are specified in the Core Operating Limits Report.


NRC RAI 13

The specification of ejected rod worth in Section 4.2 indicates that only certain limiting locations

are considered in the analysis. The previously-approved DPC-NE-3001 methodology states that

“all possible rods” are analyzed. Without considering all locations, a potentially limiting rod might

be missed. Clarify how limiting locations are determined so that a potentially limiting rod is not

missed. (SRP 15.0.2, values of core physics parameters in Chapter 15 sections)


The change in the wording in the DPC-NE-3009 report relative to the DPC-NE-3001 report was

made to exclude Control Bank locations that are non-limiting. For example, the Control Bank B

insertion for Robinson at the HZP initial condition is 11 steps. This rod insertion is insufficient to

produce an ejected rod worth that would challenge accident analysis assumptions or produce a

limiting power excursion, and therefore would be excluded from analysis.

In the initial application of the method, all Control Bank D and C rods are evaluated, crediting

core symmetry, to ensure the maximum ejected rod worths assumed in the SIMULATE-3K

accident analysis remain bounding. However, as experience is gained, some Control Bank D

and C core locations may be excluded from future cycle-specific evaluations if they are

demonstrated to be non-limiting. The current control rod insertion limits for Harris and Robinson

are presented in Tables RAI-13-1 and RAI-13-2 for information. These limits are specified in

each plant’s Core Operating Limits Report.


Table RAI-13-1 – Harris Power-Dependent Rod Insertion Limits

Power Level (%) Control Bank D Control Bank C

100 186 226

52.7 98 226

20 37 165

0 0 128

Table RAI-13-2 – Robinson Power-Dependent Rod Insertion Limits

Power Level (%) Control Bank D Control Bank C Control Bank B

100 165 226 226

67.5 98 226 226

20 0 128 226

5.5 0 98 226

0 0 87 215


NRC RAI 15

In Section 5.0, Duke Energy proposed to use the statistical core design (SCD) methodology

described in the NRC-approved DPC-NE-2005 (Reference 15) methodology for evaluation of

departure from nucleate boiling (DNB). This methodology relies on subchannel analyses

performed at a number of statepoints to determine the statistical core design limit, and as such

this limit is only valid when the analysis is performed at or near these statepoints. If the analysis

statepoint falls outside of the range of the statistical design limit, a non-SCD analysis is

performed. The NRC staff has several questions about both the SCD and non-SCD analyses.

a. Duke Energy proposed that the SCD conditions could be updated to bound statepoints

that would otherwise require non-SCD calculations. The NRC staff is unclear on how this

is consistent with Condition 1 on the approval of DPC-NE-2005, which states that

“[Duke] committed in their topical report that its use of specific uncertainties and

distributions will be justified on a plant specific basis, and also that its selection of

statepoints used for generating the statistical design limit will be justified to be

appropriate.” How will such justification be provided in the event that the SCD

statepoints are adjusted? (Conformance with limitation and condition on DPC-NE-2005)

b. Duke Energy stated that “the final selection of SCD or non-SCD methodology for a given

transient will depend on the actual analysis results and may differ from the expected

selection as presented here.” However, insufficient information has been provided to the

NRC staff to determine the acceptability of the parameter biasing for transients that are

currently envisioned as SCD transients to be performed as non-SCD analyses. This is

because the tables in Section 5 of the methodology report that provide the parameter

biasing simply say “SCD” for key parameters in the DNB ratio (DNBR) evaluation. If the

flexibility to switch between SCD and non-SCD analyses is required, additional

information must be provided to justify the modeling in either scenario for each transient.

(SRP 15.0.2)



15. Barillas, M., U. S. Nuclear Regulatory Commission, letter to Frisco, J. M., Jr., Duke

Energy Corporation, “Shearon Harris Nuclear Power Plant, Unit 1 and H. B. Robinson

Steam Electric Plant, Unit No. 2 – Issuance of Amendments Revising Technical

Specifications for Methodology Report DPC-NE-2005-P Revision 5, ‘Thermal-Hydraulic

Statistical Core Design Methodology’ (TAC Nos. MF5872 and MF5873),” March 8, 2016

(ADAMS Accession No. ML16049A630).

Duke Energy RAI 15a Response

The Duke Energy SCD methodology in Reference RAI-15-1 directly uses the VIPRE-01

thermal-hydraulic code to do all DNB calculations. The direct use of the code to explicitly

analyze DNBR sensitivity to each unique set of conditions ensures the direct applicability of this

method to varying fuel design and plant parameters.

Section 1.3 of the main body of Reference RAI-15-1 states one of the benefits of direct code

use: “This method can also be used to evaluate a statepoint outside the range of the original

key parameters assumed. If the statepoint statistical DNBR does not exceed the SDL, the

statepoint can apply the licensed limit.” Table 7, SDL Evaluation and Resubmittal Criteria, of

Reference RAI-15-1 lists specific examples of anticipated future conditions analyzed and any re-

submittal requirements before use in license analyses. The third item listed is “New Statepoint”

which requires no further NRC interaction prior to implementation.

Duke Energy RAI 15a Response Reference

RAI-15-1. “Thermal-Hydraulic Statistical Core Design Methodology,” DPC-NE-2005-PA,

Revision 5, March 2016.


Duke Energy RAI 15b Response

In the event that an SCD analysis falls outside the applicable parameter range of the Statistical

Design Limit (SDL), the first recourse is to determine an SDL for that statepoint using the SCD

method as described in the response to RAI 15a. However, in the event that the statepoint

cannot or will not be reanalyzed with the SCD method given in DPC-NE-2005, the transient may

be analyzed using the non-SCD system analysis methodology. The SCD methodology is used

to evaluate the departure from nucleate boiling (DNB) acceptance criteria. (Note that the

remainder of this response will use the term “DNB event” to generically denote a DNB analysis

performed with either the SCD or non-SCD methodology.) DNB events which require analysis

using the non-SCD methodology will typically bias initial core power high, reactor average

temperature high, pressurizer pressure low, reactor coolant system (RCS) flow low, and core

bypass flow high. This parameter biasing will produce a conservative minimum DNBR for most

events. If the DNB event is performed as a non-SCD system analysis, the resultant DNBR from

the core thermal-hydraulic analysis will be compared to the CHF correlation limit to determine

acceptability.

Some DNB events may not use the typical parameter biasing due to the OTΔT reactor trip

function. The OTΔT reactor trip has a dynamic setpoint that changes as a function of reactor

coolant average temperature and pressurizer pressure, which may introduce competing effects.

For example, biasing pressurizer pressure low would typically be conservative for a DNB

analysis as it decreases DNBR. However, relative to using a high initial pressurizer pressure, a

low initial pressurizer pressure would also decrease the OTΔT setpoint, potentially resulting in

an earlier reactor trip and a less limiting statepoint for DNBR. The biasing of pressurizer

pressure and reactor average temperature will therefore be evaluated if a DNB event is

analyzed using the non-SCD methodology and is mitigated by the OTΔT reactor trip function.

