NOC-AE-14003130, Response to Request for Additional Information Regarding the Proposed Revision to the South Texas Project Fire Protection Program Related to Alternative Shutdown Capability

Response to Request for Additional Information Regarding the Proposed Revision to the South Texas Project Fire Protection Program Related to Alternative Shutdown Capability

ML14142A015
Person / Time
Site:	South Texas
Issue date:	05/12/2014
From:	Gerry Powell South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-14003130, STI: 33867885, TAC MF2477, TAC MF2478
Download: ML14142A015 (37)

Text

Nuclear Operating Company South Texas Project Electric GeneratingStation PO. Box 28,9 Wadsworth, Texas 77483 May 12, 2014 NOC-AE-14003130 10 CFR 50.90 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 South Texas Project Units 1 & 2 Docket Nos. STN 50-498, STN 50-499 STPNOC Response to Request for Additional Information Regarding the Proposed Revision to the South Texas Project Fire Protection Program Related to Alternative Shutdown Capability TAC Nos. MF2477 and MF2478

References:

1. Letter from D.W. Rencurrel, STP Nuclear Operating Company, to NRC Document Control Desk, "License Amendment Request for Approval of a Revision to the South Texas Project Fire Protection Program Related to the Alternative Shutdown Capability," dated July 23, 2013. (NOC-AE-13002962)

(ML13212A243)

2. E-mail from B. Singal, NRC, to L. Sterling, STP Nuclear Operating Company, "Request for Additional Information - License Amendment Request to Revise Fire Protection Program - TACs MF2477 and MF2478," dated April 2, 2014.

(AE-NOC-14002520) (ML14092A348)

On July 23, 2013, STP Nuclear Operating Company (STPNOC) submitted a license amendment request to revise the South Texas Project Units 1 and 2 Fire Protection Program related to alternate shutdown capability (Reference 1). In the event that a fire requires evacuation of the control room, the proposed amendment requested crediting the performance of certain operator actions, including one automatic operation, prior to evacuation.

By e-mail dated April 2, 2014 (Reference 2), the NRC requested additional information related to the STPNOC amendment request. Attachment 1 provides the STPNOC response to the Requests for Additional Information (RAI). Supplemental information that supports the RAI responses is provided in Attachments 2 and 3.

7keo(D(

STI: 33867885

NOC-AE-14003130 Page 2 of 3 There are no commitments in this letter.

If there are any questions regarding this letter, please contact Rafael Gonzales at (361) 972-4779 or me at (361) 972-7566.

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

Executed on Mc,4 1a2 oN4 G.T. Powell Site Vice President rjg Attachments:

1. STPNOC Response to Request for Additional Information Regarding the Proposed License Amendment Related to Alternative Shutdown Capability

2. Supporting Analysis for STP Response to RAI 3

3. Supporting Analysis for STP Response to RAI 9

NOC-AE-14003130 Page 3 of 3 cc:

(paper copy) (electronic copy)

Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Morgan, Lewis & Bockius LLP 1600 East Lamar Boulevard Arlington, TX 76011-4511 Balwant K. Singal U. S. Nuclear Regulatory Commission Balwant K. Singal John Ragan Senior Project Manager Chris O'Hara U.S. Nuclear Regulatory Commission Jim von Suskil One White Flint North (MS 8 B1) NRG South Texas LP 11555 Rockville Pike Rockville, MD 20852 NRC Resident Inspector Kevin Polio U. S. Nuclear Regulatory Commission Cris Eugster P. O. Box 289, Mail Code: MN116 L. D. Blaylock Wadsworth, TX 77483 City Public Service Jim Collins Peter Nemeth City of Austin Crain Caton & James, P.C.

Electric Utility Department 721 Barton Springs Road C. Mele Austin, TX 78704 City of Austin Richard A. Ratliff Robert Free Texas Department of State Health Services

Attachment 1 NOC-AE-13003130 ATTACHMENT 1 STPNOC Response to Request for Additional Information Regarding the Proposed License Amendment Related to Alternative Shutdown Capability

Attachment 1 NOC-AE-14003130 Page 1 of 12 STPNOC Response to Request for Additional Information Regarding the Proposed License Amendment Related to Alternative Shutdown Capability NRC RAI 1 (General)

The analyses indicate that spurious actuations are assumed to occur at the time of reactor trip. Spurious actuations can occur at any time during the fire, or not at all. Please state how was it determined that spurious actuations should be assumed to occur at the time of reactor trip?

STPNOC RAI 1 Response:

During the evaluation of the Control Room fire scenarios, several thermal hydraulic iterations were performed to achieve the worst-case scenario with power or during a loss of offsite power (LOOP) for a fire in the Control Room. As shown in Attachment 1 to Enclosure 1 of the license amendment request (LAR) regarding alternative shutdown capability, the worst-case and timing would occur at time zero "Reactor trip" because the spurious actuation would be the longest duration that a component could be in an undesirable position. This was also the case in the Defense in Depth (DID) analysis with the Pressurizer Power Operated Relief Valve (PORV) postulated open for 10 minutes until the Control Room back-up actions were completed. All back-up actions outside of the Control Room have been verified for feasibility and reliability.

NRC RAI 2 (Enclosure 1, Page 9)

The licensee states, in part, that:

[C]ertain actions within the control room must be successful to assure that RCS [reactor coolant system] process variables do not exceed the limits predicted for a loss of normal ac [alternating current] power (i.e., [Title 10 of the Code of Federal Regulations (10 CFR), Part 50,] Appendix R,Section III.L requirement) until control is successfully transferred.

10 CFR 50, Appendix R, Section III.L states, during the post fire shutdown, the reactor coolant system process variables shall be maintained within those predicted for a loss of normal a.c. power, and the fission product boundary integrity shall not be affected; i.e., there shall be no fuel clad damage, rupture of any primary coolant boundary, [or] rupture of the containment boundary.

Among the South Texas Project Electric Generating Station (STPEGS), Updated Final Safety Analysis Report (UFSAR), Chapter 15 accident analyses, loss of normal ac power is classified as an anticipated operational occurrence (AOO). Acceptable analysis results for this event resemble the acceptance criteria of Appendix R,Section III.L. For example, AOO

Attachment 1 NOC-AE-14003130 Page 2 of 12 analysis results must show that there is no fuel clad damage, and that the RCS pressure boundary remains intact.

Please compare the acceptance criteria of Appendix R,Section III.L to the UFSAR acceptance criteria for AOO's, and explain any differences that are identified.

Please explain how is the AOO design requirement, which prohibits an AOO from developing into a more serious event, considered in the fire hazards analyses?

STPNOC RAI 2 Response:

AOO Requirements 10CFR50 Appendix A defines an anticipated operational occurrence as follows:

"Anticipatedoperationaloccurrences mean those conditions of normal operation which are expected to occur one or more times during the life of the nuclear power unit and include but are not limited to loss of power to all recirculationpumps, tripping of the turbine generator set, isolation of the main condenser,and loss of all offsite power."

Chapter 15, Section 2.A of NUREG-0800 (Revision 3) provides the following acceptance criteria for anticipated operational occurrences (AOOs):

i. Pressurein the reactorcoolant and main steam systems should be maintainedbelow 110 percent of the design values in accordancewith the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code.

ii. Fuel cladding integrity shall be maintainedby ensuring that the minimum departure from nucleate boiling ratio (DNBR) remains above the 95/95 DNBR limit for PWRs and that the criticalpower ratio (CPR) remains above the minimum criticalpower ratio (MCPR) safety limit for BWRs.

iii. An AO0 should not generate a postulated accident without other faults occurring independently or result in a consequential loss of function of the RCS or reactor containment barriers.

Appendix R III.L RequirementsSection III.L of 10CFR50 Appendix R provides the following acceptance criteria:

L. Alternative and dedicated shutdown capability. 1. Alternative or dedicatedshutdown capabilityprovided for a specific fire area shall be able to (a) achieve and maintain subcriticalreactivity conditions in the reactor; (b) maintain reactorcoolant inventory; (c) achieve and maintain hot standby2 conditions for a PWR (hot shutdown2 for a BWR); (d) achieve cold shutdown conditions within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; and (e) maintain cold shutdown conditions thereafter.

During the post fire shutdown, the reactorcoolant system process variablesshall be maintainedwithin those predicted for a loss of normal AC power, and the fission product boundary integrity shall not be affected; i.e., there shall be no fuel clad

Attachment 1 NOC-AE-14003130 Page 3 of 12 damage, rupture of any primary coolant boundary, of rupture of the containment boundary.

2. The performance goals for the shutdown functions shall be:

a. The reactivity control function shall be capable of achieving and maintaining cold shutdown reactivityconditions.

b. The reactorcoolant makeup function shall be capable of maintaining the reactorcoolant level above the top of the core for BWRs and be within the level indication in the pressurizerfor PWRs.

c. The reactorheat removal function shall be capable of achieving and maintainingdecay heat removal.

d. The process monitoring function shall be capable of providing directreadings of the process variablesnecessary to perform and control the above functions.

e. The supportingfunctions shall be capable of providing the process cooling, lubrication, etc., necessary to permit the operation of the equipment used for safe shutdown functions.

3. The shutdown capability for specific fire areasmay be unique for each such area, or it may be one unique combination of systems for all such areas. In either case, the alternative shutdown capability shall be independent of the specific fire area(s)and shall accommodate postfire conditions where offsite power is available and where offsite power is not available for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Proceduresshall be in effect to implement this capability.

4. If the capability to achieve and maintain cold shutdown will not be available because of fire damage, the equipment and systems comprising the means to achieve and maintain the hot standby or hot shutdown condition shall be capable of maintainingsuch conditions until cold shutdown can be achieved. If such equipment and systems will not be capable of being powered by both onsite and offsite electricpower systems because of fire damage, an independent onsite power system shall be provided. The number of operatingshift personnel, exclusive of fire brigade members, required to operate such equipment and systems shall be on site at all times.

5. Equipment and systems comprising the means to achieve and maintain cold shutdown conditions shall not be damaged by fire; or the fire damage to such equipment and systems shall be limited so that the systems can be made operable and cold shutdown can be achieved within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Materialsfor such repairsshall be readily available on site and proceduresshall be in effect to implement such repairs.

If such equipment and systems used prior to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after the fire will not be capable of being powered by both onsite and offsite electric power systems because of fire damage, an independent onsite power system shall be provided.

Attachment 1 NOC-AE-14003130 Page 4 of 12 Equipment and systems used after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> may be powered by offsite power only.

6. Shutdown systems installed to ensure postfire shutdown capability need not be designed to meet seismic Category I criteria,single failure criteria,or other design basis accident criteria,except where requiredfor other reasons, e.g.,

because of interface with or impact on existing safety systems, or because of adverse valve actions due to fire damage.

7. The safe shutdown equipment and systems for each fire area shall be known to be isolated from associatednon-safety circuits in the fire area so that hot shorts, open circuits, or shorts to ground in the associated circuits will not prevent operation of the safe shutdown equipment. The separationand barriersbetween trays and conduits containingassociatedcircuits of one safe shutdown division and trays and conduits containing associatedcircuits or safe shutdown cables from the redundant division, or the isolation of these associatedcircuits from the safe shutdown equipment, shall be such that a postulated fire involving associatedcircuits will not prevent safe shutdown.3 Corresponding notes (from 10 CFR 50 Appendix R):

2As defined in the Standard Technical Specifications.

3An acceptable method of complying with this alternative would be to meet Regulatory Guide 1.75 position 4 related to associatedcircuits and IEEE Std 384-1974 (Section 4.5) where trays from redundant safety divisions are so protected that postulated fires affect trays from only one safety division.

AOO and Appendix R II.L Acceptance Limit Comparison The acceptance criteria for AOOs address the protection of fission product barriers and the creation of accidents or consequential failures of the RCS or containment. The criteria stated in 1II.L.3, III.L.4, III.L.5 and III.L.7 address the ability of equipment impacted by the fire to perform their intended function which is not addressed by the acceptance criteria for AOOs.