Section 5 of DPC-NE-3009 identifies the following DNB events as potentially mitigated by the

OTΔT trip:


● Increase in Feedwater Flow (Section 5.1.1)

● Loss of External Electrical Load (Section 5.2.1)

● Turbine Trip (Section 5.2.2)

● Loss of Normal Feedwater Flow (Section 5.2.4)

● Feedwater System Pipe Break (Section 5.2.5)

● Uncontrolled RCCA Bank Withdrawal at Power (Section 5.4.2)

● Dropped Full-Length RCCA or RCCA Bank (Section 5.4.3)

● Withdrawal of a Single Full-Length RCCA (Section 5.4.4)

● Spectrum of RCCA Ejection Accidents (Section 5.4.8)

● Inadvertent Opening of a Pressurizer Relief or Safety Valve (Section 5.6.1)

● Steam Generator Tube Rupture (Section 5.6.2)


NRC RAI 16

Section 5.0 discussed key parameter selection and biasing, on a generic basis, for all of the

transients. The NRC staff have the following questions about this biasing. (SRP 15.0.2, values

of initial and boundary conditions in Chapter 15 sections)

a. Transients discussed as non-SCD are stated to have uncertainties included in the

biasing of initial and boundary conditions. What uncertainties are included and how are

they represented in the analysis?

b. Does the maximized or minimized reactor coolant system (RCS) flow rate include

instrument and other uncertainties?

c. How is the best estimate of core bypass flow determined?

d. Why is steam generator tube plugging not just assumed to be zero when it is biased

“low”? What is the basis for plugging values assumed that are less than 1%?


Transients analyzed using the non-SCD methodology account for the initial condition

uncertainty in core power, reactor average temperature, pressurizer pressure, total RCS flow,

and core bypass flow. The initial condition uncertainty is calculated using the total loop

uncertainty associated with a given parameter’s automatic control system, where applicable.

The total loop uncertainty is calculated by combining the various component random

uncertainties using the square-root-sum-of-squares (SRSS) method. The component random

uncertainties include primary element, sensor, and rack uncertainty terms, and non-random

uncertainties associated with the system are treated as a bias. If no automatic control system is

associated with a parameter, then the indication uncertainty associated with its Technical

Specification surveillance is used. The treatment of uncertainty for total RCS flow is described in

the response to RAI 16b. A bounding maximum core bypass flow will be used for non-SCD

events.


The parameter uncertainty will be modeled in the RETRAN-3D system analysis by increasing or

decreasing the initial condition by the initial condition uncertainty. Associated control systems for

the parameters are adjusted by the initial condition uncertainty to give a conservative response

and produce bounding consequences for each of the events. No bias is applied to the input to

reactor trips, as the reactor trip analytical limits account for their respective instrument loop

uncertainties.


The maximized and minimized RCS flow rates reflect the uncertainty in the calorimetric

combined with the loop RCS flow measurement uncertainty to create a total RCS flow

measurement uncertainty. The calorimetric is performed after startup to verify that RCS flow is

greater than Technical Specification minimum RCS flow. At HNP and RNP, the surveillance limit

for RCS flow is set to Technical Specification minimum RCS flow plus total RCS flow

measurement uncertainty, ensuring that the minimum measured RCS flow is greater than or

equal to Technical Specification minimum flow. For DNB analyses performed using the SCD

methodology, RCS flow uncertainty is accounted for in the Statistical Design Limit (SDL), so the

RCS flow surveillance limit or minimum measured flow is used as the initial condition. For DNB

analyses performed using the non-SCD methodology, Technical Specification minimum RCS

flow is used as the initial condition. Maximum RCS flow is calculated as maximum design flow

plus total RCS flow uncertainty.

Duke Energy RAI 16c Response

If available, a steady-state thermal-hydraulic analysis of all core bypass flow paths and their

associated geometry and flow resistances will provide the calculated best-estimate core bypass

flow used in the SCD analyses. Otherwise, SCD analyses will assume a conservatively high

core bypass flow that is [

]a,c


Duke Energy RAI 16d Response

The HNP and RNP RETRAN-3D base decks model 0.037% and 0.456% tube plugging,

respectively. These values were calculated using the actual number of plugged and unplugged

steam generator tubes at the time the base models were developed. Tube plugging is expected

to increase with continued plant operation, so the above values for tube plugging are considered

to be conservatively low. As such, these values will be used for transients in which low tube

plugging is conservative.


NRC RAI 17

For the increase in feedwater flow transient discussed in Section 5.1.1, “Increase in Feedwater

Flow,” Duke Energy stated that “where applicable, a coincident step decrease in main feedwater

temperature is also assumed to occur.” It is not clear to the NRC staff how applicability is

determined, or how the step change in feedwater temperature is determined. Please

clarify/justify. (SRP 15.0.2)


The coincident step decrease in main feedwater temperature applies whenever necessary to

bound the transient condition. For HFP cases, the steady-state value typically reflects normal

operation, and a coincident step decrease is applied to bound the transient condition. For HZP

cases, the steady-state value is typically selected to bound the transient condition, and no

coincident step decrease is required. When applicable, the step decrease is calculated as

described in the response to Question 1 in the letter dated 18 August 1995 in DPC-NE-3002-A,

Revision 4b (Reference RAI-17-1). As stated in the response, “The magnitude of the

temperature decrease is conservatively calculated based on maintaining a constant heat

addition rate from the feedwater heaters.”


RAI-17-1. “UFSAR Chapter 15 System Transient Analysis Methodology,” DPC-NE-3002-A,

Revision 4b, September 2010.


NRC RAI 21

Section 5.1.4.1, “RETRAN-3D Models and Options,” proposed the use of the RETRAN-3D

general transport model to track boric acid injected by the emergency core cooling system

(ECCS). Section 4.3, “Reactivity Coefficients,” indicates that differential boron worth is

considered to be a function of reactor coolant temperature and other variables. Given that [[

]], the NRC staff

was unsure of how the differential boron worth was determined for this application. Please

clarify. (SRP 15.0.2, values of core physics parameters in Chapter 15 sections)


A conservatively small differential boron worth was selected for use in the Steam System Piping

Failure accident analysis to bound expected values of this derivative during the course of the

event. SIMULATE-3 differential boron worth calculations were performed at EOC as a function

of [

]a,c


NRC RAI 22

Section 5.1.4.2, “Primary Systems and Components,” proposed to model cold leg accumulators

with the built-in RETRAN-3D accumulator model. However, the NRC staff was unclear on the

initial conditions of the accumulators (including boric acid concentration, initial level, cover gas

pressure) and whether the potential for incursion of noncondensible gases into the RCS is

considered in the steam line break analysis. Please provide additional information on the

modeling and initial/boundary conditions of the accumulators. (SRP 15.0.2, values of initial and

boundary conditions in Chapter 15 sections)


The cold leg accumulators may or may not inject during the time period of interest for a given

(U)FSAR Chapter 15 Steam System Piping Failure transient. Consistent with Section 15.3.1.1.4

of DPC-NE-3005-PA, Revision 2 (Reference RAI-22-1), the initial conditions of the accumulators

(denoted as “core flood tanks” or “CFTs” in Reference RAI-22-1) will be specified using

minimum values of pressure, temperature, inventory and boron concentration. The cold leg

accumulators are not expected to approach an empty condition during the time period of interest

for a (U)FSAR Chapter 15 Steam System Piping Failure transient. Accordingly, the potential for

incursion of non-condensable gases into the RCS is not considered in the analysis.


RAI-22-1. “UFSAR Chapter 15 Transient Analysis Methodology,“ DPC-NE-3005-PA, Revision

2, May 2005.