The criteria stated in III.L.1(a), Il.L.1(b), II.L.1(c), III.L.1(d) and II.L.1(e) address the ability of the plant to achieve cold shutdown conditions and not the acceptance criteria for AQOs.

The remainder of paragraph III.L.1 identifies that during the postfire shutdown, the reactor coolant system process variables shall be maintained within those predicted for a loss of normal AC power, which is not an acceptance criteria for AQOs and that the fission product boundary integrity shall not be affected; i.e., there shall be no fuel clad damage, rupture of any primary coolant boundary, of rupture of the containment boundary, which is an AOO acceptance criteria.

Section III.L.2 acceptance criteria is similar to the requirements of ll.L.1(a) through IIl.L.1(e) in that it addresses the ability of the plant to achieve safe shutdown conditions and not acceptance criteria for fission product barriers.

However, lll.L.2(b) does require that the reactor coolant makeup function be capable of maintaining the reactor coolant level within the level indication in the pressurizer, which is not an AOO acceptance criterion.

Attachment 1 NOC-AE-14003130 Page 5 of 12 Section III.L.6 identifies that shutdown systems installed to ensure post fire shutdown capabilities need not be designed to meet Category 1 criteria, single failure criteria, or other design basis accident criteria which is less restrictive than the criteria for AOOs. However,Section III.L.6 does require the consideration of adverse system response resulting from the fire, thus spurious actions of equipment needs to be considered.

AOO Developing Into A More Serious Event Consideration Based on the requirement stated in Section III.L.6 of Appendix R concerning the consideration of an adverse system response resulting from the fire, a spurious action of equipment can lead to a postulated accident which would be a violation of Acceptance Criteria iii stated in Chapter 15, Section 2.A of NUREG-0800 for AQOs. To comply with the requirements of Section III.L.6 of Appendix R, the STP fire hazards analysis assumes a spurious action resulting from a fire which may lead to a postulated accident. However, the analysis ensures that the requirements concerning RCS and steam line pressure and fuel cladding integrity identified in Section 2.a of NUREG-0800 for AQOs are not violated.

NRC RAI 3 (Enclosure 1, Page 9)

UFSAR, Chapter 15.2.6, does not report the results of a loss of normal ac power analysis. It states, "Plant specific analysis has shown that a loss of normal FW [feedwater] with a subsequent loss of AC power is the most limiting Condition II event in the decrease in secondary heat removal category with respect to the pressurizer overfill criterion and is analyzed in Section 15.2.7. Therefore, detailed analytical results for a loss of AC power transient will not be presented here."

As a Chapter 15 accident analyses, loss of normal ac power is less limiting than the loss of normal feedwater without offsite power. However, the loss of normal ac power could be the more limiting event when used as an Appendix R,Section III.L requirement. Please provide the following:

• Predicted values, from the loss of normal ac power analysis, that are to be used as limits.

• Identify the RCS process variables that must be maintained within those predicted for a loss of normal ac power and please explain how these RCS process variables were selected.

• Provide a comparison of the most limiting fire hazard analysis results against the loss of normal ac power analysis results, as per Appendix R,Section III.L.

STPNOC RAI 3 Response:

The loss of normal AC power event is classified as an AOO, and therefore must satisfy the acceptance limits identified in Chapter 15, Section 2.A of NUREG-0800 (Revision 3) as discussed in the response to RAI 2 above. The most limiting fire hazard analysis results are for the spuriously opened bank of steam dump valves described in Section Al.1 of Attachment 1 to Enclosure 1. This event is considered the most limiting in that indicated pressurizer water level remains off-scale for the longest period of time.

Attachment 1 NOC-AE-14003130 Page 6 of 12 Attachment 2 of this response provides the comparison of the results of a loss of normal AC power analysis and spuriously open bank of steam dump valve described in Section A1.1.

The analysis for the spuriously open bank of steam dump valve was extended from 1,000 seconds to 10,000 seconds to show the long term response of the event. The loss of normal AC analysis was performed using best estimate assumptions and assuming no failures.

The process parameters for the loss of normal AC power event are those that are required to demonstrate the acceptance limits for an AOO event. To demonstrate that the reactor coolant and main steam system pressure is maintained below 110 percent of the design values in accordance with the ASME Boiler and Pressure Vessel Code, the RCS pressure and steam generator pressure are chosen. The issue of fuel cladding integrity is demonstrated by ensuring the reactor core remains covered with water. Since the reactor is tripped at the initiation of the event, the fuel cladding heat flux is relatively low, so departure from nucleate boiling (DNB) is not an issue. By ensuring that the pressurizer does not go water solid and that the plant responds as anticipated, equipment damage is not expected.

The results presented in Attachment 2 show that process parameters RCS pressure and steam generator pressure remain within the AOO acceptance limits for both the loss of normal AC power and spuriously opened bank of steam dump valves events. The RCS water level is maintained in the pressurizer throughout the event, demonstrating that the reactor core remains covered with water.

NRC RAI 4 (Enclosure 1, Page 9)

In UFSAR, the more limiting Condition II event (i.e., the loss of feedwater without offsite power event) is chosen because it comes closer to challenging the pressurizer overfill criterion. The pressurizer overfill criterion is not among the criteria of Appendix R,Section III.L.

Please explain the role (if any) that the pressurizer overfill criterion plays in the fire hazard analyses. Refer to Case 2, "Spurious Opening of One Pressurizer PORV [power operated relief valve]" (Section A2.2.3, Enclosure 1, Attachment 2, Page 10).

STPNOC RAI 4 Response:

The STPNOC fire hazard analyses demonstrate that the pressurizer does not overfill assuming a limiting single spurious action and operator actions performed within the time frame provided on Table 1 of Enclosure 1 (P. 14-15) for a fire in the control room event as shown in the analysis results presented in Attachment 1 of Enclosure 1. Pressurizer overfill would not be acceptable for these events. The event described in Section A2.2.3 of Enclosure 1, Attachment 2, (page 10) was for a "Defense-In-Depth" analysis that assumed the operator actions proposed on Table 1 of Enclosure 1 were not performed prior to leaving the control room.

The acceptance criteria for the "Defense-In Depth" analysis required that the pressurizer level return to the indicating band after the plant reaches stable conditions as stated in Section A2.1 of Attachment 2 Enclosure 1. The results of the analysis demonstrate that this criterion is satisfied.

Attachment 1 NOC-AE-14003130 Page 7 of 12 NRC RAI 5 (Enclosure 1, Attachment 2, Page 10)

In Case 2, the pressurizer fills and the PORVs relieve water. It is stated that the PORVs are qualified to pass water. Please state how the PORVs have been qualified to pass water.

STPNOC RAI 5 Response:

Per Vendor Technical Document, the pressurizer PORVs are a Solenoid Power Operated Relief Valve design which are electrically controlled, pressure actuated, poppet type relief valves. The valves were designed and tested for water and steam with up to 4000 ppm of boric acid. The valves are designed to pass 1400 gpm of water and 210,000 pounds per hour (pph) of steam by the original manufacturer.

A Westinghouse structural analysis for the PORV's discharge line was performed for two phase flow (2350 psia conditions) and it bounded the hydrodynamic forces enveloped for water solid discharge design (120OF at 600 psia for cold water over pressure protection conditions). Therefore, the PORV discharge lines would be available in the worst case Defense-in-Depth analysis as described in Enclosure 1, Attachment 2 and the STPNOC Response to RAI 7.

NRC RAI 6 (Enclosure 1, Attachment 2, Page 13)

In Case 2, Figure A2.3.3 depicts a period (until about 2,000 seconds) of repeated opening and closing of the PORV. Please explain how the PORV automatic control system circuitry has been qualified to reliably open and close the PORV, as needed.

STPNOC RAI 6 Response:

Once the control circuit has been transferred out of the control room to the Auxiliary Shutdown Panel (ASP) during a fire, it becomes completely independent from the Control Room. A detailed review of the Equipment Qualification Package indicates the valve and solenoid were tested for 1000 cycles under accident conditions and another 10,000 cycles under normal conditions. The tested rate was 20 cycles per minute with the valve energized for 1 second, then after the 1000 cycles the valve retested under baseline conditions which included coil resistance, switch insulation resistance, position indication checks, pull-in and drop-out voltage, valve response, and a leakage test. Therefore, the valve/solenoid will perform as shown on Figure A21.3.3.

Attachment 1 NOC-AE-14003130 Page 8 of 12 NRC RAI 7 (Enclosure 1, Attachment 2, Pages 10 and 11)

An American Nuclear Society (ANS) design requirement for AOOs 1 states, "Condition II events (i.e., anticipated operational occurrences) shall be accommodated with, at most, a shutdown of the reactor with the plant capable of returning to operation after corrective action." In Case 2, the pressurizer fills and one PORV relieves water. Figure A2.3.3 depicts about 20 minutes of water relief through the PORV. Please explain how the plant will remain capable of returning to power after having experienced 20 minutes of water relief.

ANS-N18.2-1973, "Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants, August 6, 1973 STPNOC RAI 7 Response:

To return to power after a discharge of water through the pressurizer PORVs as described on Figure A2.3.3, the pressurizer PORVs and downstream piping must be qualified to pass water and the pressurizer relief tank must remain intact. At STP, the pressurizer PORVs discharge to the pressurizer relief tank. This tank has a rupture disk rated at 91 psig.

As discussed in the response to RAI #5, the pressurizer PORVs and down-stream piping are qualified to pass water. STPNOC has performed additional analysis using the GOTHIC computer code to determine the increase in pressure in the pressurizer relief tank due to the discharge through the pressurizer PORVs for Case 2. The analysis shows that the pressurizer relief tank will exceed the 91 psig rating of the rupture disk, which will result in the rupture disk performing its intended function and relieving to containment. The release from the pressurizer relief tank will result in the containment pressure and temperature increasing by less than 3 psi and less than 15'F, which will not result in any additional equipment failure. However, since the pressurizer relief tank rupture disks will need to be replaced, the event described in Section A2.3.3 of Attachment 2 to Enclosure 1 would not satisfy the ANS Condition II criteria.

The spurious opening of one pressurizer PORV with no operator action in the control room event described in Section A2.3.3 of Attachment 2 to Enclosure 1 was performed as a "Defense-in-Depth" analysis and not a Condition II event as defined by the ANS standard for AOOs. The ability to return to operation after corrective actions are taken is not a requirement of Appendix R. The results of the analysis presented in Section A2.1 of Attachment 2 to Enclosure 1, demonstrate that the acceptance limits for a "Defense-in-Depth" analysis are acceptable. That is:

" Sufficient core cooling is established and maintained throughout the transient.

" Fuel cladding integrity is not challenged.

" Pressurizer and steam generator levels return to the indicating band after the plant reaches stable conditions.

" Charging and letdown are restored to support cooldown to cold shutdown conditions.

Therefore, while the results of the analysis performed for a spuriously opened pressurizer PORV do not satisfy the ANS Condition II Criteria for an AOO, the results demonstrate that "Defense-in-Depth" analysis requirements are satisfied.

Attachment 1 NOC-AE-14003130 Page 9 of 12 NRC RAI 8 (Enclosure 1, Attachment 2, Page 13)

Stable plant conditions are maintained until excess letdown is placed in service (7,210 seconds), and pressurizer water level returns to the indicating range (16,928 seconds). The pressurizer is water-solid for about 4-1/2 hours.

Please explain how would the pressurizer pressure be controlled while the pressurizer is water-solid? Also, please define "stable plant conditions", and explain how stable conditions would be maintained for 4-1/2 hours.