NRC RAI 24

In the steam line break analysis of Section 5.1.4.3, “Secondary Systems and Components,” in

the methodology report, it is stated that auxiliary feedwater (AFW) is modeled conservatively

and is assumed to be terminated by operator action. (SRP 15.1.5.II, SRP Acceptance Criteria:

“The analyses should take account of the effect that loss of offsite power has … the initiation of

auxiliary feedwater flow, and the effects on the sequence of events for these accidents”; SRP

15.1.5.III: “the availability of the auxiliary feedwater system to supply adequate auxiliary

feedwater flow to the intact steam generators during the accident and the subsequent shutdown

condition is evaluated.”)

a. In the plant analyses of record as presented in the HNP and RNP (U)FSARs, AFW flow

starts at the time of break initiation. Please discuss why it is acceptable to eliminate this

conservatism.

b. No details were provided on the operator action needed to terminate AFW or how (or

even if) it is incorporated into the analysis. Please provide additional details for the NRC

staff’s evaluation.


The current (U)FSAR approach of modeling AFW actuation coincident with break initiation is

judged to be overly conservative. Crediting the time required to generate the AFW actuation

signal is consistent with the typical approach for (U)FSAR Chapter 15 analyses and is judged to

be acceptable. The current (U)FSAR assumption of no time delay following the AFW actuation

signal is conservatively retained.



Operator action is assumed to isolate AFW to the faulted steam generator within 10 minutes

following a main steam line break. This action is consistent with the current (U)FSAR analyses

and is included in the Time Critical Action Program for both plants to ensure that the action can

be accomplished by plant personnel. No new operator action is assumed to isolate AFW.


NRC RAI 25

For the cycle specific evaluation of the steam line break presented in Section 5.1.4.7, “Cycle-

Specific Evaluation,” of the methodology report, Duke Energy stated that [[

]]. Please provide additional details on this analysis.

(SRP 15.0.2)


A description of the power search method used to confirm that the predicted reactivity response

by RETRAN-3D is conservative is described below. The initial step is to determine the critical

eigenvalue prior to performing the power search calculation in SIMULATE-3. Equation RAI-25-1

is used to calculate this eigenvalue:

[ ]a,c (Eq. RAI-25-1)

where:

𝑘𝑘𝑐𝑐𝑖𝑖𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 = SIMULATE-3 eigenvalue corresponding to the ARI(N-1) condition prior to

transient initiation

∆𝜌𝜌𝑆𝑆𝑆𝑆𝑆𝑆 = Technical Specification minimum shutdown margin (SDM)

∆𝜌𝜌𝑝𝑝𝑝𝑝 = Allowance for the uncertainty in the predicted power defect. This allowance is

calculated by assuming a [

]a,c


The critical eigenvalue from Equation RAI-25-1 [

]a,c

Peaking factors from the core power distribution predicted by SIMULATE-3 are used in

subsequent calculations to confirm the acceptability of DNB and CFM limits.


NRC RAI 28

Section 5.2.3, “Loss of Non-Emergency AC Power to the Station Auxiliaries,” presents the

analysis methodology for the loss of non-emergency alternating current power to the station

auxiliaries transient. NRC staff are asked in SRP 15.2.1-15.2.5 Section III.3 (Reference 17) to

review the effects of single active system or component failures that may affect the course of

the transient. From the licensee's submittal, it is clear that the limiting failure is assumed to

occur in the AFW. However, it is unclear exactly what the limiting failure is or how the AFW is

modeled for the transient. The NRC staff has the following questions to clarify this issue. (SRP

15.2.1-15.2.5)

a. The licensee's submittal states that “Auxiliary feedwater actuates on either low steam

generator level or loss of non-emergency AC power with a conservative delay.” Does

this mean that there is a delay only when AFW actuates on loss of non-emergency AC

power, or is there also one when it actuates on low steam generator level?

b. The licensee's submittal states that “Minimum flow from at least one auxiliary feedwater

pump is assumed.” It is unclear what is implied about the state of the AFW pumps from

this statement, since “at least one auxiliary feedwater pump” having minimum flow says

nothing about the other pumps. Please clarify.

c. What is considered to be the limiting failure within the system? Are a variety of failures

investigated in the analysis to determine what is most limiting?


17. U. S. Nuclear Regulatory Commission, NUREG-0800, “Standard Review Plan,” Section

15.2.1 - 15.2.5, “Loss of External Load; Turbine Trip; Loss of Condenser Vacuum;

Closure of Main Steam Isolation Valve (BWR [Boiling Water Reactor]); and Steam

Pressure Regulator Failure (Closed),” Revision 2, March 2007 (ADAMS Accession No.

ML070300702).



There is a conservative delay when the Auxiliary Feedwater System (AFW) actuates on either

signal: the loss of non-emergency AC power or the low steam generator level.

Duke Energy RAI 28b and 28c Response

In the Analyses of Record (AORs) discussed below, the Harris and Robinson plants credit the

use of only one AFW pump, which is more conservative than a single failure within the AFW

system. The application of DPC-NE-3009 to the Harris and Robinson plants will evaluate the

conservative treatment of the AFW system (number of steam generators receiving flow and

number of AFW pumps available) to determine whether two AFW pumps may be credited.

For the Harris plant, the worst single failure affecting AFW for the Loss of Non-Emergency AC

Power to the Station Auxiliaries event is the loss of one AFW pump. This single failure leaves

two AFW pumps available. However, the AOR for this event for Harris credits the use of only

one AFW pump.

For the Robinson plant, the Loss of Non-Emergency AC Power to the Station Auxiliaries event

is bounded by other events. For example, the long-term aspects are bounded by the Loss of

Normal Feedwater Flow event with concurrent loss of reactor coolant pumps. The Loss of

Normal Feedwater Flow analysis credits the use of only one AFW pump, which is more

conservative than a single failure for the AFW system.


NRC RAI 29

In the feedwater system pipe break analysis methodology presented in Section 5.2.5,

“Feedwater System Pipe Break,” the short term core cooling and peak primary pressure cases

assume core physics parameters consistent with beginning of cycle (BOC) conditions. The initial

phases of the feedwater line break result in an overcooling event until the faulted steam

generator is depleted. Because of this, it is not clear that BOC core physics parameters would

provide the most limiting response, especially for the short-term core cooling case, where a

more negative moderator temperature coefficient (MTC) could provide for a worse core power

response. Please justify the choice of core physics parameters for the short-term core cooling

and peak primary pressure cases. (SRP 15.2.1-15.2.5.II.3.C, “The core burn-up is selected to

yield the most limiting combination of moderator temperature coefficient, void coefficient,

Doppler coefficient, axial power profile, and radial power distribution.”; SRP 15.2.1-15.2.5.III.5,

“The values of system parameters and initial core and system conditions as input to the model

are reviewed by the organization responsible for reactor systems. Of particular importance are

(A) the values of reactivity coefficients and control rod worths in the applicant's analysis and (B)

the variations of moderator temperature, void, and Doppler coefficients of reactivity with core

life. The reviewer evaluates the applicant’s justification showing that the core burn-up selected

yields the minimum safety margins.”)


Depending on the size of the break and the plant operating conditions at the time of the break,

the feedwater system pipe break could cause either a Reactor Coolant System (RCS) cooldown

(by excessive energy discharge through the break) or heatup (from the loss of the reactor

system heat sink). The methodology described in Section 5.2.5 of DPC-NE-3009 evaluates the

RCS heatup aspects of the Feedwater System Pipe Break transient.


If a Feedwater System Pipe Break analysis were performed to evaluate the RCS cooldown

aspects of the transient, it would use a most-negative moderator temperature coefficient and a

least-negative Doppler temperature coefficient. However, the potential RCS cooldown resulting

from a secondary pipe rupture is bounded by the cooldown in the Steam System Piping Failure

transient. In the Steam System Piping Failure analysis methodology, core physics parameters

are chosen to maximize the return to power in the RETRAN-3D calculations (refer to Section

5.1.4.4 of DPC-NE-3009).


NRC RAI 31

In the partial or complete loss of forced reactor coolant flow analysis methodology described in

Section 5.3.1, “Partial or Complete Loss of Forced Reactor Coolant Flow,” it is mentioned that

the peak pressure evaluation assumes that offsite power is maintained but no such discussion

is provided about the core cooling evaluation. Please provide a discussion of whether or not it is

conservative from a DNBR standpoint to model a loss of offsite power for the loss of flow

transient. (SRP 15.3.1-15.3.2.III.2 (Reference 18): “For new applications, LOOP [loss of offsite

power] should not be considered a single failure; each loss of flow transient should be analyzed

with and without a LOOP in combination with a single active failure.”)



15.3.1 - 15.3.2, “Loss of Forced Reactor Coolant Flow Including Trip of Pump Motor and

Flow Controller Malfunctions,” Revision 2, March 2007 (ADAMS Accession No.

ML070550010).


The Complete Loss of Forced Reactor Coolant Flow event (denoted as Complete LOF here) is

defined to result from the instantaneous trip of all reactor coolant pumps related to the loss of

power to the pump motors. In the analysis methodology, the availability of offsite power affects

the availability of systems and components in the secondary system (e.g., the Main Feedwater

System). However, the behavior of the secondary system (and availability of offsite power) is

judged to have a negligible effect on the minimum DNBR results. This conclusion is based on

the timing of minimum DNBR compared to the loop transit time.

For the discussion below, the loss of offsite power is assumed to occur coincident with reactor

trip and turbine trip. The assumption that offsite power is lost coincident with turbine trip is

consistent with the treatment of offsite power availability in Section 5.3.2 of DPC-NE-3009.


In the demonstration analysis described in Section 6.3 of DPC-NE-3009, reactor trip occurs at

1.2 seconds, followed by minimum DNBR at 3.2 seconds. A loop transit time greater than 2

seconds (i.e., 3.2 seconds minus 1.2 seconds) in this primary-system-driven event suggests

that secondary system behavior has a negligible effect on the transient results. In the

demonstration analysis described in Section 6.3 of DPC-NE-3009, the loop transit time is

estimated to be greater than 10 seconds with the complete loss of flow.

In contrast to the Complete LOF, a Partial LOF is defined to result from the instantaneous trip of

only one reactor coolant pump. In a Partial LOF analysis, the availability of offsite power affects

the availability of the remaining reactor coolant pumps, as well as the systems and components

in the secondary system. With a loss of offsite power, the remaining reactor coolant pumps

begin to coast down after a short delay following reactor trip and turbine trip. Based on the

amount of flow reduction and the rate of flow decrease in the primary system, modeling a loss of

offsite power (i.e., tripping the remaining reactor coolant pumps) is judged to yield a

conservative minimum DNBR relative to the case with offsite power available. However, the

amount of flow reduction and rate of flow decrease in the Partial LOF analysis are less than in

the Complete LOF analysis. Therefore, the Complete LOF analysis provides a bounding

minimum DNBR compared to the Partial LOF analysis, provided the ANS Condition II

acceptance criteria of the Partial LOF analysis are met.


NRC RAI 32

In the complete loss of flow demonstration analysis presented in Section 6.3, “Complete Loss of

Forced Reactor Coolant Flow (HNP),” of the report, it appears that the reactor coolant pump

coastdown curve is much less conservative than the one assumed in the analysis of record

based on the core flow rate plots provided (the flow reaches a minimum value of 60% in 10

seconds, versus 25% in the analysis of record). Please provide comparisons between plant

measurements of the pump coastdown curve and the curve assumed in the analysis so that the

NRC staff may verify that appropriately conservative boundary conditions are used. (SRP

15.3.1-15.3.2.III.5: “Time-related variations of the following parameters should be reviewed for

consistency: …core and recirculation loop coolant flow rates”)


The Loss of Forced Reactor Coolant Flow event is defined to result from the instantaneous trip

of one or more reactor coolant pumps. Coolant flow in the core decreases rapidly during the

coastdown of the affected reactor coolant pump(s).

Section 4.3.5 of DPC-NE-3008 compares a RETRAN-3D analysis of the Complete Loss of

Forced Reactor Coolant Flow event to the analysis of record (AOR) for HNP. In the benchmark

analysis, the pump coastdown behavior was closely matched to the AOR to compare the

system thermal-hydraulic response to the loss of flow. In the AOR, the core flow reaches a

value of about 25% in 10 seconds.


Figure RAI-32-1 compares selected flow coastdown results for HNP. In plant measurements of

the flow coastdown, the flow reaches a value of [ ]a,c in 10 seconds. The demonstration

analysis in Section 6.3 of DPC-NE-3009 uses a flow coastdown curve based on the plant

measurements. In the RETRAN-3D model, the pump moment of inertia is adjusted to model a

conservative flow coastdown: the flow reaches a value of 56.6% in 10 seconds. The RETRAN-

3D modeling of the flow coastdown shown in Section 6.3 of DPC-NE-3009 is conservative

relative to the plant measurements, but less restrictive than the AOR treatment. Applications of

DPC-NE-3009 will use a more conservative flow coastdown than the RETRAN-3D modeling

shown in Section 6.3 of DPC-NE-3009.


Figure RAl-32-1 - Loop Flow Coastdown Comparison

a,c


NRC RAI 33

In the locked rotor analysis methodology presented in Section 5.3.2, “Reactor Coolant Pump

Shaft Seizure (Locked Rotor) or Shaft Break,” the use of the VIPRE-01 fuel pin heat conduction

model was proposed for DNBR evaluations. However, no details were provided on how this

model is initialized or what modeling options are used. Is the model used in the same manner

as it is for the rod ejection analysis? More detail is needed for the NRC staff to appropriately

review this application of the model. (SRP 15.0.2)


Section 5.3.2 of DPC-NE-3009-P describes the analysis methodology for the Reactor Coolant

Pump Shaft Seizure (Locked Rotor) or Shaft Break events. The evaluation of the transient

results includes a review of time-related variations in fuel centerline temperature. To facilitate

this review, the VIPRE-01 calculation uses the fuel pin heat conduction model.

[

]a,c


[

]a,c


NRC RAI 34

In the HNP locked rotor demonstration analysis presented in Section 6.4, “Reactor Coolant

Pump Locked Rotor (HNP),” it is stated that “the selection of the affected loop has a negligible

effect on the transient results.” However, the NRC staff did not see a basis provided for this

claim. Duke Energy should provide additional justification, preferably in the form of sensitivity

studies, for the statement that the choice of the affected loop has a negligible effect. (SRP

15.3.1-15.3.2.III.2: “The SAR or DCD must present a quantitative analysis of the most limiting

loss of flow transient.”)


In the demonstration analysis, the affected reactor coolant pump is located in Reactor Coolant

System (RCS) Loop 2, which is connected to the pressurizer surge line (refer to Section 6.4 of

DPC-NE-3009). A sensitivity study was performed with the affected reactor coolant pump in a

loop not connected to the pressurizer surge line: RCS Loop 3. The baseline case trips the

unaffected reactor coolant pumps at the time of turbine trip and more closely matches the

assumptions in the analysis of record, which models a positive moderator temperature

coefficient. The sensitivity case changes the affected RCS loop to RCS Loop 3. The results of

the study are discussed below.