STPNOC RAI 8 Response:

After the spuriously opened pressurizer PORV block valve is closed, the pressurizer pressure is controlled by the PORV that did not spuriously open. Due to the depressurization of the RCS that result from the spuriously opened pressurizer PORV, safety injection is assumed to occur, resulting in a cooling of the RCS. After the spuriously opened pressurizer PORV is secured, RCS pressure increases and reaches the safety injection system shutoff head of approximately 1,700 psig. After safety injection flow is terminated due to RCS pressure, the RCS begins to heat up. After the RCS temperature reaches a steady state condition (approximately 2,000 seconds), the thermal expansion of the coolant ends, which results in the RCS pressure reaching steady state. This results in a termination of water relief from the pressurizer PORV. The RCS cold leg temperature is maintained at the saturation temperature of the steam generator PORV setpoint. The hot leg temperature is then a function of decay heat and natural circulation flow rate. As the hot leg temperature decreases due to the reduction in decay heat, the RCS decompresses resulting in a reduction in pressurizer pressure as shown on Figure A2.3.3.

At 7,210 seconds, excess letdown is placed in service, which assists in the decompression of the RCS. After sufficient RCS water inventory has been released through excess letdown, a bubble in the pressurizer can be reestablished. During the period when the pressurizer is water-solid, pressure can be controlled by adjusting the steam generator PORV setpoint. Increasing the steam generator PORV setpoint will increase RCS temperature which will result in an expansion of the RCS fluid and increase RCS pressure.

However, this may also result in additional water relief through the pressurizer PORV.

Decreasing the pressurizer PORV setpoint will have the opposite effect. However, due to the sensitivity of the RCS temperature and pressure relationship under water solid condition, this means of controlling RCS pressure is not being proposed. With letdown and charging unavailable, operators would maintain plant conditions until letdown is made available.

The term "stable plant conditions" as used in the submittal means that the parameters used to demonstrate that the acceptable criteria identified in Section A2.1 are not adversely trending. The results show that parameters such as RCS pressure, temperature and steam generator level are being maintained.

Attachment 1 NOC-AE-14003130 Page 10 of 12 NRC RAI 9 (Enclosure 1, Attachment 2, Page 13)

In Case 2, Figure A2.3.3 depicts a period (between 3,000 seconds and 14,000 seconds) falling and rising pressure. Please explain this pressure variation. (charging pumps secured at 610 seconds and the shutoff head of the high head safety injection pumps is stated as approximately 1,700 psia.)

STPNOC RAI 9 Response:

The falling and rising pressure is due to the decompression and compression of the RCS under water solid conditions. The falling and rising pressure corresponds to the addition and subtraction of AFW flow. The model used in the analysis for Case 2 used a simple representation of how the operators would control AFW flow based on steam generator water level. The AFW flow control model, while adequate for the analysis, was not an accurate representation of how the operators would actually control AFW flow. Attachment 3 of this response contains the results of a re-analysis with a revised AFW flow control model that more accurately reflects operator actions. The results of the analysis show that the falling and rising of the pressure is eliminated with the revised AFW flow control model.

NRC RAI 10 (Enclosure 1, Attachment 2, Pages 25-27)

For Cases 1a and 1b, in which offsite power is assumed to be lost, please justify the assumption that pressurizer backup heaters are available.

STPNOC RAI 10 Response:

During a loss of offsite power (LOOP), Pressurizer Backup Heater Groups A and B can be powered from independent Class 1 E power supplies, which are Class 1 E Standby Diesel Generators "A" and "C," respectively. If a LOOP occurs, these Class 1 E standby diesel generators receive an automatic start signal, the diesel generator breaker closes within 10 seconds of the diesel receiving the automatic start signal, and the 480 Volt ESF Load Center buses are energized one second after the diesel generator breaker is closed.

Following a LOOP, Pressurizer Backup Heater Groups A and B are not automatically connected to their respective 480 Volt ESF Load Center buses; however, these heaters may be manually connected under administrative control during a LOOP at the discretion of the operator. Therefore, these pressurizer backup heaters are available for use following a LOOP.

NRC RAI 11 (Enclosure 1, Attachment 2, Page 29)

For Case 1a, in which offsite power is assumed to be lost, please justify the assumption that (1) the PORV control system circuitry is qualified to cycle the PORV until 2,950 seconds, and (2) that power can be supplied to the PORV for that length of time.

STPNOC RAI 11 Response:

The pressurizer PORVs are connected to 125 VDC Class 1 E Distribution Switchboards and are normally powered by Class 1 E Motor Control Centers via Class 1 E 125 VDC Battery Chargers.

Attachment 1 NOC-AE-14003130 Page 11 of 12 Upon the loss of offsite power (Case la), the chargers powering the PORVs (PCV0655A and 656A) will be supplied by Class 1 E Diesel Generators (Train A and C respectively).

When the diesels are not available (during ramp up or failure), the PORVs will be supplied by Class 1 E 125 VDC Batteries (El (2)A1 1, El (2)B1 1).

The batteries are sized to supply adequate power during a two hour Design Basis Event for DC systems and components which are required to operate without a battery charger available. Taking into account the available margin on the Class 1E 125 VDC Batteries, the batteries will adequately supply the PORVs at inrush loading (worst case for cycling) for the full two hours (7200 seconds) which greatly exceeds the 2,950 second assumption in Case 1a.

The relays and contactors in the switchboard have a 600 V insulation class rating and are suitable for operation on 125 VDC. During postulated repeated actuation of the PORV, these control circuit components will be intermittently operated (cycled) within their continuous equipment ratings (for voltage and current). In addition, the time between cycles (even a short period of time between cycles) will be sufficient to allow heat dissipation of any additional heat built up due to cycling of the components during the event. Over the life of the components, these relays and contactors are designed to perform millions of operating cycles, which bounds the number of operating cycles required during repeated actuation of the PORVs. As a result, the electrical stresses on these electrical control circuit components due to the number of cycles these components would experience during repeated actuation of the PORVs will not have an adverse effect on the ability of the components to perform their design function over the life expectancy of the components.

The control circuit only contains fuses for overload protection (no overload relays with thermal overload heaters). The electrical stresses on the fuses due to the repeated actuation of the PORV will be within the continuous voltage and current rating of the control fuses and therefore will have no adverse impact to these components. The time between cycles (even a short period of time between cycles) will be sufficient to allow the dissipation of any additional heat built up due to the cycling of the PORV and allow the fuses to remain in operation and maintain their protective characteristics.