The transient results for core power, core flow, core inlet temperature and core exit pressure are

presented in Figures RAI-34-1 to RAI-34-4. These parameters are used in a transient VIPRE-01

analysis to calculate the minimum DNBR. There are negligible differences in the transient

results for normalized core power (Figure RAI-34-1), and both cases exhibit a power increase

due to the positive moderator temperature coefficient. The transient results for core inlet mass

flux (Figure RAI-34-2) and core inlet temperature (Figure RAI-34-3) show negligible differences

through the time of minimum DNBR. The core exit pressure shows about a 10 psi difference

around the time of minimum DNBR (Figure RAI-34-4), with greater differences in pressure

during the depressurization phase of the transient. The difference in minimum DNBR is

calculated to be 0.001, with minimum DNBR occurring at 3.9 seconds in both cases.


120

100 -ctJ E 80 c ..... 0

60 ~ 0 -... Q)

:= 0

40 0..

20

Figure RAl-34-1 - Normalized Core Power

• • : __......... ......- I\ ' \ • ' • • \ • • ' • ' ' • • • '---• ' ·- -Baseline

• - - Sensitivity '

0 - - - - 1 - _1 ____ - - - - - - - - - - - - - - - - - - - - - -

3.0

-2.5 ¢:: .!. s:. s 2.0 Jl

:i: -1 .5 )( ::::s u.. "' 1.0 "' ctJ

:i: 0.5

0.0

. . 0 1 2 3 4 5

Time (s) 6 7

Figure RAl-34-2 - Core Inlet Mass Flux

\ ' ~- --...... i--.-_ •

..... -Baseline •

- - - - Sensitivity ••• 1 •••• 1 •••• . . . --

0 1 2 3 4

. . . . - . - . 5

Time (s)

. - . -6 7

8 9

- - - ... - - - -8

- - - -

10

.. - - -9 10


Figure RAl-34-3 - Core Inlet Temperature

560

559

558 u:- 557 0 -~ 556 :::J ~ 555 ..... 8. 554 E ~ 553

552

551

550

2,600

2,500

-: 2,400 a. -Q) ; 2,300 in in Q)

! !

~ I~ --

! • ~

·- -Baseline

·- - - Sensitivity ____ 1 ____ 1 ____

- -0 1 2

- - - -3 4

~ ........... ~

- - - . .. - . -5

Time (s) 6

. - . -

Figure RAl-34-4 - Core Exit Pressure

-~

_/ Ii"'""

~ _/

,r ~I\

,, ~

' ~ ....

7

~ ~ - --~

.. - - .. - - - .. - . 8 9 10

n.. 2,200 ~

" 0 ... --"'--2,100 ·- -Baseline

- - Sensitivity 2,000 - - - .L - - - .L - - - - -. .

0 1 2 3 4

- - - - - - -

5 Time (s)

6

- - -

7

- - - - - - - - -

8 9 10


NRC RAI 35

Duke Energy proposed to analyze minimum DNBR using the SCD methodology for the

uncontrolled Rod Cluster Control Assembly (RCCA) bank withdrawal from subcritical or low

power transient, as described in Section 5.4.1, “Uncontrolled RCCA Bank Withdrawal from a

Subcritical or Low Power Startup Condition.” Considering the power starts at zero or a very low

level for this transient, please justify that the analysis will fall into the range of applicability of the

SCD methodology. What action would be taken if a particular case did not fall within the SCD

methodology range? (SRP 4.4, conformance with the DPC-NE-2005 methodology)


The HNP and RNP SCD ranges of applicability are selected to include the limiting statepoints

from the current analyses of record for the event denoted in DPC-NE-3009 as Uncontrolled

RCCA Bank Withdrawal from a Subcritical or Low Power Startup Condition. An event is

applicable to the SCD methodology if the thermal-hydraulic system conditions at the time of

minimum DNBR, defined as the “limiting statepoint,” fall within the SCD range of applicability as

shown in Table H-7 (RNP) and Table I-7 (HNP) of DPC-NE-2005 (Reference RAI-35-1). The

Uncontrolled RCCA Bank Withdrawal from a Subcritical or Low Power Startup Condition event

is analyzed at hot zero power. Initial core inlet temperature, core exit pressure and core flow at

hot zero power fall within the SCD applicable range and are not expected to exceed the range

at the limiting statepoint. Initial core power is nearly zero, which is outside the SCD range of

applicability. During the power excursion, however, core power typically increases into the SCD

range of applicability. As such, core power is expected to be within the range of applicability of

the SCD methodology at the time of minimum DNBR.

If the limiting statepoint falls outside the SCD range, then either the SCD range of applicability

will be adjusted as described in the response to RAI 15a, or the non-SCD methodology will be

used for the analysis as described in the response to RAI 15b.



RAI-35-1. “Thermal-Hydraulic Statistical Core Design Methodology,” DPC-NE-2005-PA,

Revision 5, March 2016.


NRC RAI 37

The primary difference between the withdrawal of a single full-length RCCA event presented in

Section 5.4.4, “Withdrawal of a Single Full-Length RCCA,” and the uncontrolled RCCA bank

withdrawal at power event presented in Section 5.4.2, “Uncontrolled RCCA Bank Withdrawal at

Power,” is that the former provides a much more localized effect than the latter, resulting in

severe radial power peaking. In the RNP demonstration analysis for this transient, it is unclear

whether these effects are considered. For example, the analysis of record in the RNP UFSAR

predicts DNB in the immediate vicinity of the withdrawn rod due to highly localized peaking,

while the demonstration analysis predicts a minimum DNBR of 1.571. Therefore, please discuss

in more detail how it is ensured that the core power distribution is appropriately calculated using

the methodology discussed in Section 5.4.4, particularly with regard to local power distributions

in the immediate vicinity of the withdrawn control rod. Are pin-level effects considered? (SRP

15.0.2, SRP 15.4.3.III.2 (Reference 19))



15.4.3, “Control Rod Misoperation (System Malfunction or Operator Error),” Revision 3,

March 2007 (ADAMS Accession No. ML063600415).



The DNB evaluation for the Withdrawal of a Single Full-Length RCCA event consists of two

main parts. The first part determines the system thermal-hydraulic response using RETRAN-3D

and uses [ ]a,c to develop

maximum allowable radial peaking (MARP) limits. The second part generates core power

distributions using SIMULATE-3 for comparison against MARP and centerline fuel melt (CFM)

limits, to determine the fraction of fuel pins that exceed each limit. The SIMULATE-3 power

distributions include the local spatial effects produced from the withdrawal of the control rod.

The cycle-specific core power distributions used in both DNB and CFM evaluations model the

localized peaking increase produced from the withdrawal of the control rod. The analysis

assumes the [

]a,c The failed fuel fractions calculated for each rodded core

configuration are then compared against the values assumed in the dose analysis to ensure the

offsite dose consequences remain within regulatory limits.

The simplified DNB analysis described in Section 6.6 assumed a radial peaking factor of 1.80

and a [ ]a,c. The assumed radial and axial peaking

factors and axial shape do not reflect the local spatial effects from SIMULATE-3. Consequently,

the minimum DNBR calculated in the demonstration analysis is higher than the minimum DNBR

expected in the licensing analysis, and is not intended to imply that the DNBR limit will not be

approached or exceeded for some rod locations in the cycle-specific evaluations.