NRC RAI 12 This analysis is geared toward minimizing pressurizer level; to show that subcooling margin is not lost. Subcooling margin, as depicted in Figure A1.8.9, reaches a minimum at about the time the indicated pressurizer level drops to 7.1%; but remains positive. Please state the minimum value of subcooling margin?

Also, please estimate the uncertainties associated with this value and what causes the subcooling margin to increase after reaching its minimum?

Table A1.8 and Figure A1.8.2 indicate that pressurizer water level is 7.1% and constant for approx. 608 seconds. Figures A1.8.1, A1.8.3, A1.8.4, A1.8.5, A1.8.6, and A1.8.9 depict a change in trend between 600 and 650 seconds. Please explain what causes this change?

Attachment 1 NOC-AE-1 4003130 Page 12 of 12 STPNOC RAI 12 Response:

The analysis documented in Section A1.8 was performed to demonstrate that with the uncertainties used in a Chapter 15 type analyses applied to the initial conditions and setpoints, the plant could achieve safe shutdown conditions without adversely impacting fission product boundary integrity. The minimum value for subcooling 'margin is 0.7 0 F, which occurs at 356 seconds with the Chapter 15 uncertainties applied, based on the actual process parameters. The uncertainty in the subcooling margin as displayed on Qualified Display System in the control room is +26 0 F/-19 0 F. Therefore, a loss in shutdown margin as indicated in the control room does not result in the inability of the plant to achieve a safe shutdown condition or result in a breach of any fission product barriers.

The subcooling margin is calculated using the average of three wide range pressure transmitters to determine the saturation temperature based on internal steam tables. This value is subtracted from the average temperature using the highest core exit thermal couples. Figures A1.8.1 and A.1.8.4 provide the RCS pressure and hot leg temperature versus time for the event. These figures show that RCS pressure is relatively constant for the period from approximately 180 to 400 seconds while the hot leg temperature (indicative of the core exit temperature) is rising, leading to a decrease in subcooling margin shown on Figure A1.8.9. At approximately 360 seconds, the hot leg temperature begins to decrease providing subcooling margin.

The change in the trend between the 600 and 650 seconds is due to a reduction in auxiliary feedwater. The analysis assumes the maximum AFW flow of 675 gpm which includes uncertainties for the analysis of this event. This assumption is conservative because maximum AFW flow results in a greater decrease in pressurizer water level and RCS pressure. At 601 seconds the operators throttle AFW flow to the steam generators which results in an increase in RCS temperature. This increase in RCS temperature results in an increase in pressurizer pressure and actual water level due to the thermal expansion of the RCS water into the pressurizer as shown on Figures A1.8.1, A1.8.3, and hot and cold leg temperature as shown on Figure A1.8.4. With the reduction in colder AFW flow, the steam generator pressure increases as shown on Figure A1.8.5. The steam generator water level increases slowly after the AFW is throttled until the secondary side water is no longer sub-cooled, at which time steam generator water level increases due to the swell as shown on Figure A1.8.6. The initial increase in RCS pressure due to the reduction in AFW flow results in an increase in subcooling margin as shown on Figure A1.8.9. The rate of increase in subcooling margin decreases as the warmer water from the cold leg passes through the core and increases the core exit thermal couple temperature. Subcooling margin continues to increase as the margin associated with the increase in RCS pressure exceeds the reduction in subcooling margin associated with the increase in core exit thermocouple temperature.

Attachment 2 NOC-AE-14003130 ATTACHMENT 2 Supporting Analysis for STP Response to RAI 3

Attachment 2 NOC-AE-14003130 Page 1 of 13 Supporting Analysis for STP Response to RAI #3 The purpose of this attachment is to provide a comparison of the results of a loss of normal AC power to the spuriously opened bank of steam dump valves described in Section A1.1 of to Enclosure 1 of Reference Al. The results of spuriously opened bank of steam dump valves analysis has been extended from the 1,000 seconds to 10,000 seconds to show the long term response of the event.

Unlike the spuriously opened bank of steam dump analysis, the loss of normal AC power analysis assumes automatic actions occur such as letdown isolation and main feedwater isolation. Another significant difference is that the spuriously opened bank of steam dump valves analysis assumes offsite power is available. The loss of AC normal power assumes the Operators can control equipment from the Control Room and they do not have to evacuate to the auxiliary shutdown panel.

A time line of events is presented on Table R1.1.1. Figures R1.1.1 through R1.1.9 show the same parameters analyzed in Figures A1.1.1 through A1.1.9 in Attachment 1 of Reference Al.

The results show that process parameter's RCS pressure and steam generator pressure remain within the AOO acceptance limits for both the loss of normal AC power and spuriously opened bank of steam dump valves events. The RCS water level is maintained in the pressurizer throughout the event, demonstrating that the reactor core remains covered with water.

Reference Al: "License Amendment Request for Approval of a Revision to the South Texas Project Fire Protection Program Related to the Alternative Shutdown Capability," dated July 23, 2013. (NOC-AE-13002962) (ML13212A243)

Attachment 2 NOC-AE-14003130 Page 2 of 13 Table R1.1.1 Time Line Comparison Normal LOOP vs One Bank of Steam Dump Valves Stuck Open Events and/or Actions One Bank of Steam Normal LOOP Dump Valves Stuck Open Time (seconds)

Time (seconds)

Reactor Trip 10 [Note 1] 10 [Note 21 One Bank Steam Dump Valves 10 [Note 21 N/A Spuriously Open Main Turbine Trips 13 .5[Note 21 13 .5[Note 2[

Start Up Feed Pump (SUFP) Starts 4 5 [Note21 N/A Main Steam Isolation Valve (Includes 5 4 5 [Note 1] 6 1 5 [Note 1]

second valve closure time)

Steam Generator Level Low Low Signal 56.8 32.3

(< 20 % NRS)

AFW Flow to Steam Generators 6 6 .1 [Note2] 2 5 .1 [Note 2]

[Note 11 [Note 2]

RCPs Tripped 1 3 0 1 0

[Note 1] [Note 21 Feedwater isolated 1 30 3 6 SUFP in PULL-TO-LOCK 1 3 0 [Note 1] N/A

[Note 2]

Charging and Letdown Isolated 1 3 0 [Note 1] 1 0 Indicated Pressurizer Water Level Off- 484 N/A Scale Low AFW Flow Throttled 6 1 0 [Note 1] 6 1 0 [Note 1]

Indicated Pressurizer Water Level 873 N/A Returns to Scale Notes:

1. Manual Operator Action

2. Automatic Action

Attachment 2 NOC-AE-14003130 Page 3 of 13 2400 2300 C.) 2200 2100 ci) 2000 C)

N 1900 cj~ 1800 rj~

C.)

1700 1600 0 200 400 600 800 1000 Time (s)

Figure R1.1.1: Pressurizer Pressure Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

2400 1-)

2300 2200 2100 2000 N 1900 1800 1700 1600 0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.1.x: Pressurizer Pressure Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 4 of 13 60 50 40 N

30 rA 20 U

10 0

0 200 400 600 800 1000 Time (s)

Figure R1.1.2: Indicated Pressurizer Water Level Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

' 60 6-Normal LOOP 50 ---- Case of One Bank of Steam Dump Valves Spuriously-

. O pen 4)

CAI3i40 _

1 ... .. .

20 0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.2.x: Indicated Pressurizer Water Level Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 5 of 13 25.00 171 40 0 200 400 600 800 1000 Time (s)

Figure R1.1.3: Actual Pressurizer Water Level Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

25.00 0

0

-o 0

r-,)

0 0

0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.3.x: Actual Pressurizer Water Level Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 6 of 13 2.68 2.67 ..

2.66 2.65 2.64

-o 2.63 2.62 2.61 2.60 M.

0 2.59 2.58 600 620 640 660 680 700 Time (s)

Figure R1.1.3.y: Actual Pressurizer Water Level Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 600 to 700 seconds.

Attachment 2 NOC-AE-14003130 Page 7 of 13 640 620 AD 600 HD 580 560 0,

540 520 0 200 400 600 800 1000 Time (s)

Figure R1.1.4.a: Loop 1 RCS Hot-leg Temperature Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

640 620 2 Valves-Ca OfOm Bankof Steam Dump Spu60 o n s.

600 * -- ............... ......... +.... .... .

580 560 i

,~

~ ~ ...~......... .... . . . . ........ ... .. . .. L........ ...

520, ,, , ,

0 2000 4000 6000 8000 10000 Time (s)

Figure Rl.1.4.a.x:' Loop X RCS Hot-leg Temperature Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 8 of 13 640 cI-,

620 600 580 03 560 540 520 0 200 400 600 800 1000 Time (s)

Figure Rl.1.4.b: Loop 1 RCS Cold-leg Temperature Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

640 ci, 620 600 S 580 560 540 U 520 0 2000 4000 6000 8000 10000 Time (s)

Figure RI.1.4.b.x: Loop 1 RCS Cold-leg Temperature Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 9 of 13 1250 1200 1150 0

1100 1050 1000 al) 950 900 0 200 400 600 800 1000 Time (s)

Figure R1.1.5: Loop 1 Steam Generator Pressure Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

1250 1200 1150 0 1100 1050 M~

0 1000 Con 950 900 0 2000 4000 6000 8000 10000 Time (s Figure R1.1.5.x: Loop 1 Steam Generator Pressure Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 10 of 13 80 0.y) 60 40 C4 Q.)

20 01 0

0 200 400 600 800 1000 Time (s)

Figure R1.1.6: Loop 1 Steam Generator Water Level for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

80 0.)

60 C

0.)

0.)

40 0

S*

20 0.

0 0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.6.x: Loop 1 Steam Generator Water Level for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 11 of 13 1

z.3 0.8 4.. - Norma LOOP ....................

- - - Case of One Bank of Steam Dump Valves C Spuriously-Open F f C 0.6 0

. . . . . . . . . . . i .................. ..........

0.4 -1 0

0.2 0

Q i _ i_ ._ _. _ . . . .

0 0 200 400 600 800 1000 Time (s)

Figure R1.1.7: Core Power Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

1

.3 0.8 -Normal LOOP

- - - Case of One Bank of Steam Dump Valves Spuriously-Open 0

0.6 0

C 0.4 0.2 0

o 0

0 2000 400 0 6000 8000 10000 Time (s)

Figure R1.1.7.x: Core Power Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 12 of 13 2500 0

S 2000 - h---- I Normal LOOP m *1500 E 1000 I

~

1~ ~ ~~~~a- --

~Steanm aOncoe Bankof of______

DumpValves I ~Spuoulouy-OpOF1 S 500 0

0 200 400 600 800 1000 Time (s)

Figure R1.1.8: Total Steam Dump Flow Rate Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

2500 0

2000 I - 4NOMnao LOQU 0 .

0 1500  !.~..--

M rj~

1000 - - - Case of One Bank of Steam Dump Valves Spwrlousty-Open M 500 -

V 0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.8.x: Total Steam Dump Flow Rate Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 2 NOC-AE-14003130 Page 13 of 13 80 70 60 50 0 40

.P4 30 0

20 10 0 200 400 600 800 1000 Time (s)

Figure R1.1.9: Sub-Cooling Margin Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 1,000 seconds.

80 1 1 ,I

- 70 60 50 40

-o 30 U*

20 10 0 2000 4000 6000 8000 10000 Time (s)

Figure R1.1.9.x: Sub-Cooling Margin Comparison for Normal LOOP and Case of One Bank of Steam Dump Valves Spuriously-Open from 0 to 10,000 seconds.

Attachment 3 NOC-AE-14003130 ATTACHMENT 3 Supporting Analysis for STP Response to RAI 9

Attachment 3 NOC-AE-14003130 Page 1 of 6 Supporting Analysis for STP Response to RAI 9 Supporting Analysis for STP Response to RAI #9 The purpose of this attachment is to explain the pressure variation observed in Case 2, Figure A2.3.3 of Attachment 2 to Enclosure 1 of Reference B1. between 3,000 seconds and 14,000 seconds.