NRC RAI 38

What reactivity insertion rate was assumed in the withdrawal of a single full-length RCCA

demonstration analysis presented in Section 6.6, “Withdrawal of a Single Full-Length RCCA

(RNP),” of the methodology report? (SRP 15.4.3.III.1)


The reactivity insertion rate assumed in the demonstration analysis presented in Section 6.6

was 0.95 pcm/s. This rate was selected as a reactivity insertion rate sensitivity study showed

that it produced the lowest transient minimum DNBR. The preliminary study examined a

spectrum of reactivity insertion rates from 0.1 pcm/s to 2.35 pcm/s.


NRC RAI 39

Duke Energy stated that the peaking resulting from statically misaligned rods (discussed in

Section 5.4.5, “Static Misalignment of a Single Full-Length RCCA”), is analyzed to confirm that

DNB or CFM will not occur. No transient systems analysis is performed. The licensee stated

that the peaking analysis is a steady-state, three-dimensional power peaking analysis, which

leads the staff to believe that the analysis is performed using SIMULATE-3; however, this was

not specified by the licensee. Please specify the name of the code used for the peaking

analysis? (SRP 15.0.2)


SIMULATE-3 is the current NRC-approved, three-dimensional computer code that will be used

to perform the power peaking analysis for the static misalignment of a single full-length RCCA.

However, the analysis methodology is independent of the model being used to perform the

power peaking analysis. An alternate NRC-approved, three-dimensional computer code could

be used in future reload analyses provided the computer code has received NRC review and

approval. Justification of the computer code’s applicability to the Harris and Robinson cores

would have to be performed through either a license amendment request (LAR) or the Generic

Letter 83-11 process. Additionally, since the computer code would be used to establish core

operating limits, an LAR would be required to add this computer code to the list of NRC-

approved methodologies used to develop core operating limits.


NRC RAI 42

The fuel assembly misloading analysis methodology described in Section 5.4.7, “Inadvertent

Loading of a Fuel Assembly in an Improper Position,” has insufficient detail for the NRC staff to

review it. Though it is apparent from the discussion that part of the evaluation hinges on whether

or not a misloading would be detected during refueling and power ascension operations and

testing, the acceptance criteria used to detect a misloading was not clearly defined.

Furthermore, the method for evaluating DNBR and CFM for misloadings that were not

detectable was not discussed in the report. Please provide the specific criteria used to detect a

misloaded assembly and the method used when misloadings are not detected. (SRP 15.0.2)


A fuel misload may result in a reactivity deviation between the as-loaded core and the reference

core design evaluated in the safety analysis. The primary concern is if the reactivity deviation

results in an increase in peaking factors that can challenge or exceed dose analysis DNB or

CFM failure assumptions. The principal protections against fuel misloads are administrative

procedures employed during the loading of fuel assemblies and components into the reactor

core. During fabrication, each fuel assembly is marked with a unique identification number to

enable easy differentiation among fuel assemblies. Following core loading and prior to

reassembling the reactor vessel, the fuel assembly identification number in each core location is

checked against a core loading diagram to ensure each assembly is in its appropriate location

and orientation.


Should these administrative controls fail, protection is provided through deviations observed

during post-refueling zero-power physics testing and during performance of low- and

intermediate-power flux maps. The zero-power physics testing criteria, such as the comparisons

of the all-rods-out critical boron concentration and bank-specific control rod worths, can detect

gross misloads. However, the principal method to detect fuel misloads is the development and

use of misload screening criteria for the low-power flux map, typically performed near 30%

power. These screening criteria are defined so that any undesirable misloads will be detected.

For this use, an undesirable misload is defined as one which would cause the core to exceed

DNB or CFM failures assumed in the plant-specific dose analysis. Because plant loading

patterns and core power distributions change from cycle to cycle, the screening criteria are by

necessity cycle-specific. In addition, the screening criteria also depend on the number and

location of incore thimbles which are available during the low-power flux map. In general, a flux

map with fewer measured detector locations requires more restrictive screening criteria to

detect undesirable misloads. A flux map which exceeds the screening criteria does not

necessarily indicate a misload, but requires further examination to ensure power distribution

limits will not be exceeded.

The cycle-specific misload analysis calculates three-dimensional power distributions for a

spectrum of potential misload events. [

]a,c The acceptance criterion for the misload analysis is that any misload which

does not exceed the screening criteria (i.e., is undetected) will not invalidate the dose analysis

assumptions on DNB or CFM.


Power distributions for the misload events [

]a,c Since the misloaded fuel assembly event is a Condition III accident,

some limited amount of fuel failures is allowed. If the number of DNB or CFM failures for a given

misload exceeds the dose analysis assumptions, then the screening criteria for the applicable

number of detector location failures must be revised so that case is detected.

An example of cycle-specific misload screening criteria is shown in Table RAI-42-1.

Table RAI-42-1 – Example of Cycle-Specific Misload Screening Criteria for the Initial Low-Power Flux Map

a,c

[

]a,c


NRC RAI 45

In Section 5.4.8.1, “Nuclear Analysis,” Duke Energy states that during the trip following a rod

ejection accident the control rods fall into the core “at a speed that satisfies the maximum rod

drop time in the technical specifications.” Since TSs are derived from the accident analysis,

please specify if the time used in the analysis is consistent with the time specified in the TSs or

is the rod drop time shorter? (SRP 15.4.8.III.1.D (Reference 20))



15.4.8, “Spectrum of Rod Ejection Accidents (PWR),” Revision 3, March 2007 (ADAMS

Accession No. ML070550014).


The rod drop time used for the Spectrum of RCCA Ejection Accidents event is consistent with

the rod drop times specified in Technical Specifications 3.1.3.4 (HNP) and 3.1.4.3 (RNP).

Technical Specification rod drop times are verified for all control rods through the performance

of rod drop timing tests, prior to unit startup following each refueling outage, to ensure safety

analysis assumptions pertaining to this parameter are satisfied.


NRC RAI 46

In Section 5.4.8.1, Duke Energy stated that the SIMULATE-3K heat conduction model is used to

calculate the temperature distribution within the pin as well as the transport of heat from the fuel,

through the gap and cladding, and into the coolant. The model is also used to [[

]]. It is unclear to the NRC staff whether and how this fuel temperature calculation

feeds back to the neutronics solution. Are individual pin radial temperature distributions

determined and used to calculate Doppler reactivity effects? If average fuel temperatures are

used to evaluate Doppler reactivity effects, please justify why this is appropriate. (SRP 15.0.2)


Individual pin radial temperature distributions are not used to calculate Doppler feedback. All

fuel rods [

]a,c is used for Doppler feedback. The radial

geometry is typically modeled using [ ]a,c radial nodes per fuel assembly, and 24 equal-

length fuel nodes in the axial direction for current designs (Section 5.4.8.1 of DPC-NE-3009).

Calculating the Doppler feedback [

]a,c

both fuel temperatures and enthalpies calculated with this model will be conservative.


Reference 8 of DPC-NE-3009 describes the benchmark of the SIMULATE-3K model against

reference solutions developed for a power ramp, uncontrolled bank withdrawal and control rod

ejection accident. The good agreement between SIMULATE-3K-predicted reactivities relative to

those for the reference solution justifies the acceptability for using the average rod fuel

temperature for calculating Doppler feedback. The good agreement also demonstrates the

fidelity of the neutronics and the coupled transient neutronics and thermal-hydraulic models for

calculating not only Doppler reactivity, but also total core reactivity.