The falling and rising pressure is due to the decompression and compression of the RCS under water-solid conditions. The falling and rising pressure corresponds to the addition and subtraction of AFW flow. The model used in the analysis for Case 2 used a simple representation of how the operators would control AFW flow based on steam generator water level. The AFW flow model, while adequate for the analysis, is not a very accurate representation of how the operators would actually control AFW. Once reaching the Auxiliary Shutdown Panel, operators would reduce AFW flow to prevent overcooling of the RCS. Flow would then be throttled to restore and maintain steam generator water level without overcooling the RCS. Depending on how the operators control AFW flow to the steam generators explains the ROS pressure and temperature swings observed in the results of Case 2. To more accurately reflect the AFW flow that the operators would deliver, a re-analysis was performed, as presented in this attachment, with a revised AFW flow control model. The results of the analysis show that the falling and rising of the pressure is eliminated with the revised AFW flow control model.

The revised AFW flow control model changes how operators deliver AFW flow to the steam generators once they have control in the Auxiliary Shutdown Panel (ASP). All other aspects of the analysis are the same. In both the previous and revised analysis, AFW flow is 640 gpm (89 Ibm/sec) per steam generator from the time AFW is initiated until the operators take control at 610 seconds. After 610 seconds in the previous analysis, AFW flow varies in a linear fashion from 640 gpm to 0 gpm for each steam generator as the indicated steam generator water level varies from 22% to 50%. In the revised analysis, the AFW flow is throttled to 144 gpm per steam generator when the indicated steam generator water level is between 22% and 30% and then varies in a linear fashion from 144 gpm to 0 gpm as the indicated water level varies from 30% to 50%. A representation of the AFW flow versus indicated steam generator water level for both the previous and revised analysis is presented on Figure R2.3.8. Figure R2.3.7 shows the revised AFW flow that steam generator Loop 1 would receive using the revised model versus the original AFW flow from Reference BI. Figure R2.3.3 through R2.3.6 show the oscillations due to this revised AFW flow model are eliminated.

Reference BI: "License Amendment Request for Approval of a Revision to the South Texas Project Fire Protection Program Related to the Alternative Shutdown Capability" dated July 23, 2013. (NOC-AE-13002962) (ML13212A243)

Attachment 3 NOC-AE-14003130 Page 2 of 6 Table R2.3 Sequence of Events for a Spurious Opening of One Pressurizer PORV Occurring at Time of Reactor Trip Event Signal Original Revised Time (sec) AFW Time (sec)

Reactor Trip Manual 10 10 One pressurizer PORV fails open Spurious 10 10 Turbine Trip On Reactor Trip 13.5 13.5 Feedwater Isolation Low Tavg 34.6 34.6 AFW flow initiated Low SG Level 36.5 36.5 SI initiated Low Pressurizer 48.5 48.5 Pressure Letdown isolated On SI Signal 48.5 48.5 Pressurizer level off-scale high 410 410 Pressurizer water solid 524 524 Close block valve to spuriously opened Manual 610 610 PORV. Second PORV block valve left open.

Secure centrifugal charging pumps Manual 610 610 Operators control AFW flow Manual 610 610 MSIV closure Manual 615 615 Secure RCPs Manual 1,810 1,810 Initiate excess letdown. Charging Manual 7,210 7,210 available for boration Pressurizer level < 100% nj 16,928 17,180

Attachment 3 NOC-AE-14003130 Page 3 of 6 Figure R2.3.1 Fire Hazard - Spurious Pzr PORV Open 14104/14 RETRAN-02-MOD005.2.1 05/05/05 EPRI 100 90 0

80 70 60 50 0-40 30 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Figure R2.3.2 Fire Hazard - Spurious Pzr PORV Open 14104/14 RETRAN-02-MOD005.2.1 05105105 EPRI 40 35 0

30 25 20 0

N 15 cj~

0 10 5

0 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Attachment 3 NOC-AE-14003130 Page 4 of 6 Figure R2.3.3 Fire Hazard - Spurious Pzr PORV Open 14/04114 RETRAN-02-MOD005.2.1 05105105 EPRI 2500 CI 2300

• 2100 j 1900

• 1.700 N

1500 1300 1100 900 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Figure R2.3.4 Fire Hazard - Spurious Pzr PORV Open 14/04/14 RETRAN-02-MOD005.2.1 05/05/05 EPRI 600 590

, 580

" 570 C.3 560

- 550 0 540 C

S 530 520 510 0 2000 4000 6000 8000 10000 12000 1.4000 16000 18000 Time (s)

Attachment 3 NOC-AE-14003130 Page 5 of 6 Figure R2.3.5 Fire Hazard - Spurious Pzr PORV Open 14104/14 1 RETRAN-02-MOD005.2.1 05105105 EPRI 70 60 0

50 r0 40 30 0 20 0

10 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Figure R2.3.6 Fire Hazard - Spurious Pzr PORV Open 14(04/14 RETRAN-02-MOD005.2.1 05/05/05 EPRI 130 120 110 100 90 80 70 60 50 e,\ 40 30 20 10 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Attachment 3 NOC-AE-14003130 Page 6 of 6 Figure R2.3.7 Fire Hazard - Spurious Pzr PORV Open 14104/14 RETRAN-02-MOD005.2.1 05/05/05 EPRI 100 0

0/ 90 -~-I-80 I... ..

70 I

-- -! I

__ 1 __ 4__

0 60 l_ I7I

-Original Revised AFW 50 40 ..............

30 I - --

0 0

20 10

......A... Ir. .........

0 I I. . . . . ..,m

. . . . ..

• KI I I I

• I E II I I ,,,J I m 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 Time (s)

Figure R2.3.8 Fire Hazard - Spurious Pzr PORV Open 14/04/14 RETRAN-02-MOD005.2.1 05/05/05 EPRI 700 600 0 500 400 300 200 100 0

0 20 40 60 80 100 Indicated SG Level (% NRS)