NRC RAI 47

In Section 5.4.8.2, “Fuel Temperature and Enthalpy Calculations,” Duke Energy proposed the

use of [[

]]. Is the [[ ]] incorporated into VIPRE-01? If so, how? If not,

please provide additional justification of how [[

]]. (SRP 4.2, SRP 15.4.8.III.1.E, SRP 15.4.8.III.2.B)


The [ ]a,c has not been incorporated into VIPRE-01. [

]a,c


NRC RAI 49

In Section 5.4.8.4, “RETRAN-3D System Thermal-Hydraulic Calculations,” Duke Energy states

that the failure of the control rod drive mechanism housing that causes the rod ejection is also

assumed to create a hole in the reactor vessel head the size of the control rod drive shaft.

However, the boundary conditions of the hole or how it is modeled are not specified. Please

provide additional information describing how the hole is modeled and the boundary conditions

used. (SRP 15.4.8.III.1.E)


As discussed in Section 5.4.8.4 of DPC-NE-3009, the mechanical failure that results in the

ejected rod is assumed to cause a hole to open in the reactor vessel head. The minimum size of

this hole is assumed to have a diameter equal to the plant-specific diameter of the control rod

drive shaft, because the hole must be large enough to allow the control rod drive shaft to eject

from the reactor vessel. The RETRAN-3D analysis of the Spectrum of RCCA Ejection Accidents

event models the minimum hole size. [

]a,c


NRC RAI 53

In the methodology presented for analysis of the inadvertent operation of the ECCS in Section

5.5.1, “Inadvertent Operation of the Emergency Core Cooling System,” of the report, it is unclear

to the NRC staff whether boron injection is modeled during the transient. The HNP analysis of

record for this event explicitly considers the effects of boric acid on reactivity. If boron injection is

modeled in the proposed methodology, please discuss the assumptions used related to boron

concentrations, boron worth, and boron transport. If not, please discuss how the proposed

method appropriately accounts for the effects of inadvertent operation of the ECCS on the core

power level. (Consistency with HNP current licensing basis (CLB))


Boron injection is modeled. The model used is the General Transport Model described in

Section 5.1.4.1 of DPC-NE-3009. Maximum boron concentration and boron worth are assumed

to reduce core power, leading to reduced RCS pressure and coolant temperatures. Minimum

boron transport delays (flushing volume) are assumed to minimize the core power response.


NRC RAI 54

Section 5.6.1, “Inadvertent Opening of a Pressurizer Relief or Safety Valve,” of the methodology

presents the proposed methodology for analyzing the inadvertent opening of a pressurizer relief

or safety valve. It is unclear to the staff whether both power-operated relief valves and safety

valves are considered as potential failures, or if the limiting valve is selected in advance. It is

also unclear how the initiating valve failure is modeled. Please clarify. (SRP 15.6.1 (Reference

21))



15.6.1, “Inadvertent Opening of a PWR Pressurizer Pressure Relief Valve or a BWR

Pressure Relief Valve,” Revision 2, March 2007 (ADAMS Accession No. ML070820094).


The analysis is applicable to either valve, but since the capacity of a safety valve bounds that of

a PORV, a stuck-open safety valve is chosen. The valve is modeled assuming the maximum

flow capacity of the valve to maximize the depressurization and cooldown. The critical flow

model used in the analysis is the combination model comprised of the Extended Henry

(subcooled) and Moody (saturated) models. The effective area of the safety valve is adjusted to

achieve the maximum flow capacity of the valve at the rated conditions. The failure is modeled

as a rapid opening of the safety valve to the fully open position.


NRC RAI 55

The SCD methodology is used to evaluate the core cooling capability for the inadvertent

opening of a pressurizer relief or safety valve transient in Section 5.6.1. Given that this event

has the potential for core uncovery, please justify why it is appropriate to evaluate the event

from nominal, rather than conservative initial conditions. Is a separate core uncovery analysis

performed? (SRP 15.0.2, SRP 15.6.1.I.1.B)


This event presents two possible challenges to core cooling. The first challenge is near the time

of reactor scram caused by the decrease in RCS pressure. Core uncovery is not a concern

during this short time period. This phase of the analysis is performed using the SCD

methodology assuming nominal initial conditions. The long-term phase of this event is

addressed as part of the LOCA analysis for Robinson assuming bounding initial conditions.

(Note that a failure of a PORV or safety valve is classified as a Condition IV event for

Robinson.) For Harris, the long-term response was addressed as part of the Steam Generator

Replacement / Power Uprate project, and AREVA (Siemens) determined using the SBLOCA

analysis methods that core cooling capability is adequate. The analysis is performed with

conservative initial conditions (e.g., power level, temperature, flow rate), and no core uncovery

or DNB occurs. The long-term portion of these analyses, should they need to be reanalyzed,

would be performed using the SBLOCA analysis methods and would assume conservative

initial conditions.


NRC RAI 56

For the steam generator tube rupture, the licensing basis analysis presented in the HNP FSAR

focuses almost exclusively on the margin to steam generator overfill, which is not presented as

an acceptance criterion in Section 5.6.2, “Steam Generator Tube Rupture,” of the methodology

report. Please discuss whether steam generator overfill will be analyzed with the proposed

method, with a justification for why the analysis is or is not needed. This discussion should

consider single failure assumptions for the margin to overfill analysis, consistent with the HNP

FSAR. (Consistency with HNP CLB)


The Margin to Overfill analysis will be performed with the proposed method. HNP is a Standard

Review Plan plant and must demonstrate that the steam generator (SG) will not overfill following

a steam generator tube rupture (SGTR). The HNP FSAR also states that once Margin to Overfill

is demonstrated, an Offsite Dose Assessment can be performed which has different sensitivities

to plant parameters. Therefore, both the Margin to Overfill and Offsite Dose analyses will be

performed with the proposed method. The Offsite Dose analysis described below is only the

thermal-hydraulic portion and does not address any radiological portion of the analysis.

Margin to Overfill Analysis

The SGTR overfill methodology is largely based on the PWR Owners’ Group work described in

WCAP-10698-P-A (Reference RAI-56-1). Following is a summary of the initial conditions,

boundary conditions, single failures and operator actions that are significant to the analysis.


Initial Conditions

All initial conditions significant to the analysis are listed below. Any initial conditions not listed

below are assumed to be nominal values.

● RCS Tavg: Sensitivity studies will be performed to determine what is limiting.

● SG Tube Plugging: Sensitivity studies will be performed to determine what is limiting.

● Power: Full power plus uncertainty.

● Pressurizer Pressure: Sensitivity studies will be performed to determine what is limiting.

● SG Level: High (Nominal + uncertainty + 10% to accommodate turbine runback).

Boundary Conditions

All boundary conditions significant to the analysis are listed below.

● Reactor Trip Signal Expected On:

– Low Pressurizer Pressure: Nominal + uncertainty (high is conservative)

– Over-Temperature Differential Temperature (OTΔT)

● Loss of offsite power upon reactor trip.

● Low Pressurizer Pressure Safety Injection: Nominal + uncertainty (high is conservative).

● Break location is at the top of the tube sheet on the cold side of the SG, to maximize the

primary-to-secondary flow rate.

● Maximum AFW flow with initiation of both motor-driven AFW pumps and the turbine-driven

AFW pump. Minimum temperatures will be applied to AFW flow.

● Safety injection flow from two high head safety injection pumps.

● Decay Heat: Sensitivity studies will be performed to determine if high or low decay heat is

limiting.


Single Failures

The following single failures will be evaluated to determine which is the most limiting:

● Failure of an intact SG PORV to open

● Failure of the TDAFW Pump Speed Controller

● Failure of an AFW flow control valve to close on demand

Operator Actions

The following operator actions are modeled. These are the same operator actions currently

credited in FSAR Section 15.6.3.

● Identify the ruptured SG and control AFW flow 8.8 minutes from event initiation or when

narrow range level reaches 30% on the ruptured SG, whichever is longer.

– In the case of the assumed failure of the AFW flow control valve to close, an additional 2

minute delay is applied to allow time for operators to close the AFW isolation valve.

● Isolate the ruptured SG 12 minutes from event initiation.

● Initiate RCS cooldown with the intact SG PORVs 5 minutes following isolation of the

ruptured SG. Cool down the RCS to 20°F subcooling.

● Initiate depressurization with a pressurizer PORV 4 minutes after termination of RCS

cooldown.

● Terminate SI 3 minutes after the end of the depressurization.

Offsite Dose Thermal-Hydraulic Input Analysis

The SGTR offsite dose methodology is largely based on the PWR Owners’ Group work

described in WCAP-10698-P-A. Following is a summary of the initial conditions, boundary

conditions, single failures and operator actions that are significant to the analysis.


Initial Conditions

All initial conditions significant to the analysis are listed below. Any initial conditions not listed

below are assumed to be nominal values.

● RCS Tavg: Sensitivity studies will be performed to determine what is limiting.

● SG Tube Plugging: Sensitivity studies will be performed to determine what is limiting.

● Power: Full power plus uncertainty.

● Pressurizer Pressure: Sensitivity studies will be performed to determine what is limiting.

Boundary Conditions

All boundary conditions significant to the analysis are listed below.

● Reactor Trip Signal Expected On:

– Low Pressurizer Pressure: Nominal - uncertainty (low is conservative)

– Over-Temperature Differential Temperature (OTΔT)

● Loss of offsite power upon reactor trip.

● Break location is at the top of the tube sheet on the cold side of the SG, to maximize the

primary-to-secondary flow rate.

● Decay Heat: High decay heat is conservative in order to maximize the post-trip heatup of the

primary system.

Single Failure

● The SG PORV on the ruptured SG fails to close at the time that operators isolate the

ruptured SG.


Operator Actions

The following operator actions are modeled. These are the same operator actions currently

credited in FSAR Section 15.6.3.

● Identify the ruptured SG and control AFW flow 10 minutes from event initiation or when



– Ruptured SG PORV fails to close.

● Operators have identified the failed-open SG PORV on the ruptured SG and locally close

the associated block valve 20 minutes following isolation of the ruptured SG.

● Initiate RCS cooldown with the intact SG PORVs 5 minutes following closure of the block

valve. Cool down the RCS to 20°F subcooling.


cooldown.


RETRAN-3D Safety Evaluation Report Limitations and Conditions

The limitations and conditions from the NRC’s generic Safety Evaluation Report on the

RETRAN-3D computer code (Reference RAI-56-2) were reviewed for the application of the

HNP/RNP base models to the Margin to Overfill and Offsite Dose Thermal-Hydraulic Input

analyses. The limitations and conditions are addressed by previous statements of resolution in

Section 3.2 of DPC-NE-3009.


Duke Energy RAI 56 Response References

RAI-56-1. “SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill,”

WCAP-10698-P-A, August 1987.

RAI-56-2. Richards, S. A., to Vine, G. L., “Safety Evaluation Report on EPRI Topical Report

NP-7450(P), Revision 4, ‘RETRAN-3D – A Program for Transient Thermal-Hydraulic

Analysis of Complex Fluid Flow Systems’ (TAC No. MA4311),” January 25, 2001.

(ADAMS Accession No. ML010470342)


NRC RAI 57

The current licensing basis for HNP relies on several operator actions to recover from a steam

generator tube rupture. Please discuss whether operator actions are modeled to terminate the

steam generator tube rupture in the DPC-NE-3009 methodology. If operator actions are

required, please describe and justify how each operator action is modeled. (There is no SRP

section specifically for the review of steam generator tube ruptures, but the requirement to

identify operator actions credited in transient and accident analyses is in SRP 15.0.I.6)


The description and justification of how each operator action is modeled in the SGTR Margin to

Overfill and Offsite Dose Thermal-Hydraulic Input analyses is discussed below. The modeled

operator actions mimic real operator actions performed in the SGTR Emergency Operating

Procedure.

SGTR Margin To Overfill Analysis Operator Actions

● Identify the ruptured SG and control AFW flow 8.8 minutes from event initiation or when


– AFW flow begins on reactor trip at maximum flow until 8.8 minutes. At this point, a

control system will throttle AFW flow to a fixed level setpoint in the ruptured SG, which

mimics real operator actions per Emergency Operating Procedures. The narrow range

level of 30% is a reasonable level setpoint that matches WCAP-10698-P-A (Reference

RAI-57-1).


– All ruptured SG valves, such as the MSIV, are closed, isolating the ruptured SG. This

mimics real operator actions per Emergency Operating Procedures.


● Initiate RCS cooldown with the intact SG PORVs 5 minutes following isolation of the

ruptured SG. Cool down the RCS to 20°F subcooling.

– SG PORVs on the intact SGs are opened to cool down the RCS until the correct core

exit temperatures from Emergency Operating Procedure E-3 are obtained. The target

core exit temperatures are based on 20°F RCS subcooling.


cooldown.

– Normal methods of depressurizing the RCS such as pressurizer spray are unavailable

due to the loss of offsite power. Therefore, a pressurizer PORV is used to depressurize

the RCS until one of the following criteria is met: 1) RCS pressure is less than the

ruptured SG pressure; 2) pressurizer level increases above the level specified in the

Emergency Operating Procedures; or 3) RCS subcooling decreases below 20°F.


– Safety injection flows are terminated, which mimics real operator actions per Emergency

Operating Procedures.

SGTR Offsite Dose Thermal-Hydraulic Input Analysis Operator Actions

● Identify the ruptured SG and control AFW flow 10 minutes from event initiation or when


– AFW flow begins on reactor trip at maximum flow until 10 minutes. At this point, a control

system will throttle AFW flow to a fixed level setpoint in the ruptured SG, which mimics

real operator actions per Emergency Operating Procedures. The narrow range level of

30% is a reasonable level setpoint similar to the modeling in WCAP-10698-P-A.

● Isolate the ruptured SG 12 minutes after event initiation.

– All valves, such as the MSIV, to the ruptured SG are closed, hydraulically isolating the

ruptured SG from the rest of the system. This mimics real operator actions per

Emergency Operating Procedures.


● Operators have identified the failed-open SG PORV on the ruptured SG and locally close

the associated block valve 20 minutes following isolation of the ruptured SG.

– This mimics real operator actions per Emergency Operating Procedures.

● Initiate RCS cooldown with the intact SG PORVs 5 minutes following closure of the block

valve. Cool down the RCS to 20°F subcooling.

– SG PORVs on intact SGs are opened to cool down the RCS until the correct core exit

temperatures from Emergency Operating Procedure E-3 are obtained. The target core

exit temperatures are based on 20°F RCS subcooling.


cooldown.

– Normal methods of depressurizing the RCS such as pressurizer spray are unavailable

due to the loss of offsite power. Therefore, a pressurizer PORV is used to depressurize

the RCS until one of the following criteria is met: 1) RCS pressure is less than the

ruptured SG pressure; 2) pressurizer level increases above the level specified in the

Emergency Operating Procedures; or 3) RCS subcooling decreases below 20°F.


– Safety injection flows are terminated, which mimics real operator actions per Emergency

Operating Procedures.


RAI-57-1. “SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill,”

WCAP-10698-P-A, August 1987.

proprietary information – withhold under …joseph donahue vice president nuclear engineering 526...

Documents